Cheniere Corpus Christi 10-K 2018 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

  For the fiscal year ended December 31, 2018

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 For the transition period fromto

Commission file number 333-215435

Cheniere Corpus Christi Holdings, LLC

(Exact name of registrant as specified in its charter)

Delaware	47-1929160
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
700 Milam Street, Suite 1900
Houston, Texas	77002
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code: (713) 375-5000

Securities registered pursuant to Section 12(b) of the Act: None 

Securities registered pursuant to Section 12(g) of the Act: None 

The registrant meets the conditions set forth in General Instruction 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  o  No  x

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  x  No  o

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  o  No  x

Note: As of January 1, 2018, 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  x    No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

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 Act.

Large accelerated filer  o	Accelerated filer                     o
Non-accelerated filer    x	Smaller reporting company    o
	Emerging growth company    o

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 Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes  o  No  x

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

Documents incorporated by reference: None

CHENIERE CORPUS CHRISTI HOLDINGS, LLC

TABLE OF CONTENTS

PART I
Items 1. and 2. Business and Properties	1
Item 1A. Risk Factors	9
Item 1B. Unresolved Staff Comments	22
Item 3. Legal Proceedings	22
Item 4. Mine Safety Disclosure	22
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6. Selected Financial Data	23
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	33
Item 8. Financial Statements and Supplementary Data	34
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	71
Item 9A. Controls and Procedures	71
Item 9B. Other Information	71
PART III
Item 10. Managers, Executive Officers and Company Governance	72
Item 11. Executive Compensation	72
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Member Matters	72
Item 13. Certain Relationships and Related Transactions, and Manager Independence	72
Item 14. Principal Accountant Fees and Services	72
PART IV
Item 15. Exhibits and Financial Statement Schedules	73
Item 16. Form 10-K Summary	79
Signatures	80

i

DEFINITIONS

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

Common Industry and Other Terms

Bcf	billion cubic feet
Bcf/d	billion cubic feet per day
Bcf/yr	billion cubic feet per year
Bcfe	billion cubic feet equivalent
DOE	U.S. Department of Energy
EPC	engineering, procurement and construction
FERC	Federal Energy Regulatory Commission
FTA countries	countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP	generally accepted accounting principles in the United States
Henry Hub	the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
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, 2018, including our ownership of certain subsidiaries, and the references to these entities used in this annual report:

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

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, 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 facilities, pipeline facilities 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 and pipelines, including the financing of such Trains and pipelines;

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

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

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

CCH is a Delaware limited liability company formed in September 2014 by Cheniere Energy, Inc., a Houston-based energy 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 wholly-owned subsidiaries CCL and CCP, respectively.

The Liquefaction Project is being developed in stages with the first phase being three Trains (“Phase 1”), with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage (“Stage 1”) includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, one LNG storage tank and the completion of the second partial berth. Trains 1 and 2 are undergoing commissioning and Train 3 is under construction.

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:

• achieving the date of first commercial delivery for our SPA customers;

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

• completing construction and commencing operation of the first three Trains of the Liquefaction Project;

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

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

• maintaining a prudent and cost-effective capital structure.

Our Liquefaction Project

The Liquefaction Project is being developed and constructed at the Corpus Christi LNG terminal. We have received authorization from the FERC to site, construct and operate Stages 1 and 2 of the Liquefaction Project. The following table summarizes the overall project status of the Liquefaction Project as of December 31, 2018:

	Stage 1		Stage 2
Overall project completion percentage	96.7%		42.0%
Completion percentage of:
Engineering	100%		87.0%
Procurement	100%		63.0%
Subcontract work	89.5%		8.5%
Construction	93.1%		11.7%
Expected date of substantial completion	Train 1	1Q 2019	Train 3	2H 2021
	Train 2	2H 2019

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 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 begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from seven to 10 years from the date the order was issued.

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Customers

CCL has entered into fixed price 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 between approximately 75% to 85% of the expected aggregate adjusted nominal production capacity from these Trains. Under these SPAs, the customers will purchase LNG from CCL 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. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, 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 related to, and operating and maintenance costs 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 and increasing to approximately $1.4 billion for Train 2, in each case upon the date of first commercial delivery for the respective Train, 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.;

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

• approximately $270 million from Naturgy LNG GOM, Limited (formerly known as Gas Natural Fenosa LNG GOM, Limited), 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 from buyers under all of our other third-party SPAs for Trains 1 through 3 of the Liquefaction Project is approximately $790 million.

CCL expects to sell LNG that it produces that is in excess of the contract quantities committed under CCL’s third-party SPAs to Cheniere Marketing International LLP (“Cheniere Marketing”), an indirect wholly-owned subsidiary of Cheniere.

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, 2018, CCL had secured up to approximately 2,801 TBtu of natural gas feedstock through long-term natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.

Construction

CCL entered into separate lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Stages 1 and 2 of the Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost 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.

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The total contract prices of the EPC contract for Stage 1 and the EPC contract for Stage 2, which do not include the Corpus Christi Pipeline, are approximately $7.8 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through December 31, 2018. Total expected capital costs for Trains 1 through 3 are estimated to be between $11.0 billion and $12.0 billion before financing costs and between $15.0 billion and $16.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

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 commenced in January 2017 and 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. This regulatory requirement increases 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 and operation of our liquefaction facilities, the export of LNG and the transportation of natural gas through the Corpus Christi Pipeline are highly regulated activities. Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate consumption for domestic, commercial, industrial or any other use and to natural gas companies engaged in such transportation or sale. However, the FERC’s jurisdiction does not extend to the production, gathering, local distribution or export of natural gas.

 In general, the FERC’s authority to regulate interstate natural gas pipelines and the services that they provide includes:

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

• the certification and construction of new 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.

In addition, under the NGA, our pipelines are not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including its own marketing affiliate. The FERC has the authority to grant certificates allowing construction and operation of facilities used in interstate gas transportation and authorizing the provision of services.

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 several 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, although except as specifically provided in the EPAct, nothing in the EPAct is intended to affect otherwise applicable law related to any other federal or state agency’s authorities or responsibilities related to LNG terminals.

In December 2014, the FERC issued an order granting CCL authorization under Section 3 of the NGA to site, construct and operate Stage 1 and Stage 2 of the Liquefaction Project and issued a certificate of public convenience and necessity under Section

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7(c) of the NGA authorizing CCP to construct and operate 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 U.S. Court of Appeals for the District of Columbia Circuit to review the December 2014 Order and the Order Denying Rehearing, and that petition was denied on November 4, 2016.

In 2002, the FERC concluded that it would apply light-handed regulation over the rates, terms and conditions agreed to by parties for LNG terminalling services, such that LNG terminal owners would not be required to provide open-access service at non-discriminatory rates or maintain a tariff or rate schedule on file with the FERC, as distinguished from the requirements applied to our FERC-regulated natural gas pipeline. The EPAct codified the FERC’s policy, but those provisions expired on January 1, 2015. Nonetheless, we see no indication that the FERC intends to modify its longstanding policy of light-handed regulation of LNG terminals.

The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in marketing functions. Interstate pipelines must treat all transmission customers on a not unduly discriminatory basis. The general principles of the 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. CCP has established the required policies and procedures to comply with the FERC’s Standards of Conduct, and is subject to audit by the FERC to review compliance, policies and its training programs.

Several other material governmental and regulatory approvals and permits will be required throughout the life of the Liquefaction Project. In addition, the December 2014 Order requires us to obtain certain additional FERC and other regulatory agency approvals as construction progresses. To date, we have been able to obtain these approvals as needed and the need for these approvals has not materially affected our construction progress. Throughout the life of the Liquefaction Project, we will be 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.

The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.

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.

Exports of natural gas to FTA countries are “deemed to be consistent with the public interest” and authorization to export LNG to FTA countries shall be granted by the DOE without “modification or delay.” FTA countries which currently import LNG include Canada, Chile, Colombia, Dominican Republic, Israel, Jordan, Mexico, Panama, Singapore and South Korea. Exports of natural gas to non-FTA countries are considered by the DOE in the context of a comment period whereby interveners are provided the opportunity to assert that such authorization would not be consistent with the public interest.

Pipeline

The Corpus Christi Pipeline is also subject to regulation by the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities.

The Pipeline Safety Improvement Act of 2002, as amended (“PSIA”), which is administered by the PHMSA Office of Pipeline Safety, governs the areas of testing, education, training and communication. The PSIA requires pipeline companies to perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as “high consequence areas.” Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing,

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or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for gas transportation pipelines, which requires pipeline operators to perform ongoing assessments of pipeline integrity; 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 preventive and mitigation actions.

In 2009, the PHMSA issued a final rule (known as “Control Room Management/Human Factors Rule”) that became effective in 2010 requiring pipeline operators to write and institute certain control room procedures that address human factors and fatigue management.

In March 2015, PHMSA issued a final rule amending the pipeline safety regulations to update and clarify certain regulatory requirements, including who can perform post-construction inspections on transmission pipelines. In September 2015, PHMSA issued a rule indefinitely delaying the effective date for the amendment to the regulation regarding post-construction inspections.

In May 2015, PHMSA issued a notice of proposed rulemaking proposing to amend gas pipeline safety regulations regarding plastic piping systems used in gas services, including the installation of plastic pipe used for gas transmission lines. The PHMSA has not finalized any of the regulations proposed in this notice.

In July 2015, PHMSA issued a notice of proposed rulemaking proposing to add a specific timeframe for operators’ notification of accidents or incidents, as well as amending the safety regulations regarding operator qualification requirements by expanding the requirements to include new construction and certain previously excluded operation and maintenance tasks, requiring a program effectiveness review and adding new recordkeeping requirements. In January 2017, PHMSA issued a final rule (effective as of March 24, 2017) adding a specific time frame for operators’ notification of accidents or incidents but delayed final action on the proposed operator qualification requirements until a later date.

In April 2016, the PHMSA issued a notice of proposed rulemaking addressing changes to the regulations governing the safety of gas transmission pipelines. Specifically, PHMSA is considering certain integrity management requirements for “moderate consequence areas,” requiring an integrity verification process for specific categories of pipelines, and mandating more explicit requirements for the integration of data from integrity assessments to an operator’s compliance procedures. The PHMSA is also considering whether to revise requirements for corrosion control and expanding the definition of regulated gathering lines. These notices of proposed rulemaking are still pending at the PHMSA. The PHMSA has not finalized any of the regulations proposed in this notice.

Natural Gas Pipeline Safety Act of 1968 (“NGPSA”)

Texas administers federal pipeline safety standards under the NGPSA, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal sanctions.

Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011

The Corpus Christi Pipeline is also subject to the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. Under the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, PHMSA has civil penalty authority up to approximately $200,000 per day per violation (increased from the prior $100,000), with a maximum of approximately $2 million in civil penalties for any related series of violations (increased from the prior $1 million).

Other Governmental Permits, Approvals and Authorizations

The construction and operation of the Liquefaction Project require additional federal permits, orders, approvals and consultations required by federal agencies, including the DOT, Advisory Council on Historic Preservation, 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, Environmental Protection Agency (the “EPA”) and U.S. Department of Homeland Security.

Three significant permits are the USACE Section 404 of the Clean Water Act/Section 10 of the Rivers and Harbors Act Permit (the “Section 10/404 Permit”), the Clean Air Act Title V Operating Permit (the “Title V Permit”) and the Prevention of

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Significant Deterioration Permit (the “PSD Permit”), of which the latter two permits are issued by the Texas Commission on Environmental Quality (“TCEQ”).

An application for an amendment to CCL’s Section 10/404 Permit to authorize construction of the Liquefaction Project was issued by the USACE in July 2014 and subsequently modified in October 2014. The TCEQ issued amended PSD permits for criteria pollutants and greenhouse gas (“GHG”) in July 2018 to reflect updates related to refined operational direction and changes that were made during the design and procurement process.

The TCEQ issued an amended Air Standard Permit for the Corpus Christi Pipeline compressor station at Sinton, Texas in November 2018 for modifications to the facility and to update permit representations.

CCL was issued a waste water discharge permit in October 2017 authorizing discharges from the Liquefaction Project.

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, which, as to the collection of initial margin, are being phased in, 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.

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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.

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 for multiple sections of the economy. This rule requires mandatory reporting of GHG emissions from stationary sources, including fuel combustion sources. 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. The Obama Administration took several actions intended to limit GHG emissions, including regulating emissions from new and existing Electricity Generating Units and from new and modified oil and gas operations. The timing, extent and impact of these rules and other Obama Administration initiatives remain uncertain as the Trump Administration has undertaken steps to delay their implementation, and to review, repeal and potentially replace them. On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan after concluding the October 2015 final rule exceeds EPA’s statutory authority under the CAA. In August 2018, the EPA proposed the Affordable Clean Energy rule as a replacement for the Clean Power Plan, which requires states to develop plans to implement certain performance standards within three years after the Final Rule is published in the Federal Register. Many of the Trump Administration’s efforts to rollback Obama Administration actions have been challenged in court.

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.

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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 and the Railroad Commission of Texas).

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. In the event such wastes are generated in connection with our facilities, we will be subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

Protection of Species, Habitats and Wetlands

Various federal and state statutes, such as the Endangered Species Act (the “ESA”), the Migratory Bird Treaty Act, the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If our Corpus Christi LNG terminal or the Corpus Christi Pipeline adversely affect 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 July 2018, the U.S. Fish and Wildlife Service (the “FWS”) announced a series of proposed changes to the rules implementing the ESA, including proposed revisions to the regulations governing interagency cooperation, listing species and delisting critical habitat, and prohibitions related to threatened wildlife and plants. The proposed revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions. It is not possible at this time to predict how such changes, if adopted, would impact our business.

In addition, in December 2017, the Department of Interior’s (“DOI’s”) Solicitor’s Office issued an official opinion that the Migratory Bird Treaty Act’s broad prohibition on “taking” migratory birds applies only to affirmative actions and does not include incidental taking. In April 2018 the FWS issued guidance consistent with the DOI’s opinion. The opinion has been challenged in court.

Market Factors and Competition

The Liquefaction Project currently does not experience competition with respect to Trains 1 through 3. CCL has entered into fixed price SPAs generally with terms of 20 years (plus extension rights) with nine third parties that will utilize substantially all of the liquefaction capacity available from these Trains. Each customer will be required to pay an escalating fixed fee for its annual contract quantity even if it elects not to purchase any LNG from us.

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 developing natural gas liquefaction facilities in Cameron Parish, Louisiana, and Sabine Pass Liquefaction, LLC (“SPL”) has entered into fixed price SPAs with third parties for the sale of LNG from Trains 1 through 5 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 ability to enter into additional long-term SPAs to underpin the development of additional Trains, sell any quantities of LNG available under the SPAs with Cheniere Marketing, or develop new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and economic growth in developing countries. In addition, Cheniere’s ability to obtain additional

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funding to execute its business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and Cheniere’s 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 19 trillion cubic feet (“Tcf”) between 2017 and 2025, with LNG’s share growing from about 10% in 2017 to about 15% of the global gas market in 2025.  Wood Mackenzie Limited forecasts that global demand for LNG will increase by approximately 60%, from approximately 287 mtpa, or 13.8 Tcf in 2017, to approximately 461 mtpa, or 22.1 Tcf, in 2025, and that LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 413 mtpa in 2025, resulting in a market need for construction of an additional approximately 48 mtpa of LNG production.  We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Project is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

Our LNG terminal business has limited exposure to 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.  We have contracted an aggregate amount of LNG that is between approximately 75% to 85% of the expected aggregate adjusted nominal production capacity of Trains 1 through 3 of the Liquefaction Project with third-party customers. As of January 31, 2019, 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, medium-term and short-term contracting of LNG from our terminal.

Subsidiaries

Our assets are generally held by or under our subsidiaries. We conduct most of our business through these subsidiaries, including the development and construction 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, 2019, Cheniere and its subsidiaries had 1,372 full-time employees, including 257 employees who directly supported the Liquefaction Project.

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.

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Risks Relating to Our Financial Matters

Our existing level of cash resources, negative 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, 2018, we had zero cash and cash equivalents, $289.1 million of current restricted cash and $9.6 billion of total debt outstanding on a consolidated basis (before unamortized debt issuance costs), excluding $315.5 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 fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

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

We had net income of $6.3 million for the year ended December 31, 2018 and net losses of $48.7 million and $85.5 million for the years ended December 31, 2017 and 2016, respectively. In addition, our net cash flow used in operating activities was $60.2 million, $64.3 million and $41.1 million for the years ended December 31, 2018, 2017 and 2016, 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 our Trains could cause, and could increase the level of, our 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 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 the payments under long-term contracts. As of December 31, 2018, 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.

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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 swaps 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 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 terminals 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, we may be required to clear through a derivatives clearing organization any swaps into which we enter that fall within a class of swaps designated by the CFTC for mandatory clearing and we could have to execute trades in such swaps on certain trading platforms or exchanges. The CFTC has designated certain interest rate swaps and index credit default swaps for mandatory clearing, but has not yet finalized rules designating any physical commodity swaps, for mandatory clearing or mandatory exchange trading. Although we expect to 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 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.

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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.

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

Our ability to complete construction of Stages 1 and 2 depends on our ability to obtain sufficient equity funding to cover the remaining equity-funded share of the capital costs of the Liquefaction Project. If we are unable to obtain sufficient equity funding, we will not be able to draw on all of the loans provided under our credit facility (the “CCH Credit Facility”) and may not be able to complete construction of Stages 1 and 2 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, 2018, we have not received any contributions under the Equity Contribution Agreement. Cheniere will only be 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.

We are dependent on Cheniere to provide this equity funding. If Cheniere is unable to or does not provide this equity funding when requested, we will not be able to draw on the remaining commitments under the CCH Credit Facility, and, under certain circumstances, failure to timely provide this equity funding following a funding request will constitute an event of default under the CCH Credit Facility and the indenture for our 7.000% Senior Secured Notes due 2024, 5.875% Senior Secured Notes due 2025 and 5.125% Senior Secured Notes due 2027 (the “CCH Indenture”). The insufficiency of equity contributions to meet the equity-funded portion of our finance plan for Stages 1 and 2 of Liquefaction Project may cause a delay in development of our Trains and we may never be able to complete Stages 1 and 2. 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 the applicable Train, 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 the 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

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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.

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

Any delay in completion of a Train 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.

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;

• 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.

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We currently have no 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 currently project that we will not generate cash flow from operations until the first half of 2019, when Train 1 is expected to achieve substantial completion. Any delays beyond the expected development periods for Trains 1 through 3 would prolong, and could increase the level of, our 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 third-party engineers to estimate 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 pipelines 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 will depend upon third-party pipelines and other facilities that will 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.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities and the development and operation of our pipeline 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 terminals, including the Liquefaction Project and other facilities, and the import and export of LNG and the 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 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 and Corpus Christi Pipeline. 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 FERC’s or the DOE’s 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,

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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.

Our Corpus Christi Pipeline and its FERC gas tariffs is 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 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;

• 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.

Hurricanes or other disasters could result in an interruption of our operations, a delay in the completion of the Liquefaction Project, higher construction costs and the deferral of the dates on which payments are due to us under the SPAs, all of which could adversely affect us.

In August and September of 2005, Hurricanes Katrina and Rita, respectively, damaged coastal and inland areas located in Texas, Louisiana, Mississippi and Alabama, resulting in the temporary suspension of construction of the Sabine Pass LNG terminal that is also operated by Cheniere LNG O&M Services, LLC, a wholly owned subsidiary of Cheniere. In September 2008, Hurricane Ike struck the Texas and Louisiana coasts, and the Sabine Pass LNG terminal experienced minor damage. In August 2017, Hurricane Harvey struck the Texas and Louisiana coasts. The Sabine Pass LNG terminal experienced a temporary suspension in construction and LNG loading operations, and the Corpus Christi LNG terminal experienced a temporary suspension in construction. The Corpus Christi LNG terminal did not sustain significant damage.

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. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our coastal operations.

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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 construct the Liquefaction Project, and even if successfully constructed, the Liquefaction Project would 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 construct or operate all of our proposed LNG facilities or Trains or any additional LNG facilities or Trains beyond those currently planned, which could limit our growth prospects.

We may not construct some of our proposed LNG facilities or 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.

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 CCH Indenture. Despite the protection provided by the CCH Indenture, 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 has formed two entities, which are not owned or controlled by CCH, to develop up to seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa and one storage tank 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 Indenture. 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 Indenture 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.

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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, 2019, Cheniere and its subsidiaries had 1,372 full-time employees, including 257 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 Sabine Pass Liquefaction Project, for the time and expertise of Cheniere’s personnel. Further, we and Cheniere face competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.

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

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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 projects are 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 projects 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 projects;

• 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.

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;

• 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;

• 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;

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• 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 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 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 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 terminals 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. 

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After our Liquefaction Project is placed in service, its operations will involve significant risks.

If we are successful in completing our proposed liquefaction facilities, we will still face risks associated with operating the facilities. These risks will include, but will not be limited to, 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 transportation precedent 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. However, we cannot control the regulatory and permitting approvals or third parties’ construction times, either with respect to capacity that has been secured or capacity that will be secured. If and when we need to replace one or more of our 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, 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;

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• 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.

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 our LNG terminals 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, 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 October 2015, the EPA promulgated a final rule to implement the Obama Administration’s Clean Power Plan, which is designed to reduce GHG emissions from power plants in the United States.  In February 2016, the U.S. Supreme Court stayed the final rule, effectively suspending the duty to comply with the rule until certain legal challenges are resolved. On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan after concluding the October 2015 final rule exceeds EPA’s statutory authority under the CAA. In August 2018, the EPA proposed the Affordable Clean Energy rule as a replacement for the Clean Power Plan, which requires states to develop plans to implement certain performance standards within three years after the Final Rule is published in the Federal Register. The Trump Administration announced in June 2017 that the United States would withdraw from the Paris Accord, an international agreement within the United Nations Framework Convention on Climate Change under which the Obama Administration committed the United States to reducing its economy-wide GHG emission by 26-28% below 2005 levels by 2025. Other federal and state initiatives may be considered in the future to address GHG emissions through, for example, United States treaty commitments, direct regulation, a carbon emissions tax, or cap-and-trade programs. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.

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Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals, could cause additional expenditures, restrictions and delays in our business and to our proposed construction, 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 2019 will be dependent upon one facility, the Liquefaction Project located in Texas. Due to our lack of asset and geographic diversification, an adverse development at the Liquefaction Facilities, the Corpus Christi Pipeline, 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.

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.

PHMSA Matter

In February 2018, PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (“the NOPV”) to CCP alleging probable violations of federal pipeline safety regulations relating to welding during the construction of the pipeline and proposes civil penalties totaling $0.2 million. We worked with PHMSA to address the matters in the NOPV.  In September 2018, PHMSA withdrew the proposed civil penalty and NOPV and closed the case citing no further safety concern regarding the welds at CCP.   

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 audited consolidated and combined financial data for the periods indicated for CCH (in thousands). CCH was formed by Cheniere in September 2014 to hold its limited partner interest in CCP, the equity interests of CCP GP, which holds the general partner interest in CCP, and the equity interests of CCL. Prior to this date, CCP and CCL received capital contributions from other affiliated entities of Cheniere. The formation of CCH is treated as a reorganization between entities under common control. As a result, CCH’s combined financial statements for periods prior to the formation of CCH were derived from the consolidated financial statements and accounting records of Cheniere and reflect the combined historical results of operations and cash flows of CCL, CCP and CCP GP. For periods subsequent to the formation of CCH, CCH’s consolidated financial statements are presented on a consolidated basis because CCH, CCL, CCP and CCP GP became a separate consolidated group following such formation. 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,
	2018			2017			2016			2015			2014
Revenues	$	—		$	—		$	—		$	—		$	—
Loss from operations	(21,879		)	(19,161		)	(6,472		)	(23,044		)	(38,235		)
Other income (expense)	28,165			(29,491		)	(79,015		)	(204,053		)	(368		)
Net income (loss)	6,286			(48,652		)	(85,487		)	(227,097		)	(38,603		)

	December 31,
	2018		2017		2016		2015		2014
Property, plant and equipment, net	$	11,138,825	$	8,261,383	$	6,076,672	$	3,924,551	$	44,173
Total assets	11,720,353		8,659,880		6,636,448		4,304,042		68,030
Long-term debt, net	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 were formed in September 2014 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 wholly-owned subsidiaries CCL and CCP, respectively.

The Liquefaction Project is being developed in stages with the first phase being three Trains (“Phase 1”), with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage (“Stage 1”) includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, one LNG storage tank and the completion of the second partial berth. Trains 1 and 2 are undergoing commissioning and Train 3 is under construction.

Overview of Significant Events

Our significant accomplishments since January 1, 2018 and through the filing date of this Form 10-K include the following:

Strategic

• In May 2018, Cheniere’s board of directors made a positive final investment decision with respect to Stage 2 of the Liquefaction Project and issued a full notice to proceed to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) under the EPC contract for Stage 2.

• In February 2018, CCL entered into a 20-year SPA with PetroChina International Company Limited, a subsidiary of China National Petroleum Corporation, for the sale of LNG beginning in 2023 on a free on board basis.

Operational

• In December 2018, CCL commenced production and shipment of LNG commissioning cargoes from Train 1 of the Liquefaction Project.

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Financial

• We completed the following debt transactions:

◦ In June 2018, we amended and restated our working capital facility (“CCH Working Capital Facility”) to increase total commitments under the CCH Working Capital Facility to $1.2 billion. Borrowings will be used for certain working capital requirements related to developing and placing into operations the Liquefaction Project and for related business purposes.

◦ In May 2018, we amended and restated our existing credit facilities (the “CCH Credit Facility”) to increase total commitments under the CCH Credit Facility to $6.1 billion. Borrowings will be used to fund a portion of the costs of developing, constructing and placing into service the three Trains and the related facilities of the Liquefaction Project and for related business purposes.

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at December 31, 2018 and 2017 (in thousands):

	December 31,
	2018		2017
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the Liquefaction Project	289,141		226,559
Available commitments under the following credit facilities:
CCH Credit Facility	981,675		2,086,714
CCH Working Capital Facility	716,475		186,422

For additional information regarding our debt agreements, see Note 9—Debt of our Notes to Consolidated Financial Statements.

Corpus Christi LNG Terminal

Liquefaction Facilities

The Liquefaction Project is being developed and constructed at the Corpus Christi LNG terminal. We have received authorization from the FERC to site, construct and operate Stages 1 and 2 of the Liquefaction Project. The following table summarizes the overall project status of the Liquefaction Project as of December 31, 2018:

	Stage 1		Stage 2
Overall project completion percentage	96.7%		42.0%
Completion percentage of:
Engineering	100%		87.0%
Procurement	100%		63.0%
Subcontract work	89.5%		8.5%
Construction	93.1%		11.7%
Expected date of substantial completion	Train 1	1Q 2019	Train 3	2H 2021
	Train 2	2H 2019

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 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 begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from seven to 10 years from the date the order was issued.

Customers

CCL has entered into fixed price 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 between approximately 75% to 85% of the expected aggregate adjusted nominal production capacity from these Trains. Under these SPAs, the customers will purchase LNG from CCL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment

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for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, 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 related to, and operating and maintenance costs 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 and increasing to approximately $1.4 billion for Train 2, in each case upon the date of first commercial delivery for the respective Train, and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the Liquefaction Project.

CCL expects to sell LNG that it produces that is in excess of the contract quantities committed under CCL’s third-party SPAs to Cheniere Marketing International LLP, an indirect wholly-owned subsidiary of Cheniere.

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, 2018, CCL had secured up to approximately 2,801 TBtu of natural gas feedstock through long-term natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.

Construction

CCL entered into separate lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Stages 1 and 2 of the Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost 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 prices of the EPC contract for Stage 1 and the EPC contract for Stage 2, which do not include the Corpus Christi Pipeline, are approximately $7.8 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through December 31, 2018. Total expected capital costs for Trains 1 through 3 are estimated to be between $11.0 billion and $12.0 billion before financing costs and between $15.0 billion and $16.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

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 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 commenced in January 2017 and was completed in the second quarter of 2018.

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Capital Resources

We expect to finance the construction costs of the Liquefaction Project from one or more of the following: project financing, operating cash flows from CCL and CCP and equity contributions from Cheniere. We realized offsets to LNG terminal costs of $48.7 million in the year ended December 31, 2018 that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of Train 1 during the testing phase for its construction. 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, 2018 and 2017 (in thousands):

	December 31,
	2018		2017
Senior notes (1)	$	4,250,000	$	4,250,000
Credit facilities outstanding balance (2)	5,323,737		2,484,737
Letters of credit issued (2)	315,525		163,578
Available commitments under credit facilities (2)	1,698,150		2,273,136
Total capital resources from borrowings and available commitments	$	11,587,412	$	9,171,451

(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”) and 5.125% Senior Secured Notes due 2027 (the “2027 CCH Senior Notes”) (collectively, the “CCH Senior Notes”).

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

For additional information regarding our debt agreements related to the Liquefaction Project, see Note 9—Debt of our Notes to Consolidated Financial Statements.

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 indenture governing the CCH Senior Notes (the “CCH Indenture”) contains 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.

At any time prior to six months before the respective dates of maturity for each series 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 CCH Indenture, plus accrued and unpaid interest, if any, to the date of redemption. We also may at any time within six months of the respective dates of maturity for each series of the CCH Senior Notes, 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.

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, 2018 and 2017, we had $1.0 billion and $2.1 billion of available commitments and $5.2 billion and $2.5 billion loans outstanding under the CCH Credit Facility, respectively.

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

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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 placing into operations 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, 2018 and 2017, we had $716.5 million and $186.4 million of available commitments, $315.5 million and $163.6 million aggregate amount of issued letters of credit and $168.0 million and no 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, 2018, we have not received any contributions under the Equity Contribution Agreement. Cheniere will only be 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. In March 2017, Cheniere entered into a $750 million senior secured revolving credit facility (the “CEI Revolving Credit Facility”). The proceeds of the CEI Revolving Credit Facility are available to Cheniere to back-stop its obligations under the Equity Contribution Agreement and for general corporate purposes.

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, 2018, we were in compliance with all covenants related to our debt agreements.

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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, 2018, 2017 and 2016 (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,
	2018			2017			2016
Operating cash flows	$	(60,162	)	$	(64,316	)	$	(41,079	)
Investing cash flows	(2,960,267		)	(1,962,209		)	(2,095,897		)
Financing cash flows	3,083,011			1,982,544			2,360,746
Net increase (decrease) in cash, cash equivalents and restricted cash	62,582			(43,981		)	223,770
Cash, cash equivalents and restricted cash—beginning of period	226,559			270,540			46,770
Cash, cash equivalents and restricted cash—end of period	$	289,141		$	226,559		$	270,540

Operating Cash Flows

Operating cash net outflows during the years ended December 31, 2018, 2017 and 2016 were $60.2 million, $64.3 million and $41.1 million respectively. The decrease in operating cash flows from the year ended December 31, 2017 to the year ended December 31, 2018 was primarily due to decreased cash used for settlement of derivative instruments, partially offset by increased cash used for working capital requirements. The increase in operating cash outflows from the year ended December 31, 2016 to the year ended December 31, 2017 was primarily related to increased cash used for settlement of derivative instruments.

Investing Cash Flows

Investing cash net outflows during the years ended December 31, 2018, 2017 and 2016 were $2,960.3 million, $1,962.2 million and $2,095.9 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. In addition to cash outflows for construction costs for the Liquefaction Project, during the year ended December 31, 2017 we received $36.3 million from the return of collateral payments previously paid for the Liquefaction Project, which was offset by $11.3 million paid for infrastructure to support the Liquefaction Project. During the year ended December 31, 2016, we used an additional $44.4 million primarily for infrastructure of the Liquefaction Project, which included the $36.3 million of collateral payments that were returned to us during the year ended December 31, 2017.

Financing Cash Flows

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 these 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;

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• $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.

Financing cash net inflows during the year ended December 31, 2016 were $2,360.7 million, primarily as a result of:

• $2.1 billion of borrowings under the CCH Credit Facility;

• issuances of aggregate principal amounts of $1.25 billion of the 2024 CCH Senior Notes and $1.5 billion of the 2025 CCH Senior Notes in December 2016, which were used to prepay $2.4 billion of the outstanding borrowings under the CCH Credit Facility; and

• $56.8 million of debt issuance costs related to up-front fees paid upon the closing of these transactions.

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, 2018 (in thousands):

	Payments Due By Period (1)
	Total		2019		2020 - 2021		2022 - 2023		Thereafter
Debt (2)	$	9,573,737	$	168,000	$	—	$	—	$	9,405,737
Interest payments (2)	3,021,191		498,885		997,819		988,477		536,010
Construction obligations (3)	1,438,676		893,464		545,212		—		—
Purchase obligations (4)	3,892,561		698,109		1,056,217		432,137		1,706,098
Operating lease obligations (5)	6,721		596		2,450		2,450		1,225
Obligations to affiliates and related parties (6)	97,754		2,225		20,090		19,500		55,939
Other obligations (7)	182,559		12,730		50,391		63,828		55,610
Total	$	18,213,199	$	2,274,009	$	2,672,179	$	1,506,392	$	11,760,619

(1) Agreements in force as of December 31, 2018 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2018.

(2) Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2018.  See Note 9—Debt of our Notes to Consolidated Financial Statements.

(3) Construction obligations primarily relate to the EPC contracts for the Liquefaction Project.  A discussion of these obligations can be found at Note 14—Commitments and Contingencies of our Notes to Consolidated Financial Statements.

(4) Purchase obligations consist of contracts for which conditions precedent have been met, and primarily relate to natural gas supply, transportation and storage services for the Liquefaction Project. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly.

(5) Operating lease obligations primarily relate to land sites for the Liquefaction Project. A discussion of these obligations can be found in Note 13—Leases of our Notes to Consolidated Financial Statements.

(6) Obligations to affiliates and related parties relate to land leased from Cheniere Land Holdings, LLC, a wholly owned subsidiary of Cheniere, for the Liquefaction Project and transportation services for the Liquefaction Project under agreements with a related party of Cheniere.

(7) Other obligations primarily relate to agreements with certain local taxing jurisdictions, and are based on estimated tax obligations as of December 31, 2018.

In addition, in the ordinary course of business, we maintain letters of credit and have certain cash restricted in support of certain performance obligations of our subsidiaries. As of December 31, 2018, we had $315.5 million aggregate amount of issued letters of credit under the CCH Working Capital Facility and $289.1 million of current restricted cash. For more information, see Note 3—Restricted Cash of our Notes to Consolidated Financial Statements.

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Results of 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.

Our consolidated net loss was $85.5 million in the year ended December 31, 2016. This $36.8 million decrease in net loss in 2017 compared to 2016 was primarily a result of decreased loss on early extinguishment of debt and decreased derivative loss, net associated with interest rate derivative activity.

Income (loss) from operations

	Year Ended December 31,
(in thousands)	2018			2017			Change			2016			Change
Revenues	$	—		$	—		$	—		$	—		$	—
Operating and maintenance expense	76			3,115			(3,039		)	1,372			1,743
Operating and maintenance expense—affiliate	4,283			2,401			1,882			95			2,306
Development expense (recovery)	177			516			(339		)	(81		)	597
Development expense (recovery)—affiliate	—			8			(8		)	(10		)	18
General and administrative expense	5,263			5,551			(288		)	4,240			1,311
General and administrative expense—affiliate	2,201			1,173			1,028			607			566
Depreciation and amortization expense	9,859			892			8,967			249			643
Impairment expense and loss on disposal of assets	20			5,505			(5,485		)	—			5,505
Total expenses	21,879			19,161			2,718			6,472			12,689
Loss from operations	$	(21,879	)	$	(19,161	)	$	(2,718	)	$	(6,472	)	$	12,689

2018 vs. 2017

Our loss from operations increased $2.7 million during the year ended December 31, 2018 from the year ended December 31, 2017 primarily due to the increase in depreciation and amortization expense, as the assets related to Corpus Christi Pipeline began depreciating upon completion of the construction. This increase was offset by a decrease in impairment expense and loss on disposal of assets, which related to damaged infrastructure as an effect of Hurricane Harvey during the year ended December 31, 2017, and a decrease in operating and maintenance expense due to gains recorded for the imbalance settlements on Corpus Christi Pipeline, which began operations upon commencement of commissioning of Train 1.

2017 vs. 2016

Our loss from operations increased $12.7 million during the year ended December 31, 2017 from the year ended December 31, 2016 primarily as a result of increased impairment expense and loss on disposal of assets, increased operating and maintenance expense and general and administrative expense from increased professional fees and labor costs.

Other expense (income)

	Year Ended December 31,
(in thousands)	2018			2017			Change			2016		Change
Loss on modification or extinguishment of debt	$	15,332		$	32,480		$	(17,148	)	$	63,318	$	(30,838	)
Derivative loss (gain), net	(43,105		)	(3,249		)	(39,856		)	15,571		(18,820		)
Other expense (income)	(392		)	260			(652		)	126		134
Total other expense (income)	$	(28,165	)	$	29,491		$	(57,656	)	$	79,015	$	(49,524	)

2018 vs. 2017

Loss on modification or extinguishment of debt decreased during the year ended December 31, 2018, as compared to the year ended December 31, 2017. Loss on modification or extinguishment of debt recognized in 2018 was attributable to the costs

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relating to the incurrence of third party fees and write off of unamortized debt issuance costs as a result of the amendment and restatement of the CCH Credit Facility. Loss on modification or extinguishment of debt recognized in 2017 was attributable to the write-off of debt issuance costs of $32.5 million in May 2017 upon the prepayment of approximately $1.4 billion of outstanding borrowings under the CCH Credit Facility in connection with the issuance of the 2027 CCH Senior Notes.

Derivative gain, net increased from a net loss during the year ended December 31, 2017 to a net gain during the year ended December 31, 2018, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods. During the year ended December 31, 2018, we also received $4.8 million of proceeds in June 2018 upon the termination of interest rate swaps associated with the amendment and restatement of the CCH Credit Facility. During the year ended December 31, 2017, we also paid $13.0 million in May 2017 upon the settlement of interest rate swaps associated with approximately $1.4 billion of commitments that were terminated under the CCH Credit Facility.

2017 vs. 2016

Loss on early extinguishment of debt decreased during the year ended December 31, 2017, as compared to the year ended December 31, 2016. Loss on early extinguishment of debt during the year ended December 31, 2016 was primarily attributable to a $63.3 million write-off of debt issuance costs related to the $2.4 billion prepayment of outstanding borrowings under the CCH Credit Facility in connection with the issuance of the 2024 CCH Senior Notes and the 2025 CCH Senior Notes.

Derivative gain, net increased from a net loss during the year ended December 31, 2016 to a net gain during the year ended December 31, 2017. The increase in 2017 was primarily due to a favorable shift in the long-term forward LIBOR curve between the periods, which was partially offset by the $13.0 million payment upon the settlement of interest rate swaps, as described above.

Off-Balance Sheet Arrangements

As of December 31, 2018, 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, properties, plant and equipment and income taxes. 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.

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 and index-based 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 index-based physical commodity contracts is developed through the use of internal models which are impacted by inputs that may be unobservable in the marketplace, market transactions and other relevant data.

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.

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Income Taxes

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance if, based on all available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. In determining the need for a valuation allowance we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We have recorded a full valuation allowance on our net federal and state deferred tax assets as of both December 31, 2018 and 2017. We intend to maintain a valuation allowance on our net federal and state deferred tax assets until there is sufficient evidence to support the reversal of these allowances.

We recognize the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. The largest amount of the tax benefit that is greater than 50 percent likely of being effectively settled is recorded. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

See Note 12—Income Taxes of our Notes to Consolidated Financial Statements for further discussion of our accounting for income taxes.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 16—Recent Accounting Standards 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, 2018					December 31, 2017
	Fair Value			Change in Fair Value		Fair Value			Change in Fair Value
Liquefaction Supply Derivatives	$	(68	)	$	1,165	$	(91	)	$	10

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 also 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”). 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 1-month LIBOR curve across the remaining terms of the Interest Rate Derivatives as follows (in thousands):

	December 31, 2018				December 31, 2017
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
Interest Rate Derivatives	$	18,069	$	37,145	$	(32,258	)	$	43,994

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

33

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

Management’s Report to the Member of Cheniere Corpus Christi Holdings, LLC	35
Report of Independent Registered Public Accounting Firm	36
Consolidated Balance Sheets	37
Consolidated Statements of Operations	38
Consolidated Statements of Member’s Equity	39
Consolidated Statements of Cash Flows	40
Notes to Consolidated Financial Statements	41
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	70

34

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, 2018, 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 Sabine Pass Liquefaction’s Form 10-K.

By:	/s/ Michael J. Wortley
	Michael J. Wortley
	President and Chief Financial Officer (Principal Executive and Financial Officer)

35

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member

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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, 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 revenue recognition in 2018, 2017 and 2016 due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto.

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 25, 2019

36

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2018		2017
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	289,141		226,559
Receivables	24,989		—
Accounts receivable—affiliate	21,060		—
Advances to affiliate	94,397		31,486
Inventory	26,198		—
Derivative assets	17,759		—
Other current assets	15,217		1,494
Other current assets—affiliate	633		190
Total current assets	489,394		259,729
Property, plant and equipment, net	11,138,825		8,261,383
Debt issuance and deferred financing costs, net	38,012		98,175
Non-current derivative assets	22,413		2,469
Other non-current assets, net	31,709		38,124
Total assets	$	11,720,353	$	8,659,880
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	16,202	$	6,461
Accrued liabilities	162,205		258,060
Current debt	168,000		—
Due to affiliates	25,086		23,789
Derivative liabilities	13,576		19,609
Total current liabilities	385,069		307,919
Long-term debt, net	9,245,552		6,669,476
Non-current derivative liabilities	8,595		15,209
Commitments and contingencies (see Note 14)
Member’s equity	2,081,137		1,667,276
Total liabilities and member’s equity	$	11,720,353	$	8,659,880

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

37

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2018			2017			2016
Revenues	$	—		$	—		$	—
Expenses
Operating and maintenance expense	76			3,115			1,372
Operating and maintenance expense—affiliate	4,283			2,401			95
Development expense (recovery)	177			516			(81		)
Development expense (recovery)—affiliate	—			8			(10		)
General and administrative expense	5,263			5,551			4,240
General and administrative expense—affiliate	2,201			1,173			607
Depreciation and amortization expense	9,859			892			249
Impairment expense and loss on disposal of assets	20			5,505			—
Total expenses	21,879			19,161			6,472
Loss from operations	(21,879		)	(19,161		)	(6,472		)
Other income (expense)
Loss on modification or extinguishment of debt	(15,332		)	(32,480		)	(63,318		)
Derivative gain (loss), net	43,105			3,249			(15,571		)
Other income (expense)	392			(260		)	(126		)
Total other income (expense)	28,165			(29,491		)	(79,015		)
Net income (loss)	$	6,286		$	(48,652	)	$	(85,487	)

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

38

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

(in thousands)

	Cheniere CCH HoldCo I, LLC			Total Member’s Equity
Balance at December 31, 2015	$	1,399,350		$	1,399,350
Capital contributions	234			234
Distribution to affiliate	(288		)	(288		)
Net loss	(85,487		)	(85,487		)
Balance at December 31, 2016	1,313,809			1,313,809
Capital contributions	402,119			402,119
Net loss	(48,652		)	(48,652		)
Balance at December 31, 2017	1,667,276			1,667,276
Capital contributions	407,575			407,575
Net income	6,286			6,286
Balance at December 31, 2018	$	2,081,137		$	2,081,137

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

39

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2018			2017			2016
Cash flows from operating activities
Net income (loss)	$	6,286		$	(48,652	)	$	(85,487	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization expense	9,859			892			249
Loss on modification or extinguishment of debt	15,332			32,480			63,318
Total gains on derivatives, net	(43,128		)	(3,158		)	15,571
Net cash used for settlement of derivative instruments	(7,222		)	(50,981		)	(34,082		)
Impairment expense and loss on disposal of assets	20			5,505			—
Changes in operating assets and liabilities:
Inventory	(24,852		)	—			—
Accounts payable and accrued liabilities	10,354			152			415
Due to affiliates	530			1,567			(331		)
Advances to affiliate	(10,911		)	—			—
Other, net	(16,313		)	(1,454		)	(745		)
Other, net—affiliate	(117		)	(667		)	13
Net cash used in operating activities	(60,162		)	(64,316		)	(41,079		)
Cash flows from investing activities
Property, plant and equipment, net	(2,962,936		)	(1,987,254		)	(2,051,530		)
Other	2,669			25,045			(44,367		)
Net cash used in investing activities	(2,960,267		)	(1,962,209		)	(2,095,897		)
Cash flows from financing activities
Proceeds from issuances of debt	3,114,800			3,040,000			4,838,000
Repayments of debt	(301,455		)	(1,436,050		)	(2,420,212		)
Debt issuance and deferred financing costs	(45,743		)	(23,496		)	(56,783		)
Debt extinguishment cost	(9,108		)	(29		)	(62		)
Capital contributions	324,517			402,119			91
Distributions	—			—			(288		)
Net cash provided by financing activities	3,083,011			1,982,544			2,360,746
Net increase (decrease) in cash, cash equivalents and restricted cash	62,582			(43,981		)	223,770
Cash, cash equivalents and restricted cash—beginning of period	226,559			270,540			46,770
Cash, cash equivalents and restricted cash—end of period	$	289,141		$	226,559		$	270,540

Balances per Consolidated Balance Sheets:

	December 31,
	2018		2017
Cash and cash equivalents	$	—	$	—
Restricted cash	289,141		226,559
Total cash, cash equivalents and restricted cash	$	289,141	$	226,559

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

40

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

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 developing and constructing natural gas liquefaction and export facilities at the Corpus Christi LNG terminal (the “Liquefaction Facilities”) near Corpus Christi, Texas 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”) through our wholly owned subsidiaries CCL and CCP, respectively. The Liquefaction Project is being developed in stages with the first phase being three Trains (“Phase 1”), with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). Trains 1 and 2 are undergoing commissioning and Train 3 is under construction.

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 wholly owned 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.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto (“ASC 606”) using the full retrospective method. We have elected to adopt the new accounting standard retrospectively and have recast the accompanying Consolidated Financial Statements to reflect the adoption of ASC 606 for all periods presented. The adoption of ASC 606 did not impact our previously reported Consolidated Financial Statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings.

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 the recoverability of property, plant and equipment, derivative instruments, asset retirement obligations (“AROs”), income taxes including valuation allowances for deferred tax assets and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

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 other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. 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.

41

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED 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, 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 9—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.

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 restricted as to usage or withdrawal and will not become available to us as cash and cash equivalents. We have presented restricted cash separately from cash and cash equivalents on our Consolidated Balance Sheets.

Receivables

Receivables are primarily composed of settlements related to natural gas procurement activities. Receivable are reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses.  The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral.  We did not recognize any impairment expense related to receivables during the years ended December 31, 2018, 2017 and 2016.

Inventory

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 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 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 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 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. Substantially all of our long-lived assets are located in the United States.

42

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED 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. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2018 or 2016.

Interest Capitalization

We capitalize interest and other related debt costs during the construction period of our LNG terminals and related pipelines 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 pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative

43

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

instruments designated as cash flow hedges during the years ended December 31, 2018, 2017 and 2016. See Note 6—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of restricted cash. 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 SPAs generally with terms of 20 years with nine unaffiliated third parties. CCL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.

Debt

Our debt consists of current and long-term secured 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. 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 of debt are recorded in gain (loss) on modification or extinguishment of debt on our Consolidated Statements of Operations.

Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as a direct deduction from the debt liability unless incurred in connection with a line of credit arrangement, in which case they are presented as an asset on our Consolidated Balance Sheets. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on modification or extinguishment of debt.

Asset Retirement Obligations

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

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

Income Taxes

We are a disregarded entity for federal and state income tax purposes.  Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is included in the consolidated

44

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

federal income tax return of Cheniere.  The provision for income taxes, taxes payable and deferred income tax balances have been recorded as if we had filed all tax returns on a separate return basis from Cheniere. Deferred tax assets and liabilities are included in our Consolidated Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the tax position.

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 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, 2018 and 2017, restricted cash consisted of the following (in thousands):

	December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	289,141	$	226,559

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—INVENTORY

As of December 31, 2018 and 2017, inventory consisted of the following (in thousands):

	December 31,
	2018		2017
Natural gas	$	1,326	$	—
Materials and other	24,872		—
Total inventory	$	26,198	$	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

As of December 31, 2018 and 2017, property, plant and equipment, net consisted of the following (in thousands):

	December 31,
	2018			2017
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	618,547		$	—
LNG site and related costs	44,725			13,844
LNG terminal construction-in-process	10,470,577			8,242,520
Accumulated depreciation	(7,416		)	—
Total LNG terminal costs, net	11,126,433			8,256,364
Fixed assets
Fixed assets	15,534			6,042
Accumulated depreciation	(3,142		)	(1,023		)
Total fixed assets, net	12,392			5,019
Property, plant and equipment, net	$	11,138,825		$	8,261,383

Depreciation expense was $9.5 million, $0.8 million and $0.2 million during the years ended December 31, 2018, 2017 and 2016, respectively.

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 realized offsets to LNG terminal costs of $48.7 million in the year ended December 31, 2018 for sales of commissioning cargoes from the Liquefaction Project.

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 with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows:

Components	Useful life (yrs)
Water pipelines	30
Natural gas pipeline facilities	40
Liquefaction processing equipment	6-50
Other	15-30

Fixed Assets and Other

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

NOTE 6—DERIVATIVE INSTRUMENTS

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

• interest rate swaps (“Interest Rate Derivatives”) to hedge a portion of the variable-rate interest payments on our credit facility (the “CCH Credit Facility”) and

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

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

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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, 2018 and 2017, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in thousands):

	Fair Value Measurements as of
	December 31, 2018										December 31, 2017
	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)	$	—	$	18,069	$	—		$	18,069		$	—	$	(32,258	)	$	—		$	(32,258	)
Liquefaction Supply Derivatives asset (liability)	1,299		2,990		(4,357		)	(68		)	—		—			(91		)	(91		)

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

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by market commodity basis 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. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

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 may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. As of December 31, 2018 and 2017, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow.

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 market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2018:

	Net Fair Value Liability (in thousands)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$(4,357)	Market approach incorporating present value techniques	Basis Spread	$(0.980) - $0.058

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The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2018, 2017 and 2016 (in thousands):

	Year Ended December 31,
	2018			2017			2016
Balance, beginning of period	$	(91	)	$	—		$	—
Realized and mark-to-market gains:
Included in operating and maintenance expense	(9,944		)	—			—
Purchases	5,678			(91		)	—
Balance, end of period	$	(4,357	)	$	(91	)	$	—
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(9,944	)	$	—		$	—

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 net settlement. 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, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

In June 2018, we settled a portion of the Interest Rate Derivatives and received $4.8 million of proceeds upon the termination of interest rate swaps associated with the amendment of the CCH Credit Facility, as discussed in Note 9—Debt. In May 2017, we settled a portion of the Interest Rate Derivatives and paid $13.0 million in conjunction with the termination of approximately $1.4 billion of commitments under the CCH Credit Facility.

As of December 31, 2018, we had the following Interest Rate Derivatives outstanding:

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives	$28.8 million	$4.7 billion	May 20, 2015	May 31, 2022	2.30%	One-month LIBOR

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

	December 31,
Consolidated Balance Sheet Location	2018			2017
Derivative assets	$	10,556		$	—
Non-current derivative assets	7,918			2,469
Total derivative assets	18,474			2,469
Derivative liabilities	(7		)	(19,609		)
Non-current derivative liabilities	(398		)	(15,118		)
Total derivative liabilities	(405		)	(34,727		)
Derivative asset (liability), net	$	18,069		$	(32,258	)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2018, 2017 and 2016 (in thousands):

	Year Ended December 31,
	2018		2017		2016
Interest Rate Derivatives gain (loss)	$	43,105	$	3,249	$	(15,571	)

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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 terms of the physical natural gas supply contracts range up to eight years, some of which commence upon the satisfaction of certain conditions precedent.

Our Financial Liquefaction Supply Derivatives 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. We are required by these financial institutions to use margin deposits as credit support for our Financial Liquefaction Supply Derivatives activities.

As of December 31, 2018 and 2017, CCL had secured up to approximately 2,801 TBtu and 2,024 TBtu, respectively, of natural gas feedstock through natural gas supply contracts, The forward notional for our Liquefaction Supply Derivatives was approximately 2,854 TBtu and 1,019 TBtu as of December 31, 2018 and 2017, respectively.

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, 2018			December 31, 2017
Derivative assets	$	7,203		$	—
Non-current derivative assets	14,495			—
Total derivative assets	21,698			—
Derivative liabilities	(13,569		)	—
Non-current derivative liabilities	(8,197		)	(91		)
Total derivative liabilities	(21,766		)	(91		)
Derivative liability, net	$	(68	)	$	(91	)

(1) Does not include collateral call of $4.5 million for such contracts, which are included in other current assets in our Balance Sheet as December 31, 2018.

The following table shows the changes in the fair value and settlements of our Liquefaction Supply Derivatives recorded in operating and maintenance expense on our Consolidated Statements of Operations during the years ended December 31, 2018, 2017 and 2016 (in thousands):

	Year Ended December 31,
	2018		2017			2016
Liquefaction Supply Derivatives gain (loss)	$	23	$	(91	)	$	—

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, 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		)
As of December 31, 2017
Interest Rate Derivatives	$	2,808		$	(339	)	$	2,469
Interest Rate Derivatives	(34,747		)	20			(34,727		)
Liquefaction Supply Derivatives	(130		)	39			(91		)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 7—OTHER NON-CURRENT ASSETS

As of December 31, 2018 and 2017, other non-current assets, net consisted of the following (in thousands):

	December 31,
	2018		2017
Advances and other asset conveyances to third parties to support LNG terminals	$	18,209	$	30,442
Tax-related payments and receivables	3,783		3,400
Information technology service assets	2,435		610
Other	7,282		3,672
Total other non-current assets, net	$	31,709	$	38,124

NOTE 8—ACCRUED LIABILITIES

As of December 31, 2018 and 2017, accrued liabilities consisted of the following (in thousands): 

	December 31,
	2018		2017
Interest costs and related debt fees	$	994	$	136,283
Liquefaction Project costs	138,874		107,055
Other	22,337		14,722
Total accrued liabilities	$	162,205	$	258,060

NOTE 9—DEBT

As of December 31, 2018 and 2017, our debt consisted of the following (in thousands): 

	December 31,
	2018			2017
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
CCH Credit Facility	5,155,737			2,484,737
Unamortized premium, discount and debt issuance costs, net	(160,185		)	(65,261		)
Total long-term debt, net	9,245,552			6,669,476
Current debt
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	168,000			—
Total debt, net	$	9,413,552		$	6,669,476

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, 2018 (in thousands): 

Years Ending December 31,	Principal Payments
2019	$	168,000
2020	—
2021	—
2022	—
2023	—
Thereafter	9,405,737
Total	$	9,573,737

Senior Notes

The 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes (collectively, the “CCH Senior Notes”) are jointly and severally guaranteed by the Guarantors. The indenture governing the CCH Senior Notes (the “CCH Indenture”)

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contains 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 series 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 CCH Indenture, plus accrued and unpaid interest, if any, to the date of redemption. We also may at any time within six months of the respective dates of maturity for each series of the CCH Senior Notes, 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, 2018 (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	5,155,737		168,000
Commitments terminated	3,832,263		—
Letters of credit issued	—		315,525
Available commitment	$	981,675	$	716,475
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75%
Maturity date	June 30, 2024		June 29, 2023

As of December 31, 2018, the weighted average interest rate on our current debt was 5.76%.

CCH Credit Facility

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

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

Loans under the CCH Credit Facility accrue interest at a variable rate per annum equal to, at our election, LIBOR or the base rate (determined by reference to the applicable agent’s prime rate), plus the applicable margin. The applicable margin for LIBOR loans is 1.75% and for base rate loans is 0.75%. Interest on LIBOR loans is due and payable at the end of each applicable interest period and interest on base rate loans is due and payable at the end of each quarter. The CCH Credit Facility also requires us to pay a commitment fee at a rate per annum equal to 40% of the margin for LIBOR loans, multiplied by the outstanding undrawn debt commitments.

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Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all 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 Credit 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.

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”), the issuance of letters of credit for certain working capital requirements related to developing and placing into operations the Liquefaction Project and for related business purposes. Loans under the CCH Working Capital Facility are guaranteed by the Guarantors. We may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed for working capital under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility.

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

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

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

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

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

The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets

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and the assets of the Guarantors as well as all of our membership interests and the membership interests in the Guarantors on a pari passu basis with the CCH Senior Notes and the CCH Credit Facility.

Restrictive Debt Covenants

As of December 31, 2018, 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,
	2018			2017			2016
Total interest cost	$	451,135		$	360,932		$	221,865
Capitalized interest, including amounts capitalized as an Allowance for Funds Used During Construction	(451,135		)	(360,932		)	(221,865		)
Total interest expense, net	$	—		$	—		$	—

Fair Value Disclosures

The following table shows the carrying amount, which is net of unamortized premium, discount and debt issuance costs, and estimated fair value of our debt (in thousands):

	December 31, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	4,191,754	$	4,228,750	$	4,184,739	$	4,590,625
Credit facilities (2)	5,221,798		5,221,798		2,484,737		2,484,737

(1) Includes 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes (collectively, the “CCH Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the CCH Senior Notes and other similar instruments.

(2) 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.

NOTE 10—REVENUES FROM CONTRACTS WITH CUSTOMERS

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.

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 sale 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.

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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, 2018 and 2017:

	December 31, 2018			December 31, 2017
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
Revenues	$	34.8	12	$	28.0	12

(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) 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 table above excludes all variable consideration under our SPAs. 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.

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.

NOTE 11—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, 2018, 2017 and 2016 (in thousands):

	Year Ended December 31,
	2018			2017		2016
Operating and maintenance expense—affiliate
Services Agreements	$	3,412		$	2,075	$	7
Lease Agreements	874			326		88
Other Agreements	(3		)	—		—
Total operating and maintenance expense—affiliate	4,283			2,401		95
Development expense (recovery)—affiliate
Services Agreements	—			8		(10		)
General and administrative expense—affiliate
Services Agreements	2,201			1,173		607

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We had $25.1 million and $23.8 million due to affiliates as of December 31, 2018 and 2017, respectively, under agreements with affiliates, as described below.

LNG Sale and Purchase Agreements

CCL has a fixed price 20-year SPA with Cheniere Marketing International LLP (“Cheniere Marketing”) (the “Cheniere Marketing Base SPA”) 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, CCL has a fixed price 25-year SPA with Cheniere Marketing which allows them to purchase volumes of approximately 15 TBtu per annum of LNG. As of December 31, 2018 and 2017, CCL had $21.1 million and zero of accounts receivable—affiliate, respectively, under this agreement.

Services Agreements

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

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

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

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

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

Management Services Agreements (“MSAs”)

CCL has 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 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

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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 an 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.

Land Agreements

We had $0.3 million and $0.2 million as of December 31, 2018 and 2017, respectively, of prepaid expenses related to these agreements in other current assets—affiliate.

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 $0.7 million, and the terms of the agreements range from three to five years.

Easement Agreements

In February 2018, CCL entered into agreements with Cheniere Land Holdings which grants CCL a limited license to use certain roads on land owned by Cheniere Land Holdings for the Liquefaction Facilities. The total annual lease payment is $0.1 million, and the term of each agreement is five years.

In May 2018, CCL entered into agreements with Cheniere Land Holdings which grants CCL the right to construct, install and operate waterlines on land owned by Cheniere Land Holdings for the Liquefaction Facilities. During the year ended December 31, 2018, CCL paid $0.4 million as equity contributions to Cheniere Land Holdings for the value of these agreements.

In August 2018, CCL entered into an agreement with Cheniere Land Holdings which grants CCL a limited license to use certain land owned by Cheniere Land Holdings for the Liquefaction Facilities. CCL made a one-time payment of $0.5 million under this agreement, and the term of the agreement is three years.

Special Warranty Deed

In May 2018, CCL entered into a special warranty deed agreement with Cheniere Land Holdings whereby land owned by Cheniere Land Holdings was transferred to CCL as a non-cash equity contribution of $20.8 million.

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.

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Tug Hosting Agreement

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

State Tax Sharing Agreements

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

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

Equity Contribution Agreements

Equity Contribution Agreement

In May 2018, we amended and restated the existing equity contribution agreement with Cheniere (the “Equity Contribution Agreement”) pursuant to which Cheniere agreed to provide cash contributions up to approximately $1.1 billion, not including $2.0 billion previously contributed under the original equity contribution agreement. As of December 31, 2018, we have not received any contributions under the Equity Contribution Agreement. Cheniere will only be required to make additional contributions under the Equity Contribution Agreement after the commitments under the CCH Credit Facility have been reduced to zero and to the extent cash flows from operations of the Liquefaction Project are unavailable for Liquefaction Project costs.

Early Works Equity Contribution Agreement

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

NOTE 12—INCOME TAXES

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows: 

	Year Ended December 31,
	2018		2017		2016
U.S. federal statutory tax rate	21.0	%	35.0	%	35.0	%
State tax rate	(105.8	)%	—	%	—	%
U.S. tax reform rate change	—	%	(121.1	)%	—	%
Other	1.2	%	(0.2	)%	—	%
Valuation allowance	83.6	%	86.3	%	(35.0	)%
Effective tax rate	—	%	—	%	—	%

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Significant components of our deferred tax assets at December 31, 2018 and 2017 are as follows (in thousands):

	December 31,
	2018			2017
Deferred tax assets
Federal net operating loss carryforward	$	108,007		$	49,194
State net operating loss carryforward	6,646			—
Derivative instruments	3,288			15,487
Long-term debt	—			14,270
Property, plant and equipment	—			9,143
Other	—			303
Less: valuation allowance	(93,650		)	(88,397		)
Total deferred tax assets	24,291			��
Deferred tax liabilities
Long-term debt	(12,477		)	—
Property, plant and equipment	(11,301		)	—
Other	(513		)	—
Total deferred tax liabilities	(24,291		)	—
Net deferred tax assets	$	—		$	—

At December 31, 2018, we had federal and state net operating loss (“NOL”) carryforwards of $514.3 million and $73.9 million, respectively. These NOL carryforwards will expire between 2035 and 2038.

We did not have any uncertain tax positions which required accrual or disclosure as of December 31, 2018 and 2017. We have elected to report future interest and penalties related to unrecognized tax benefits, if any, as income tax expense in our Consolidated Statements of Operations.

Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal deferred tax assets as of December 31, 2018 and 2017.  We will continue to evaluate the realizability of our deferred tax assets in the future. The increase in the valuation allowance was $5.3 million for the year ended December 31, 2018.

Our taxable income or loss is included in the consolidated federal income tax return of Cheniere. Cheniere’s federal and state tax returns for the years after 2014 remain open for examination.

Cheniere experienced an ownership change within the provisions of U.S. Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. Cheniere will continue to monitor trading activity in its respective shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize Cheniere’s existing NOL carryforwards.

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NOTE 13—LEASES

During the years ended December 31, 2018, 2017 and 2016, we recognized rental expense for all operating leases of $1.6 million, $1.2 million and $1.0 million, respectively, related primarily to land sites for the Corpus Christi LNG terminal. CCL and CCP have agreements with Cheniere Land Holdings to lease land owned by Cheniere Land Holdings for the Liquefaction Project. See Note 11—Related Party Transactions for additional information regarding these lease agreements.

Future annual minimum lease payments, excluding inflationary adjustments, for operating leases are as follows (in thousands): 

Years Ending December 31,	Operating Leases (1)
2019	$	596
2020	1,225
2021	1,225
2022	1,225
2023	1,225
Thereafter	1,225
Total	$	6,721

(1) Includes payments for certain non-lease components.

NOTE 14—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, 2018, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contracts

CCL has lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Stage 1 and Stage 2 of the Liquefaction Project. The EPC contract prices for Stage 1 of the Liquefaction Project and Stage 2 of the Liquefaction Project are approximately $7.8 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through December 31, 2018. 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 11—Related Party Transactions.

Obligations under Natural Gas Supply, Transportation and Storage Service Agreements

CCL primarily has index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The terms of these contracts range up to eight years, some of which commence upon the satisfaction of certain conditions precedent. As of December 31, 2018, CCL had secured up to approximately 2,801 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent are met.

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

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As of December 31, 2018, 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)
2019	$	682,956
2020	613,700
2021	442,044
2022	254,572
2023	177,093
Thereafter	1,703,501
Total	$	3,873,866

(1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on prices and basis spreads as of December 31, 2018.

Services Agreements

CCL and CCP have certain services agreements with affiliates. See Note 11—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 11—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. Additionally, we have various operating lease commitments, as disclosed in Note 13—Leases.

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, 2018, 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 15—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2018		2017		2016
Cash paid during the period for interest, net of amounts capitalized	$	104,811	$	—	$	—
Noncash capital contribution for conveyance of property, plant and equipment from affiliate	83,058		—		143

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $178.3 million, $274.3 million and $145.6 million as of December 31, 2018, 2017 and 2016, respectively.

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NOTE 16—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of a recent accounting standard that had not been adopted by us as of December 31, 2018:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	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. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available.	January 1, 2019	We will adopt this standard 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. The adoption of the standard will not have a material impact on our Consolidated Financial Statements but will result in additional disclosures including the significant judgments and assumptions used in applying the standard.

Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period:

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported Consolidated Financial Statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 10—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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NOTE 17—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 CCH Indenture, (3) upon the legal defeasance or covenant defeasance or discharge of obligations under the CCH Indenture and (4) the release and discharge of the Guarantors pursuant to the Common Security and Account Agreement. See Note 9—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, 2018.

Condensed Consolidating Balance Sheet
December 31, 2018
(in thousands)
	Parent Issuer		Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—		$	—
Restricted cash	282,248		6,893		—			289,141
Receivables	—		24,989		—			24,989
Accounts receivable—affiliate	—		21,060		—			21,060
Advances to affiliate	—		94,397		—			94,397
Inventory	—		26,198		—			26,198
Derivative assets	10,556		7,203		—			17,759
Other current assets	178		15,039		—			15,217
Other current assets—affiliate	—		634		(1		)	633
Total current assets	292,982		196,413		(1		)	489,394
Property, plant and equipment, net	1,094,671		10,044,154		—			11,138,825
Debt issuance and deferred financing costs, net	38,012		—		—			38,012
Non-current derivative assets	7,917		14,496		—			22,413
Investments in subsidiaries	10,194,296		—		(10,194,296		)	—
Other non-current assets, net	1		31,708		—			31,709
Total assets	$	11,627,879	$	10,286,771	$	(10,194,297	)	$	11,720,353
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	71	$	16,131	$	—		$	16,202
Accrued liabilities	1,242		160,963		—			162,205
Current debt	168,000		—		—			168,000
Due to affiliates	—		25,086		—			25,086
Derivative liabilities	6		13,570		—			13,576
Total current liabilities	169,319		215,750		—			385,069
Long-term debt, net	9,245,552		—		—			9,245,552
Non-current derivative liabilities	398		8,197		—			8,595
Deferred tax liability	—		2,008		(2,008		)	—
Member’s equity	2,212,610		10,060,816		(10,192,289		)	2,081,137
Total liabilities and member’s equity	$	11,627,879	$	10,286,771	$	(10,194,297	)	$	11,720,353

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Condensed Consolidating Balance Sheet
December 31, 2017
(in thousands)
	Parent Issuer		Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—		$	—
Restricted cash	226,559		—		—			226,559
Advances to affiliate	—		31,486		—			31,486
Other current assets	246		1,248		—			1,494
Other current assets—affiliate	—		191		(1		)	190
Total current assets	226,805		32,925		(1		)	259,729
Property, plant and equipment, net	651,687		7,609,696		—			8,261,383
Debt issuance and deferred financing costs, net	98,175		—		—			98,175
Non-current derivative assets	2,469		—		—			2,469
Investments in subsidiaries	7,648,111		—		(7,648,111		)	—
Other non-current assets, net	—		38,124		—			38,124
Total assets	$	8,627,247	$	7,680,745	$	(7,648,112	)	$	8,659,880
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	82	$	6,379	$	—		$	6,461
Accrued liabilities	136,389		121,671		—			258,060
Due to affiliates	—		23,789		—			23,789
Derivative liabilities	19,609		—		—			19,609
Total current liabilities	156,080		151,839		—			307,919
Long-term debt, net	6,669,476		—		—			6,669,476
Non-current derivative liabilities	15,118		91		—			15,209
Deferred tax liability	—		2,983		(2,983		)	—
Member’s equity	1,786,573		7,525,832		(7,645,129		)	1,667,276
Total liabilities and member’s equity	$	8,627,247	$	7,680,745	$	(7,648,112	)	$	8,659,880

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Condensed Consolidating Statement of Operations
Year Ended December 31, 2018
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Revenues	$	—		$	—		$	—		$	—
Expenses
Operating and maintenance expense	—			76			—			76
Operating and maintenance expense—affiliate	—			4,283			—			4,283
Development expense	—			177			—			177
General and administrative expense	1,513			3,750			—			5,263
General and administrative expense—affiliate	—			2,201			—			2,201
Depreciation and amortization expense	239			9,620			—			9,859
Impairment expense and gain on disposal of assets	—			20			—			20
Total expenses	1,752			20,127			—			21,879
Loss from operations	(1,752		)	(20,127		)	—			(21,879		)
Other income (expense)
Loss on modification or extinguishment of debt	(15,332		)	—			—			(15,332		)
Derivative gain, net	43,105			—			—			43,105
Other income	352			7,952			(7,912		)	392
Total other income	28,125			7,952			(7,912		)	28,165
Income (loss) before income taxes	26,373			(12,175		)	(7,912		)	6,286
Income tax benefit	—			831			(831		)	—
Net income (loss)	$	26,373		$	(11,344	)	$	(8,743	)	$	6,286

64

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	$	—		$	—		$	—		$	—
Expenses
Operating and maintenance expense	—			3,115			—			3,115
Operating and maintenance expense—affiliate	—			2,401			—			2,401
Development expense	—			516			—			516
Development expense—affiliate	—			8			—			8
General and administrative expense	1,360			4,191			—			5,551
General and administrative expense—affiliate	—			1,173			—			1,173
Depreciation and amortization expense	13			879			—			892
Impairment expense and loss on disposal of assets	—			5,505			—			5,505
Total expenses	1,373			17,788			—			19,161
Loss from operations	(1,373		)	(17,788		)	—			(19,161		)
Other income (expense)
Loss on modification or extinguishment of debt	(32,480		)	—			—			(32,480		)
Derivative gain, net	3,249			—			—			3,249
Other income (expense)	(265		)	15,580			(15,575		)	(260		)
Total other income (expense)	(29,496		)	15,580			(15,575		)	(29,491		)
Loss before income taxes	(30,869		)	(2,208		)	(15,575		)	(48,652		)
Income tax provision	—			(2,983		)	2,983			—
Net loss	$	(30,869	)	$	(5,191	)	$	(12,592	)	$	(48,652	)

65

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Operations
Year Ended December 31, 2016
(in thousands)
	Parent Issuer			Guarantors			Eliminations		Consolidated
Revenues	$	—		$	—		$	—	$	—
Expenses
Operating and maintenance expense	—			1,372			—		1,372
Operating and maintenance expense—affiliate	—			95			—		95
Development expense recovery	—			(81		)	—		(81		)
Development expense recovery—affiliate	—			(10		)	—		(10		)
General and administrative expense	709			3,531			—		4,240
General and administrative expense—affiliate	—			607			—		607
Depreciation and amortization expense	—			249			—		249
Total expenses	709			5,763			—		6,472
Loss from operations	(709		)	(5,763		)	—		(6,472		)
Other income (expense)
Loss on modification or extinguishment of debt	(63,318		)	—			—		(63,318		)
Derivative loss, net	(15,571		)	—			—		(15,571		)
Other income (expense)	(131		)	5			—		(126		)
Total other income (expense)	(79,020		)	5			—		(79,015		)
Net loss	$	(79,729	)	$	(5,758	)	$	—	$	(85,487	)

66

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

Balances per Condensed Consolidating Balance Sheet:

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

67

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2017
	Parent Issuer		Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—
Restricted cash	226,559		—		—		226,559
Total cash, cash equivalents and restricted cash	$	226,559	$	—	$	—	$	226,559

68

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2016
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows used in operating activities	$	(34,954	)	$	(6,125	)	$	—		$	(41,079	)
Cash flows from investing activities
Property, plant and equipment, net	(126,547		)	(1,924,983		)	—			(2,051,530		)
Investments in subsidiaries	(1,975,474		)	—			1,975,474			—
Other	—			(44,367		)	—			(44,367		)
Net cash used in investing activities	(2,102,021		)	(1,969,350		)	1,975,474			(2,095,897		)
Cash flows from financing activities
Proceeds from issuances of debt	4,838,000			—			—			4,838,000
Repayments of debt	(2,420,212		)	—			—			(2,420,212		)
Debt issuance and deferred financing costs	(56,783		)	—			—			(56,783		)
Debt extinguishment cost	(62		)	—			—			(62		)
Capital contributions	90			1,975,475			(1,975,474		)	91
Distributions	(288		)	—			—			(288		)
Net cash provided by financing activities	2,360,745			1,975,475			(1,975,474		)	2,360,746
Net increase in cash, cash equivalents and restricted cash	223,770			—			—			223,770
Cash, cash equivalents and restricted cash—beginning of period	46,770			—			—			46,770
Cash, cash equivalents and restricted cash—end of period	$	270,540		$	—		$	—		$	270,540

69

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, 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		)
Year ended December 31, 2017:
Revenues	$	—		$	—		$	—		$	—
Loss from operations	(2,719		)	(3,138		)	(5,576		)	(7,728		)
Net income (loss)	(1,757		)	(68,758		)	(8,577		)	30,440

70

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, 2018, 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 35 and is incorporated herein by reference.

ITEM 9B. OTHER INFORMATION

None.

71

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, 2018 and 2017. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 2018 and 2017 (in thousands): 

	Fiscal 2018		Fiscal 2017
Audit Fees	$	950	$	1,050
Tax Fees	128		89
Total	$	1,078	$	1,139

Audit Fees—Audit fees for 2018 and 2017 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 2018 and 2017.

Tax Fees—Tax fees for 2018 and 2017 were for tax consultation services with respect to a sales and use tax analysis for the Liquefaction Project.

Other Fees—There were no other fees in 2018 and 2017.

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, 2018 and 2017.

72

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements and Exhibits

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

Management’s Report to the Member of Cheniere Corpus Christi Holdings, LLC	35
Report of Independent Registered Public Accounting Firm	36
Consolidated Balance Sheets	37
Consolidated Statements of Operations	38
Consolidated Statements of Member’s Equity	39
Consolidated Statements of Cash Flows	40
Notes to Consolidated Financial Statements	41
Supplemental Information to Consolidated Financial Statements—Quarterly Financial Data	70

(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.	Description
3.1	Certificate of Formation of the Company (Incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
3.2	Certificate of Correction to Certificate of Formation of the Company (Incorporated by reference to Exhibit 3.2 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
3.3	Amended and Restated Limited Liability Company Agreement of the Company (Incorporated by reference to Exhibit 3.3 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
3.4	Certificate of Formation of CCL (Incorporated by reference to Exhibit 3.4 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)

73

Exhibit No.	Description
3.5	Amended and Restated Limited Liability Company Agreement of CCL (Incorporated by reference to Exhibit 3.5 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
3.6	Certificate of Formation of CCP GP (Incorporated by reference to Exhibit 3.6 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
3.7	Certificate of Correction to Certificate of Formation of CCP GP (Incorporated by reference to Exhibit 3.7 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
3.8	Amended and Restated Limited Liability Company Agreement of CCP GP (Incorporated by reference to Exhibit 3.8 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
3.9	Certificate of Limited Partnership of CCP (Incorporated by reference to Exhibit 3.9 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
3.10	Certificate of Amendment to Certificate of Limited Partnership of CCP (Incorporated by reference to Exhibit 3.10 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
3.11	Amended and Restated Agreement of Limited Partnership of CCP (Incorporated by reference to Exhibit 3.11 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
4.1	Indenture, dated as of May 18, 2016, among the Company, as Issuer, CCL, CCP and CCP GP, as Guarantors, and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 18, 2016)
4.2	Form of 7.000% Senior Secured Note due 2024 (Included as Exhibit A-1 to Exhibit 4.1 above)
4.3	First Supplemental Indenture, dated as of December 9, 2016, among the Company, as Issuer, CCL, CCP and CCP GP, as Guarantors, and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 9, 2016)
4.4	Form of 5.875% Senior Secured Note due 2025 (Included as Exhibit A-1 to Exhibit 4.3 above)
4.5	Second Supplemental Indenture, dated as of May 19, 2017, among the Company, as issuer, CCL, CCP and CCP GP, as Guarantors, and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (SEC File No. 333-215435), filed on May 19, 2017)
4.6	Form of 5.125% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.5 above)
10.1	Amended and Restated Term Loan Facility Agreement, dated May 22, 2018, among the Company, CCP, CCP GP, CCL, the lenders party thereto from time to time and Société Générale as the Term Loan Facility Agent (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 333-215435), filed on May 24, 2018)
10.2	Amended and Restated Common Terms Agreement, dated May 22, 2018, among the Company, CCP, CCP GP, CCL, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, and Société Générale as Intercreditor Agent, and any other facility lenders party thereto from time to time (Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (SEC File No. 333-215435), filed on May 24, 2018)
10.3*	First Amendment to the Amended and Restated Common Terms Agreement, dated as of November 28, 2018, by and among the Company, CCL, CCP and CCP GP, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as Intercreditor Agent
10.4	Amended and Restated Common Security and Account Agreement, dated May 22, 2018, among the Company, CCP, CCP GP, CCL, the Senior Creditor Group Representatives, Société Générale as the Intercreditor Agent, Société Générale as Security Trustee and Mizuho Bank, Ltd as the Account Bank. (Incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (SEC File No. 333-215435), filed on May 24, 2018)
10.5*	First Amendment to the Amended and Restated Common Security and Account Agreement, dated as of November 28, 2018, by and among the Company, CCL, CCP and CCP GP, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank
10.6	Amended and Restated Pledge Agreement, dated May 22, 2018, among CCH HoldCo I and Société Générale as Security Trustee (Incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K (SEC File No. 333-215435), filed on May 24, 2018)

74

Exhibit No.	Description
10.7	Amended and Restated Equity Contribution Agreement, dated May 22, 2018, among the Company and Cheniere (Incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K (SEC File No. 333-215435), filed on May 24, 2018)
10.8	Amended and Restated Working Capital Facility Agreement, dated June 29, 2018, among the Company, CCP, CCP GP, CCL, the lenders party thereto from time to time, the issuing banks party thereto from time to time, the Bank of Nova Scotia as Working Capital Facility Agent, and Société Générale as Security Trustee (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 333-215435), filed on July 2, 2018)
10.9	Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 10, 2013)
10.10	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Cost Impacts Associated with Delay in NTP, dated March 9, 2015, (ii) the Change Order CO-00002 DLE/IAC Scope Change, dated March 25, 2015, (iii) the Change Order CO-00003 Currency and Fuel Provisional Sum Closures, dated May 13, 2015 and (iv) the Change Order CO-00004 Bridging Extension Through May 17, 2015, dated May 12, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.22 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on July 30, 2015)
10.11	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00005 Revised Buildings to Include Jetty and Geo-Tech Impact to Buildings, dated June 4, 2015, (ii) the Change Order CO-00006 Marine and Dredging Execution Change, dated June 16, 2015, (iii) the Change Order CO-00007 Temporary Laydown Areas, AEP Substation Relocation, Power Monitoring System for Substation, Bollards for Power Line Poles, Multiplex Interface for AEP Hecker Station, dated June 30, 2015, (iv) the Change Order CO-00008 West Jetty Shroud and Fencing, Temporary Strainers on Loading Arms, Breasting and Mooring Analysis, Addition of Crossbar from Platform at Ethylene Bullets to Platform for PSV Deck, Reduction of Vapor Fence at Bed 22, Relocation of Gangway Tower, Changes in Dolphin Size, dated July 28, 2015, (v) the Change Order CO-00009 Post FEED Studies, dated July 1, 2015, (vi) the Change Order CO-00010 Additional Post FEED Studies, Feed Gas ESD Valve Bypass, Flow Meter on Bog Line, Additional Simulations, FERC #43, dated July 1, 2015, (vii) the Change Order CO-00011 Credit to EPC Contract Value for TSA Work, dated July 7, 2015 and (viii) the Change Order CO-00012 Reduction of Provisional Sum for Operating Spares, Liquid Condensate Tie-In, Automatic Shut-Off Valve in Condensate Truck Fill Line, Firewater Monitor and Hydrant Coverage Test, dated August 11, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.4 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on October 30, 2015)
10.12	Change order to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00013 Change in FEED Gas Tie-In, Utility Water and Potable Water Tie-In Changes, Ditch Design at Permanent Buildings, Koch Pipeline Cover, Monitoring of Raw Water Lake During Piling, Card Readers and Muster Points, Additional Asphalt in the Temporary Facilities Area, FAA Lighting and Marking, FERC Condition 84, dated October 13, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.134 to Cheniere’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 19, 2016)
10.13	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00014 Stage 1 Isolation, dated January 11, 2016, (ii) the Change Order CO-00015 IAC Conversion to Lump Sum, dated January 20, 2016 and (iii) the Change Order CO-00016 Permanent Plant Buildings, dated January 20, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.6 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 5, 2016)

75

Exhibit No.	Description
10.14	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00017 Process and Utility Tie-Ins Studies and Associated Scopes (138 kV Pricing, Transfer Line, Connections for Future LNG Truck Loading Facility), dated May 24, 2016, (ii) the Change Order CO-00018 FERC Conditions 40, 63, 64, 80, dated May 4, 2016, (iii) the Change Order CO-00019 Trelleborg Marine Equipment, BOG Compressor Tie-In, Multiplexer Credit, Additional FERC Hours, dated May 4, 2016 and (iv) the Change Order CO-00020 Impact Due to Overhead Power Transmission Lines on La Quinta Road and Flare System Modification Evaluation, dated May 31, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.8 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 9, 2016)
10.15	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00022 Permanent Plant Building Modifications, dated June 20, 2016 and (ii) the Change Order CO-00024 N2 Dewar Interface, Temporary Power to Air Cooler, Condensate Pipeline Maximum Allowable Operating Pressure, dated June 28, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.5 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 3, 2016)
10.16	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00026 Changes to Outfall (P1, P2, and P5) to LaQuinta Ditch, dated August 31, 2016, (ii) the Change Order CO-00028 Anti-Dumping Duties, dated September 26, 2016 and (iii) the Change Order CO-00029 Additional Flare System Evaluation, dated September 26, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment) (Incorporated by reference to Exhibit 10.12 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.17	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00021 Secondary Access Road, DMPA-1 Scope and Use, Credit for Material Disposal, Power Pole Relocation, dated June 29, 2016, (ii) the Change Order CO-00023 Differing Soil Conditions and Bed 24 Over-Excavation Due to Differing Soil Conditions, dated June 29, 2016, (iii) the Change Order CO-00025 Priority 6 Roads Differing Soil Conditions and 102-J01 Over-Excavation due to Differing Soil Conditions, dated August 23, 2016, (iv) the Change Order CO-00027 Lines Traversing Laydown Area Access Road and Underground Utilities for Temporary Facilities, dated September 26, 2016 and (v) the Change Order CO-00032 Integrated Security System, dated February 3, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.45 to Amendment No. 1 to the Company’s Registration Statement on Form S-4/A (SEC File No. 333-215435), filed on March 8, 2017)
10.18	Change order to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00030, dated November 1, 2016 (Incorporated by reference to Exhibit 10.46 to Amendment No. 1 to the Company’s Registration Statement on Form S-4/A (SEC File No. 333-215435), filed on March 8, 2017)
10.19	Change order to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00031 Flare System Modification Implementation, dated January 17, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.48 to Amendment No. 2 to the Company’s Registration Statement on Form S-4/A (SEC File No. 333-215435), filed on March 23, 2017)
10.20	Change order to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00033 Marine Ground Flare, dated February 27, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-215435), filed on May 4, 2017)

76

Exhibit No.	Description
10.21	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00034 Condensate Tie-In, Utility Water Tie-In, and Feed Gas Tie-In Relocation, dated April 18, 2017 and (ii) the Change Order CO-00035 Nitrogen Tie-In Relocation, dated April 21, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-215435), filed on August 8, 2017)
10.22	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00036 Security Fencing Revisions, 138kV Overhead Power Stop Work, Additional Permanent Plant Access Control System Changes, and Wet/Dry Flare Expansion Loop Relocation, dated August 3, 2017 and (ii) the Change Order CO-00037 9% Nickel Lump Sum Conversion, dated September 14, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.50 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-221307), filed on November 2, 2017)
10.23	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00038 Settlement of Various Scopes, dated November 10, 2017, (ii) the Change Order CO-00039 OSHA Handrails, East Jetty Scaffold, Attachment Y, and Insurance Provisional Sum, dated February 26, 2018 and (iii) the Change Order CO-00041 GE Service Bulletins and JT Valve Modifications, dated March 6, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-215435), filed on May 4, 2018)
10.24	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00042 Owner Modification of Warehouse 1 and Laboratory, dated April 30, 2018, (ii) the Change Order CO-00043 Hurricane Harvey Relief and Special Schedule Rewards, dated May 18, 2018, (iii) the Change Order CO-00044 Condensate Takeaway Modifications and Tell-Tale Signs for Leak Detection and Repair, dated June 6, 2018 and (iv) the Change Order CO-00045 Early Turnover of Security Operations Building, dated June 6, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-215435), filed on August 9, 2018)
10.25*	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00040 Hurricane Harvey Recovery Weekend Work, dated April 5, 2018, (ii) the Change Order CO-00046 Early Turnover of Seven Buildings, dated September 12, 2018, (iii) the Change Order CO-00047 System Inspection Isometrics, dated October 3, 2018, (iv) the Change Order CO-00048 Early Turnover of West Jetty, LNG Tank A, Tug Utility Station and Marine Flare, dated November 13, 2018 and (v) the Change Order CO-00049 Early Turnover of WTP, Sanitary, Diesel/Gasoline, and Partial Electrical System, dated December 7, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)
10.26	Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated December 12, 2017, by and between CCL and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.23 to Amendment No.1 to the Company’s Annual Report on Form 10-K/A (SEC File No. 333-215435), filed on April 27, 2018)
10.27	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Stage 2 EPC Agreement Revised Table A-2, dated May 18, 2018, (ii) the Change Order CO-00002 Stage 2 EPC Agreement Amended and Restated Attachment C, dated May 18, 2018, (iii) the Change Order CO-00003 Fuel Provisional Sum Adjustment, dated May 24, 2018, (iv) the Change Order CO-00004 Currency Provisional Sum Adjustment, dated May 29, 2018, (v) the Change Order CO-00005 JT Valve Modifications, dated July 10, 2018 and (vi) the Change Order CO-00006 Tank B Soil Conditions, International Building Code, and East Jetty Marine Facility Schedule Acceleration, dated September 5, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-215435), filed on November 8, 2018)

77

Exhibit No.	Description
10.28*	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00007 Tell-Tale Signs, Additional Tie-Ins, and System Inspection Isometrics, dated October 15, 2018, (ii) the Change Order CO-00008 Insurance Provisional Sum Interim Adjustment, dated November 19, 2018 and (iii) the Change Order CO-00009 Traffic and Logistics Impacts Due to Enforcement of Electronic Logging Devices, dated November 28, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)
10.29	Operation and Maintenance Agreement, dated as of May 13, 2015, among Cheniere LNG O&M Services, LLC and CCL (Incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.30	Operation and Maintenance Agreement, dated as of May 13, 2015, among Cheniere LNG O&M Services, LLC and CCP (Incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.31	LNG Sale and Purchase Agreement (FOB), dated April 1, 2014, between CCL (Seller) and Endesa Generación, S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on April 2, 2014)
10.32	LNG Sale and Purchase Agreement (FOB), dated April 7, 2014, between CCL (Seller) and Endesa S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere’s Current Report on Form 8-K(SEC File No. 001-16383), filed on April 8, 2014)
10.33	Assignment and Amendment Agreement, dated April 7, 2014, among Endesa Generación S.A., Endesa S.A. and CCL (Incorporated by reference to Exhibit 10.3 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 1, 2014)
10.34	Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated July 23, 2015, between Endesa S.A. (Buyer) and CCL (Seller) (Incorporated by reference to Exhibit 10.9 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on October 30, 2015)
10.35	Amendment No. 2 of LNG Sale and Purchase Agreement (FOB), dated July 23, 2015, between Endesa S.A. (Buyer) and CCL (Seller) (Incorporated by reference to Exhibit 10.10 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on October 30, 2015)
10.36	Amended and Restated LNG Sale and Purchase Agreement (FOB), dated March 20, 2015, between CCL (Seller) and PT Pertamina (Persero) (Buyer) (Incorporated by reference to Exhibit 10.5 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on April 30, 2015)
10.37	Amendment No. 1, dated February 4, 2016, to Amended and Restated LNG Sale and Purchase Agreement (FOB) between CCL and PT Pertamina (Persero), dated March 20, 2015 (Incorporated by reference to Exhibit 10.22 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.38	LNG Sale and Purchase Agreement (FOB), dated June 2, 2014, between CCL (Seller) and Gas Natural Fenosa LNG SL (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on June 2, 2014)
10.39	Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 27, 2018, between CCL (Seller) and Gas Natural Fenosa LNG GOM, Limited (Buyer) (Incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-215435), filed on May 4, 2018)
10.40	Amended and Restated Base LNG Sale and Purchase Agreement (FOB), dated as of November 28, 2014, between CCL and Cheniere Marketing International LLP (Incorporated by reference to Exhibit 10.32 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.41	Amendment No. 1, dated June 26, 2015, to Amended and Restated Base LNG Sale and Purchase Agreement (FOB), dated as of November 28, 2014, between CCL and Cheniere Marketing International LLP (Incorporated by reference to Exhibit 10.33 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.42	Amendment No. 2, dated December 27, 2016, to Amended and Restated Base LNG Sale and Purchase Agreement (FOB), dated as of November 28, 2014, between CCL and Cheniere Marketing International LLP (Incorporated by reference to Exhibit 10.34 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.43	Construction Agreement for the Corpus Christi Pipeline Project, dated as of November 10, 2016, by and between CCP and Associated Pipe Line Contractors, Inc. (Incorporated by reference to Exhibit 10.38 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)

78

Exhibit No.	Description
10.44	Construction Agreement for the Corpus Christi Pipeline Project, dated as of November 3, 2016, by and between CCP and Ref-Chem, L.P. (Incorporated by reference to Exhibit 10.39 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.45	Construction Agreement for the Corpus Christi Pipeline Project, dated as of November 4, 2016, by and between CCP and Sunland Construction, Inc. (Incorporated by reference to Exhibit 10.40 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
21.1*	Subsidiaries of the Company
31.1*	Certification by President and Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**	Certification by President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
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

*	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.

ITEM 16. FORM 10-K SUMMARY

None.

79

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 25, 2019

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

Signature	Title	Date
/s/ Michael J. Wortley	Manager, President and Chief Financial Officer (Principal Executive and Financial Officer)	February 25, 2019
Michael J. Wortley
/s/ Doug Shanda	Manager	February 25, 2019
Doug Shanda
/s/ Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 25, 2019
Leonard Travis

80

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS OF SUBSIDIARIES INCLUDED

PURSUANT TO RULE 3-16 OF REGULATION S-X

AUDITED FINANCIAL STATEMENTS OF CORPUS CHRISTI LIQUEFACTION, LLC	S-2
Independent Auditors’ Report	S-4
Balance Sheets	S-5
Statements of Operations	S-6
Statements of Member’s Equity	S-7
Statements of Cash Flows	S-8
Notes to Financial Statements	S-9
AUDITED FINANCIAL STATEMENTS OF CHENIERE CORPUS CHRISTI PIPELINE, L.P.	S-26
Independent Auditors’ Report	S-28
Balance Sheets	S-29
Statements of Operations	S-30
Statements of Partners’ Equity	S-31
Statements of Cash Flows	S-32
Notes to Financial Statements	S-33
AUDITED FINANCIAL STATEMENTS OF CORPUS CHRISTI PIPELINE GP, LLC	S-43
Independent Auditors’ Report	S-45
Balance Sheets	S-46
Statements of Operations	S-47
Statements of Member’s Equity	S-48
Statements of Cash Flows	S-49
Notes to Financial Statements	S-50

S-1

Corpus Christi Liquefaction, LLC

Financial Statements

As of December 31, 2018 and 2017

and for the years ended December 31, 2018, 2017 and 2016

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

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
MMBtu	million British thermal units, an energy unit
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, 2018 and the references to these entities used in these Financial Statements:

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

S-3

Independent Auditors’ Report

To the Member

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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in Note 2 to the financial statements, the Company has changed its method of accounting for revenue recognition in 2018, 2017 and 2016 due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

/s/    KPMG LLP

KPMG LLP

Houston, Texas

February 25, 2019

S-4

CORPUS CHRISTI LIQUEFACTION, LLC

BALANCE SHEETS

(in thousands)

	December 31,
	2018		2017
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	6,893		—
Receivables	24,989		—
Accounts receivable—affiliate	27,241		—
Advances to affiliate	78,805		11,414
Inventory	25,093		—
Derivative assets	7,203		—
Other current assets	8,717		1,237
Other current assets—affiliate	633		190
Total current assets	179,574		12,841
Property, plant and equipment, net	9,662,863		7,259,438
Non-current derivative assets	14,496		—
Other non-current assets, net	27,918		37,854
Total assets	$	9,884,851	$	7,310,133
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	15,186	$	4,456
Accrued liabilities	148,920		96,886
Due to affiliates	24,500		21,741
Derivative liabilities	13,570		—
Total current liabilities	202,176		123,083
Non-current derivative liabilities	8,197		91
Commitments and contingencies (see Note 12)
Member’s equity	9,674,478		7,186,959
Total liabilities and member’s equity	$	9,884,851	$	7,310,133

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,
	2018			2017			2016
Revenues	$	—		$	—		$	—
Expenses
Operating and maintenance expense	2,261			3,099			1,350
Operating and maintenance expense—affiliate	1,178			2,331			92
Development expense (recovery)	177			516			(81		)
Development expense (recovery)—affiliate	—			8			(10		)
General and administrative expense	3,016			3,951			3,231
General and administrative expense—affiliate	2,087			1,127			600
Depreciation and amortization expense	3,460			810			239
Impairment expense and loss on disposal of assets	20			5,500			—
Total expenses	12,199			17,342			5,421
Loss from operations	(12,199		)	(17,342		)	(5,421		)
Other income
Other income	40			5			5
Other income—affiliate	12			12			12
Total other income	52			17			17
Loss before income taxes	(12,147		)	(17,325		)	(5,404		)
Income tax provision	(144		)	—			—
Net loss	$	(12,291	)	$	(17,325	)	$	(5,404	)

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

S-6

CORPUS CHRISTI LIQUEFACTION, LLC

STATEMENTS OF MEMBER'S EQUITY

(in thousands)

	Cheniere Corpus Christi Holdings, LLC			Total Member’s Equity
Balance at December 31, 2015	$	3,819,983		$	3,819,983
Capital contributions	1,872,933			1,872,933
Net loss	(5,404		)	(5,404		)
Balance at December 31, 2016	5,687,512			5,687,512
Capital contributions	1,516,772			1,516,772
Net loss	(17,325		)	(17,325		)
Balance at December 31, 2017	7,186,959			7,186,959
Capital contributions	2,567,554			2,567,554
Distributions	(67,744		)	(67,744		)
Net loss	(12,291		)	(12,291		)
Balance at December 31, 2018	$	9,674,478		$	9,674,478

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,
	2018			2017			2016
Cash flows from operating activities
Net loss	$	(12,291	)	$	(17,325	)	$	(5,404	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization expense	3,460			810			239
Total losses (gains) on derivatives, net	(23		)	91			—
Impairment expense and loss on disposal of assets	20			5,500			—
Other	144			—			—
Changes in operating assets and liabilities:
Inventory	(23,746		)	—			—
Accounts payable and accrued liabilities	7,417			58			369
Due to affiliates	(459		)	1,561			(241		)
Other, net	(9,740		)	(1,202		)	(580		)
Other, net—affiliate	(109		)	(667		)	13
Net cash used in operating activities	(35,327		)	(11,174		)	(5,604		)
Cash flows from investing activities
Property, plant and equipment, net	(2,379,990		)	(1,530,642		)	(1,822,962		)
Other	4,843			25,045			(44,367		)
Net cash used in investing activities	(2,375,147		)	(1,505,597		)	(1,867,329		)
Cash flows from financing activities
Capital contributions	2,485,111			1,516,771			1,872,933
Distributions	(67,744		)	—			—
Net cash provided by financing activities	2,417,367			1,516,771			1,872,933
Net increase in cash, cash equivalents and restricted cash	6,893			—			—
Cash, cash equivalents and restricted cash—beginning of period	—			—			—
Cash, cash equivalents and restricted cash—end of period	$	6,893		$	—		$	—

Balances per Balance Sheets:

	December 31,
	2018			2017
Cash and cash equivalents	$	—		$	—
Restricted cash	6,893			—
Total cash, cash equivalents and restricted cash	$	6,893	��	$	—

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

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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. The Liquefaction Project is being developed in stages with the first phase being three Trains (“Phase 1”), with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). Trains 1 and 2 are undergoing commissioning and Train 3 is under construction.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Financial Statements have been prepared in accordance with GAAP.

We have evaluated subsequent events through February 25, 2019, the date the Financial Statements were available to be issued.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto (“ASC 606”) using the full retrospective method. We have elected to adopt the new accounting standard retrospectively and have recast the accompanying financial statements to reflect the adoption of ASC 606 for all periods presented. The adoption of ASC 606 did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings.

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 property, plant and equipment, derivative instruments, income taxes including valuation allowances for deferred tax assets and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

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 other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. 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 5—Derivative Instruments. The carrying amount of receivables and accounts payable reported on the Balance Sheets approximate fair value.

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CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 restricted as to usage or withdrawal and will not become available to us as cash and cash equivalents. We have presented restricted cash separately from cash and cash equivalents on our Balance Sheets. As of December 31, 2018 and 2017, restricted cash consisted of funds restricted for the Liquefaction Project.

Receivables

Receivables are primarily composed of settlements related to natural gas procurement activities. Receivable are reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses.  The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral.  We did not recognize any impairment expense related to receivables during the years ended December 31, 2018, 2017 and 2016.

Inventory

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 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 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 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. Substantially all of our long-lived assets are located in the United States.

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

S-10

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

31, 2017, we recognized $5.5 million of impairment expense related to damaged infrastructure as an effect of Hurricane Harvey. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2018 or 2016.

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, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2018, 2017 and 2016. See Note 5—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 unaffiliated third parties. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.

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.  The provision for income taxes, taxes payable and deferred income tax balances have been recorded as if we had filed all tax returns on a separate return basis from Cheniere. Deferred tax assets and liabilities are included in our Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the tax position.

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—INVENTORY

As of December 31, 2018 and 2017, inventory consisted of the following (in thousands):

	December 31,
	2018		2017
Natural gas	$	1,326	$	—
Materials and other	23,767		—
Total inventory	$	25,093	$	—

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

As of December 31, 2018 and 2017, property, plant and equipment, net consisted of the following (in thousands):

	December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	218,288		$	—
LNG site and related costs	42,551			11,662
LNG terminal construction-in-process	9,392,758			7,244,447
Accumulated depreciation	(1,503		)	—
Total LNG terminal costs, net	9,652,094			7,256,109
Fixed assets
Fixed assets	13,366			4,261
Accumulated depreciation	(2,597		)	(932		)
Total fixed assets, net	10,769			3,329
Property, plant and equipment, net	$	9,662,863		$	7,259,438

Depreciation expense was $3.2 million, $0.7 million and $0.2 million during the years ended December 31, 2018, 2017 and 2016, respectively.

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 realized offsets to LNG terminal costs of $48.7 million in the year ended December 31, 2018 for sales of commissioning cargoes from the Liquefaction Project.

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 with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows:

Components	Useful life (yrs)
Water pipelines	30
Liquefaction processing equipment	6-50
Other	15-30

Fixed Assets and Other

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

NOTE 5—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”).

S-12

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 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, 2018 and 2017, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Balance Sheets (in thousands):

	Fair Value Measurements as of
	December 31, 2018										December 31, 2017
	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)	$	1,299	$	2,990	$	(4,357	)	$	(68	)	$	—	$	—	$	(91	)	$	(91	)

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

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by market commodity basis 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. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

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 may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. As of December 31, 2018 and 2017, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow.

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 market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2018:

	Net Fair Value Liability (in thousands)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$(4,357)	Market approach incorporating present value techniques	Basis Spread	$(0.980) - $0.058

S-13

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2018, 2017 and 2016 (in thousands):

	Year Ended December 31,
	2018			2017			2016
Balance, beginning of period	$	(91	)	$	—		$	—
Realized and mark-to-market losses:
Included in operating and maintenance expense	(9,944		)	—			—
Purchases	5,678			(91		)	—
Balance, end of period	$	(4,357	)	$	(91	)	$	—
Change in unrealized losses relating to instruments still held at end of period	$	(9,944	)	$	—		$	—

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 net settlement. 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, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Liquefaction Supply Derivatives

We have 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 terms of the physical natural gas supply contracts range up to eight years, some of which commence upon the satisfaction of certain conditions precedent.

Our Financial Liquefaction Supply Derivatives 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. We are required by these financial institutions to use margin deposits as credit support for our Financial Liquefaction Supply Derivatives activities.

As of December 31, 2018 and 2017, we had secured up to approximately 2,801 TBtu and 2,024 TBtu, respectively, of natural gas feedstock through natural gas supply contracts, The forward notional for our Liquefaction Supply Derivatives was approximately 2,854 TBtu and 1,019 TBtu as of December 31, 2018 and 2017, respectively.

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, 2018			December 31, 2017
Derivative assets	$	7,203		$	—
Non-current derivative assets	14,495			—
Total derivative assets	21,698			—
Derivative liabilities	(13,569		)	—
Non-current derivative liabilities	(8,197		)	(91		)
Total derivative liabilities	(21,766		)	(91		)
Derivative liability, net	$	(68	)	$	(91	)

(1) Does not include collateral call of $4.5 million for such contracts, which are included in other current assets in our Balance Sheet as December 31, 2018.

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CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

The following table shows the changes in the fair value and settlements of our Liquefaction Supply Derivatives recorded in operating and maintenance expense on our Statements of Operations during the years ended December 31, 2018, 2017 and 2016 (in thousands):

	Year Ended December 31,
	2018		2017			2016
Liquefaction Supply Derivatives gain (loss)	$	23	$	(91	)	$	—

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, 2018
Liquefaction Supply Derivatives	$	31,770		$	(10,072	)	$	21,698
Liquefaction Supply Derivatives	(29,996		)	8,230			(21,766		)
As of December 31, 2017
Liquefaction Supply Derivatives	$	(130	)	$	39		$	(91	)

NOTE 6—OTHER NON-CURRENT ASSETS

As of December 31, 2018 and 2017, other non-current assets, net consisted of the following (in thousands):

	December 31,
	2018		2017
Advances and other asset conveyances to third parties to support LNG terminals	$	18,209	$	30,442
Tax-related payments and receivables	3,783		3,400
Information technology service assets	2,251		585
Other	3,675		3,427
Total other non-current assets, net	$	27,918	$	37,854

NOTE 7—ACCRUED LIABILITIES

As of December 31, 2018 and 2017, accrued liabilities consisted of the following (in thousands): 

	December 31,
	2018		2017
Liquefaction Project costs	$	129,633	$	82,750
Other	19,287		14,136
Total accrued liabilities	$	148,920	$	96,886

NOTE 8—REVENUES FROM CONTRACTS WITH CUSTOMERS

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.

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 sale 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, 2018 and 2017:

	December 31, 2018			December 31, 2017
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
Revenues	$	34.8	12	$	28.0	12

(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) 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 table above excludes all variable consideration under our SPAs. 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.

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 9—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, 2018, 2017 and 2016 (in thousands):

	Year Ended December 31,
	2018		2017		2016
Operating and maintenance expense—affiliate
Services Agreements	$	298	$	2,005	$	4
Lease Agreements	880		326		88
Total operating and maintenance expense—affiliate	1,178		2,331		92
Development expense (recovery)—affiliate
Services Agreements	—		8		(10		)
General and administrative expense—affiliate
Services Agreements	2,087		1,127		600
Other income—affiliate
Lease Agreements	12		12		12

We had $24.5 million and $21.7 million due to affiliates as of December 31, 2018 and 2017, respectively, under agreements with affiliates, as described below.

LNG Sale and Purchase Agreements

We have a fixed price 20-year SPA with Cheniere Marketing International LLP (“Cheniere Marketing”) (the “Cheniere Marketing Base SPA”) 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 a fixed price 25-year SPA with Cheniere Marketing which allows us to purchase volumes of approximately 15 TBtu per annum of LNG. As of December 31, 2018 and 2017, we had $21.1 million and zero of accounts receivable—affiliate, respectively, under this agreement.

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

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CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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.

Land Agreements

We had $0.3 million and $0.2 million as of December 31, 2018 and 2017, respectively, of prepaid expense related to this agreement 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 $0.7 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. 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

In February 2018, we entered into agreements with Cheniere Land Holdings which grants us a limited license to use certain roads on land owned by Cheniere Land Holdings for the Liquefaction Facilities. The total annual lease payment is $0.1 million, and the term of each agreement is five years.

In May 2018, we entered into agreements with Cheniere Land Holdings which grants us the right to construct, install and operate waterlines on land owned by Cheniere Land Holdings for the Liquefaction Facilities. During the year ended December 31, 2018, we paid $0.4 million as equity contributions to Cheniere Land Holdings for the value of these agreements.

In August 2018, we entered into an agreement with Cheniere Land Holdings which grants us a limited license to use certain land owned by Cheniere Land Holdings for the Liquefaction Facilities. We made a one-time payment of $0.5 million under this agreement, and the term of the agreement is three years.

Special Warranty Deed

In May 2018, we entered into a special warranty deed agreement with Cheniere Land Holdings whereby land owned by Cheniere Land Holdings was transferred to us as a non-cash equity contribution of $20.8 million.

S-18

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 about 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.

Natural Gas Transportation Agreements

We have an amended transportation precedent 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 commercial operation of Train 1 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 $1.1 million included in due to affiliate as of December 31, 2018 under the transportation agreement.

Contract for Sale and Purchase of Natural Gas

We have an agreement with CCP that allows us to sell and purchase natural gas with CCP. Natural gas purchased under this agreement is recorded as inventory, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process.

Operational Balancing Agreements

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, 2018 we had $6.2 million in accounts receivable—affiliate 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.

CCH Equity Contribution Agreements

CCH is expected to contribute a portion of the contributions received from the equity contribution agreements below, in addition to proceeds received from its debt obligations, to fund a portion of the costs associated with the development, construction, operation and maintenance of the Liquefaction Project.

S-19

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Equity Contribution Agreement

In May 2018, CCH 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, 2018, CCH had not received any contributions under the Equity Contribution Agreement. Cheniere will only be required to make additional contributions under the Equity Contribution Agreement after the commitments under its credit facility have been reduced to zero and to the extent cash flows from operations of the Liquefaction Project are unavailable for Liquefaction Project costs.

Early Works Equity Contribution Agreement

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

NOTE 10—INCOME TAXES

Income tax provision included in our reported net loss consisted of the following (in thousands): 

	Year Ended December 31,
	2018		2017		2016
Current:
Federal	$	—	$	—	$	—
State	144		—		—
Total current	144		—		—
Deferred:
Federal	—		—		—
State	—		—		—
Total deferred	—		—		—
Total income tax provision	$	144	$	—	$	—

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows: 

	Year Ended December 31,
	2018		2017		2016
U.S. federal statutory tax rate	21.0	%	35.0	%	35.0	%
State tax rate	(0.9	)%	—	%	—	%
U.S. tax reform rate change	—	%	(100.8	)%	—	%
Other	(0.7	)%	(0.5	)%	(0.1	)%
Valuation allowance	(20.6	)%	66.3	%	(34.9	)%
Effective tax rate	(1.2	)%	—	%	—	%

S-20

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Significant components of our deferred tax assets at December 31, 2018 and 2017 are as follows (in thousands):

	December 31,
	2018			2017
Deferred tax assets
Federal net operating loss carryforward	$	5,001		$	5,788
Property, plant and equipment	24,150			20,069
Other	—			327
Less: valuation allowance	(28,693		)	(26,184		)
Total deferred tax asset	458			—
Deferred tax liabilities
Other	(458		)	—
Total deferred tax liability	(458		)	—
Net deferred tax assets	$	—		$	—

At December 31, 2018, we had federal net operating loss (“NOL”) carryforwards of $23.8 million. These NOL carryforwards will expire between 2033 and 2037.

We did not have any uncertain tax positions which required accrual or disclosure as of December 31, 2018 and 2017. We have elected to report future interest and penalties related to unrecognized tax benefits, if any, as income tax expense in our Statements of Operations.

Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal deferred tax assets as of December 31, 2018 and 2017.  We will continue to evaluate the realizability of our deferred tax assets in the future. The increase in the valuation allowance was $2.5 million for the year ended December 31, 2018.

Our taxable income or loss is included in the consolidated federal income tax return of Cheniere. Cheniere’s federal and state tax returns for the years after 2014 remain open for examination. Tax authorities may have the ability to review and adjust carryover attributes that were generated prior to these periods if utilized in an open tax year.

Cheniere experienced an ownership change within the provisions of U.S. Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. Cheniere will continue to monitor trading activity in its respective shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize Cheniere’s existing NOL carryforwards.

NOTE 11—LEASES

During the years ended December 31, 2018, 2017 and 2016, we recognized rental expense for all operating leases of $1.5 million, $1.2 million and $1.0 million, respectively, related primarily to land sites for the Corpus Christi LNG terminal. We have agreements with Cheniere Land Holdings to lease land owned by Cheniere Land Holdings for the Liquefaction Project. See Note 9—Related Party Transactions for additional information regarding this lease agreement.

Future annual minimum lease payments, excluding inflationary adjustments, for operating leases are as follows (in thousands): 

Years Ending December 31,	Operating Leases (1)
2019	$	596
2020	1,225
2021	1,225
2022	1,225
2023	1,225
Thereafter	1,225
Total	$	6,721

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CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(1) Includes payments for certain non-lease components.

NOTE 12—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, 2018, 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 Stage 1 and Stage 2 of the Liquefaction Project. The EPC contract prices for Stage 1 of the Liquefaction Project and Stage 2 of the Liquefaction Project are approximately $7.8 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through December 31, 2018. 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 9—Related Party Transactions.

Obligations under Natural Gas Supply, Transportation and Storage Service Agreements

We primarily have index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The terms of these contracts range up to eight years, some of which commence upon the satisfaction of certain conditions precedent. As of December 31, 2018, we had secured up to approximately 2,801 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent are met.

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

As of December 31, 2018, 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)
2019	$	682,956
2020	613,700
2021	442,044
2022	254,572
2023	177,093
Thereafter	1,703,501
Total	$	3,873,866

(1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on prices and basis spreads as of December 31, 2018.

S-22

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Services Agreements

We have certain services agreements with affiliates. See Note 9—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere.  See Note 9—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 15—Guarantees 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. Additionally, we have various operating lease commitments, as disclosed in Note 11—Leases.

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, 2018, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2018		2017		2016
Noncash capital contribution for conveyance of property, plant and equipment from affiliate	$	82,299	$	—	$	—
Noncash capital contribution of NOL from affiliate	144		—		—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $168.9 million, $110.3 million and $59.4 million as of December 31, 2018, 2017 and 2016, respectively.

S-23

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 14—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of a recent accounting standard that had not been adopted by us as of December 31, 2018:

Standard	Description	Expected Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842)	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. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We will adopt this standard 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. The adoption of the standard will not have a material impact on our Financial Statements but will result in additional disclosures including the significant judgments and assumptions used in applying the standard.

Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period:

Standard	Description	Expected Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 8—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Financial Statements or related disclosures.

NOTE 15—GUARANTEES

The subsidiaries of CCH, including us, have jointly and severally guaranteed 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) a term loan facility of which CCH had approximately $981.7

S-24

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

million of available commitments and approximately $5.2 billion of outstanding borrowings as of December 31, 2018 and (5) a $1.2 billion working capital facility of which CCH had $716.5 million of available commitments and $168.0 million outstanding borrowings as of December 31, 2018. 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. As of December 31, 2018, there was no liability that was recorded related to these guarantees.

S-25

Cheniere Corpus Christi Pipeline, L.P.

Financial Statements

As of December 31, 2018 and 2017

and for the years ended December 31, 2018, 2017 and 2016

S-26

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, 2018 and the references to these entities used in these Financial Statements:

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

S-27

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, 2018 and 2017, and the related statements of operations, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in Note 2 to the financial statements, the Partnership has changed its method of accounting for revenue recognition in 2018, 2017 and 2016 due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

/s/    KPMG LLP

KPMG LLP

Houston, Texas

February 25, 2019

S-28

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

BALANCE SHEETS

(in thousands)

	December 31,
	2018		2017
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	—		—
Accounts receivable—affiliate	1,100		—
Advances to affiliate	15,592		20,072
Inventory	1,105		—
Operational balancing assets	6,106		—
Other current assets	216		11
Total current assets	24,119		20,083
Property, plant and equipment, net	376,658		350,258
Other non-current assets	3,790		270
Total assets	$	404,567	$	370,611
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	945	$	1,923
Accrued liabilities	12,033		24,785
Due to affiliates	1,679		2,048
Operational balancing liabilities—affiliate	6,189		—
Total current liabilities	20,846		28,756
Deferred tax liability	2,008		2,983
Commitments and contingencies (see Note 8)
Partners’ equity	381,713		338,872
Total liabilities and partners’ equity	$	404,567	$	370,611

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

S-29

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2018			2017			2016
Revenues—affiliate	$	1,559		$	—		$	—
Expenses
Operating and maintenance expense (recovery)	(2,185		)	16			22
Operating and maintenance expense—affiliate	9,315			82			15
General and administrative expense	718			234			295
General and administrative expense—affiliate	114			46			7
Depreciation and amortization expense	6,160			69			10
Impairment expense and loss on disposal of assets	—			5			—
Total expenses	14,122			452			349
Loss from operations	(12,563		)	(452		)	(349		)
Other income
Other income	7,912			15,575			—
Other income—affiliate	5			—			—
Total other income	7,917			15,575			—
Income (loss) before income taxes	(4,646		)	15,123			(349		)
Income tax benefit (provision)	975			(2,983		)	—
Net income (loss)	$	(3,671	)	$	12,140		$	(349	)

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

S-30

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, 2015	$	1	$	20,897		$	20,898
Capital contributions	—		102,680			102,680
Net loss	—		(349		)	(349		)
Balance at December 31, 2016	1		123,228			123,229
Capital contributions	—		203,660			203,660
Distributions	—		(157		)	(157		)
Net income	—		12,140			12,140
Balance at December 31, 2017	1		338,871			338,872
Capital contributions	—		47,907			47,907
Distributions	—		(1,395		)	(1,395		)
Net loss	—		(3,671		)	(3,671		)
Balance at December 31, 2018	$	1	$	381,712		$	381,713

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

S-31

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2018			2017			2016
Cash flows from operating activities
Net income (loss)	$	(3,671	)	$	12,140		$	(349	)
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization expense	6,160			69			10
Allowance for funds used during construction	(7,912		)	(15,575		)	—
Deferred income taxes	(975		)	2,983			—
Impairment expense and loss on disposal of assets	—			5			—
Changes in operating assets and liabilities:
Accounts receivable—affiliate	(1,100		)	—			—
Operational balancing assets	(6,106		)	—			—
Inventory	(1,105		)	—
Accounts payable and accrued liabilities	2,862			26			(75		)
Due to affiliates	989			6			(90		)
Operational balancing liabilities—affiliate	6,189			—			—
Advances to affiliate	(10,911		)	—			—
Other, net	(537		)	(157		)	(12		)
Net cash used in operating activities	(16,117		)	(503		)	(516		)
Cash flows from investing activities
Property, plant and equipment, net	(27,463		)	(203,000		)	(102,021		)
Other	(2,174		)	—			—
Net cash used in investing activities	(29,637		)	(203,000		)	(102,021		)
Cash flows from financing activities
Capital contributions	47,149			203,660			102,537
Distributions	(1,395		)	(157		)	—
Net cash provided by financing activities	45,754			203,503			102,537
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,
	2018		2017
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-32

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 developed by CCL (the “Liquefaction Facilities” and together with the Corpus Christi Pipeline, the “Liquefaction Project”) with several interstate and intrastate natural gas pipelines. The Liquefaction Project is being developed in stages with the first phase being three Trains (“Phase 1”), with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). Trains 1 and 2 are undergoing commissioning and Train 3 is under construction.

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.

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.

We have evaluated subsequent events through February 25, 2019, the date the Financial Statements were available to be issued.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto (“ASC 606”) using the full retrospective method. We have elected to adopt the new accounting standard retrospectively and have recast the accompanying financial statements to reflect the adoption of ASC 606 for all periods presented. The adoption of ASC 606 did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings.

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 property, plant and equipment, asset retirement obligations (“AROs”), income taxes including valuation allowances for deferred tax assets and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Revenue Recognition

We transport natural gas for shippers under a tariff regulated by the Federal Energy Regulatory Commission (“FERC”). The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the pipeline system. Our revenues are derived from agreements for the receipt and delivery of natural gas at points along the pipeline system as specified in each shipper’s individual transportation contract. See Note 5—Revenues from Contracts with Customers for further discussion of revenues.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Cash, Cash Equivalents and Restricted Cash

We did not have any cash and cash equivalents or restricted cash as of December 31, 2018, since our operations are funded through contributions from CCH.

Accounts Receivable

Accounts receivable is reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses. The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral. We did not recognize any impairment expense related to accounts receivable during the years ended December 31, 2018, 2017 and 2016.

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. 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 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 impairment expense and loss (gain) on disposal of assets. Substantially all of our long-lived assets are located in the United States.

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

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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.

Regulated Natural Gas Pipelines

The Corpus Christi Pipeline is subject to the jurisdiction of the Federal Energy Regulatory Commission (“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 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.

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction (“AFUDC”) represents the cost capitalized on debt funds related to the construction of long-lived assets. 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 $7.9 million, $15.6 million and zero for the years ended December 31, 2018, 2017 and 2016, 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.  The provision for income taxes, taxes payable and deferred income tax balances have been recorded as if we had filed all tax returns on a separate return basis from Cheniere. Deferred tax assets and liabilities are included in our Financial

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. This assessment requires significant judgment and is based upon our assessment of our ability to generate future taxable income among other factors.

Business Segment

Our pipeline business at the Corpus Christi LNG terminal 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, 2018 and 2017, property, plant and equipment, net consisted of the following (in thousands):

	December 31,
	2018			2017
Natural gas pipeline costs
Natural gas pipeline	$	369,653		$	—
Natural gas pipeline construction-in-process	9,022			346,526
Land	2,174			2,182
Accumulated depreciation	(5,726		)	—
Total natural gas pipeline costs	375,123			348,708
Fixed assets
Fixed assets	2,017			1,628
Accumulated depreciation	(482		)	(78		)
Total fixed assets, net	1,535			1,550
Property, plant and equipment, net	$	376,658		$	350,258

Depreciation expense was $6.1 million, $0.1 million and $10 thousand during the years ended December 31, 2018, 2017 and 2016, respectively.

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, 2018 and 2017, accrued liabilities consisted of the following (in thousands): 

	December 31,
	2018		2017
Pipeline costs	$	9,241	$	24,305
Other	2,792		480
Total accrued liabilities	$	12,033	$	24,785

NOTE 5—REVENUES FROM CONTRACTS WITH CUSTOMERS

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 commercial operation of Train 1 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. Upon the start of commercial operation of Train 1, CCL will pay 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.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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

Because our sales contract with CCL has a long-term duration, 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, 2018 and 2017:

	December 31, 2018			December 31, 2017
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
Revenues—affiliate	$	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.

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, 2018, 2017 and 2016 (in thousands):

	Year Ended December 31,
	2018		2017		2016
Revenues—affiliate
Transportation Agreements	$	1,556	$	—	$	—
Operational Balancing Agreement	3		—		—
Total revenues—affiliate	1,559		—		—
Operating and maintenance expense—affiliate
Services Agreements	3,114		70		3
Lease Agreements	12		12		12
Operational Balancing Agreement	6,189		—		—
Total operating and maintenance expense—affiliate	9,315		82		15
General and administrative expense—affiliate
Services Agreements	114		46		7
Other income—affiliate
Lease Agreements	5		—		—

We had $1.7 million and $2.0 million due to affiliates as of December 31, 2018 and 2017, respectively, under agreements with affiliates, as described below.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Services Agreements

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

We have an O&M Agreement with Cheniere LNG O&M Services, LLC (“O&M Services”) 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”) 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.

Lease Agreement

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, paid in advance upon 30 days of the effective date, is $12 thousand and is recorded as operating and maintenance expense—affiliate. 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.

Natural Gas Transportation Agreements

CCL has an amended 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. See Note 5—Revenues from Contracts with Customers for information regarding these agreements. We had $1.1 million of accounts receivable—affiliate as of December 31, 2018 under the transportation agreement.

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.

Operational Balancing Agreements

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, 2018 we had $6.2 million in operational balancing liabilities—affiliate 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

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after May 2015.

CCH Equity Contribution Agreements

CCH is expected to contribute a portion of the contributions received from the equity contribution agreements below, in addition to proceeds received from its debt obligations, to fund a portion of the costs associated with the development, construction, operation and maintenance of the Liquefaction Project.

Equity Contribution Agreement

In May 2018, CCH 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, 2018, CCH had not received any contributions under the Equity Contribution Agreement. Cheniere will only be required to make additional contributions under the Equity Contribution Agreement after the commitments under the CCH Credit Facility have been reduced to zero and to the extent cash flows from operations of the Liquefaction Project are unavailable for Liquefaction Project costs.

Early Works Equity Contribution Agreement

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

NOTE 7—INCOME TAXES

Income tax provision included in our reported net income (loss) consisted of the following (in thousands): 

	Year Ended December 31,
	2018			2017		2016
Current:
Federal	$	—		$	—	$	—
State	—			—		—
Total current	—			—		—
Deferred:
Federal	(975		)	2,983		—
State	—			—		—
Total deferred	(975		)	2,983		—
Total income tax provision (benefit)	$	(975	)	$	2,983	$	—

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows: 

	Year Ended December 31,
	2018		2017		2016
U.S. federal statutory tax rate	21.0	%	35.0	%	35.0	%
U.S. tax reform rate change	—	%	(13.2	)%	—	%
Other	—	%	—	%	(0.2	)%
Valuation allowance	—	%	(2.1	)%	(34.8	)%
Effective tax rate	21.0	%	19.7	%	—	%

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Significant components of our deferred tax assets and liabilities at December 31, 2018 and 2017 are as follows (in thousands):

	December 31,
	2018			2017
Deferred tax assets
Federal net operating loss carryforward	$	39,395		$	4
Property, plant and equipment	—			—
Less: valuation allowance	—			—
Total net deferred tax assets	39,395			4
Deferred tax liabilities
Property, plant and equipment	(41,362		)	(2,982		)
Other	(41		)	(5		)
Total deferred tax liabilities	(41,403		)	(2,987		)
Net deferred tax liabilities	$	(2,008	)	$	(2,983	)

At December 31, 2018, we had federal net operating loss (“NOL”) carryforwards of $187.6 million, of which$19 thousand will expire in 2037 and the remaining NOLs can be carried forward indefinitely.

We did not have any uncertain tax positions which required accrual or disclosure as of December 31, 2018 or 2017. We have elected to report future interest and penalties related to unrecognized tax benefits, if any, as income tax expense in our Statements of Operations.

Our taxable income or loss is included in the consolidated federal income tax return of Cheniere. Cheniere’s federal and state tax returns for the years after 2014 remain open for examination.

Cheniere experienced an ownership change within the provisions of U.S. Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. Cheniere will continue to monitor trading activity in its respective shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize Cheniere’s existing NOL carryforwards.

NOTE 8—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, 2018, 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 11—Guarantees for information regarding these guarantees.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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. Additionally, we have operating lease commitments with affiliates, as disclosed in Note 6—Related Party Transactions.

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, 2018, 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 9—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2018		2017		2016
Noncash capital contribution for conveyance of property, plant and equipment from affiliate	$	758	$	—	$	143

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $10.4 million, $28.5 million and $27.1 million as of December 31, 2018, 2017 and 2016, respectively.

NOTE 10—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of a recent accounting standard that had not been adopted by us as of December 31, 2018:

Standard	Description	Expected Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	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. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We will adopt this standard 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. The adoption of the standard will not have a material impact on our Financial Statements but will result in additional disclosures including the significant judgments and assumptions used in applying the standard.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period:

Standard	Description	Expected Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 5—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Financial Statements or related disclosures.

NOTE 11—GUARANTEES

The subsidiaries of CCH, including us, have jointly and severally guaranteed 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) a term loan facility of which CCH had approximately $981.7 million of available commitments and approximately $5.2 billion of outstanding borrowings as of December 31, 2018 and (5) a $1.2 billion working capital facility of which CCH had $716.5 million of available commitments and $168.0 million outstanding borrowings as of December 31, 2018. 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. As of December 31, 2018, there was no liability that was recorded related to these guarantees.

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Corpus Christi Pipeline GP, LLC

Financial Statements

As of December 31, 2018 and 2017

and for the years ended December 31, 2018, 2017 and 2016

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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, 2018 and the references to these entities used in these Financial Statements:

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

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Independent Auditors’ Report

To the Member

Corpus Christi Pipeline GP, LLC:

We have audited the accompanying financial statements of Corpus Christi Pipeline GP, LLC, which comprise the balance sheets as of December 31, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in accordance with U.S. generally accepted accounting principles.

/s/    KPMG LLP

KPMG LLP

Houston, Texas

February 25, 2019

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CORPUS CHRISTI PIPELINE GP, LLC

BALANCE SHEETS

	December 31,
	2018			2017
ASSETS
Cash and cash equivalents	$	—		$	—
Restricted cash	—			—
Receivable—affiliate	1,000			1,000
Total assets	$	1,000		$	1,000
LIABILITIES AND MEMBER’S EQUITY
Liabilities	$	—		$	—
Accrued liabilities	10,000			—
Total current liabilities	10,000			—
Member’s equity (deficit)	(9,000		)	1,000
Total liabilities and member’s equity (deficit)	$	1,000		$	1,000

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

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CORPUS CHRISTI PIPELINE GP, LLC

STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2018			2017			2016
Revenues	$	—		$	—		$	—
General and administrative expense	15,594			5,585			5,300
Net loss	$	(15,594	)	$	(5,585	)	$	(5,300	)

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

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CORPUS CHRISTI PIPELINE GP, LLC

STATEMENTS OF MEMBER'S EQUITY

	Cheniere Corpus Christi Holdings, LLC			Total Member’s Equity
Balance at December 31, 2015	$	1,000		$	1,000
Capital contributions	5,300			5,300
Net loss	(5,300		)	(5,300		)
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	)

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

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CORPUS CHRISTI PIPELINE GP, LLC

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2018			2017			2016
Cash flows from operating activities
Net loss	$	(15,594	)	$	(5,585	)	$	(5,300	)
Changes in operating assets and liabilities:
Accrued liabilities	10,000			—			—
Net cash used in operating activities	(5,594		)	(5,585		)	(5,300		)
Cash flows from investing activities	—			—			—
Cash flows from financing activities
Capital contributions	5,594			5,585			5,300
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,
	2018		2017
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 developed by CCL (the “Liquefaction Facilities” and together with the Corpus Christi Pipeline, the “Liquefaction Project”) with several interstate and intrastate natural gas pipelines. The Liquefaction Project is being developed in stages with the first phase being three Trains (“Phase 1”), with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). Trains 1 and 2 are undergoing commissioning and Train 3 is under construction.

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.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Financial Statements have been prepared in accordance with GAAP. We have evaluated subsequent events through February 25, 2019, the date the Financial Statements were available to be issued.

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 accounts receivable and income taxes including valuation allowances for deferred tax assets. 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, 2018, since 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.  The provision for income taxes, taxes payable and deferred income tax balances have been recorded as if we had filed all tax returns on a separate return basis from Cheniere. Deferred tax assets and liabilities are included in our Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the tax position.

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CORPUS CHRISTI PIPELINE GP, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 3—INCOME TAXES

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows: 

	Year Ended December 31,
	2018		2017		2016
U.S. federal statutory tax rate	21.0	%	35.0	%	35.0	%
U.S. tax reform rate change	—	%	(30.3	)%	—	%
Valuation allowance	(21.0	)%	(4.7	)%	(35.0	)%
Effective tax rate	—	%	—	%	—	%

Significant components of our deferred tax assets and liabilities at December 31, 2018 and 2017 are as follows:

	December 31,
	2018			2017
Deferred tax assets
Federal net operating loss carryforward	$	5,814		$	2,539
Less: valuation allowance	(5,814		)	(2,539		)
Total net deferred tax asset	$	—		$	—

At December 31, 2018, we had federal net operating loss (“NOL”) carryforwards of $27,686, of which $12,090 will expire between 2035 and 2037 and $15,595 will be carried forward indefinitely.

We did not have any uncertain tax positions which required accrual or disclosure as of December 31, 2018 or 2017. We have elected to report future interest and penalties related to unrecognized tax benefits, if any, as income tax expense in our Statements of Operations.

Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal net deferred tax assets as of December 31, 2018 and 2017.  We will continue to evaluate the realizability of our deferred tax assets in the future. The increase in the valuation allowance was $3,275 for the year ended December 31, 2018.

Our taxable income or loss is included in the consolidated federal income tax return of Cheniere. Cheniere’s federal and state tax returns for the years after 2014 remain open for examination.

Cheniere experienced an ownership change within the provisions of U.S. Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. Cheniere will continue to monitor trading activity in its respective shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize Cheniere’s existing NOL carryforwards.

NOTE 4—GUARANTEES

The subsidiaries of CCH, including us, have jointly and severally guaranteed 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) a term loan facility of which CCH had approximately $981.7 million of available commitments and approximately $5.2 billion of outstanding borrowings as of December 31, 2018 and (5) a $1.2 billion working capital facility of which CCH had $716.5 million of available commitments and $168.0 million outstanding borrowings as of December 31, 2018. 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. As of December 31, 2018, there was no liability that was recorded related to these guarantees.

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