Document

Description

Expected Date of Adoption

Effect on our Consolidated Financial Statements or Other Significant Matters

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

We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

10-K 1 cch2017form10-k.htm 10-K Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2017

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

For the transition period from to

Commission File No. 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 Exchange Act. Yes o No x

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 x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 Exchange Act. (Check one):



Large accelerated filer o	Accelerated filer o
Non-accelerated filer x (Do not check if a smaller reporting company)	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 Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange 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	10
Item 1B. Unresolved Staff Comments	23
Item 3. Legal Proceedings	23
Item 4. Mine Safety Disclosure	24
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6. Selected Financial Data	25
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	36
Item 8. Financial Statements and Supplementary Data	37
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	78
Signatures	79

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

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2017, 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.

iii

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

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


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


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


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


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


•	statements regarding the impact of the Tax Cuts and Jobs Act, including impact on deferred tax assets; 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,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” 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. 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.

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 a natural gas liquefaction and export facility (the “Liquefaction Facility”) and a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline” and together with the Liquefaction Facility, the “Liquefaction Project”) on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas, through wholly-owned subsidiaries CCL and CCP, respectively.

The Liquefaction Project is being developed in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, 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. The Liquefaction Project also includes the Corpus Christi Pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines. Stage 1 and the Corpus Christi Pipeline are currently under construction, and Train 3 is being commercialized and has all necessary regulatory approvals in place. Construction of the Corpus Christi Pipeline is nearing completion.

Our Business Strategy

Our primary objective for the Liquefaction Project is to generate steady and reliable revenues and operating cash flows by:


•	completing construction and commencing operation of the first three Trains and the Corpus Christi Pipeline on schedule and within budget;


•	operating and maintaining our assets safely, efficiently and reliably in compliance with all applicable government regulations;


•	developing a portfolio of natural gas supply and transportation agreements to support our LNG liquefaction operations;


•	making LNG available to our long-term SPA customers;


•	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. Substantially all of our long-lived assets are located in the United States. In December 2014, we 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 Stage 1 of the Liquefaction Project as of December 31, 2017:



	Stage 1
Overall project completion percentage	81.8%
Completion percentage of:
Engineering	100%
Procurement	100%
Subcontract work	62.2%
Construction	59.2%
Expected date of substantial completion	Train 1	1H 2019
	Train 2	2H 2019

(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 7 to 10 years from the date the order was issued.

Customers

CCL entered into eight fixed-price SPAs with terms of at least 20 years (plus extension rights) with seven third parties to make available an aggregate amount of LNG that is between approximately 85% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 and 2. Under these eight 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 price component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of Stage 1 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 Train 1 or Train 2, as specified in each SPA.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to $1.4 billion upon the date of first commercial delivery of Train 2 of the Liquefaction Project, with the applicable fixed fees generally starting from the date of first commercial delivery from the applicable Train.

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 and 2 of the Liquefaction Project are:


•	approximately $410 million from Endesa S.A.;


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


•	approximately $270 million from Gas Natural Fenosa LNG GOM, Limited, which is guaranteed by 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 and 2 of the Liquefaction Project is approximately $460 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 volatility 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. We expect to enter into gas supply contracts under these enabling agreements as and when required for the Liquefaction Project. As of December 31, 2017, CCL has secured up to approximately 2,024 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.

The total contract price of the EPC contract for Stage 1, which does not include the Corpus Christi Pipeline, is approximately $7.8 billion, reflecting amounts incurred under change orders through December 31, 2017. Total expected capital costs for Stage 1 and the Corpus Christi Pipeline are estimated to be between $9.0 billion and $10.0 billion before financing costs, and between $11.0 billion and $12.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies and total expected capital costs for the Corpus Christi Pipeline of between $350 million and $400 million. The total contract price of the EPC contract for Stage 2, which was amended and restated in December 2017, is approximately $2.4 billion.

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 is nearing completion.

Final Investment Decision on Stage 2

We will contemplate making a final investment decision (“FID”) to commence construction of Stage 2 of the Liquefaction Project based upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct the facility.

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 may increase the cost of constructing and operating the Liquefaction Project, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations. Any development of additional Trains, pipelines and other related facilities will require a similar permitting process.

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 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 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 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 (the “Court of Appeals”) 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.

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 $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation. In accordance with the EPAct, the FERC issued a final rule under the NGA making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement of material fact or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud or deceit upon any entity.

DOE Export Licenses

The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal as discussed in Our Liquefaction Project. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.

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, 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 and Hazardous Material Safety Administration

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, 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 require 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, the 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, the PHMSA issued a rule indefinitely delaying the effective date for the amendment to the regulation regarding post-construction inspections. These notices of proposed rulemaking are still pending at the PHMSA.

In May 2015, the 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, the 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, the 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, the PHMSA proposed 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 also proposed revisions to corrosion control requirements, as well as an expansion of the definition of regulated gathering lines. 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 Jobs Creation Act of 2011

The Corpus Christi Pipeline is also subject to the Pipeline Safety, Regulatory Certainty, and Jobs 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 is subject to 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 (the “CWA”)/ Section 10 of the Rivers and Harbors Act Permit (the “Section 10/404 Permit”), the Clean Air Act Title V (“Title V”) Operating Permit and the Prevention of Significant Deterioration (“PSD”) Permit, the latter two permits 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 submitted in August 2012. The process included a public comment period which commenced in May 2013 and closed in June 2013. The amended permit was issued by the USACE in July 2014 and subsequently modified in October 2014. CCL applied for new PSD and Title V permits with the TCEQ in August 2012. The TCEQ issued the PSD permit for criteria pollutants in September 2014, the PSD permit for greenhouse gases (“GHG”) in February 2015 and the Title V permit in July 2015. The PSD permit issued in September 2014 was altered in February 2015 to reflect CCL’s decision to change the emissions control technology on the refrigeration turbines from water- injected to dry low emission turbines. CCL has submitted an application to amend the PSD permit for criteria pollutants. The planned amendment would reflect updates related to refined operational direction and changes that were made during the design and procurement process. The amendment process is expected to include a public comment period.

In August 2012, CCP applied to the TCEQ for new PSD and Title V permits for the proposed compressor station at Sinton, Texas (the “Sinton Compressor Station”). The PSD permit for criteria pollutants at the Sinton Compressor Station was issued by the TCEQ in December 2013. In November 2014, the TCEQ approved an alteration to the permit to reflect that the Sinton Compressor Station is now considered a minor source, and voided the PSD permit number. The Title V permit for the Sinton Compressor Station was issued by the TCEQ in May 2015, however TCEQ voided the Title V Permit in October 2017 as the facility was no longer a major source.

CCL was issued a waste water discharge permit in January 2014 authorizing discharges from the Liquefaction Facility.

The Liquefaction Facility is subject to PHMSA safety regulations and standards for the transportation and storage of LNG and regulations of the U.S. Coast Guard relating to maritime safety and facility security.

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. As required by the Dodd-Frank Act, the CFTC, the SEC and other regulators have been promulgating rules and regulations implementing the regulatory provisions of the Dodd-Frank Act. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC continues to review and refine its rulemakings through additional interpretations and supplemental rulemakings.

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.

Under the Commodity Exchange Act as amended by the Dodd-Frank Act, the CFTC is directed generally to prevent manipulation of or fraud involving financial instruments, such as futures, options and swaps, on any commodity, including contracts for sale of physical commodities such as physical energy. 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. The Dodd-Frank Act’s swaps regulatory provisions and the related rules may adversely affect our existing derivative contracts and restrict our ability to monetize such contracts, cause us to restructure certain contracts, reduce the availability of derivatives to protect against risks or to optimize assets, increase the costs of entering into and maintaining swaps, adversely affect our ability to execute our hedging strategies and impact the liquidity of certain swaps products, all of which could increase our business costs.

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 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 (“EGUs”) 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. The October 2017 proposal does not include regulations to replace the Clean Power Plan and EPA stated in the October 2017 proposal that it has not determined whether it will issue replacement regulations to regulate GHG emissions from existing EGUs. 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”)

Our Liquefaction Facility is subject to review and regulation pursuant to the CZMA, which is applicable to the construction of facilities located within the coastal zone. 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 management and protection of the coastal areas.

Clean Water Act (“CWA”)

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

Resource Conservation and Recovery Act (“RCRA”)

The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. 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 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 the Liquefaction Project or the Corpus Cristi Pipeline may 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.

Market Factors

The Liquefaction Project currently does not experience competition with respect to Trains 1 and 2. We have entered into eight fixed price SPAs with terms of at least 20 years (plus extension rights) with seven 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 we need to replace any existing SPA or enter into new SPAs, we 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 has entered into six fixed price, 20-year third-party SPAs for the sale of LNG from 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 to 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 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 2016 and 2025, with LNG’s share growing from about 10% currently to about 15% of the global gas market. Wood Mackenzie forecasts that global demand for LNG will increase by 65%, from approximately 255 mtpa, or 12.2 Tcf, in 2016, to approximately 422 mtpa, or 20.3 Tcf, in 2025 and that LNG production from existing facilities and new facilities already under construction will be able to supply the market with approximately 386 mtpa in 2025, resulting in a market need for construction of additional facilities capable of producing an incremental 36.4 mtpa of LNG. We believe our new project that does not already have capacity sold under long-term contracts is competitive with new proposed projects globally and is well-positioned to capture a portion of this incremental market need.

Our LNG 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. To date, we have contracted an aggregate amount of LNG that is between approximately 85% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 and 2 of the Liquefaction Project with third-party customers. As of January 31, 2018, 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, 2018, Cheniere and its subsidiaries had 1,230 full-time employees, including 231 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. We electronically file our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports with the SEC. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers, like us, that file electronically with the SEC.


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 flow, liquidity and prospects.

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


•	Risks Relating to Our Financial Matters; and


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

Risks Relating to Our Financial Matters

Our existing level of cash resources, 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, 2017, we had zero cash and cash equivalents, $226.6 million of current restricted cash and $6.7 billion of total debt outstanding on a consolidated basis (before unamortized debt issuance costs), excluding $163.6 million of outstanding letters of credit. We incur, and will incur, significant interest expense relating to the assets at the Liquefaction Project, and we anticipate needing to incur additional debt to finance the construction of Train 3. 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 losses of $48.7 million, $85.5 million and $227.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. In addition, our net cash flow used in operating activities was $64.3 million, $41.1 million and $107.2 million for the years ended December 31, 2017, 2016 and 2015, 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 on the performance, upon satisfaction of the conditions precedent to payment thereunder, by six third-party customers that have entered into SPAs with us and agreed to pay us an aggregate of

approximately $1.4 billion annually in fixed fees upon the date of first commercial delivery of Train 2. We are dependent on each customer’s continued willingness and ability to perform its obligations under its SPA. We are exposed to the credit risk of any guarantor of these customers’ obligations under their respective SPA in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its SPA, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the SPA.

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

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

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

To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would 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. The CFTC also has adopted final rules regarding aggregation of positions that apply to futures on agricultural commodities, under which a party that controls the trading for the account of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions in all such controlled accounts and of all such controlled or owned parties with their own positions for purposes of determining compliance with position limits rules unless an exemption applies. 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 proposed 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.

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 Stage 1 and the Corpus Christi Pipeline 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 “2015 CCH Credit Facility”) and may not be able to complete construction of Stage 1 and the Corpus Christi Pipeline.

In May 2015, we entered into an equity contribution agreement with Cheniere (the “Equity Contribution Agreement”) pursuant to which Cheniere agreed to provide tiered equity contributions of approximately $2.6 billion for Stage 1 and the Corpus Christi Pipeline. The first tier of equity funding of approximately $1.5 billion (the “First Tier Equity Funding”) was contributed to us concurrently with the closing of the 2015 CCH Credit Facility. The second tier of equity funding, up to a maximum amount of approximately $1.1 billion, will be contributed concurrently and pro rata with funding under our project financing debt starting on the date on which further disbursements of such debt would result in a senior debt to equity ratio of greater than 75/25 (the “Second Tier Pro Rata Equity Funding”). As of December 31, 2017, we have received $1.9 billion in contributions under the Equity Contribution Agreement, of which approximately $1.5 billion was the First Tier Equity Funding and approximately $0.4 billion was part of the Second Tier Pro Rata Equity Funding.

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 2015 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 2015 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 the Stage 1 and the Corpus Christi Pipeline may cause a delay in development of our Trains and the Corpus Christi Pipeline and we may never be able to complete Stage 1 and the Corpus Christi Pipeline. 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 or the Corpus Christi Pipeline, 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.

Construction of Stage 2 will require significant financial resources and satisfaction of various other conditions. If we are unable to obtain sufficient financial resources to construct Stage 2 or satisfy the other conditions, including regulatory conditions, required to construct Stage 2, we may be unable to fully develop the Liquefaction Project and may suffer adverse consequences under certain existing contractual arrangements.

It is our current business plan to construct Stage 2 of the Liquefaction Project. On December 6, 2013, we entered into the EPC contract for Stage 2 which was amended and restated on December 12, 2017. The total contract price of the EPC contract for Stage 2 is approximately $2.4 billion. We also have obtained necessary regulatory approval for the construction and operation of Stage 2.

We need to meet significant additional conditions to construct Stage 2 as part of the Liquefaction Project, including regulatory conditions. The construction of Stage 2 as part of the Liquefaction Project will constitute an “Expansion” under the terms of our Common Terms Agreement and the CCH Indenture and would require us to meet certain conditions thereunder, including obtaining the consent of our senior lenders under the Common Terms Agreement and the demonstration of a fixed projected debt service coverage ratio of at least 1.40:1.00 under the CCH Indenture.

If we were to construct Stage 2, we estimate that total expected capital costs for Stage 2 would be between $2.0 billion and $4.0 billion, before financing costs, and between $3.0 billion and $5.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies. Accordingly, we will require significant debt and equity financing to be able to commence construction of Stage 2, which will depend in part on our ability to enter into additional SPAs for the sale of LNG.

In December 2017, we entered into an early works equity contribution agreement with Cheniere pursuant to which Cheniere is obligated to provide, directly or indirectly, at our request based on amounts due and payable in respect of limited notices to proceed issued under the Stage 2 EPC Contract, cash contributions of up to $310.0 million for the early works related to Stage 2. The amount of cash contributions Cheniere provides may be increased by Cheniere in its sole discretion. As of December 31, 2017, we have received $35.0 million in contributions from Cheniere under this agreement.

We can provide no assurances that we will be able to satisfy the applicable conditions under our Common Terms Agreement or the CCH Indenture with respect the construction of Stage 2. We may not be able to enter into additional SPAs or obtain debt and/or equity financing for the construction of Stage 2 on terms that result in positive economics to us, or at all. We also may not be able to obtain consent from the senior creditors under our Common Terms Agreement to proceed with the Stage 2 construction. Any of these events or an inability to meet other conditions applicable to the construction of Stage 2 would cause us not to be able to construct Stage 2 on a timely basis, or at all. Consequently, there is no assurance that we will ultimately construct Stage 2 and we may not have any revenues from LNG produced by Stage 2 or current or future SPAs related to LNG from Stage 2. Additionally, if we do not construct Stage 2 in a timely basis or at all, counterparties under our existing contracts related to Stage 2 could seek remedies if available under those contracts or be entitled to termination costs or fees. Any modifications to our existing contracts as a result of our failure to construct Stage 2 on a timely basis or at all could result in costs to us. For example, under the original EPC contract for Stage 2 prior to its amendment in December 2017, since we did not issue the full NTP under the contract by December 31, 2016, either party could have terminated the EPC contract for Stage 2, and CCL would have been required to reimburse Bechtel for costs reasonably incurred by Bechtel on account of such termination and pay a lump sum of $5 million.

In lieu of, or in addition to, Stage 2 or any subsequent stages or expansion of the Liquefaction Project, Cheniere or an affiliate of Cheniere may develop one or more Trains and related facilities adjacent to the Liquefaction Project as part of a separate

project that is not owned by us. In this case, we may transfer and/or amend previously-obtained permits and other authorizations or applications such that they may be used by that project. We also may enter into arrangements with such a separate project to share the use and capacity of each other’s land and facilities, including pooling of capacity of the 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 Finance Documents. These sharing arrangements would be subject to quiet enjoyment rights both for the Project Entities and the owner of the other Train(s). In order to undertake these facility sharing arrangements, we would need to satisfy certain conditions under the CCH Indenture.

Cost overruns and delays in the completion of one or more Trains or the Corpus Christi Pipeline, 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 or the Corpus Christi Pipeline 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. Cheniere does not have any prior experience in constructing liquefaction facilities other than the ongoing experience obtained in connection with the construction of Trains at Cheniere’s natural gas liquefaction facility at Sabine Pass (the “Sabine Pass Liquefaction Project”). Other than Trains 1 through 4 of the Sabine Pass Liquefaction Project, as of January 2018, no liquefaction facilities have been constructed and placed in service in the United States in over 40 years. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations.

Delays in the construction of one or more Trains or the Corpus Christi Pipeline 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 or the Corpus Christi Pipeline, 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 or the Corpus Christi Pipeline 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 provided under the agreement.

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

We currently have no revenues or 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 and 2 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 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. 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 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.

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 9.5mpta 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.

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

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, 2018, Cheniere and its subsidiaries had 1,230 full-time employees, including 231 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, 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;


•	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.

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 Trains1 and 2. 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;


•	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, including cyberterrorism, or military campaigns may adversely impact our business.

A terrorist, including a cyberterrorist, 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 may also result in temporary or permanent closure of existing LNG facilities, including the Liquefaction Project, 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, including cyberterrorism, 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 and regulations that regulate and restrict, among other things, discharges to air, land and water, with particular respect to the protection of the environment and natural resources; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances. 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 environmental laws and regulations authorize regulators having jurisdiction over the Corpus Christi LNG terminal 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 related to pollution control equipment 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. In March 2017, President Trump directed EPA via Executive Order to review and determine whether it is appropriate to revise or rescind the Clean Power Plan. 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. The October 2017 proposal does not include regulations to replace the Clean Power Plan and EPA stated in the October 2017 proposal that it has not determined whether it will issue replacement regulations to regulate GHG emissions from existing EGUs. 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, including a future replacement rule for the Clean Power Plan could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.

Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our 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.

Due to our lack of asset and geographic diversification, an adverse development at the Liquefaction Facility, 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.

U.S. federal income tax reform could adversely affect us.

On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was signed into law, significantly reforming the U.S. Internal Revenue Code. The TCJA, among other things, includes changes to U.S. federal tax rates, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, and imposes limitations on the use of net operating losses arising in taxable years beginning after December 31, 2017. The reduction of the U.S. corporate tax rate results in a decreased valuation of our deferred tax asset and liabilities. We continue to examine the impact the TCJA may have on our business. The estimated impact of the TCJA is based on our management’s current knowledge and assumptions and recognized impacts could be materially different from current estimates based on our actual results.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


ITEM 3.	LEGAL PROCEEDINGS

PHMSA Matter

In February 2018, PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (“the NOPV”) to CCP relating to a February 2017 inspection of the Corpus Christi Pipeline. The NOPV alleges 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 are currently reviewing the alleged violations and do not expect that the resolution of this matter will have a material adverse impact on our financial results or operations.


ITEM 4.	MINE SAFETY DISCLOSURE

Not applicable.

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,
	2017			2016			2015			2014			2013
Revenues	$	—		$	—		$	—		$	—		$	—
Loss from operations	(19,161		)	(6,472		)	(23,044		)	(38,235		)	(32,849		)
Other expense	(29,491		)	(79,015		)	(204,053		)	(368		)	(378		)
Net loss	(48,652		)	(85,487		)	(227,097		)	(38,603		)	(33,227		)



	December 31,
	2017		2016		2015		2014
Property, plant and equipment, net	$	8,261,383	$	6,076,672	$	3,924,551	$	44,173
Total assets	8,659,880		6,636,448		4,304,042		68,030
Long-term debt, net	6,669,476		5,081,715		2,713,000		—


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 a natural gas liquefaction and export facility (the “Liquefaction Facility”) and a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline” and together with the Liquefaction Facility, the “Liquefaction Project”) on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas, through wholly-owned subsidiaries CCL and CCP, respectively.

Overview of Significant Events

Our significant accomplishments since January 1, 2017 and through the filing date of this Form 10-K include the following:

Strategic


•	In February 2018, CCL entered into a 20-year SPA with PetroChina International Company Limited, a subsidiary of China National Petroleum Corporation (“CNPC”), for the sale of LNG beginning in 2023.


•	CCL entered into an amended and restated EPC contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for Stage 2 of the Liquefaction Project. CCL also issued limited notice to proceed to Bechtel, and procurement and early site work has commenced.

Financial


•	In May 2017, we issued an aggregate principal amount of $1.5 billion of 5.125% Senior Secured Notes due 2027 (the “2027 CCH Senior Notes”). Net proceeds of the offering of approximately $1.4 billion, after deducting commissions,

fees and expenses and after provisioning for incremental interest required under the 2027 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under our credit facility (the “2015 CCH Credit Facility”).

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at December 31, 2017 and 2016 (in thousands):



	December 31,
	2017		2016
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the Liquefaction Project	226,559		270,540
Available commitments under the following credit facilities:
2015 CCH Credit Facility	2,086,714		3,602,714
$350 million CCH Working Capital Facility (“CCH Working Capital Facility”)	186,422		350,000

For additional information regarding our debt agreements, see Note 7—Debt of our Notes to Consolidated Financial Statements.

Liquefaction Facilities

The Liquefaction Project is being developed and constructed at the Corpus Christi LNG terminal. In December 2014, we 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 Stage 1 of the Liquefaction Project as of December 31, 2017:



	Stage 1
Overall project completion percentage	81.8%
Completion percentage of:
Engineering	100%
Procurement	100%
Subcontract work	62.2%
Construction	59.2%
Expected date of substantial completion	Train 1	1H 2019
	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 7 to 10 years from the date the order was issued.

Customers

In aggregate, the fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to $1.4 billion upon the date of first commercial delivery of Train 2 of the Liquefaction Project, with the applicable fixed fees generally starting from the date of first commercial delivery from the applicable Train.

Natural Gas Transportation, Storage and Supply

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.

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 is nearing completion.

Final Investment Decision on Stage 2

We will contemplate making an FID to commence construction of Stage 2 of the Liquefaction Project based upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct the facility.

Capital Resources

We expect to finance the construction costs of the Liquefaction Project from one or more of the following: project debt and borrowings, operating cash flow from CCL and CCP and equity contributions from Cheniere. The following table provides a summary of our capital resources for the Liquefaction Project, excluding any equity contributions, at December 31, 2017 and 2016 (in thousands):



	December 31,
	2017		2016
Senior notes (1)	$	4,250,000	$	2,750,000
Credit facilities outstanding balance (2)	2,484,737		2,380,788
Letters of credit issued (2)	163,578		—
Available commitments under credit facilities (2)	2,273,136		3,952,714
Total capital resources from borrowings and available commitments	$	9,171,451	$	9,083,502


(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 2027 CCH Senior Notes (collectively, the “CCH Senior Notes”).


(2)	Includes 2015 CCH Credit Facility and CCH Working Capital Facility.

For additional information regarding our debt agreements related to the Liquefaction Project, see Note 7—Debt of our Notes to Consolidated Financial Statements.

CCH Senior Notes

In May 2017, we issued an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, in addition to the existing 2024 CCH Senior Notes and 2025 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.

2015 CCH Credit Facility

In May 2015, we entered into the 2015 CCH Credit Facility. Our obligations under the 2015 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, 2017 and 2016, we had $2.1 billion and $3.6 billion of available commitments and $2.5 billion and $2.4 billion of outstanding borrowings under the 2015 CCH Credit Facility, respectively.

The principal of the loans made under the 2015 CCH Credit Facility must be repaid in quarterly installments, commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following project completion and (2) a set date determined by reference to the date under which a certain LNG buyer linked to Train 2 of the Liquefaction Project 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 project completion and designed to achieve a minimum projected fixed debt service coverage ratio of 1.55:1.

Under the 2015 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 distributions under agreements governing our indebtedness generally until, among other requirements, the completion of the construction of Trains 1 and 2 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 December 2016, we entered into the $350 million CCH Working Capital Facility, which is intended to be used for loans (“CCH Working Capital Loans”), the issuance of letters of credit, as well as for swing line loans (“CCH Swing Line Loans”) for certain working capital requirements related to developing and placing into operation the Liquefaction Project. 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 under the Common Terms Agreement that was entered into concurrently with the 2015 CCH Credit Facility. We did not have any amounts outstanding under the CCH Working Capital Facility as of both December 31, 2017 and 2016 and $163.6 million and zero aggregate amount of letters of credit were issued as of December 31, 2017 and 2016, respectively.

The CCH Working Capital Facility matures on December 14, 2021, and we may prepay the CCH Working Capital Loans, CCH Swing Line 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. CCH Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the CCH Working Capital Facility, (2) the date that is 15 days after such CCH Swing Line Loan is made and (3) the first borrowing date for a CCH Working Capital Loan or CCH Swing Line Loan occurring at least four business days following the date the CCH Swing Line Loan is made. 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 our assets and the assets of the Guarantors as well as all of our membership interests and each of the Guarantors on a pari passu basis with the CCH Senior Notes and the 2015 CCH Credit Facility.

Equity Contribution Agreement

Early Works Equity Contribution Agreement

In December 2017, we entered into an early works equity contribution agreement with Cheniere pursuant to which Cheniere is obligated to provide, directly or indirectly, at our request based on amounts due and payable in respect of limited notices to proceed issued under the Stage 2 EPC Contract, cash contributions of up to $310.0 million to us for the early works related to Stage 2. The amount of cash contributions Cheniere provides may be increased by Cheniere in its sole discretion. As of December 31, 2017, we have received $35.0 million in contributions from Cheniere under this agreement.

Restrictive Debt Covenants

As of December 31, 2017, we were in compliance with all covenants related to our debt agreements.

Tax-Related Matters

On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. The reduction in the corporate tax rate will likely reduce our effective tax rate in future periods. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. The result of the remeasurement was a $58.9 million reduction to our U.S. net deferred tax assets and represents a 121.1% decrease to our effective tax rate. A corresponding change, reducing the effective tax rate, was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense.

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, 2017, 2016 and 2015 (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,
	2017			2016			2015
Operating cash flows	$	(64,316	)	$	(41,079	)	$	(107,202	)
Investing cash flows	(1,962,209		)	(2,095,897		)	(3,839,415		)
Financing cash flows	1,982,544			2,360,746			3,993,387

Net increase (decrease) in cash, cash equivalents and restricted cash	(43,981		)	223,770			46,770
Cash, cash equivalents and restricted cash—beginning of period	270,540			46,770			—
Cash, cash equivalents and restricted cash—end of period	$	226,559		$	270,540		$	46,770

Operating Cash Flows

Operating cash outflows during the years ended December 31, 2017, 2016 and 2015 were $64.3 million, $41.1 million and $107.2 million, respectively. The increase in operating cash outflows in 2017 compared to 2016 was primarily related to increased cash used for settlement of derivative instruments. The operating cash outflows in 2015 were higher than in 2016 primarily due to the payment of $50.1 million for contingency and syndication premiums upon meeting the contingency related to the interest rate swaps to hedge the exposure to volatility in portion of the floating-rate interest payments under the 2015 CCH Credit Facility (“Interest Rate Derivatives”) in May 2015, as well as interest payments related to the 2015 CCH Credit Facility.

Investing Cash Flows

Investing cash outflows during each of the years ended December 31, 2017, 2016 and 2015 were $2.0 billion, $2.1 billion and $3.8 billion, respectively, and are primarily used to fund the construction costs for Stage 1 of 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, we received $36.3 million during the year ended December 31, 2017 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 inflows during the year ended December 31, 2017 were $2.0 billion, primarily as a result of:


•	$1.5 billion of borrowings under the 2015 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 2015 CCH Credit Facility;


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


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


•	$402.1 million of equity contributions from Cheniere.

Financing cash inflows during the year ended December 31, 2016 were $2.4 billion, primarily as a result of:


•	$2.1 billion of borrowings under the 2015 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 2015 CCH Credit Facility; and


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

Financing cash inflows during the year ended December 31, 2015 were $4.0 billion, primarily as a result of:


•	$2.7 billion of borrowings under the 2015 CCH Credit Facility;


•	$0.3 billion of debt issuance costs related to up-front fees paid upon the closing of the 2015 CCH Credit Facility; and


•	$1.6 billion of equity contributions from Cheniere.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2017 (in thousands):



	Payments Due By Period (1)
	Total		2018		2019 - 2020		2021 - 2022		Thereafter
Debt (2)	$	6,734,737	$	—	$	—	$	2,484,737	$	4,250,000
Interest payments (2)	2,476,865		372,651		750,493		678,252		675,469
Construction obligations (3)	1,203,076		831,636		371,440		—		—
Purchase obligations (4)	24,352		22,936		1,416		—		—
Operating lease obligations (5)	1,981		895		1,086		—		—
Obligations to affiliates (6)	1,098		357		654		87		—
Other obligations (7)	120,915		3,000		36,493		53,989		27,433
Total	$	10,563,024	$	1,231,475	$	1,161,582	$	3,217,065	$	4,952,902


(1)	Agreements in force as of December 31, 2017 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2017.


(2)	Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2017. See Note 7—Debt of our Notes to Consolidated Financial Statements.

(3)

Construction obligations primarily relate to the EPC contracts for the Liquefaction Project. The estimated remaining cost pursuant to our EPC contracts as of December 31, 2017 is included for Trains with respect to which we have made an FID to commence construction; the EPC contract termination amount is included for Trains with respect to which we have not made an FID. A discussion of these obligations can be found at Note 11—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 maintenance contracts and purchase of spare parts 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 10—Leases of our Notes to Consolidated Financial Statements.


(6)	Obligations to affiliates relate to land leased from Cheniere Land Holdings, LLC, a wholly owned subsidiary of Cheniere, for the Liquefaction Project.


(7)	Other obligations primarily relate to agreements with certain local taxing jurisdictions, and are based on estimated tax obligations as of December 31, 2017.

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, 2017, we had $163.6 million aggregate amount of issued letters of credit under the CCH Working Capital Facility and $226.6 million of current restricted cash. For more information, see Note 3—Restricted Cash of our Notes to Consolidated Financial Statements.

Results of Operations

Our consolidated net loss was $48.7 million in the year ended December 31, 2017, compared to a net loss of $85.5 million in the year ended December 31, 2016. This $36.8 million decrease in net loss in 2017 was primarily a result of decreased loss on early extinguishment of debt and decreased derivative loss, net associated with interest rate derivative activity.

Our consolidated net loss was $227.1 million in the year ended December 31, 2015. This $141.6 million decrease in net loss in 2016 compared to 2015 was primarily a result of decreased derivative loss, net and decreased interest expense, net of amounts capitalized, which were partially offset by increased loss on early extinguishment of debt.

In August 2017, Hurricane Harvey struck the Texas and Louisiana coasts, and the Corpus Christi LNG terminal experienced a temporary suspension in construction. The terminal did not sustain significant damage, and the effects of Hurricane Harvey did not have a material impact on our Consolidated Financial Statements.

Loss from operations



	Year Ended December 31,
(in thousands)	2017			2016			Change			2015			Change
Revenues	$	—		$	—		$	—		$	—		$	—

Operating and maintenance expense	3,115			1,372			1,743			572			800
Operating and maintenance expense—affiliate	2,401			95			2,306			—			95
Development expense (recovery)	516			(81		)	597			13,690			(13,771		)
Development expense (recovery)—affiliate	8			(10		)	18			5,525			(5,535		)
General and administrative expense	5,551			4,240			1,311			3,189			1,051
General and administrative expense—affiliate	1,173			607			566			13			594
Depreciation and amortization expense	892			249			643			55			194
Impairment expense and loss on disposal of assets	5,505			—			5,505			—			—

Loss from operations	$	(19,161	)	$	(6,472	)	$	(12,689	)	$	(23,044	)	$	(16,572	)

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 operating and maintenance expense and general and administrative expense from increased professional fees and labor costs.

2016 vs. 2015

Our loss from operations decreased $16.6 million during the year ended December 31, 2017 from the year ended December 31, 2016 primarily as a result of decreased development expenses from decreased professional fees and labor costs.

Other expense (income)



	Year Ended December 31,
(in thousands)	2017			2016		Change			2015			Change
Interest expense, net of capitalized interest	$	—		$	—	$	—		$	25,680		$	(25,680	)
Loss on early extinguishment of debt	32,480			63,318		(30,838		)	16,498			46,820
Derivative loss (gain), net	(3,249		)	15,571		(18,820		)	161,917			(146,346		)
Other expense (income)	260			126		134			(42		)	168
Total other expense (income)	$	29,491		$	79,015	$	(49,524	)	$	204,053		$	(125,038	)

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 recognized in 2017 was attributable to the write-offs of debt issuance costs of $32.5 million in May 2017 upon the prepayment of approximately $1.4 billion of outstanding borrowings under the 2015 CCH Credit Facility in connection with the issuance of the 2027 CCH Senior Notes. 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 2015 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 a $13.0 million loss in May 2017 upon the settlement of interest rate swaps associated with approximately $1.4 billion of commitments that were terminated under the 2015 CCH Credit Facility.

2016 vs. 2015

Interest expense, net of capitalized interest, decreased from $25.7 million in the year ended December 31, 2015 to zero in the year ended December 31, 2016 as we were able to capitalize total interest expense, which was directly related to the construction of the Liquefaction Project.

Loss on early extinguishment of debt increased during the year ended December 31, 2016, as compared to the year ended December 31, 2015. Loss on early extinguishment of debt during the year ended December 31, 2015 was attributable to $16.5 million associated with the termination of a portion of the original commitments under the 2015 CCH Credit Facility.

Derivative loss, net decreased during the year ended December 31, 2016, as compared to the year ended December 31, 2015, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods. Included in derivative loss, net recognized during the year ended December 31, 2015 was a $50.1 million loss recognized upon meeting the contingency related to the Interest Rate Derivatives.

Off-Balance Sheet Arrangements

As of December 31, 2017, 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 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 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 index-based physical commodity contracts is developed through the use of internal models which may be impacted by inputs that are 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.

Impairment of Long-Lived Assets

A long-lived asset, including an intangible asset, is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may not be recoverable. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We use a variety of fair value measurement approaches when market information for the same or similar assets does not exist. Projections of future operating results and cash flows may vary significantly from results. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

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, 2017 and 2016. 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 9—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 13—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 to secure natural gas feedstock for 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, 2017					December 31, 2016
	Fair Value			Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(91	)	$	10	$	—	$	—

Interest Rate Risk

We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 CCH Credit Facility. 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, 2017					December 31, 2016
	Fair Value			Change in Fair Value		Fair Value			Change in Fair Value
Interest Rate Derivatives	$	(32,258	)	$	43,994	$	(86,488	)	$	52,047

See Note 5—Derivative Instruments for additional details about our derivative instruments.


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	38
Report of Independent Registered Public Accounting Firm	39
Consolidated Balance Sheets	40
Consolidated Statements of Operations	41
Consolidated Statements of Member’s Equity	42
Consolidated Statements of Cash Flows	43
Notes to Consolidated Financial Statements	44
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	70

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, 2017, 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)

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, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

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

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

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

/s/ KPMG LLP

KPMG LLP

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

Houston, Texas

February 20, 2018

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)



	December 31,
	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	226,559		197,201
Advances to affiliate	31,486		20,108
Other current assets	1,494		37,195
Other current assets—affiliate	190		141
Total current assets	259,729		254,645

Non-current restricted cash	—		73,339
Property, plant and equipment, net	8,261,383		6,076,672
Debt issuance and deferred financing costs, net	98,175		155,847
Non-current advances under long-term contracts	—		46,398
Other non-current assets, net	40,593		29,547
Total assets	$	8,659,880	$	6,636,448

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	6,461	$	9,120
Accrued liabilities	258,060		137,648
Due to affiliates	23,789		7,050
Derivative liabilities	19,609		43,383
Total current liabilities	307,919		197,201

Long-term debt, net	6,669,476		5,081,715
Non-current derivative liabilities	15,209		43,105
Other non-current liabilities—affiliate	—		618

Commitments and contingencies (see Note 11)

Member’s equity	1,667,276		1,313,809
Total liabilities and member’s equity	$	8,659,880	$	6,636,448

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

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)



	Year Ended December 31,
	2017			2016			2015
Revenues	$	—		$	—		$	—

Expenses
Operating and maintenance expense	3,115			1,372			572
Operating and maintenance expense—affiliate	2,401			95			—
Development expense (recovery)	516			(81		)	13,690
Development expense (recovery)—affiliate	8			(10		)	5,525
General and administrative expense	5,551			4,240			3,189
General and administrative expense—affiliate	1,173			607			13
Depreciation and amortization expense	892			249			55
Impairment expense and loss on disposal of assets	5,505			—			—
Total expenses	19,161			6,472			23,044

Loss from operations	(19,161		)	(6,472		)	(23,044		)

Other income (expense)
Interest expense, net of capitalized interest	—			—			(25,680		)
Loss on early extinguishment of debt	(32,480		)	(63,318		)	(16,498		)
Derivative gain (loss), net	3,249			(15,571		)	(161,917		)
Other income (expense)	(260		)	(126		)	42
Total other expense	(29,491		)	(79,015		)	(204,053		)

Net loss	$	(48,652	)	$	(85,487	)	$	(227,097	)

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

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, 2014	$	65,532		$	65,532
Capital contributions	1,560,915			1,560,915
Net loss	(227,097		)	(227,097		)
Balance at December 31, 2015	1,399,350			1,399,350
Capital contributions	91			91
Noncash capital contribution from affiliate	143			143
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

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

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities
Net loss	$	(48,652	)	$	(85,487	)	$	(227,097	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization expense	892			249			55
Amortization of debt issuance costs, net of capitalization	—			—			6,340
Loss on early extinguishment of debt	32,480			63,318			16,498
Total losses (gains) on derivatives, net	(3,158		)	15,571			161,917
Net cash used for settlement of derivative instruments	(50,981		)	(34,082		)	(56,918		)
Impairment expense and loss on disposal of assets	5,505			—			—
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities	152			415			1,002
Due to affiliates	1,567			(331		)	275
Advances to affiliate	—			—			(10,073		)
Other, net	(1,454		)	(745		)	301
Other, net—affiliate	(667		)	13			498
Net cash used in operating activities	(64,316		)	(41,079		)	(107,202		)

Cash flows from investing activities
Property, plant and equipment, net	(1,987,254		)	(2,051,530		)	(3,820,947		)
Other	25,045			(44,367		)	(18,468		)
Net cash used in investing activities	(1,962,209		)	(2,095,897		)	(3,839,415		)

Cash flows from financing activities
Proceeds from issuances of debt	3,040,000			4,838,000			2,713,000
Repayments of debt	(1,436,050		)	(2,420,212		)	—
Debt issuance and deferred financing costs	(23,496		)	(56,783		)	(280,528		)
Capital contributions	402,119			91			1,560,915
Distributions	—			(288		)	—
Other	(29		)	(62		)	—
Net cash provided by financing activities	1,982,544			2,360,746			3,993,387

Net increase (decrease) in cash, cash equivalents and restricted cash	(43,981		)	223,770			46,770
Cash, cash equivalents and restricted cash—beginning of period	270,540			46,770			—
Cash, cash equivalents and restricted cash—end of period	$	226,559		$	270,540		$	46,770

Balances per Consolidated Balance Sheets:



	December 31,
	2017		2016
Cash and cash equivalents	$	—	$	—
Restricted cash	226,559		197,201
Non-current restricted cash	—		73,339
Total cash, cash equivalents and restricted cash	$	226,559	$	270,540

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

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 a natural gas liquefaction and export facility at the Corpus Christi LNG terminal (the “Liquefaction Facility”), which is on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas, and a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline” and together with the Liquefaction Facility, the “Liquefaction Project”) through wholly owned subsidiaries CCL and CCP, respectively. The Liquefaction Project is being developed in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, 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. Stage 1 and the Corpus Christi Pipeline are currently under construction, and Train 3 is being commercialized and has all necessary regulatory approvals in place. Construction of the Corpus Christi Pipeline is nearing completion.

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.

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 value 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.

Recurring fair-value measurements are performed for interest rate derivatives as disclosed in Note 5—Derivative Instruments. The carrying amount of restricted cash and accounts payable reported on the Consolidated Balance Sheets approximates fair value. Debt fair values, as disclosed in Note 7—Debt, is the estimated amount we would have to pay to repurchase our debt in the open market, and are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs.

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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.

Accounting for LNG Activities

Generally, we begin capitalizing the costs of our LNG terminal and related 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 LNG terminal and related 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 lease is obtained, the costs are expensed.

We capitalize interest and other related debt costs during the construction period of our LNG terminal and related pipeline. Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset.

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. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. 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 other operating costs and expenses. 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 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, 2016 or 2015.

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 deferred

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

preliminary survey and investigation costs, 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. 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 instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. See Note 5—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. 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 eight fixed price SPAs with terms of at least 20 years with seven 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 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 net of unamortized debt issuance costs related to term notes. Debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the extinguishment of debt on our Consolidated Statements of Operations.

Debt issuance and deferred financing costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. Debt issuance 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 along with deferred financing costs. Debt issuance and deferred financing 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 early 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 is conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our assessment of AROs is described below.

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

Income Taxes

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

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, 2017 and 2016, restricted cash consisted of the following (in thousands):



	December 31,
	2017		2016
Current restricted cash
Liquefaction Project	$	226,559	$	197,201

Non-current restricted cash
Liquefaction Project	$	—	$	73,339

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—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in thousands):



	December 31,
	2017			2016
LNG terminal costs
LNG terminal construction-in-process	$	8,242,520		$	6,060,299
LNG site and related costs	13,844			14,006
Total LNG terminal costs	8,256,364			6,074,305
Fixed assets
Fixed assets	6,042			2,620
Accumulated depreciation	(1,023		)	(253		)
Total fixed assets, net	5,019			2,367
Property, plant and equipment, net	$	8,261,383		$	6,076,672

Depreciation expense was $0.8 million, $0.2 million and $0.1 million in the years ended December 31, 2017, 2016 and 2015, respectively.

Fixed Assets

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 5—DERIVATIVE INSTRUMENTS

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


•	interest rate swaps (“Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable-rate interest payments on our credit facility (the “2015 CCH Credit Facility”) and


•	natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“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.

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Interest Rate Derivatives

As of December 31, 2017, 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

$4.9 billion

May 20, 2015

May 31, 2022

2.29%

One-month LIBOR

Our Interest Rate Derivatives are categorized within Level 2 of the fair value hierarchy and are required to be measured at fair value on a recurring basis. 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.

In May 2017, we settled a portion of our Interest Rate Derivatives and recognized a derivative loss of $13.0 million in conjunction with the termination of approximately $1.4 billion of commitments under the 2015 CCH Credit Facility, as discussed in Note 7—Debt.

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



	December 31,
Balance Sheet Location	2017			2016
Non-current derivative assets	$	2,469		$	—

Derivative liabilities	(19,609		)	(43,383		)
Non-current derivative liabilities	(15,118		)	(43,105		)
Total derivative liabilities	(34,727		)	(86,488		)

Derivative liability, net	$	(32,258	)	$	(86,488	)

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, 2017, 2016 and 2015 (in thousands):



	Year Ended December 31,
	2017		2016			2015
Interest Rate Derivatives gain (loss)	$	3,249	$	(15,571	)	$	(161,917	)

Liquefaction Supply Derivatives

CCL entered into all of its Liquefaction Supply Derivatives during the year ended December 31, 2017. The fair value of the Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of any 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.

CCL has entered into index-based physical natural gas supply contracts to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the physical natural gas supply contracts range from approximately three to seven years, most of which commence upon the satisfaction of certain conditions precedent, if applicable, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The curves used to generate the fair value of the 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 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, 2017, some of the Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow. As of December 31, 2017, CCL had secured up to approximately 2,024 TBtu of natural gas feedstock through natural gas supply contracts supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent. The forward notional natural gas buy position of the Liquefaction Supply Derivatives was approximately 1,019 TBtu as of December 31, 2017.

The Level 3 fair value measurements of our 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 portfolio. The following table includes quantitative information for the unobservable inputs for our Liquefaction Supply Derivatives as of December 31, 2017:



	Net Fair Value Liability (in thousands)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Liquefaction Supply Derivatives	$(91)	Market approach incorporating present value techniques	Basis Spread	$(0.703) - $(0.002)

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.

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



	December 31,
Balance Sheet Location	2017			2016
Non-current derivative liabilities	$	(91	)	$	—

The following table shows the changes in the fair value from the mark-to-market gains of our Liquefaction Supply Derivatives recorded in our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in thousands):



		Year Ended December 31,
	Statement of Operations Location	2017		2016		2015
Liquefaction Supply Derivatives loss	Operating and maintenance expense	$	91	$	—	$	—

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
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		)
As of December 31, 2016
Interest Rate Derivatives	(95,923		)	9,435			(86,488		)

NOTE 6—ACCRUED LIABILITIES

As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in thousands):



	December 31,
	2017		2016
Interest costs and related debt fees	$	136,283	$	59,994
Liquefaction Project costs	107,055		73,150
Other	14,722		4,504
Total accrued liabilities	$	258,060	$	137,648

NOTE 7—DEBT

As of December 31, 2017 and 2016, our debt consisted of the following (in thousands):



	December 31,
	2017			2016
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			—
2015 CCH Credit Facility	2,484,737			2,380,788
Unamortized debt issuance costs	(65,261		)	(49,073		)
Total long-term debt, net	6,669,476			5,081,715

Current debt
$350 million CCH Working Capital Facility (“CCH Working Capital Facility”)	—			—
Total debt, net	$	6,669,476		$	5,081,715

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, 2017 (in thousands):



Years Ending December 31,	Principal Payments
2018	$	—
2019	—
2020	—
2021	—
2022	2,484,737
Thereafter	4,250,000
Total	$	6,734,737

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Senior Notes

In May 2017, we issued an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, which are jointly and severally guaranteed by our subsidiaries CCL, CCP and CCP GP (each a “Guarantor” and collectively, the “Guarantors”). Net proceeds of the offering of approximately $1.4 billion, after deducting commissions, fees and expenses and provisioning for incremental interest required under the 2027 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the 2015 CCH Credit Facility, resulting in a write-off of debt issuance costs associated with the 2015 CCH Credit Facility of $32.5 million during the year ended December 31, 2017. Borrowings under the 2027 CCH Senior Notes accrue interest at a fixed rate of 5.125%.

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”) contains customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s 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 CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s 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 CCH and its 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, CCH 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. CCH 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, 2017 (in thousands):



	2015 CCH Credit Facility		CCH Working Capital Facility
Original facility size	$	8,403,714	$	350,000
Less:
Outstanding balance	2,484,737		—
Commitments terminated	3,832,263		—
Letters of credit issued	—		163,578
Available commitment	$	2,086,714	$	186,422

Interest rate	LIBOR plus 2.25% or base rate plus 1.25% (1)		LIBOR plus 1.50% - 2.00% or base rate plus 0.50% - 1.00%
Maturity date	Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date		December 14, 2021, with various terms for underlying loans


(1)	There is a 0.25% step-up for both LIBOR and base rate loans following the completion of Trains 1 and 2 of the Liquefaction Project as defined in the common terms agreement.

2015 CCH Credit Facility

In May 2015, we entered into the 2015 CCH Credit Facility, which is being used to fund a portion of the costs associated with the development, construction, operation and maintenance of Stage 1 of the Liquefaction Project. Borrowings under the 2015 CCH Credit Facility may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred.

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Loans under the 2015 CCH Credit Facility accrue interest at a variable rate per annum equal to, at our election, LIBOR or the base rate, plus the applicable margin. The applicable margins for LIBOR loans are 2.25% prior to completion of Trains 1 and 2 of the Liquefaction Project and 2.50% on completion and thereafter. The applicable margins for base rate loans are 1.25% prior to completion of Trains 1 and 2 of the Liquefaction Project and 1.50% on completion and thereafter. 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 2015 CCH Credit Facility also requires us to pay a commitment fee at a rate per annum equal to 40% of the margin for LIBOR loans, multiplied by the outstanding undrawn debt commitments.

Our obligations under the 2015 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.

CCH Working Capital Facility

Loans under the CCH Working Capital Facility, including CCH Working Capital Loans, CCH Swing Line 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 federal funds rate, plus 0.50%, (2) the prime rate and (3) one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR Revolving Loans ranges from 1.50% to 2.00% per annum, and the applicable margin for base rate Revolving Loans ranges from 0.50% to 1.00% per annum. Interest on CCH Working Capital Loans, CCH Swing Line Loans and CCH LC 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 without giving effect to any outstanding CCH Swing Line Loans, (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 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 an 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.

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The CCH Working Capital Facility matures on December 14, 2021, 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. CCH Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the CCH Working Capital Facility, (2) the date that is 15 days after such CCH Swing Line Loan is made and (3) the first borrowing date for a CCH Working Capital Loan or CCH Swing Line Loan occurring at least four business days following the date the CCH Swing Line Loan is made. 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 Guarantors as well as all of our membership interests and each of the Guarantors on a pari passu basis with the CCH Senior Notes and the 2015 CCH Credit Facility.

Restrictive Debt Covenants

As of December 31, 2017, 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,
	2017			2016			2015
Total interest cost	$	360,932		$	221,865		$	110,156
Capitalized interest, including amounts capitalized as AFUDC	(360,932		)	(221,865		)	(84,476		)
Total interest expense, net	$	—		$	—		$	25,680

Fair Value Disclosures

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



	December 31, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	4,250,000	$	4,590,625	$	2,750,000	$	2,901,563
Credit facilities (2)	2,484,737		2,484,737		2,380,788		2,380,788


(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 2015 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 8—RELATED PARTY TRANSACTIONS

We had $23.8 million and $7.1 million due to affiliates and zero and $0.6 million of other non-current liabilities—affiliate as of December 31, 2017 and 2016, respectively, under agreements with affiliates, as described below.

LNG Sale and Purchase Agreements

CCL had two fixed price 20-year SPAs with Cheniere Marketing International LLP (“Cheniere Marketing”) as of December 31, 2017. The first SPA (the “Cheniere Marketing Base SPA”) 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 Facility that is not committed to customers under third-party SPAs or to Cheniere

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Marketing under the second SPA (the “Amended Cheniere Marketing Foundation SPA”), as determined by CCL in each contract year, in each case for a price consisting of a fixed fee of $3.00 per MMBtu of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. 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.

Under the Amended Cheniere Marketing Foundation SPA Cheniere Marketing was allowed to purchase LNG from CCL for a price consisting of a fixed fee of $3.50 per MMBtu (a portion of which is subject to annual adjustment for inflation) of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. The Amended Cheniere Marketing Foundation SPA commencement date, at the option of Cheniere Marketing, was the date of first commercial delivery for Train 2 and included an annual contract quantity of 40 TBtu of LNG. The Amended Cheniere Marketing Foundation SPA was terminated in January 2018.

Services Agreements

We recorded aggregate expenses from affiliates on our Consolidated Statements of Operations of $3.3 million, $0.6 million and $5.5 million for the years ended December 31, 2017, 2016 and 2015, respectively, under the services agreements below.

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 Facility, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facility, for services performed while the Liquefaction Facility 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 Facility. 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 and other services required to operate and maintain the Liquefaction Facility. Prior to the substantial completion of each Train of the Liquefaction Facility, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facility, for services performed while the Liquefaction Facility 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 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 Facility, 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 Facility and obtaining insurance. Prior to the substantial completion of each Train of the Liquefaction Facility, no monthly fee payment is required except for reimbursement of expenses. After substantial completion of each Train, CCL will pay, in addition

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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.

Lease Agreements

CCL has agreements with Cheniere Land Holdings, LLC (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, to lease approximately 60 acres of land owned by Cheniere Land Holdings for the Liquefaction Facility. The total annual lease payment, paid in advance upon 30 days of the effective date of the respective leases, is $0.4 million, and the terms of the agreements range from three to five years. We recorded $0.3 million, $0.1 million and zero of lease expense related to these agreements as operating and maintenance expense—affiliate for the years ended December 31, 2017, 2016 and 2015, respectively. We had $0.2 million and $0.1 million as of December 31, 2017 and 2016, respectively, of prepaid expense related to this agreement in other current assets—affiliate.

In September 2016, CCP entered into a pipeline right of way easement agreement with Cheniere Land Holdings granting CCP the right to construct, install and operate a natural gas pipeline on land owned by Cheniere Land Holdings. Under this agreement, Cheniere Land Holdings conveyed to CCP $0.1 million of assets during the year ended December 31, 2016. CCP also made a one-time payment of $0.3 million to Cheniere Land Holdings for the permanent easement of this land as of December 31, 2016.

Dredge Material Disposal Agreement

CCL has a dredge material disposal agreement with Cheniere Land Holdings that terminates in 2025 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 Facility. 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.

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 Facility 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

We have an equity contribution agreement with Cheniere pursuant to which Cheniere has agreed to provide, directly or indirectly, at our request based on reaching specified milestones of the Liquefaction Project, cash contributions up to approximately $2.6 billion for Stage 1. As of December 31, 2017, we have received $1.9 billion in contributions from Cheniere under this agreement.

Early Works Equity Contribution Agreement

In December 2017, we entered into an early works equity contribution agreement with Cheniere pursuant to which Cheniere is obligated to provide, directly or indirectly, at our request based on amounts due and payable in respect of limited notices to proceed issued under the Stage 2 EPC Contract, cash contributions of up to $310.0 million to us for the early works related to Stage 2. The amount of cash contributions Cheniere provides may be increased by Cheniere in its sole discretion. As of December 31, 2017, we have received $35.0 million in contributions from Cheniere under this agreement.

NOTE 9—INCOME TAXES

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



	Year Ended December 31,
	2017		2016		2015
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
U.S. tax reform rate change	(121.1	)%	—	%	—	%
Other	(0.2	)%	—	%	—	%
Valuation allowance	86.3	%	(35.0	)%	(35.0	)%
Effective tax rate	—	%	—	%	—	%

Significant components of our deferred tax assets at December 31, 2017 and 2016 are as follows (in thousands):



	December 31,
	2017			2016
Deferred tax assets
Federal net operating loss carryforward	$	49,194		$	53,618
Derivative instruments	15,487			46,754
Long-term debt	14,270			15,953
Property, plant and equipment	9,143			13,680
Other	303			393
Less: valuation allowance	(88,397		)	(130,398		)
Total net deferred tax asset	$	—		$	—

At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of approximately $234 million. These NOL carryforwards will expire between 2035 and 2037.

We did not have any uncertain tax positions which required accrual or disclosure as of December 31, 2017 and 2016. 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, 2017 and 2016. We will continue to evaluate the realizability of our deferred tax assets in the future. The decrease in the valuation allowance was $41.4 million for the year ended December 31, 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. The result of the remeasurement was a $58.9 million reduction to our U.S. net deferred tax assets and represents a 121.1% decrease to our effective tax rate. A corresponding change, reducing the effective tax rate, was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense.

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 2013 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. An analysis of the annual limitation on the utilization of Cheniere’s NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of Cheniere’s NOLs in full over the carryover period. 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 10—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $1.2 million, $1.0 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 8—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
2018	$	895
2019	841
2020	245
2021	—
2022	—
Thereafter	—
Total	$	1,981

NOTE 11—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, 2017, 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 three Trains and related facilities for the Liquefaction Project. The EPC contract for Stage 2 or the Liquefaction Project was amended and restated in December 31, 2017. 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, 2017. CCL has the right to terminate each of the EPC contracts for its convenience, in which case Bechtel will be paid the portion of the contract price for the work performed plus costs reasonably incurred by Bechtel on account of such termination and demobilization. If the EPC contract for Stage 1 of the Liquefaction Project is terminated, Bechtel will also be paid a lump sum of up to $30.0 million depending on the termination date. If the amended and restated EPC contract for Stage 2 of the Liquefaction Project is terminated, Bechtel will be paid a lump sum of up to $2.5 million if the termination date

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

is prior to the issuance of the notice to proceed, or Bechtel will be paid a lump sum of up to $30.0 million if the termination date is after the issuance of the notice to proceed, 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 8—Related Party Transactions.

Services Agreements

CCL and CCP have certain services agreements with affiliates. See Note 8—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 8—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 and meet the definition of a commitment as of December 31, 2017. Additionally, we have various operating lease commitments, as disclosed in Note 10—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, 2017, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

NOTE 12—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Year Ended December 31,
	2017		2016		2015
Cash paid during the period for interest, net of amounts capitalized	$	—	$	—	$	17,456
Noncash capital contribution for conveyance of asset from affiliate	—		143		—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $274.3 million, $145.6 million and $81.1 million as of December 31, 2017, 2016 and 2015 respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 13—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:



Standard	Description	Expected 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 will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard.
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 continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we expect that the requirement to recognize all leases on our Consolidated Balance Sheets will be a significant change from current practice but will not have a material impact upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 14—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 7—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, 2017.



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
Investments in subsidiaries	7,648,111		—		(7,648,111		)	—
Other non-current assets, net	2,469		38,124		—			40,593
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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Condensed Consolidating Balance Sheet
December 31, 2016
(in thousands)

	Parent Issuer		Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—		$	—
Restricted cash	197,201		—		—			197,201
Advances to affiliate	—		20,108		—			20,108
Other current assets	152		37,043		—			37,195
Other current assets—affiliate	—		142		(1		)	141
Total current assets	197,353		57,293		(1		)	254,645

Non-current restricted cash	73,339		—		—			73,339
Property, plant and equipment, net	306,342		5,770,330		—			6,076,672
Debt issuance and deferred financing costs, net	155,847		—		—			155,847
Investments in subsidiaries	5,927,833		—		(5,927,833		)	—
Non-current advances under long-term contracts	—		46,398		—			46,398
Other non-current assets, net	50		29,497		—			29,547
Total assets	$	6,660,764	$	5,903,518	$	(5,927,834	)	$	6,636,448

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	332	$	8,788	$	—		$	9,120
Accrued liabilities	61,328		76,320		—			137,648
Due to affiliates	—		7,050		—			7,050
Derivative liabilities	43,383		—		—			43,383
Total current liabilities	105,043		92,158		—			197,201

Long-term debt, net	5,081,715		—		—			5,081,715
Non-current derivative liabilities	43,105		—		—			43,105
Other non-current liabilities—affiliate	—		618		—			618

Member’s equity	1,430,901		5,810,742		(5,927,834		)	1,313,809
Total liabilities and member’s equity	$	6,660,764	$	5,903,518	$	(5,927,834	)	$	6,636,448

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 early 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	)

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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 early 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	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Condensed Consolidating Statement of Operations
Year Ended December 31, 2015
(in thousands)

	Parent Issuer			Guarantors			Eliminations		Consolidated

Revenues	$	—		$	—		$	—	$	—

Expenses
Operating and maintenance expense	—			572			—		572
Development expense	—			13,690			—		13,690
Development expense—affiliate	—			5,525			—		5,525
General and administrative expense	724			2,465			—		3,189
General and administrative expense—affiliate	—			13			—		13
Depreciation and amortization expense	—			55			—		55
Total expenses	724			22,320			—		23,044

Loss from operations	(724		)	(22,320		)	—		(23,044		)

Other income (expense)
Interest expense, net of capitalized interest	(25,680		)	—			—		(25,680		)
Loss on early extinguishment of debt	(16,498		)	—			—		(16,498		)
Derivative loss, net	(161,917		)	—			—		(161,917		)
Other income	36			6			—		42
Total other income (expense)	(204,059		)	6			—		(204,053		)

Net loss	$	(204,783	)	$	(22,314	)	$	—	$	(227,097	)

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 from operating activities
Net loss	$	(30,869	)	$	(5,191	)	$	(12,592	)	$	(48,652	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization expense	13			879			—			892
Allowance for funds used during construction	—			(15,575		)	15,575			—
Deferred income taxes	—			2,983			(2,983		)	—
Loss on early extinguishment of debt	32,480			—			—			32,480
Total losses (gains) on derivatives, net	(3,249		)	91			—			(3,158		)
Net cash used for settlement of derivative instruments	(50,981		)	—			—			(50,981		)
Impairment expense and loss on disposal of assets	—			5,505			—			5,505
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities	68			84			—			152
Due to affiliates	—			1,567			—			1,567
Other, net	(95		)	(1,359		)	—			(1,454		)
Other, net—affiliate	—			(667		)	—			(667		)
Net cash 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		)
Capital contributions	402,119			1,720,437			(1,720,437		)	402,119
Distributions	—			(157		)	157			—
Other	(29		)	—			—			(29		)
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

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 from operating activities
Net loss	$	(79,729	)	$	(5,758	)	$	—		$	(85,487	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization expense	—			249			—			249
Loss on early extinguishment of debt	63,318			—			—			63,318
Total losses on derivatives, net	15,571			—			—			15,571
Net cash used for settlement of derivative instruments	(34,082		)	—			—			(34,082		)
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities	121			294			—			415
Due to affiliates	—			(331		)	—			(331		)
Other, net	(153		)	(592		)	—			(745		)
Other, net—affiliate	—			13			—			13
Net cash 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		)
Capital contributions	90			1,975,475			(1,975,474		)	91
Distribution to affiliate	(288		)	—			—			(288		)
Other	(62		)	—			—			(62		)
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

Balances per Condensed Consolidating Balance Sheet:



	December 31, 2016
	Parent Issuer		Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—
Restricted cash	197,201		—		—		197,201
Non-current restricted cash	73,339		—		—		73,339
Total cash, cash equivalents and restricted cash	$	270,540	$	—	$	—	$	270,540

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2015
(in thousands)

	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows from operating activities
Net loss	$	(204,783	)	$	(22,314	)	$	—		$	(227,097	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization expense	—			55			—			55
Amortization of debt issuance costs, net of capitalization	6,340			—			—			6,340
Loss on early extinguishment of debt	16,498			—			—			16,498
Total losses on derivatives, net	161,917			—			—			161,917
Net cash used for settlement of derivative instruments	(56,918		)	—			—			(56,918		)
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities	453			549			—			1,002
Due to affiliates	(860		)	1,135			—			275
Advances to affiliate	—			(10,073		)	—			(10,073		)
Other, net	—			301			—			301
Other, net—affiliate	—			498			—			498
Net cash used in operating activities	(77,353		)	(29,849		)	—			(107,202		)

Cash flows from investing activities
Property, plant and equipment, net	(63,783		)	(3,757,164		)	—			(3,820,947		)
Investments in subsidiaries	(3,804,848		)	—			3,804,848			—
Other	(633		)	(17,835		)	—			(18,468		)
Net cash used in investing activities	(3,869,264		)	(3,774,999		)	3,804,848			(3,839,415		)

Cash flows from financing activities
Proceeds from issuances of long-term debt	2,713,000			—			—			2,713,000
Debt issuance and deferred financing costs	(280,528		)	—			—			(280,528		)
Capital contributions	1,560,915			3,804,848			(3,804,848		)	1,560,915
Net cash provided by financing activities	3,993,387			3,804,848			(3,804,848		)	3,993,387

Net increase in cash, cash equivalents and restricted cash	46,770			—			—			46,770
Cash, cash equivalents and restricted cash—beginning of period	—			—			—			—
Cash, cash equivalents and restricted cash—end of period	$	46,770		$	—		$	—		$	46,770

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

Year ended December 31, 2016:
Revenues	$	—		$	—		$	—		$	—
Loss from operations	(733		)	(1,672		)	(1,809		)	(2,258		)
Net income (loss)	(160,884		)	(106,585		)	18,230			163,752


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 Securities Exchange Act of 1934, as amended (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, 2017, 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 38 and is incorporated herein by reference.


ITEM 9B.	OTHER INFORMATION

None.

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, 2017 and 2016. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 2017 and 2016 (in thousands):



	Fiscal 2017		Fiscal 2016
Audit Fees	$	1,050	$	1,070
Tax Fees	89		29
Total	$	1,139	$	1,099

Audit Fees—Audit fees for 2017 and 2016 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 2017 and 2016.

Tax Fees—Tax fees for 2017 and 2016 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 2017 and 2016.

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, 2017 and 2016.

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	38
Report of Independent Registered Public Accounting Firm	39
Consolidated Balance Sheets	40
Consolidated Statements of Operations	41
Consolidated Statements of Member’s Equity	42
Consolidated Statements of Cash Flows	43
Notes to Consolidated Financial Statements	44
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)



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		Corpus Christi Liquefied Natural Gas Project Term Loan Facility Agreement, dated May 13, 2015, among the Company, as Borrower, CCL, CCP, and CCP GP, as Guarantors, Term Lenders party thereto from time to time, and Société Générale, as Term Loan Facility Agent (Incorporated by reference to Exhibit 10.4 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 13, 2015)
10.2		Common Security and Account Agreement, dated May 13, 2015, among the Company, as Company, CCL, CCP, and CCP GP, as Guarantors, the Senior Creditor Group Representatives party thereto from time to time, Société Générale, as Intercreditor Agent and Security Trustee, and Mizuho Bank, Ltd., as Account Bank (Incorporated by reference to Exhibit 10.2 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 13, 2015)
10.3		Consent for Amendment to the Common Security and Account Agreement, dated September 7, 2017, among the Company, as Company, CCL, CCP, and CCP GP, as Guarantors, the Senior Creditor Group Representatives party thereto from time to time, Société Générale, as Intercreditor Agent and Security Trustee, and Mizuho Bank, Ltd., as Account Bank (Incorporated by reference to Exhibit 10.51 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-221307), filed on November 2, 2017)
10.4		Common Terms Agreement, dated May 13, 2015, among the Company, as Borrower, CCL, CCP, and CCP GP, as Guarantors, Société Générale, as Term Loan Facility Agent and Intercreditor Agent and any other facility agents party thereto from time to time (Incorporated by reference to Exhibit 10.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 13, 2015)
10.5		Consent for Amendment to the Common Terms Agreement, dated September 7, 2017, among the Company, as Borrower, CCL, CCP, and CCP GP, as Guarantors, Société Générale, as Term Loan Facility Agent and Intercreditor Agent and any other facility agents party thereto from time to time (Incorporated by reference to Exhibit 10.52 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-221307), filed on November 2, 2017)
10.6		Equity Contribution Agreement, dated May 13, 2015, among the Company and Cheniere (Incorporated by reference to Exhibit 10.5 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 13, 2015)



Exhibit No.		Description
10.7		Working Capital Facility Agreement, dated as of December 14, 2016, among CCH, as Borrower, CCL, CCP, and CCP GP, as Guarantors, The Bank of Nova Scotia, as Working Capital Facility Agent, The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation, as Issuing Banks, Mizuho Bank, Ltd., as Swing Line Lender, and the lenders party thereto from time to time (Incorporated by reference to Exhibit 10.1 to the Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 20, 2016)
10.8		First Amendment to Working Capital Facility Agreement, dated December 20, 2016, among CCH, as Borrower, CCL, CCP, and CCP GP, as Guarantors, The Bank of Nova Scotia, as Working Capital Facility Agent, The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation, as Issuing Banks, Mizuho Bank, Ltd., as Swing Line Lender, and the lenders party thereto from time to time (Incorporated by reference to Exhibit 10.42 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
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)



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)



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*		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.)
10.24		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)
10.25		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)
10.26		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)
10.27		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)
10.28		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)
10.29		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)
10.30		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)
10.31		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)
10.32		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)
10.33		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)
10.34		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)
10.35		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)



Exhibit No.		Description
10.36		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)
10.37		Amended and Restated Foundation Customer LNG Sale and Purchase Agreement (FOB), dated as of November 28, 2014, between CCL and Cheniere Marketing International LLP (Incorporated by reference to Exhibit 10.35 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.38		Amendment No. 1, dated June 26, 2015, to Amended and Restated Foundation Customer LNG Sale and Purchase Agreement (FOB), dated as of November 28, 2014, between CCL and Cheniere Marketing International LLP (Incorporated by reference to Exhibit 10.36 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.39		Amendment No. 2, dated December 27, 2016, to Amended and Restated Foundation Customer LNG Sale and Purchase Agreement (FOB), dated as of November 28, 2014, between CCL and Cheniere Marketing LLP (Incorporated by reference to Exhibit 10.37 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017)
10.40		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)
10.41		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)
10.42		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.

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 20, 2018

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 20, 2018
Michael J. Wortley		February 20, 2018

/s/ Doug Shanda	Manager	February 20, 2018
Doug Shanda	Manager	February 20, 2018

/s/ Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 20, 2018
Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 20, 2018

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-20
Independent Auditors’ Report	S-22
Balance Sheets	S-23
Statements of Operations	S-24
Statements of Partners’ Equity	S-25
Statements of Cash Flows	S-26
Notes to Financial Statements	S-27

AUDITED FINANCIAL STATEMENTS OF CORPUS CHRISTI PIPELINE GP, LLC	S-36
Independent Auditors’ Report	S-38
Balance Sheets	S-39
Statements of Operations	S-40
Statements of Member’s Equity	S-41
Statements of Cash Flows	S-42
Notes to Financial Statements	S-43

S-1

Corpus Christi Liquefaction, LLC

Financial Statements

As of December 31, 2017 and 2016

and for the years ended December 31, 2017, 2016 and 2015

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



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

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2017 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, which comprise the balance sheets as of December 31, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in accordance with U.S. generally accepted accounting principles.

/s/ KPMG LLP

KPMG LLP

Houston, Texas

February 20, 2018

S-4

CORPUS CHRISTI LIQUEFACTION, LLC

BALANCE SHEETS

(in thousands)



	December 31,
	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	—		—
Advances to affiliate	11,414		2,184
Other current assets	1,237		37,014
Other current assets—affiliate	190		141
Total current assets	12,841		39,339

Property, plant and equipment, net	7,259,438		5,640,973
Non-current advances under long-term contracts	—		46,398
Other non-current assets, net	37,854		26,285
Total assets	$	7,310,133	$	5,752,995

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	4,456	$	1,105
Accrued liabilities	96,886		57,924
Due to affiliates	21,741		5,836
Total current liabilities	123,083		64,865

Non-current derivative liabilities	91		—
Other non-current liabilities—affiliate	—		618

Commitments and contingencies (see Note 8)

Member’s equity	7,186,959		5,687,512
Total liabilities and member’s equity	$	7,310,133	$	5,752,995

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,
	2017			2016			2015

Revenues	$	—		$	—		$	—

Expenses
Operating and maintenance expense	3,099			1,350			572
Operating and maintenance expense—affiliate	2,331			92			—
Development expense (recovery)	516			(81		)	13,690
Development expense (recovery)—affiliate	8			(10		)	5,525
General and administrative expense	3,951			3,231			2,353
General and administrative expense—affiliate	1,127			600			—
Depreciation and amortization expense	810			239			55
Impairment expense and loss on disposal of assets	5,500			—			—
Total expenses	17,342			5,421			22,195

Loss from operations	(17,342		)	(5,421		)	(22,195		)

Other income
Other income	5			5			6
Other income—affiliate	12			12			—
Total other income	17			17			6

Net loss	$	(17,325	)	$	(5,404	)	$	(22,189	)

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, 2014	$	51,921		$	51,921
Capital contributions	3,790,251			3,790,251
Net loss	(22,189		)	(22,189		)
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

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,
	2017			2016			2015
Cash flows from operating activities
Net loss	$	(17,325	)	$	(5,404	)	$	(22,189	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization expense	810			239			55
Total losses on derivatives, net	91			—			—
Impairment expense and loss on disposal of assets	5,500			—			—
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities	58			369			529
Due to affiliates	1,561			(241		)	1,139
Advances to affiliate	—			—			(3,122		)
Other, net	(1,202		)	(580		)	430
Other, net—affiliate	(667		)	13			498
Net cash used in operating activities	(11,174		)	(5,604		)	(22,660		)

Cash flows from investing activities
Property, plant and equipment, net	(1,530,642		)	(1,822,962		)	(3,753,264		)
Other	25,045			(44,367		)	(14,327		)
Net cash used in investing activities	(1,505,597		)	(1,867,329		)	(3,767,591		)

Cash flows from financing activities
Capital contributions	1,516,771			1,872,933			3,790,251
Net cash provided by financing activities	1,516,771			1,872,933			3,790,251

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,
	2017		2016
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-8

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

CCL is a Delaware limited liability company formed by Cheniere in 2011 to own, develop and operate a natural gas liquefaction and export facility at the Corpus Christi LNG terminal, which is on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas (the “Liquefaction Facility”). CCP is developing a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline” and together with the Liquefaction Facility, the “Liquefaction Project”) that will interconnect the Liquefaction Facility with several interstate and intrastate natural gas pipelines. The Liquefaction Project is being developed in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, 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, which is being constructed concurrently with the Corpus Christi Pipeline, 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 currently under construction, Train 3 is being commercialized and has all necessary regulatory approvals in place and the Corpus Christi Pipeline is nearing completion.

NOTE 2—BASIS OF PRESENTATION AND 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 20, 2018, 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 value 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

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 4—Derivative Instruments. The carrying amount of accounts payable reported on the Balance Sheets approximates fair value.

Cash, Cash Equivalents and Restricted Cash

We did not have any cash and cash equivalents or restricted cash as of December 31, 2017, since our operations are funded through contributions from CCH.

S-9

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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.

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 other operating costs and expenses. 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 are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. 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, 2016 or 2015.

Derivative Instruments

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 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, 2017, 2016 and 2015. See Note 4—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. 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 eight fixed price SPAs with terms of at least 20 years with seven unaffiliated third parties. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.

S-10

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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.

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.

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in thousands):



	December 31,
	2017			2016
LNG terminal costs
LNG terminal construction-in-process	$	7,244,447		$	5,628,320
LNG site and related costs	11,662			11,662
Total LNG terminal costs	7,256,109			5,639,982
Fixed assets
Fixed assets	4,261			1,234
Accumulated depreciation	(932		)	(243		)
Total fixed assets, net	3,329			991
Property, plant and equipment, net	$	7,259,438		$	5,640,973

Depreciation expense during the years ended December 31, 2017, 2016 and 2015 was $0.7 million, $0.2 million and $0.1 million, respectively.

Fixed Assets

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—DERIVATIVE INSTRUMENTS

During the year ended December 31, 2017, we entered into all of our commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). The Liquefaction Supply Derivatives are not 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.

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. The fair value of the Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of any associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is

S-11

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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. The terms of the physical natural gas supply contracts range from approximately three to seven years, most of which commence upon the satisfaction of certain conditions precedent, if applicable, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.

Our Liquefaction Supply Derivatives are categorized within Level 3 of the fair value hierarchy and are required to be measured at fair value on a recurring basis. The fair value of our Liquefaction Supply Derivatives is determined using a market-based approach incorporating present value techniques, as needed, and 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 the 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 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, 2017, we have secured up to approximately 2,024 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent. The forward notional natural gas buy position of the Liquefaction Supply Derivatives was approximately 1,019 TBtu as of December 31, 2017.



	Net Fair Value Liability (in thousands)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Liquefaction Supply Derivatives	$(91)	Market approach incorporating present value techniques	Basis Spread	$(0.703) - $(0.002)

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



	December 31,
Balance Sheet Location	2017			2016
Non-current derivative liabilities	$	(91	)	$	—

The following table shows the changes in the fair value from the mark-to-market losses of our Liquefaction Supply Derivatives recorded in our Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in thousands):



		Year Ended December 31,
	Statement of Operations Location	2017		2016		2015
Liquefaction Supply Derivatives loss	Operating and maintenance expense	$	91	$	—	$	—

S-12

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 Liquefaction Supply 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)	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets		Net Amounts Presented in the Balance Sheets
As of December 31, 2017
Liquefaction Supply Derivatives	$	(130	)	$	39	$	(91	)
As of December 31, 2016
Liquefaction Supply Derivatives	—			—		—

NOTE 5—RELATED PARTY TRANSACTIONS

We had $21.7 million and $5.8 million due to affiliates and zero and $0.6 million of other non-current liabilities—affiliate as of December 31, 2017 and 2016, respectively, under agreements with affiliates, as described below.

LNG Sale and Purchase Agreements

We had two fixed price 20-year SPAs with Cheniere Marketing International LLP (“Cheniere Marketing”) as of December 31, 2017. The first SPA (the “Cheniere Marketing Base SPA”) 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 Facility that is not committed to customers under third-party SPAs or to Cheniere Marketing under the second SPA (the “Amended Cheniere Marketing Foundation SPA”), as determined by us in each contract year, in each case for a price consisting of a fixed fee of $3.00 per MMBtu of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. 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.

Under the Amended Cheniere Marketing Foundation SPA Cheniere Marketing was allowed to purchase LNG from us for a price consisting of a fixed fee of $3.50 per MMBtu (a portion of which is subject to annual adjustment for inflation) of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. The Amended Cheniere Marketing Foundation SPA commencement date, at the option of Cheniere Marketing, was the date of first commercial delivery for Train 2 and included an annual contract quantity of 40 TBtu of LNG. The Amended Cheniere Marketing Foundation SPA was terminated in January 2018.

Services Agreements

We recorded aggregate expenses from affiliates on our Statements of Operations of $3.1 million, $0.6 million and $5.5 million for the years ended December 31, 2017, 2016 and 2015, respectively, under the services agreements below.

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 Facility, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facility, for services performed while the Liquefaction Facility 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.

S-13

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 Facility. 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 and other services required to operate and maintain the Liquefaction Facility. Prior to the substantial completion of each Train of the Liquefaction Facility, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facility, for services performed while the Liquefaction Facility 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 Facility, 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 Facility and obtaining insurance. Prior to the substantial completion of each Train of the Liquefaction Facility, 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.

Lease Agreements

We have agreements with Cheniere Land Holdings, LLC (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, to lease approximately 60 acres of land owned by Cheniere Land Holdings for the Liquefaction Facility. The total annual lease payment, paid in advance of the effective date of the respective leases, is $0.4 million, and the terms of the agreements range from three to five years. We recorded $0.3 million, $1.0 million and zero of lease expense related to these agreements as operating and maintenance expense—affiliate for the years ended December 31, 2017, 2016 and 2015, respectively. We had $0.2 million and $0.1 million as of December 31, 2017 and 2016, respectively, of prepaid expense related to this agreement in other current assets—affiliate.

In September 2016, we entered into an agreement with CCP to lease a portion of the Liquefaction Facility site for the purpose of the construction and operation of a meter station to measure the amount of natural gas delivered to the Liquefaction Facility. 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 entered into 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 Facility site. CCP made a one-time payment of $0.1 million to us for the permanent easement of this land as of December 31, 2016, which was recorded in capital contributions on our Statements of Partners’ Equity.

Dredge Material Disposal Agreement

We have a dredge material disposal agreement with Cheniere Land Holdings that terminates in 2025 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 Facility. 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.

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 Facility 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.

S-14

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Transportation Precedent Agreement (“TPA”)

We have an amended TPA 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 Facility. Subject to receipt of certain authorizations, under the TPA, CCP agrees to construct and place into service a pipeline, add compression, and provide interconnections to the Liquefaction Facility. We also have a firm transportation service agreement with CCP and a negotiated rate agreement (collectively, the “FTSA”). CCP has agreed to provide us, and we agree to receive from CCP, firm transportation services pursuant to the FTSA.

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.

CCH Equity Contribution Agreement

CCH has an equity contribution agreement with Cheniere (the “CCH Equity Contribution Agreement”) pursuant to which Cheniere has agreed to provide, directly or indirectly, at CCH’s request based on reaching specified milestones of the Liquefaction Project, cash contributions up to approximately $2.6 billion for Stage 1. As of December 31, 2017, CCH had received $1.9 billion in contributions from Cheniere under this agreement.

CCH Early Works Equity Contribution Agreement

In December 2017, CCH entered into an early works equity contribution agreement with Cheniere pursuant to which Cheniere is obligated to provide, directly or indirectly, at CCH’s request based on amounts due and payable in respect of limited notices to proceed issued under the Stage 2 EPC Contract, cash contributions of up to $310.0 million to CCH for the early works related to Stage 2. The amount of cash contributions Cheniere provides may be increased by Cheniere in its sole discretion. As of December 31, 2017, CCH had received $35.0 million in contributions from Cheniere under this agreement.

NOTE 6—INCOME TAXES

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



	Year Ended December 31,
	2017		2016		2015
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
U.S. tax reform rate change	(100.8	)%	—	%	—	%
Other	(0.5	)%	(0.1	)%	—	%
Valuation allowance	66.3	%	(34.9	)%	(35.0	)%
Effective tax rate	—	%	—	%	—	%

S-15

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Significant components of our deferred tax assets at December 31, 2017 and 2016 are as follows (in thousands):



	December 31,
	2017			2016
Deferred tax assets
Federal net operating loss carryforward	$	5,788		$	7,721
Property, plant and equipment	20,069			29,560
Other	327			394
Less: valuation allowance	(26,184		)	(37,675		)
Total net deferred tax asset	$	—		$	—

At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of approximately $28 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, 2017 or 2016. 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, 2017 and 2016. We will continue to evaluate the realizability of our deferred tax assets in the future. The decrease in the valuation allowance was $11.5 million for the year ended December 31, 2017.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. The result of the remeasurement was a $17.5 million reduction to our U.S net deferred tax assets and represents a 100.8% decrease to our effective tax rate. A corresponding change, reducing the effective tax rate, was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense.

NOTE 7—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $1.2 million, $1.0 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 5—Related Party Transactions for additional information regarding this lease agreement.

S-16

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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



Years Ending December 31,	Operating Leases
2018	$	895
2019	841
2020	245
2021	—
2022	—
Thereafter	—
Total	$	1,981

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, 2017, 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 three Trains and related facilities for the Liquefaction Project. The EPC contract for Stage 2 or the Liquefaction Project was amended and restated in December 31, 2017. 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, 2017. We have the right to terminate each of the EPC contracts for our convenience, in which case Bechtel will be paid the portion of the contract price for the work performed plus costs reasonably incurred by Bechtel on account of such termination and demobilization. If the EPC contract for Stage 1 of the Liquefaction Project is terminated, Bechtel will also be paid a lump sum of up to $30.0 million depending on the termination date. If the amended and restated EPC contract for Stage 2 of the Liquefaction Project is terminated, Bechtel will be paid a lump sum of up to $2.5 million if the termination date is prior to the issuance of the notice to proceed, or Bechtel will be paid a lump sum of up to $30.0 million if the termination date is after the issuance of the notice to proceed, 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 of contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project. We have also entered into SPAs with Cheniere Marketing, as further described in Note 5—Related Party Transactions.

Services Agreements

We have certain services agreements with affiliates. See Note 5—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. See Note 5—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.

S-17

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Other Commitments

Legal Proceedings

NOTE 9—SUPPLEMENTAL CASH FLOW INFORMATION

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $110.3 million, $59.4 million and $72.9 million, as of December 31, 2017, 2016 and 2015, respectively.

NOTE 10—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:

S-18

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED



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 continue to evaluate the effect of this standard on our Financial Statements. Preliminarily, we expect that the requirement to recognize all leases on our Balance Sheets will be a significant change from current practice but will not have a material impact upon our Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows, or which, if any, practical expedients we will elect upon transition.
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	We are currently evaluating the impact of the provisions of this guidance on our Financial Statements and 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 $2.1 billion and $3.6 billion of available commitments and approximately $2.5 billion and $2.4 billion of outstanding borrowings as of December 31, 2017 and 2016, respectively, and (5) a $350.0 million working capital facility of which CCH had $186.4 million and $350.0 million of available commitments as of December 31, 2017 and 2016, respectively, and no outstanding borrowings as of both December 31, 2017 and 2016. 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, 2017 and 2016, there was no liability that was recorded related to these guarantees.

S-19

Cheniere Corpus Christi Pipeline, L.P.

Financial Statements

As of December 31, 2017 and 2016

and for the years ended December 31, 2017, 2016 and 2015

S-20

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



Bcfe		billion cubic feet equivalent
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
mtpa		million tonnes per annum
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, 2017 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-21

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., which comprise the balance sheets as of December 31, 2017 and 2016, and the related statements of operations, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Auditors’ Responsibility

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, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in accordance with U.S. generally accepted accounting principles.

/s/ KPMG LLP

KPMG LLP

Houston, Texas

February 20, 2018

S-22

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

BALANCE SHEETS

(in thousands)



	December 31,
	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	—		—
Advances to affiliate	20,072		17,924
Other current assets	11		29
Total current assets	20,083		17,953

Property, plant and equipment, net	350,258		129,357
Other non-current assets	270		3,212
Total assets	$	370,611	$	150,522

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	1,923	$	7,683
Accrued liabilities	24,785		18,396
Due to affiliates	2,048		1,214
Total current liabilities	28,756		27,293

Deferred tax liability	2,983		—

Commitments and contingencies (see Note 6)

Partners’ equity	338,872		123,229
Total liabilities and partners’ equity	$	370,611	$	150,522

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

S-23

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

STATEMENTS OF OPERATIONS

(in thousands)



	Year Ended December 31,
	2017			2016			2015

Revenues	$	—		$	—		$	—

Expenses
Operating and maintenance expense	16			22			—
Operating and maintenance expense—affiliate	82			15			—
General and administrative expense	234			295			111
General and administrative expense—affiliate	46			7			13
Depreciation and amortization expense	69			10			—
Loss on disposal of assets	5			—			—
Total expenses	452			349			124

Loss from operations	(452		)	(349		)	(124		)

Other income	15,575			—			—

Income (loss) before income taxes	15,123			(349		)	(124		)
Income tax provision	(2,983		)	—			—

Net income (loss)	$	12,140		$	(349	)	$	(124	)

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

S-24

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, 2014	$	1	$	6,425		$	6,426
Capital contributions	—		14,596			14,596
Net loss	—		(124		)	(124		)
Balance at December 31, 2015	1		20,897			20,898
Capital contributions	—		102,537			102,537
Non-cash capital contribution from affiliate	—		143			143
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

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

S-25

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities
Net income (loss)	$	12,140		$	(349	)	$	(124	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization expense	69			10			—
Allowance for funds used during construction	(15,575		)	—			—
Deferred income taxes	2,983			—			—
Loss on disposal of assets	5			—			—
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities	26			(75		)	20
Due to affiliates	6			(90		)	(4		)
Advances to affiliate	—			—			(6,951		)
Other, net	(157		)	(12		)	(129		)
Net cash used in operating activities	(503		)	(516		)	(7,188		)

Cash flows from investing activities
Property, plant and equipment, net	(203,000		)	(102,021		)	(3,900		)
Other	—			—			(3,508		)
Net cash used in investing activities	(203,000		)	(102,021		)	(7,408		)

Cash flows from financing activities
Capital contributions	203,660			102,537			14,596
Distributions	(157		)	—			—
Net cash provided by financing activities	203,503			102,537			14,596

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,
	2017		2016
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-26

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 are developing and constructing a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline”) that will interconnect the natural gas liquefaction and export facility at the Corpus Christi LNG terminal being developed by CCL (the “Liquefaction Facility” 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 for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, 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, which is being constructed concurrently with the Corpus Christi Pipeline, 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 currently under construction, Train 3 is being commercialized and has all necessary regulatory approvals in place and construction of the Corpus Christi Pipeline is nearing completion.

CCL has entered into a transportation precedent agreement and other agreements to secure firm pipeline capacity with us for up to three Trains. Commencement of service under the agreements is conditioned upon the satisfaction or waiver by us of certain conditions precedent, including: (1) our receipt of all required permits, including FERC authorization, (2) our receipt of full notice to proceed from CCL, (3) our receipt of sufficient funding to pay for the costs of the Corpus Christi Pipeline and (4) our construction and placement of the Corpus Christi Pipeline into service.

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 20, 2018, 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 value 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.

Cash, Cash Equivalents and Restricted Cash

We did not have any cash and cash equivalents or restricted cash as of December 31, 2017, since our operations are funded through contributions from CCH.

S-27

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Accounting for Pipeline Activities

Generally, we begin capitalizing the costs associated with our pipeline once the individual project meets the following criteria: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) 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 intangible assets. The costs of lease options are amortized over the life of the lease once obtained. If no 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 operations. 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 are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.

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 deferred preliminary survey and investigation costs, 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.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction (“AFUDC”) represents the cost 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 $15.6 million for the year ended December 31, 2017. We did not recognize any income related to AFUDC during the years ended December 31, 2016 and 2015.

Asset Retirement Obligations

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. 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

Property, plant and equipment, net consists of natural gas pipeline costs and fixed assets, as follows (in thousands):



	December 31,
	2017			2016
Natural gas pipeline costs
Natural gas pipeline construction-in-process	$	346,526		$	125,637
Land	2,182			2,344
Total natural gas pipeline costs	348,708			127,981
Fixed assets
Fixed assets	1,628			1,386
Accumulated depreciation	(78		)	(10		)
Total fixed assets, net	1,550			1,376
Property, plant and equipment, net	$	350,258		$	129,357

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Depreciation expense during the years ended December 31, 2017, 2016 and 2015 was $68 thousand, $10 thousand and zero, respectively.

Fixed Assets

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—RELATED PARTY TRANSACTIONS

We had $2.0 million and $1.2 million due to affiliates as of December 31, 2017 and 2016, respectively, under agreements with affiliates, as described below.

Services Agreements

We recorded aggregate expenses from affiliates on our Statements of Operations of $116 thousand, $10 thousand and $13 thousand for the years ended December 31, 2017, 2016 and 2015, respectively, under the services agreements below.

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

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

In September 2016, we entered into an agreement with CCL to lease from them a portion of the Liquefaction Facility site for the purpose of the construction and operation of a meter station to measure the amount of natural gas delivered to the Liquefaction Facility. 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 Facility site. We made a one-time payment of $0.1 million to CCL for the permanent easement of this land as of December 31, 2016, which was recorded as a reduction to capital contributions on our Statements of Partners’ Equity.

In September 2016, we entered into a pipeline right of way easement agreement with Cheniere Land Holdings, LLC (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, which granted us the right to construct, install and operate a natural gas pipeline on land owned by Cheniere Land Holdings. Under this agreement, Cheniere Land Holdings conveyed to us $0.1 million of assets during the year ended December 31, 2016, which was recorded as a non-cash capital contribution from affiliate. We also made a one-time payment of $0.3 million to Cheniere Land Holdings for the permanent easement of this land as of December 31, 2016, which was recorded as a reduction to capital contributions.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Transportation Precedent Agreement (“TPA”)

We have an amended TPA with CCL 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 Facility. Subject to receipt of certain authorizations, under the TPA, we agree to construct and place into service a pipeline, add compression, and provide interconnections to the Liquefaction Facility. We also have a firm transportation service agreement with CCL and a negotiated rate agreement (collectively, the “FTSA”). We agree to provide CCL, and CCL agrees to receive from us, firm transportation services pursuant to the FTSA.

State Tax Sharing Agreement

CCH Equity Contribution Agreements

CCH Equity Contribution Agreement

CCH Early Works Equity Contribution Agreement

NOTE 5—INCOME TAXES

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



	Year Ended December 31,
	2017		2016		2015
Current:
Federal	$	—	$	—	$	—
State	—		—		—
Total current	—		—		—

Deferred:
Federal	2,983		—		—
State	—		—		—
Total deferred	2,983		—		—
Total income tax provision	$	2,983	$	—	$	—

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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



	Year Ended December 31,
	2017		2016		2015
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
U.S. tax reform rate change	(13.2	)%	—	%	—	%
Other	—	%	(0.2	)%	(0.1	)%
Valuation allowance	(2.1	)%	(34.8	)%	(34.9	)%
Effective tax rate	19.7	%	—	%	—	%

Significant components of our deferred tax assets and liabilities at December 31, 2017 and 2016 are as follows (in thousands):



	December 31,
	2017			2016
Deferred tax assets
Federal net operating loss carryforward	$	4		$	—
Property, plant and equipment	—			322
Less: valuation allowance	—			(322		)
Total net deferred tax assets	4			—

Deferred tax liabilities
Property, plant and equipment	(2,982		)	—
Other	(5		)	—
Total deferred tax liabilities	(2,987		)	—

Net deferred tax liabilities	$	(2,983	)	$	—

At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of approximately $17 thousand. This NOL carryforward will expire in 2036.

We moved from a deferred tax asset of $322 thousand in 2016 to a net deferred tax liability of $3.0 million in 2017. Because we are in a net deferred tax liability position a valuation allowance is no longer required. The decrease in the valuation allowance was $322 thousand for the year ended December 31, 2017.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. The result of the remeasurement was a $2.0 million reduction to our U.S. net deferred tax liabilities and represents a 13.2% decrease to our effective tax rate.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 6—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2017, are not recognized as liabilities but require disclosures in our Financial Statements.

Services Agreements

We have certain services agreements with affiliates. See Note 4—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. See Note 4—Related Party Transactions for information regarding this agreement.

Obligations under Guarantee Contract

The subsidiaries of CCH, including us, have jointly and severally guaranteed the debt obligations of CCH. See Note 9—Guarantees 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 and meet the definition of a commitment as of December 31, 2017. Additionally, we have operating lease commitments with affiliates, as disclosed in Note 4—Related Party Transactions.

Legal Proceedings

NOTE 7—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Year Ended December 31,
	2017	2016	2015
Non-cash capital contribution for conveyance of asset from affiliate	—	143	—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $28.5 million, $27.1 million and $7.1 million, as of December 31, 2017, 2016 and 2015, respectively.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 8—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:



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 will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard.
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 continue to evaluate the effect of this standard on our Financial Statements. Preliminarily, we do not anticipate a material impact from the requirement to recognize all leases upon our Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.
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	We are currently evaluating the impact of the provisions of this guidance on our Financial Statements and related disclosures.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 9—GUARANTEES

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Corpus Christi Pipeline GP, LLC

Financial Statements

As of December 31, 2017 and 2016

and for the years ended December 31, 2017, 2016 and 2015

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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



Bcfe		billion cubic feet equivalent
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
mtpa		million tonnes per annum
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, 2017 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, 2017 and 2016, 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, 2017, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Auditors’ Responsibility

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, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in accordance with U.S. generally accepted accounting principles.

/s/ KPMG LLP

KPMG LLP

Houston, Texas

February 20, 2018

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CORPUS CHRISTI PIPELINE GP, LLC

BALANCE SHEETS



	December 31,
	2017		2016

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	$	—	$	—

Member’s equity	1,000		1,000

Total liabilities and member’s equity	$	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,
	2017			2016			2015
Revenues	$	—		$	—		$	—

General and administrative expense	5,585			5,300			1,207

Net loss	$	(5,585	)	$	(5,300	)	$	(1,207	)

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, 2014	$	1,000		$	1,000
Capital contributions	1,207			1,207
Net loss	(1,207		)	(1,207		)
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

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,
	2017			2016			2015
Cash flows from operating activities
Net loss	$	(5,585	)	$	(5,300	)	$	(1,207	)

Cash flows from investing activities	—			—			—

Cash flows from financing activities
Capital contributions	5,585			5,300			1,207

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,
	2017		2016
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 on September 11, 2014 by CCH, which is a wholly owned subsidiary of Cheniere (NYSE American: LNG). Cheniere contributed CCP to us on November 7, 2014. CCP is developing and constructing a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline”) that will interconnect the natural gas liquefaction and export facility at the Corpus Christi LNG terminal (the “Liquefaction Facility” and together with the Corpus Christi Pipeline, the “Liquefaction Project”) with several interstate and intrastate natural gas pipelines. The Liquefaction Project is being developed by CCL in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, 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”) is in construction and 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 currently under construction, Train 3 is being commercialized and has all necessary regulatory approvals in place and construction of the Corpus Christi Pipeline is nearing completion.

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 20, 2018, 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 collectability 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, 2017, since our operations are funded through contributions from CCH.

Income Taxes

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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,
	2017		2016		2015
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
U.S. tax reform rate change	(30.3	)%	—	%	—	%
Valuation allowance	(4.7	)%	(35.0	)%	(35.0	)%
Effective tax rate	—	%	—	%	—	%

Significant components of our deferred tax assets and liabilities at December 31, 2017 and 2016 are as follows:



	December 31,
	2017			2016
Deferred tax assets
Federal net operating loss carryforward	$	2,539		$	2,277
Less: valuation allowance	(2,539		)	(2,277		)
Total net deferred tax asset	$	—		$	—

At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of approximately $12,000. These NOL carryforwards will expire between 2035 and 2037.

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, 2017 and 2016. We will continue to evaluate the realizability of our deferred tax assets in the future. The increase in the valuation allowance was $262 for the year ended December 31, 2017.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. The result of the remeasurement was a $1,700 reduction to our U.S. net deferred tax assets and represents a 30.3% decrease to our effective tax rate. This remeasurement is fully offset by a corresponding change to our valuation allowance, and therefore there was no impact to current period income tax expense.

NOTE 4—GUARANTEES

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CORPUS CHRISTI PIPELINE GP, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

billion and $3.6 billion of available commitments and approximately $2.5 billion and $2.4 billion of outstanding borrowings as of December 31, 2017 and 2016, respectively, and (5) a $350.0 million working capital facility of which CCH had $186.4 million and $350.0 million of available commitments as of December 31, 2017 and 2016, respectively, and no outstanding borrowings as of December 31, 2017 and 2016. As of December 31, 2017 and 2016, there was no liability that was recorded related to these guarantees.

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