UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 333-215435
Cheniere Corpus Christi Holdings, LLC
(Exact name of registrant as specified in its charter)
| | | | | |
| Delaware | 47-1929160 |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
700 Milam Street, Suite 1900
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 375-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | |
| Title of each class | Trading Symbol | Name of each exchange on which registered |
| None | None | None |
Securities registered pursuant to Section 12(g) of the Act: None
The registrant meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Note: The registrant was a voluntary filer until September 24, 2020. The registrant has filed all reports required pursuant to Sections 13 or 15(d) during the preceding 12 months as if the registrant was subject to such filing requirements.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| | | | | | | | | | | | | | | | | |
| Large accelerated filer | ☐ | | Accelerated filer | ☐ |
| Non-accelerated filer | ☒ | | Smaller reporting company | ☐ |
| | | | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates: Not applicable
Indicate the number of shares outstanding of the issuer’s classes of common stock, as of the latest practicable date: Not applicable
Documents incorporated by reference: None
CHENIERE CORPUS CHRISTI HOLDINGS, LLC
TABLE OF CONTENTS
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, 2020, 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.
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
•statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction facility, pipeline facility or other projects, or any expansions or portions thereof, by certain dates, or at all;
•statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
•statements relating to the construction of our Trains and pipeline, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;
•statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
•statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
•statements regarding our planned development and construction of additional Trains or pipelines, including the financing of such Trains or pipelines;
•statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
•statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
•statements regarding the outbreak of COVID-19 and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing credit worthiness of our contractual counterparties, any disruptions in our operations or construction of our Trains and the health and safety of Cheniere’s employees, and on our customers, the global economy and the demand for LNG;
•any other statements that relate to non-historical or future information; and
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
Cheniere Corpus Christi Holdings, LLC (“CCH”) is a Delaware limited liability company formed in September 2014 by Cheniere Energy, Inc. (“Cheniere”), a Houston-based energy infrastructure company primarily engaged in LNG-related businesses, to develop, construct, operate, maintain and own natural gas liquefaction and export facilities (the “Liquefaction Facilities”) and a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) near Corpus Christi, Texas, through our subsidiaries Corpus Christi Liquefaction, LLC (“CCL”) and Cheniere Corpus Christi Pipeline, L.P. (“CCP”), respectively.
LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.
We are currently operating two Trains and one additional Train is undergoing commissioning that is expected to be substantially completed in the first quarter of 2021, for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters.
Our Business Strategy
Our primary business strategy for the Liquefaction Project is to develop, construct and operate assets supported by long-term, fixed fee contracts. We plan to implement our strategy by:
•safely, efficiently and reliably maintaining and operating our assets, including our Trains;
•procuring natural gas and pipeline transport capacity to our facility;
•commencing commercial delivery for our long-term SPA customers, of which we have initiated for seven of nine long-term SPA customers as of December 31, 2020;
•completing construction and commencing operation of Train 3 of the Liquefaction Project;
•making LNG available to our long-term SPA customers to generate steady and reliable revenues and operating cash flows;
•further expanding and/or optimizing the Liquefaction Project by leveraging existing infrastructure; and
•maintaining a prudent and cost-effective capital structure.
Our Liquefaction Project
We are currently operating two Trains and two marine berths at the Liquefaction Project and commissioning one additional Train that is expected to be substantially completed in the first quarter of 2021. We have received authorization from the FERC to site, construct and operate Trains 1 through 3 of the Liquefaction Project. We completed construction of Trains 1 and 2 of the Liquefaction Project and commenced commercial operating activities in February 2019 and August 2019, respectively. The following table summarizes the project completion and construction status of Train 3 of the Liquefaction Project, including the related infrastructure, as of December 31, 2020:
| | | | | | | | | | | | | |
| | | Train 3 |
| Overall project completion percentage | | | 99.6% |
| Completion percentage of: | | | |
| Engineering | | | 100.0% |
| Procurement | | | 100.0% |
| Subcontract work | | | 99.9% |
| Construction | | | 99.0% |
| Expected date of substantial completion | | | | 1Q 2021 |
| | | | | |
The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal to FTA countries and to non-FTA countries through December 31, 2050, up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas.
In December 2020, the DOE announced a new policy in which it would no longer issue short-term export authorizations separately from long-term authorizations. Accordingly, the DOE amended each of CCL’s long-term authorizations to include short-term export authority, and vacated the short-term orders.
An application was filed in September 2019 to authorize additional exports from the Liquefaction Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 108 Bcf/yr of natural gas, for a total Liquefaction Project export of 875.16 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of the volumes contemplated in the application. In April 2020, the DOE issued an order authorizing CCL to export to FTA countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet issued an order authorizing CCL to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the Liquefaction Project from the currently authorized level to approximately 875.16 Bcf/yr was also submitted to the FERC and is currently pending.
Customers
CCL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 19 years (plus extension rights) with nine third parties for Trains 1 through 3 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 70% of the total production capacity from these Trains. Under these SPAs, the customers will purchase LNG from CCL on a free on board (“FOB”) basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the Liquefaction Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for the applicable Train, as specified in each SPA.
In aggregate, the minimum annual fixed fee portion to be paid by the third-party SPA customers is approximately $1.4 billion for Trains 1 and 2 and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the Liquefaction Project.
The annual contracted cash flows from fixed fees of each buyer of LNG under CCL’s third-party SPAs that constitute more than 10% of CCL’s aggregate fixed fees under all its SPAs for Trains 1 through 3 of the Liquefaction Project are:
•approximately $410 million from Endesa S.A. (“Endesa”);
•approximately $280 million from PT Pertamina (Persero) (“Pertamina”); and
•approximately $270 million from Naturgy LNG GOM, Limited (formerly known as Gas Natural Fenosa LNG GOM, Limited) (“Naturgy”), which is guaranteed by Naturgy Energy Group, S.A. (formerly known as Gas Natural SDG S.A.).
The annual aggregate contracted cash flow from fixed fees for all of our other SPAs with third-parties is approximately $790 million.
In addition, Cheniere Marketing International LLP (“Cheniere Marketing”), has agreements with CCL to purchase: (1) approximately 15 TBtu per annum of LNG with an approximate term of 23 years, (2) any LNG produced by CCL in excess of that required for other customers at Cheniere Marketing’s option and (3) approximately 44 TBtu of LNG with a term of up to seven years associated with the integrated production marketing (“IPM”) gas supply agreement between CCL and EOG.
The following table shows customers with revenues of 10% or greater of total revenues from external customers:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Percentage of Total Revenues from External Customers |
| | | | Year Ended December 31, |
| | | | | | 2020 | | 2019 | | 2018 |
| Endesa | | | | | | 31% | | 57% | | —% |
| Pertamina | | | | | | 16% | | 23% | | —% |
| Naturgy | | | | | | 14% | | —% | | —% |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Natural Gas Transportation, Storage and Supply
To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing variability in natural gas needs for the Liquefaction Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2020, CCL had secured up to approximately 2,938 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.
A portion of the natural gas feedstock transactions for CCL are IPM transactions, in which the natural gas producers are paid based on a global gas market price less a fixed liquefaction fee and certain costs incurred by us.
Construction
CCL entered into separate lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 3 of the Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause CCL to enter into a change order, or CCL agrees with Bechtel to a change order.
The total contract price of the EPC contract for Train 3, which is currently undergoing commissioning, is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2020. As of December 31, 2020, we have incurred $2.4 billion under this contract.
Pipeline Facilities
In December 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the Natural Gas Act of 1938, as amended (the “NGA”), authorizing CCP to construct and operate the Corpus Christi Pipeline. The Corpus Christi Pipeline is designed to transport 2.25 Bcf/d of natural gas feedstock required by the Liquefaction Project from the existing regional natural gas pipeline grid. The construction of the Corpus Christi Pipeline was completed in the second quarter of 2018.
Governmental Regulation
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.
Federal Energy Regulatory Commission
The design, construction, operation, maintenance and expansion of the Liquefaction Project, the import or export of LNG and the purchase and transportation of natural gas in interstate commerce through the Corpus Christi Pipeline are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA. Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale for resale of natural gas in interstate commerce, to natural gas companies engaged in such transportation or sale and to the construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.
The FERC’s authority to regulate interstate natural gas pipelines and the services that they provide generally includes regulation of:
•rates and charges, and terms and conditions for natural gas transportation, storage and related services;
•the certification and construction of new facilities and modification of existing facilities;
•the extension and abandonment of services and facilities;
•the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;
•the acquisition and disposition of facilities;
•the initiation and discontinuation of services; and
•various other matters.
Under the NGA, our pipeline is not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including its own marketing affiliate. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates. Although the provisions that codified FERC’s policy in this area expired on January 1, 2015, we see no indication that the FERC intends to change its policy in this area.
We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate automatically granted by the FERC to our marketing affiliates. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.
In order to site, construct and operate the Corpus Christi LNG terminal, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct, amendments to the NGA. For example, nothing in the EPAct amendments
to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law.
In December 2014, the FERC issued an order granting CCL authorization under Section 3 of the NGA to site, construct and operate Trains 1 through 3 of the Liquefaction Project and issued a certificate of public convenience and necessity under Section 7(c) of the NGA authorizing construction and operation of the Corpus Christi Pipeline (the “December 2014 Order”). A party to the proceeding requested a rehearing of the December 2014 Order, and in May 2015, the FERC denied rehearing (the “Order Denying Rehearing”). The party petitioned the relevant Court of Appeals to review the December 2014 Order and the Order Denying Rehearing; that petition was denied on November 4, 2016. In June of 2018, CCL and CCP filed an application with the FERC for authorization under Section 3 of the NGA to site, construct and operate additional facilities for the liquefaction and export of domestically-produced natural gas (“Corpus Christi Stage 3”) at the existing Liquefaction Project and pipeline location, which is being developed by a wholly owned subsidiary of Cheniere that is not owned or controlled by us. In November 2019, the FERC authorized CCP to construct and operate the pipeline for Corpus Christi Stage 3. The order is not subject to appellate court review. In 2020, FERC authorized CCP to construct and operate a portion of Corpus Christi Stage 3 (Sinton Compressor Station Unit No. 1) on an interim basis independently from the remaining Corpus Christi Stage 3 facilities. Sinton Unit No. 1 received FERC approval for in-service in December 2020.
On September 27, 2019, CCL filed a request with the FERC pursuant to Section 3 of the NGA, requesting authorization to increase the total LNG production capacity of the terminal from currently authorized levels to an amount which reflects more accurately the capacity of the facility based on enhancements during the engineering, design and construction process, as well as operational experience to date. The requested authorizations do not involve construction of new facilities. Corresponding applications for authorization to export the incremental volumes were also submitted to the DOE.
The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in natural gas marketing functions. The general principles of the FERC Standards of Conduct are: (1) independent functioning, which requires transmission function employees to function independently of marketing function employees; (2) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (3) transparency, which imposes posting requirements to detect undue preference due to the improper disclosure of non-public transmission function information. We have established the required policies, procedures and training to comply with the FERC’s Standards of Conduct.
All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other material governmental and regulatory approvals and permits will be required throughout the life of the Liquefaction Project. In addition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of the Liquefaction Project. For example, throughout the life of the Liquefaction Project, we are subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations have not materially affected our construction or operations.
DOE Export Licenses
The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal as discussed in Our Liquefaction Project. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.
Under Section 3 of the NGA applications for exports of natural gas to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for
trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest.
Pipeline and Hazardous Materials Safety Administration
The Liquefaction Project is subject to regulation by PHMSA. PHMSA is authorized by the applicable pipeline safety laws to establish minimum safety standards for certain pipelines and LNG facilities. The regulatory standards PHMSA has established are applicable to the design, installation, testing, construction, operation, maintenance and management of natural gas and hazardous liquid pipeline facilities and LNG facilities that affect interstate or foreign commerce. PHMSA has also established training, worker qualification and reporting requirements.
In October 2019, PHMSA published final rules revising its regulations governing the safety of certain gas transmission pipelines (effective July 1, 2020) and established new enforcement procedures for the issuance of temporary emergency orders (effective December 2, 2019).
PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $218,000 per day per violation, with a maximum administrative civil penalty of approximately $2 million for any related series of violations.
Other Governmental Permits, Approvals and Authorizations
Construction and operation of the Liquefaction Project requires additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including the DOT, U.S. Army Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service (the “FWS”), the U.S. Environmental Protection Agency (the “EPA”), U.S. Department of Homeland Security, the Texas Commission on Environmental Quality (“TCEQ”) and the Railroad Commission of Texas (“RRC”).
The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10) (the “Section 10/404 Permit”). The EPA administers the Clean Air Act (“CAA”), and has delegated authority to the TCEQ to issue the Title V Operating Permit (the “Title V Permit”) and the Prevention of Significant Deterioration Permit (the “PSD Permit”). These two permits are issued by the TCEQ.
Commodity Futures Trading Commission (“CFTC”)
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in those markets. Most of the regulations are already in effect, while other rules and regulations, including the new rules on speculative position limits that were finalized by the CFTC on October 15, 2020, are in the process of being phased in. The full impact of the CFTC’s position limits rules is not yet known and these rules could have a significant impact on our business.
As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require Swap Dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We qualify as a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.
Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.
Environmental Regulation
The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations require significant expenditures for compliance, can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.
Clean Air Act
The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by any such requirements.
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of greenhouse gas (“GHG”) emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules were largely stayed or repealed during the Trump Administration including by amendments adopted by the EPA on February 23, 2018 and additional amendments to new source performance standards for the oil and gas industry on September 14 and 15, 2020. On January 20, 2021, President Biden issued an executive order directing the EPA to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in more stringent GHG emissions rulemaking. We are supportive of regulations reducing GHG emissions over time.
From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. In addition, many states have already taken regulatory action to monitor and/or reduce emissions of GHGs, primarily through the development of GHG emission inventories or regional GHG cap and trade programs. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Coastal Zone Management Act (“CZMA”)
The siting and construction of the Corpus Christi LNG terminal within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.
Clean Water Act
The Liquefaction Project is subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Texas, by the TCEQ).
Resource Conservation and Recovery Act (“RCRA”)
The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the
operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.
Protection of Species, Habitats and Wetlands
Various federal and state statutes, such as the Endangered Species Act (the “ESA”), the Migratory Bird Treaty Act (“MBTA”), the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If our Corpus Christi LNG terminal or the Corpus Christi Pipeline adversely affects a protected species or its habitat, we may be required to develop and follow a plan to avoid those impacts. In that case, siting, construction or operation may be delayed or restricted and cause us to incur increased costs.
In August 2019, the FWS announced a series of changes to the rules implementing the ESA, including revisions to the regulations governing interagency cooperation, listing species and delisting critical habitat, and prohibitions related to threatened wildlife and plants, and in August and September 2020, the FWS proposed additional changes to its regulations for designating critical habitat. The revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions.
In addition, in January 2021, the FWS issued a final rule defining the scope of the MBTA to cover only actions intentionally directed at migratory birds, their nests or their eggs.
On January 20, 2021, President Biden issued an executive order directing the heads of all agencies to immediately review all regulatory actions taken between January 20, 2017 and January 20, 2021, including FWS regulations implementing the ESA and the MBTA and EPA regulations implementing the CWA and the Oil Pollution Act, which could result in stricter requirements with respect to endangered or threatened animal, fish and plant species and/or their designated habitats, migratory birds, wetlands or other natural resources
It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe that our operations, or the construction and operations of our Liquefaction Project, will be materially and adversely affected by such regulatory actions.
Market Factors and Competition
If and when CCL needs to replace any existing SPA or enter into new SPAs, CCL will compete on the basis of price per contracted volume of LNG with other natural gas liquefaction projects throughout the world. Cheniere is currently constructing and operating natural gas liquefaction facilities in Cameron Parish, Louisiana through its subsidiary Sabine Pass Liquefaction, LLC (“SPL”), which has entered into fixed price SPAs with third parties for the sale of LNG from Trains 1 through 6 of these natural gas liquefaction facilities, and may continue to enter into commercial agreements with respect to this natural gas liquefaction facility that might otherwise have been entered into with respect to Train 3. Revenues associated with any incremental volumes of the Liquefaction Project, including those made available to Cheniere Marketing, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to markets than us. Our affiliates have proximity to our customers, with offices located in Houston, London, Singapore, Beijing and Tokyo.
Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sale of LNG by Cheniere Marketing, or development of new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and economic growth in developing countries. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our ability to access capital markets.
We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Players around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure
growth. Currently, hundreds of billions of dollars are being invested across Europe and Asia in natural gas projects under construction, and if we included planned commitments, the total would exceed $1 trillion. Some examples include India’s commitment to invest over $60 billion to drive its gas-based economy, Europe’s commitment of well over $100 billion in gas-fired power, import terminals and pipelines, and China’s hundreds of billions all along the natural gas value chain. We highlight regasification capacity, which will not only expand existing import capacities in rapidly growing markets like China and India, but also add new import markets all over the globe, raising the total to approximately 60 by 2030 from 43 today and just 15 markets as recently as 2005.
As a result of these dynamics, global demand for natural gas is projected by the International Energy Agency to grow by approximately 21 trillion cubic feet (“Tcf”) between 2019 and 2030 and 42 Tcf between 2019 and 2040. LNG’s share is seen growing from about 12% in 2019 to about 16% of the global gas market in 2030 and 19% in 2040. Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 56%, from approximately 347 mtpa, or 16.6 Tcf, in 2019, to approximately 541 mtpa, or 26.0 Tcf, in 2030 and to 723 mtpa or 34.7 Tcf in 2040. WoodMac also forecasts LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 476 mtpa in 2030, declining to 381 mtpa in 2040. This will result in a market need for construction of an additional approximately 65 mtpa of LNG production by 2030 and about 343 mtpa by 2040. As a cleaner burning fuel with far lower emissions than coal or liquid fuels in power generation, we expect gas and LNG to play a central role in balancing grids and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Project is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.
Our LNG terminal business has limited exposure to the decline in oil prices as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes. As of January 31, 2021, U.S. natural gas prices indicate that LNG exported from the U.S. continues to be competitively priced, supporting the opportunity for U.S. LNG to fill uncontracted future demand through the execution of long-term and medium-term contracting of LNG from our terminal.
Subsidiaries
Our assets are generally held by our subsidiaries. We conduct most of our business through these subsidiaries, including the development, construction and operation of our Liquefaction Project.
Employees
We have no employees. We have contracts with Cheniere and its subsidiaries for operations, maintenance and management services. As of January 31, 2021, Cheniere and its subsidiaries had 1,519 full-time employees, including 330 employees who directly supported the Liquefaction Project. See Note 12—Related Party Transactions of our Notes to Consolidated Financial Statements for a discussion of the services agreements pursuant to which general and administrative services are provided to CCL and CCP.
Available Information
Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers.
ITEM 1A. RISK FACTORS
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
•Risks Relating to Our Financial Matters; and
•Risks Relating to the Completion of Our Liquefaction Facilities and the Development and Operation of Our Business.
Risks Relating to Our Financial Matters
Our existing level of cash resources, operating cash flow and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
As of December 31, 2020, we had no cash and cash equivalents, $70 million of current restricted cash and $10.5 billion of total debt outstanding on a consolidated basis (before unamortized debt issuance costs), excluding $293 million of outstanding letters of credit. We incur, and will incur, significant interest expense relating to the assets at the Liquefaction Project. Our ability to refinance our indebtedness will depend on our ability to access the capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs.
We have not always been profitable historically, and we have not historically had positive operating cash flow. We may not be able to achieve sustained profitability or generate positive operating cash flow in the future.
We had a net loss of $374 million for the year ended December 31, 2019, as well as net losses in prior years. In addition, our net cash flow used in operating activities was $396 million, $33 million and $61 million for the years ended December 31, 2020, 2019 and 2018, respectively. In the future, we may incur operating losses and experience negative operating cash flow. We may not be able to reduce costs, increase revenues or reduce our debt service obligations sufficiently to maintain our cash resources, which could cause us to have inadequate liquidity to continue our business.
We will continue to incur significant capital and operating expenditures while we develop and construct the Liquefaction Project. Any delays beyond the expected development period for Train 3 could cause operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of receipt of cash flows under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate any significant positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timely complete the applicable Train.
The COVID-19 global pandemic and volatility in the energy markets may materially and adversely affect our business, financial condition, operating results, cash flow, liquidity and prospects.
The COVID-19 global pandemic has resulted in significant disruption globally. Actions taken by various governmental authorities, individuals and companies around the world to prevent the spread of COVID-19 have restricted travel, business operations, and the overall level of individual movement and in-person interaction across the globe. Additionally, recent disputes over production levels between members of the Organization of Petroleum Exporting Countries and other oil producing countries have resulted in increased volatility in oil and natural gas prices.
The extent, duration and magnitude of the COVID-19 pandemic’s effects will depend on future developments, all of which are highly uncertain and difficult to predict, including the impact of the pandemic on global and regional economies, travel, and economic activity, as well as actions taken by governments, businesses and individuals in response to the pandemic or any future resurgence. These developments include the impact of the COVID-19 pandemic on unemployment rates, the demand for oil and natural gas, levels of consumer confidence and the post-pandemic pace of recovery.
Many uncertainties remain with respect to the COVID-19 pandemic, and we continue to monitor the rapidly evolving situation. The COVID-19 pandemic alone or coupled with continued volatility in the energy markets may materially and adversely affect our business, financial condition, operating results, cash flow, liquidity and prospects or have the effect of heightening many of the other risks described herein. The extent to which our business, contracts, financial condition, operating results, cash flow, liquidity and prospects are affected by the COVID-19 global pandemic or volatility in the energy markets will depend on various factors beyond our control and are highly uncertain, including the duration and scope of the outbreak, decreased demand for LNG and the resulting economic effects of the COVID-19 global pandemic.
Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant customer fails to perform its contractual obligations for any reason.
Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2020, we had SPAs with nine third-party customers. We are dependent on each customer’s continued willingness and ability to perform its obligations under its SPA. We are exposed to the credit risk of any guarantor of these customers’ obligations under their respective agreements in the event that we must seek recourse under a guaranty. As a result of the disruptions caused by the COVID-19 pandemic and the volatility in the energy markets, we believe we are exposed to heightened credit and performance risk of our customers. Additionally, some customers have indicated to us that COVID-19 has impacted their operations and/or may impact their operations in the future. Some of our SPA customers’ primary countries of business have experienced a significant number of COVID-19 cases and/or have been subject to government imposed lockdown or quarantine measures. Although we believe that impacts of the COVID-19 pandemic on LNG regasification facilities, downstream markets and broader energy demand do not constitute valid force majeure claims under our FOB LNG SPAs, if any significant 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, if any, for a breach of the agreement.
Outbreaks of infectious diseases, such as the outbreak of COVID-19, at our facilities could adversely affect our operations.
Federal, state and local governments have enacted various measures to try to contain the outbreak of COVID-19, such as travel bans and restrictions, quarantines, shelter-in-place orders and business shutdowns. Our facilities at the Corpus Christi LNG terminal are critical infrastructure and have continued to operate during the outbreak, which means that Cheniere must keep its employees who operate our facilities safe and minimize unnecessary risk of exposure to the virus. In response, Cheniere has taken extra precautionary measures to protect the continued safety and welfare of its employees who continue to work at our facilities and have modified certain business and workforce practices, such as implementing work from home policies where appropriate, but there can be no assurances that these measures will prevent any outbreak. Furthermore, the measures taken to prevent an outbreak at our facilities have resulted in increased costs and it is unclear how long such increased costs will continue to be incurred. If a large number of Cheniere’s employees in those critical facilities were to contract COVID-19 at the same time, our operations could be adversely affected and it is unclear how long such increased costs will continue to be incurred.
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 (1) changing interest rates and (2) commodity-related marketing and price risks, we enter into derivative financial instruments, including futures, swaps and option contracts. To the extent we hedge our exposure to commodity price or interest rate exposures, we forego the benefits we would otherwise experience if commodity prices or interest rates were to change favorably to our hedged position. Hedging arrangements could also expose us to risk of financial loss in some circumstances, including when:
•expected supply is less than the amount hedged or is otherwise imperfect;
•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.
Our use of derivative financial instruments are recorded at fair value on our Consolidated Balance Sheets with changes in the fair value resulting from fluctuations in the underlying commodity prices or hedged item recognized in earnings, unless they satisfy criteria for, and we elect, the normal purchases and sales exception or hedge accounting treatment. All of our derivative financial instruments do not qualify for these exceptions from fair value reporting through earnings. As a result, our quarterly and annual results are subject to significant fluctuations caused by changes in fair value, including circumstances in which there is no underlying economic impact yet realized.
The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices or interest rates change.
The regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.
The provisions of the Dodd-Frank Act and the rules adopted by the CFTC, the SEC and other federal regulators establishing federal regulation of the 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 terminal and to secure natural gas feedstock for our liquefaction facilities.
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.
Risks Relating to the Completion of Our Liquefaction Facilities and the Development and Operation of Our Business
Our ability to complete construction of the Liquefaction Project depends on our ability to obtain sufficient equity funding to cover the remaining capital costs. If we are unable to obtain sufficient equity funding, we may experience delays in completing, or we may not be able to complete, construction of the Liquefaction Project.
In May 2018, we amended and restated the existing equity contribution agreement with Cheniere (the “CEI Equity Contribution Agreement”), pursuant to which Cheniere agreed to provide cash contributions up to approximately $1.1 billion, not including $2.0 billion previously contributed under the original equity contribution agreement. As of December 31, 2020, we have received $703 million in contributions under the CEI Equity Contribution Agreement and Cheniere has posted $124 million of letters of credit on our behalf. Cheniere is only required to make additional contributions under the CEI Equity Contribution Agreement after the commitments under the Term Loan Facility have been reduced to zero and to the extent certain cash flows from operations of the Liquefaction Project are unavailable to fund Liquefaction Project costs.
The insufficiency of equity contributions to meet the equity-funded portion of our finance plan for the remaining costs to construct the Liquefaction Project may cause a delay in development of our Trains and we may not be able to complete Train 3. Even if we are able to obtain alternative equity funding, the funding may be inadequate to cover any increases in costs and may not be sufficient to mitigate the impact of delays in completion of Train 3, which may cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. Any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Cost overruns and delays in the completion of Train 3 or any future Trains, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The actual construction costs of Train 3 and any future Trains may be significantly higher than our current estimates as a result of many factors, including change orders under existing or future EPC contracts resulting from the occurrence of certain specified events that may give our EPC contractor the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. We have already experienced increased costs due to change orders. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations.
The COVID-19 pandemic and the resulting actions taken by governmental and regulatory authorities to prevent the spread of COVID-19 may cause a slow-down in the construction of one or more Trains. Our EPC contractor has advised us of voluntary proactive measures it is taking to protect employees and to mitigate risks associated with COVID-19, however, it has not indicated that there will be any changes to the project cost or schedule and is still performing its obligations under its EPC contract. While the construction of Train 3 is continuing, if there was a major outbreak of COVID-19 at any construction site or the implementation of restrictions by the government that prevented construction for an extended period, we could experience significant delays in the construction of one or more Trains.
Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to our existing EPC contract or any future EPC contract related to additional Trains, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the Liquefaction Project is fully constructed (which could cause further delays). Our ability to obtain financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are dependent on Bechtel and other contractors for the successful completion of the Liquefaction Project.
Timely and cost-effective completion of the Liquefaction Project in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of Bechtel and our other contractors under their agreements.
The ability of Bechtel and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:
•design and engineer each Train to operate in accordance with specifications;
•engage and retain third-party subcontractors and procure equipment and supplies;
•respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
•attract, develop and retain skilled personnel, including engineers;
•post required construction bonds and comply with the terms thereof;
•manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
•maintain their own financial condition, including adequate working capital.
Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Liquefaction Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of Bechtel and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.
Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Liquefaction Project or result in a contractor’s unwillingness to perform further work on the Liquefaction Project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We have historically not had any revenues or positive cash flows. Our ability to achieve profitability and generate positive operating cash flow in the future is subject to significant uncertainty.
We will continue to incur significant capital and operating expenditures while we develop and construct the Liquefaction Project. We began to generate cash flow from operations in the first quarter of 2019 when substantial completion of Train 1 was achieved.
Any delays beyond the construction of Train 3 or the development period for any future Train we may develop could result in operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flow under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate any significant positive operating cash flows and achieve profitability in the future is dependent on our ability to successfully and timely complete the applicable Train.
We are relying on estimates for the future capacity ratings and performance capabilities of the Liquefaction Project, and these estimates may prove to be inaccurate.
We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of the Liquefaction Project. If any Train, when actually constructed, fails to have the capacity ratings and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our Trains to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
If third-party pipelines and other facilities interconnected to our pipeline and facilities are or become unavailable to transport natural gas, this could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We depend upon third-party pipelines and other facilities that provide gas delivery options to our Liquefaction Project. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to meet our SPA obligations and continue shipping natural gas from producing regions or to end markets could be restricted, thereby reducing our revenues which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipeline and the export of LNG could impede operations and construction and could have a material adverse effect on us.
The design, construction and operation of interstate natural gas pipelines, LNG terminal, including the Liquefaction Project and other facilities, and the import and export of LNG and the purchase and transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG. Although the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the three Trains and related facilities of the Liquefaction Project and Section 7 of the NGA authorizing the siting, construction and operation of the Corpus Christi Pipeline, the FERC orders require us to comply with certain ongoing conditions and obtain certain additional approvals in conjunction with ongoing construction and operations of the Liquefaction Project. We will be required to obtain similar approvals and permits with respect to any expansion or modification of our liquefaction and pipeline facilities. We cannot control the outcome of the regulatory review and approval processes. Certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We do not know whether or when any such approvals or permits can be obtained, or whether any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, including as a result of untimely notices or filings, we may not be able to recover our investment in our projects. Additionally, government disruptions, such as a U.S. government shutdown, may delay or halt our ability to obtain and maintain necessary approvals and permits. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Delays in the completion of Train 3 could lead to reduced revenues or termination of one or more of the SPAs by our customers.
Any delay in completion of Train 3 could cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. In particular, each of our SPAs provides that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our Corpus Christi Pipeline and its FERC gas tariffs are subject to FERC regulation.
The Corpus Christi Pipeline is subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA”). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by the Corpus Christi Pipeline must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
If we fail to comply with all applicable statutes, rules, regulations and orders, the Corpus Christi Pipeline could be subject to substantial penalties and fines.
In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.3 million per day for each violation.
Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.
The PHMSA requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact a “high consequence area”;
•improve data collection, integration and analysis;
•repair and remediate the pipeline as necessary; and
•implement preventative and mitigating actions.
We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines.
Our business could be materially and adversely affected if we lose the right to situate the Corpus Christi Pipeline on property owned by third parties.
We do not own the land on which the Corpus Christi Pipeline is situated, and we are subject to the possibility of increased costs to retain necessary land use rights. If we were to lose these rights or be required to relocate the Corpus Christi Pipeline, our business could be materially and adversely affected.
Hurricanes or other disasters could result in an interruption of our operations, a delay in the completion of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us.
Hurricane Harvey in 2017 caused temporary suspension in construction of our Liquefaction Project and caused minor damage to our Liquefaction Project. In August 2020, we entered into an arrangement with our affiliate to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers from the other facility in the event operational conditions impact operations at the Corpus Christi LNG terminal or at our affiliate’s terminal. During the year ended December 31, 2020, 17 TBtu was loaded at our facilities for our affiliate pursuant to this agreement. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Corpus Christi LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Liquefaction Project or our other facilities and increases in our insurance premiums. The U.S. Global Change Research Program has reported that the U.S.’s energy and transportation systems are expected to be increasingly disrupted by climate change and extreme weather events. An increase in frequency and severity of extreme weather events such as storms, floods, fires and rising sea levels could have an adverse effect on our operations.
We may not be successful in fully implementing our proposed business strategy to provide liquefaction capabilities at the Liquefaction Project.
It will take several years to finish construction of Train 3 at the Liquefaction Project and any additional stages of the Liquefaction Project that we may develop, and even if successfully constructed, the Liquefaction Project already is, and will continue to be, subject to the operating risks described herein. Accordingly, there are many risks associated with the
Liquefaction Project, and if we are not successful in implementing our business strategy, we may not be able to generate cash flows, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may not complete construction or operate our proposed LNG facility or all of our Trains or any additional LNG facilities or Trains beyond those currently planned, which could limit our growth prospects.
We may not complete construction of our proposed LNG facility or some of our Trains, whether due to lack of commercial interest or inability to obtain financing or otherwise. Our ability to develop additional liquefaction facilities will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world. Competitors may have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to sources of natural gas and LNG than we do. If we are unable or unwilling to construct and operate additional LNG facilities, our prospects for growth will be limited.
Our cost estimates for Trains are subject to change as a result of cost overruns, change orders under existing or future construction contracts, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules. In the event we experience cost overruns, delays or both, the amount of funding needed to complete a Train could exceed our available funds and result in our failure to complete such Train and thereby negatively impact our business and limit our growth prospects.
We may enter into certain arrangements to share the use and operations of our facilities with adjacent projects, which would require us to meet certain conditions under the indentures governing each of our senior notes (the “CCH Indentures”). Despite the protection provided by the CCH Indentures, the nature of such sharing arrangements is not currently known and may limit our operational flexibility, use of land and/or facilities and the ability of the security trustee under the Common Security and Account Agreement to take certain enforcement actions against the security interest in substantially all of our assets and the assets of our current and any future guarantors.
Cheniere is developing up to seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG adjacent to the Liquefaction Project, along with a second natural gas pipeline. If these entities ultimately construct these Trains and facilities or any additional Trains or facilities, they would not be part of the Liquefaction Project but CCL and CCP may nevertheless enter into sharing arrangements with the entities owning those Trains and related facilities that would involve sharing the use and capacity of each other’s land and facilities, including pooling of capacity of Trains, sharing of common facilities, such as storage tanks and berths, and use of capacity of the pipeline facilities, to the extent permitted under the Common Terms Agreement and the CCH Indentures. CCL and CCP also may transfer and/or amend previously-obtained permits and other authorizations or applications such that they may be used by those entities. As future arrangements that would only be fully determined if the circumstances arise, there is uncertainty as to the full scope and impact of these sharing arrangements. The CCH Indentures require us to meet certain conditions in respect of such sharing arrangements. These sharing arrangements would be subject to quiet enjoyment rights for CCL, CCP and the owner of the other Train(s). The nature of these sharing arrangements could limit the ability of the security trustee under the Common Security and Account Agreement to take certain enforcement action against the security interest in substantially all of our assets and the assets of our current and any future guarantors in respect of which quiet enjoyment rights have been granted to a third party.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. However, we may not be able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational damages.
Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, penalties for non-compliance with relevant regulatory requirements or
litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are entirely dependent on Cheniere, including employees of Cheniere and its subsidiaries, for key personnel, and a loss of key personnel could have a material adverse effect on our business.
As of January 31, 2021, Cheniere and its subsidiaries had 1,519 full-time employees, including 330 employees who directly supported the Liquefaction Project. We have contracted with subsidiaries of Cheniere to provide the personnel necessary for the construction and operation of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate liquefaction facilities and pipelines and to provide our customers with the highest quality service. We also compete with any other project Cheniere is developing, including the liquefaction facility operated by SPL, for the time and expertise of Cheniere’s personnel. Further, we and Cheniere face competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.
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, changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates.
We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, Cheniere Marketing has entered into an SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers. These agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently developing the Sabine Pass Liquefaction Project in Cameron Parish, Louisiana, and is developing additional Trains and related facilities and a second natural gas pipeline at a site adjacent to the Liquefaction Project. Cheniere may enter into commercial arrangements with respect to these projects that might otherwise have been entered into with respect to Train 3 or another expansion of the Liquefaction Project and may require that we transfer and/or amend permits and other authorizations we have received to enable them to be used by such projects.
We have or will have numerous contracts and commercial arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements with one or more Cheniere-affiliated entities as well as other agreements and arrangements. We anticipate that we will enter into other such agreements in the future, which cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates will be necessary or desirable, additional conflicts of interest will be involved.
We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.
We face competition based upon the international market price for LNG.
Our Liquefaction Project is subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our Liquefaction Project are diverse and include, among others:
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to our Liquefaction Project;
•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
•increases in capacity and utilization of nuclear power and related facilities; and
•displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
•competitive liquefaction capacity in North America;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions, including extreme weather events and temperature volatility resulting from climate change;
•reduced demand and lower prices for natural gas;
•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
•cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
•political conditions in natural gas producing regions;
•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;
•adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the Liquefaction Project will be dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import or export LNG from or to the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction or regasification facilities in the United States.
In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in the United States.
As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or to the United States on a commercial basis. Any significant impediment to the ability to deliver LNG to or from the United States generally, or to the Corpus Christi LNG terminal or from the Liquefaction Project specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are subject to significant construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.
The construction and operation of our LNG terminal and liquefaction facilities are and will be subject to the inherent risks associated with these types of operations, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operation of the Liquefaction Project involves significant risks.
As of December 31, 2020, Trains 1 and 2 of the Liquefaction Project had reached substantial completion and were placed into operation, and Train 3 was undergoing commissioning. As more fully discussed in these Risk Factors, the Liquefaction Project faces operational risks, including the following:
•the facilities performing below expected levels of efficiency;
•breakdown or failures of equipment;
•operational errors by vessel or tug operators;
•operational errors by us or any contracted facility operator;
•labor disputes; and
•weather-related interruptions of operations.
We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation requirements, which could have a material adverse effect on us.
We believe that there is sufficient capacity on the Corpus Christi Pipeline to accommodate all of our natural gas feedstock transportation requirements for Trains 1 through 3. We have also entered into firm transportation agreements with several third-party pipeline companies partially securing firm pipeline transportation capacity for the Liquefaction Project on interstate and intrastate pipelines which will connect to the Corpus Christi Pipeline for the production contemplated for Trains 1 through 3. If and when we need to replace one or more of our existing agreements with these interconnecting pipelines or enter into additional agreements, we may not be able to do so on commercially reasonable terms or at all, which would impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition, 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 impediments to the transport of LNG, such as shortages of LNG vessels worldwide or operational impacts on LNG shipping, including maritime transportation routes, 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. Additionally, the availability of LNG vessels and transportation costs could be impacted 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;
•shortages of or delays in the receipt of necessary construction materials;
•political or economic disturbances;
•changes in governmental regulations or maritime self-regulatory organizations;
•work stoppages or other labor disturbances;
•bankruptcy or other financial crisis of shipbuilders or shipowners;
•quality or engineering problems;
•disruptions to maritime transportation routes; and
•weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.
Terrorist attacks, cyber incidents or military campaigns may adversely impact our business.
A terrorist attack, cyber incident or military incident involving an LNG facility, our infrastructure or an LNG vessel may result in delays in, or cancellation of, construction of new LNG facilities, including one or more of the Trains, which would increase our costs and decrease our cash flows. A terrorist incident or cyber incident may also result in temporary or permanent closure of our existing facilities, which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of terrorism, cyber incidents or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources, and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our LNG terminal and pipelines, including FERC and PHMSA, to issue compliance orders, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties or to capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of GHG emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules were largely stayed or repealed during the Trump Administration including by amendments adopted by the EPA on February 23, 2018 and additional amendments to new source performance standards for the oil and gas industry on September 14 and 15, 2020. On January 20, 2021, President Biden issued an executive order directing the EPA to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in more stringent GHG emissions rulemaking. In addition, other federal and state initiatives may be considered in the future to address GHG emissions through, for example, United States treaty commitments, direct regulation, market-based regulations such as a carbon emissions tax or cap-and-trade programs, or clean energy standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminal, or could increase compliance costs for our operations. We are supportive of regulations reducing GHG emissions over time.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminal or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our lack of diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Substantially all of our anticipated revenue in 2021 will be dependent upon the Liquefaction Project. Due to our lack of asset and geographic diversification, an adverse development at the Liquefaction Project or in the LNG industry would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Not applicable.
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data set forth below are derived from our audited consolidated and combined financial data for the periods indicated (in millions). 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, |
| | | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| Consolidated Statement of Operations Data: | | | | | | | | | | |
| Revenues | | $ | 2,529 | | | $ | 1,405 | | | $ | — | | | $ | — | | | $ | — | |
| Income (loss) from operations | | 671 | | | 75 | | | (22) | | | (19) | | | (6) | |
| Interest expense, net of capitalized interest | | (365) | | | (278) | | | — | | | — | | | — | |
| | | | | | | | | | |
| | | | | | | | | | |
| Net income (loss) | | 63 | | | (374) | | | 6 | | | (49) | | | (85) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, |
| | | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| Consolidated Balance Sheet Data: | | | | | | | | | | |
| Property, plant and equipment, net | | $ | 12,853 | | | $ | 12,507 | | | $ | 11,139 | | | $ | 8,261 | | | $ | 6,077 | |
| Total assets | | 13,640 | | | 13,112 | | | 11,720 | | | 8,660 | | | 6,636 | |
| Current debt | | 269 | | | — | | | — | | | — | | | — | |
| Long-term debt, net | | 10,101 | | | 10,093 | | | 9,246 | | | 6,669 | | | 5,082 | |
| | | | | | | | | | |
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
We are operating and constructing a natural gas liquefaction and export facility (the “Liquefaction Facilities”) and operating a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) near Corpus Christi, Texas, through our subsidiaries CCL and CCP, respectively.
We are currently operating two Trains and one additional Train is undergoing commissioning that is expected to be substantially completed in the first quarter of 2021, for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters.
Overview of Significant Events
Our significant events since January 1, 2020 and through the filing date of this Form 10-K include the following:
Strategic
•In August 2020, we entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.
Operational
•As of February 19, 2021, more than 225 cumulative LNG cargoes totaling over 15 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
•In December 2020, CCL commenced shipment of LNG commissioning cargoes from Train 3 of the Liquefaction Project.
Financial
•In May 2020, the date of first commercial delivery was reached under the 20-year SPAs with PT Pertamina (Persero), Naturgy LNG GOM, Limited, Woodside Energy Trading Singapore Pte Ltd, Iberdrola Generación España, S.A.U. (assigned by Iberdrola, S.A.) and Électricité de France, S.A. relating to Train 2 of the Liquefaction Project.
•In August 2020, Moody’s Investors Service upgraded its rating of our senior secured debt from Ba1 (Positive Outlook) to Baa3.
•In August 2020, we issued an aggregate principal amount of approximately $769 million of 3.52% Senior Secured Notes due 2039 (the “3.52% CCH Senior Secured Notes”). The net proceeds of these notes were used to repay a portion of the outstanding borrowings under our amended and restated credit facility (the “CCH Credit Facility”), pay costs associated with certain interest rate derivative instruments that were settled and pay certain fees, costs and expenses incurred in connection with these transactions.
Impact of COVID-19 and Market Environment
The LNG business environment in 2020 was impacted by the coronavirus pandemic and its economic ramifications. Lockdown measures across the globe reduced economic activity and resulted in lower energy needs throughout most of the year. However, LNG demand proved relatively resilient as compared to other hydrocarbons, showing an annual gain of approximately 1.4%, or 5 MT, to 364 MT in 2020. While the economic recovery in Asia, and particularly in China, lifted LNG demand in the second half of the year, uncertainty about the pandemic’s track remains the primary near-term risk to LNG trade. A slow return towards normal is expected to occur in the coming months, depending on the speed of vaccine rollout within regions, vaccine effectiveness against mutations and the speed and shape of economic recovery across the LNG importing nations. The continued improvements in global economic indicators seen in the fourth quarter is encouraging especially in China, which represents one of the key countries for LNG demand growth.
In the fourth quarter of 2020, natural gas and LNG spot prices significantly increased in line with the increase in economic activity and with seasonal norms. After falling to all-time lows in the second quarter, global LNG price benchmarks have made an impressive climb and exited the year at the highest levels since March 2019. As an example, the Dutch Title Transfer Facility (“TTF”), a virtual trading point for natural gas in the Netherlands, settled December at $5.08/MMBtu, $3.94/MMBtu higher than its June 2020 settlement. Similarly, the Japan Korea Marker (“JKM”), an LNG benchmark price assessment for spot physical cargoes delivered ex-ship into certain key markets in Asia, settled December at $6.90/MMBtu, which is $4.84/MMBtu higher than its all-time low July 2020 settlement. Record-low winter temperatures, supply outages and transportation bottlenecks contributed to drive JKM prices up to all-time highs by mid-January 2021. In a projection published in July 2020, IHS Markit estimated LNG demand to reach 383 MT in 2021, implying a return to higher growth in 2021.
We have limited exposure to the fluctuations in oil and LNG spot prices as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements linked to a Henry Hub price. For this reason, we do not expect price fluctuations to have a material impact on our forecasted financial results for 2021.
The number of LNG cargoes for which customers notified us that they would not take delivery has reduced from this summer, a sign that the market is continuing to adjust and rebalance toward equilibrium. We do not expect these events to have a material adverse impact on our forecasted financial results for 2021, due to the highly contracted nature of our business and the fact that customers continue to be obligated to pay fixed fees for cargoes with respect to which they have exercised their contractual right to cancel. As such, during the year ended December 31, 2020, we recognized $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized subsequent to December 31, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. We experienced decreased revenues during the year ended December 31, 2020 associated with LNG cargoes that were scheduled for delivery for which customers notified us that they would not take delivery of such cargoes.
In addition, in response to the COVID-19 pandemic, Cheniere has modified certain business and workforce practices to protect the safety and welfare of its employees who continue to work at its facilities and offices worldwide, as well as implemented certain mitigation efforts to ensure business continuity. In March 2020, Cheniere began consulting with a medical advisor, and implemented social distancing through revised shift schedules, work from home policies and designated remote work locations where appropriate, restricted non-essential business travel and began requiring self-screening for employees and contractors. In April 2020, Cheniere began providing temporary housing for its workforce for our facilities, implemented
temperature testing, incorporated medical and social workers to support employees, implemented prior self-isolation and screening for temporary housing and implemented marine operations with zero contact during loading activities. These measures have resulted in increased costs. While response measures continue to evolve and in most cases have moderated or ceased, we expect Cheniere to incur incremental operating costs associated with business continuity and protection of its workforce until the risks associated with the pandemic diminish. We have incurred approximately $31 million of such costs during the year ended December 31, 2020.
Results of Operations
The following charts summarize the number of Trains that were in operation during the years ended December 31, 2020, 2019 and 2018 and total revenues and total LNG volumes loaded (including both operational and commissioning volumes) for the respective periods:
Our consolidated net income was $63 million for the year ended December 31, 2020, compared to net loss of $374 million in the year ended December 31, 2019. This $437 million decrease in net loss in 2020 was primarily the result of increased income from operations due to additional Trains in operation, which was partially offset by increased losses on commodity derivatives to secure natural gas feedstock for the Liquefaction Project, increased interest rate derivative losses and increased interest expense, net of capitalized interest.
Our consolidated net loss was $374 million in the year ended December 31, 2019, compared to net income of $6 million in the year ended December 31, 2018. This $381 million decrease in net income in 2019 was primarily the result of increased interest expense, net of capitalized interest and derivative loss, net, which was partially offset by increased income from operations.
We enter into derivative instruments to manage our exposure to changing interest rates and commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions economically hedged receive accrual accounting treatment, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, use of derivative instruments may increase the volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.
Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| (in millions, except volumes) | | | | | | | 2020 | | 2019 | | Change | | 2018 | | Change |
| LNG revenues | | | | | | | $ | 2,046 | | | $ | 679 | | | $ | 1,367 | | | $ | — | | | $ | 679 | |
| LNG revenues—affiliate | | | | | | | 483 | | | 726 | | | (243) | | | — | | | 726 | |
| | | | | | | | | | | | | | | |
| Total revenues | | | | | | | $ | 2,529 | | | $ | 1,405 | | | $ | 1,124 | | | $ | — | | | $ | 1,405 | |
| | | | | | | | | | | | | | | |
| LNG volumes recognized as revenues (in TBtu) (1) | | | | | | | 410 | | | 286 | | | 124 | | | — | | | 286 | |
(1) Excludes volume associated with cargoes for which customers notified us that they would not take delivery.
2020 vs. 2019 and 2019 vs. 2018
We began recognizing LNG revenues from the Liquefaction Project following the substantial completion and the commencement of operating activities of Trains 1 and 2 in February 2019 and August 2019, respectively. The additional Trains in operation between the periods resulted in additional revenue. During the year ended December 31, 2020, we recognized $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized subsequent to December 31, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. We expect our LNG revenues to increase in the future upon Train 3 of the Liquefaction Project becoming operational.
Also included in LNG revenues are the sale of unutilized natural gas procured for the liquefaction process and gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized revenues of $171 million, $83 million and zero during the years ended December 31, 2020, 2019 and 2018, respectively, related to these transactions.
Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the years ended years ended December 31, 2020, 2019 and 2018, we realized offsets to LNG terminal costs of $32 million, $156 million and $49 million corresponding to 6 TBtu, 38 TBtu and 7 TBtu of LNG, respectively, that were related to the sale of commissioning cargoes.
Operating costs and expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| (in millions) | | | | | | | 2020 | | 2019 | | Change | | 2018 | | Change |
| Cost of sales | | | | | | | $ | 901 | | | $ | 691 | | | $ | 210 | | | $ | — | | | $ | 691 | |
| Cost of sales—affiliate | | | | | | | 30 | | | 3 | | | 27 | | | — | | | 3 | |
| Cost of sales—related party | | | | | | | 114 | | | 86 | | | 28 | | | — | | | 86 | |
| Operating and maintenance expense | | | | | | | 347 | | | 242 | | | 105 | | | — | | | 242 | |
| Operating and maintenance expense—affiliate | | | | | | | 90 | | | 59 | | | 31 | | | 4 | | | 55 | |
| Operating and maintenance expense—related party | | | | | | | 6 | | | — | | | 6 | | | — | | | — | |
| Development expense | | | | | | | — | | | 1 | | | (1) | | | 1 | | | — | |
| | | | | | | | | | | | | | | |
| General and administrative expense | | | | | | | 7 | | | 6 | | | 1 | | | 5 | | | 1 | |
| General and administrative expense—affiliate | | | | | | | 20 | | | 11 | | | 9 | | | 2 | | | 9 | |
| Depreciation and amortization expense | | | | | | | 342 | | | 231 | | | 111 | | | 10 | | | 221 | |
| Impairment expense and loss on disposal of assets | | | | | | | 1 | | | — | | | 1 | | | — | | | — | |
| Total operating costs and expenses | | | | | | | $ | 1,858 | | | $ | 1,330 | | | $ | 528 | | | $ | 22 | | | $ | 1,308 | |
2020 vs 2019 and 2019 vs 2018
Our total operating costs and expenses increased during the year ended December 31, 2020 from the years ended December 31, 2019 and 2018, primarily as a result of additional Trains in operation between the periods, increased losses on commodity derivatives to secure natural gas feedstock for the Liquefaction Project and costs incurred during the year ended December 31, 2020 in response to the COVID-19 pandemic, as further described above in Impact of COVID-19 and Market Environment.
Cost of sales (including affiliate and related party) increased during the year ended December 31, 2020 from the years ended December 31, 2019 and 2018, primarily as a result of decreases in fair value of commodity derivatives to secure natural gas feedstock for the Liquefaction Project due to a unfavorable shift in long-term forward prices relative to our hedged position and increased cost of natural gas feedstock as a result of higher volume related to our LNG sales due to additional Trains in operation between the periods, but lower pricing. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process.
Operating and maintenance expense (including affiliate and related party) primarily includes costs associated with operating and maintaining the Liquefaction Project. Operating and maintenance expense (including affiliate and related party) increased during the year ended December 31, 2020 from the years ended December 31, 2019 and 2018, primarily due to increased natural gas transportation and storage capacity demand charges, increased third-party service and maintenance contract costs and increased payroll and benefit costs of operations personnel, generally as a result of an additional Trains in operation between the periods. Additionally, operating and maintenance expense (including affiliate) during the year ended December 31, 2020 includes costs incurred in response to the COVID-19 pandemic, as further described earlier in Impact of COVID-19 and Market Environment. Operating and maintenance (including affiliates) also includes insurance and regulatory costs and other operating costs.
Depreciation and amortization expense increased during each of the years ended December 31, 2020 and 2019 as a result of commencing operations of Trains 1 and 2 of the Liquefaction Project in February 2019 and August 2019, respectively, as the related assets began depreciating upon reaching substantial completion.
Other expense
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| (in millions) | | | | | | | 2020 | | 2019 | | Change | | 2018 | | Change |
| Interest expense, net of capitalized interest | | | | | | | $ | 365 | | | $ | 278 | | | $ | 87 | | | $ | — | | | $ | 278 | |
| Loss on modification or extinguishment of debt | | | | | | | 9 | | | 41 | | | (32) | | | 15 | | | 26 | |
| Interest rate derivative loss (gain), net | | | | | | | 233 | | | 134 | | | 99 | | | (43) | | | 177 | |
| Other expense (income), net | | | | | | | 1 | | | (4) | | | 5 | | | — | | | (4) | |
| Total other expense | | | | | | | $ | 608 | | | $ | 449 | | | $ | 159 | | | $ | (28) | | | $ | 477 | |
2020 vs 2019 and 2019 vs 2018
Interest expense, net of capitalized interest increased during each of the years ended December 31, 2020 and 2019 compared to the year ended December 31, 2018, primarily as a result of a decrease in the portion of total interest costs that is eligible for capitalization due to the commencement of operations at the Liquefaction Project. We incurred $484 million, $539 million and $451 million of total interest cost during the years ended December 31, 2020, 2019 and 2018, respectively, of which we capitalized $119 million, $261 million and $451 million, respectively. Capitalized interest primarily related to interest costs incurred to construct the remaining assets of the Liquefaction Project.
Loss on modification or extinguishment of debt decreased during the year ended December 31, 2020 as compared to the year ended December 31, 2019 and increased during the year ended December 31, 2019 as compared to the year ended December 31, 2018. Loss on modification or extinguishment of debt in each of the years included the incurrence of fees paid to lenders, third party fees and write off of unamortized discount and debt issuance costs recognized upon refinancing our credit facilities with senior notes, paydown of our credit facilities as part of Cheniere’s capital allocation framework or upon amendment and restatement of our credit facilities.
Interest rate derivative loss, net increased during the year ended December 31, 2020 compared to the years ended December 31, 2019 and 2018, primarily due to an unfavorable shift in the long-term forward LIBOR curve between the periods.
Liquidity and Capital Resources
The following table provides a summary of our liquidity position at December 31, 2020 and 2019 (in millions):
| | | | | | | | | | | |
| December 31, |
| | | |
| 2020 | | 2019 |
| Cash and cash equivalents | $ | — | | | $ | — | |
| Restricted cash designated for the Liquefaction Project | 70 | | | 80 | |
| Available commitments under the following credit facilities: | | | |
| CCH Credit Facility | — | | | — | |
| $1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) | 767 | | | 729 | |
Corpus Christi LNG Terminal
Liquefaction Facilities
We are currently operating two Trains and two marine berths at the Liquefaction Project and commissioning one additional Train that is expected to be substantially completed in the first quarter of 2021. We have received authorization from the FERC to site, construct and operate Trains 1 through 3 of the Liquefaction Project. We completed construction of Trains 1 and 2 of the Liquefaction Project and commenced commercial operating activities in February 2019 and August 2019, respectively. The following table summarizes the project completion and construction status of Train 3 of the Liquefaction Project, including the related infrastructure, as of December 31, 2020:
| | | | | | | | | | | | | |
| | | Train 3 |
| Overall project completion percentage | | | 99.6% |
| Completion percentage of: | | | |
| Engineering | | | 100.0% |
| Procurement | | | 100.0% |
| Subcontract work | | | 99.9% |
| Construction | | | 99.0% |
| Expected date of substantial completion | | | | 1Q 2021 |
| | | | | |
The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal to FTA countries and to non-FTA countries through December 31, 2050, up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas.
In December 2020, the DOE announced a new policy in which it would no longer issue short-term export authorizations separately from long-term authorizations. Accordingly, the DOE amended each of CCL’s long-term authorizations to include short-term export authority, and vacated the short-term orders.
An application was filed in September 2019 to authorize additional exports from the Liquefaction Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 108 Bcf/yr of natural gas, for a total Liquefaction Project export of 875.16 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of the volumes contemplated in the application. In April 2020, the DOE issued an order authorizing CCL to export to FTA countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet issued an order authorizing CCL to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the Liquefaction Project from the currently authorized level to approximately 875.16 Bcf/yr was also submitted to the FERC and is currently pending.
Customers
CCL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 19 years (plus extension rights) with nine third parties for Trains 1 through 3 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 70% of the total production capacity from these Trains. Under these SPAs, the customers will purchase LNG from CCL on a FOB basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the Liquefaction Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for the applicable Train, as specified in each SPA.
In aggregate, the minimum annual fixed fee portion to be paid by the third-party SPA customers is approximately $1.4 billion for Trains 1 and 2 and increasing to approximately $1.8 billion following the substantial completion of Train 3 of the Liquefaction Project.
In addition, Cheniere Marketing International LLP (“Cheniere Marketing”) has agreements with CCL to purchase: (1) approximately 15 TBtu per annum of LNG with an approximate term of 23 years, (2) any LNG produced by CCL in excess of that required for other customers at Cheniere Marketing’s option and (3) approximately 44 TBtu of LNG with a term of up to seven years associated with the integrated production marketing (“IPM”) gas supply agreement between CCL and EOG.
Natural Gas Transportation, Storage and Supply
To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing variability in natural gas needs for the Liquefaction Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2020, CCL had secured up to approximately 2,938 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.
A portion of the natural gas feedstock transactions for CCL are IPM transactions, in which the natural gas producers are paid based on a global gas market price less a fixed liquefaction fee and certain costs incurred by us.
Construction
CCL entered into separate lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 3 of the Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause CCL to enter into a change order, or CCL agrees with Bechtel to a change order.
The total contract price of the EPC contract for Train 3, which is currently undergoing commissioning, is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2020. As of December 31, 2020, we have incurred $2.4 billion under this contract.
Capital Resources
We expect to finance the construction costs of the Liquefaction Project from one or more of the following: operating cash flows from CCL and CCP, project debt and equity contributions from Cheniere. The following table provides a summary of our capital resources from borrowings and available commitments for the Liquefaction Project, excluding any equity contributions, at December 31, 2020 and 2019 (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | | 2020 | | 2019 |
| Senior notes (1) | | $ | 7,721 | | | $ | 6,952 | |
| Credit facilities outstanding balance (2) | | 2,767 | | | 3,283 | |
| Letters of credit issued (2) | | 293 | | | 471 | |
| Available commitments under credit facilities (2) | | 767 | | | 729 | |
| Total capital resources from borrowings and available commitments (3) | | $ | 11,548 | | | $ | 11,435 | |
(1)Includes the 7.000% Senior Secured Notes due 2024, 5.875% Senior Secured Notes due 2025, 5.125% Senior Secured Notes due 2027, 3.700% Senior Secured Notes due 2029, 4.80% Senior Secured Notes due 2039, 3.925% Senior Secured Notes due 2039 and the 3.52% CCH Senior Secured Notes (collectively, the “CCH Senior Notes”).
(2)Includes CCH Credit Facility and CCH Working Capital Facility.
(3)Does not include additional borrowings or contributions by our indirect parents which may be used for the Liquefaction Project.
CCH Senior Notes
The CCH Senior Notes are jointly and severally guaranteed by each of our consolidated subsidiaries, CCL, CCP and CCP GP (each a “Guarantor” and collectively, the “Guarantors”). The indentures governing the CCH Senior Notes contain customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to us or any of our restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of us and our restricted subsidiaries taken as a whole; or permit any Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets. The covenants included in the respective indentures that govern the CCH Senior Notes are subject to a number of important limitations and exceptions.
The CCH Senior Notes are our senior secured obligations, ranking senior in right of payment to any and all of our future indebtedness that is subordinated to the CCH Senior Notes and equal in right of payment with our other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Notes. The CCH Senior Notes are secured by a first-priority security interest in substantially all of our assets and the assets of the CCH Guarantors.
At any time prior to six months before the respective dates of maturity for each of the CCH Senior Notes, we may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the appropriate indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time within six months of the
respective dates of maturity for each of the CCH Senior Notes, we may redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
The Guarantors’ guarantees are full and unconditional, subject to certain release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of all or substantially all of the capital stock or the assets of the Guarantors, (2) the designation of the Guarantor as an “unrestricted subsidiary” in accordance with the indentures governing the CCH Senior Notes (the “CCH Indentures”), (3) upon the legal defeasance or covenant defeasance or discharge of obligations under the CCH Indentures and (4) the release and discharge of the Guarantors pursuant to the Common Security and Account Agreement. In the event of a default in payment of the principal or interest by us, whether at maturity of the CCH Senior Notes or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the Guarantors to enforce the guarantee.
The rights of holders of the CCH Senior Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or federal or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
Summarized financial information about us and the Guarantors as a group (the “Obligor Group”) is omitted herein because such information would not be materially different from our Consolidated Financial Statements.
The CCH Senior Notes are our senior secured obligations, ranking senior in right of payment to any and all of our future indebtedness that is subordinated to the CCH Senior Notes and equal in right of payment with our other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Notes. The CCH Senior Notes are secured by a first-priority security interest in substantially all of our assets and the assets of the CCH Guarantors.
The security interests in our assets and the assets of the CCH Guarantors are subject to release provisions including (1) upon satisfaction and discharge of the CCH Indentures, (2) upon the legal defeasance or covenant defeasance with respect to the applicable CCH Senior Notes or (3) upon payment in full in cash of the applicable CCH Senior Notes and all other related obligations that are outstanding, due and payable at the time the CCH Senior Notes are paid full in cash; and in accordance with the Common Security and Account Agreement governing the parties to the CCH Senior Notes.
CCH Credit Facility
In May 2018, we amended and restated the CCH Credit Facility to increase total commitments under the CCH Credit Facility from $4.6 billion to $6.1 billion. Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in us. There were no available commitments under the CCH Credit Facility as of both December 31, 2020 and 2019. We had $2.6 billion and $3.3 billion of loans outstanding under the CCH Credit Facility as of December 31, 2020 and 2019, respectively.
The CCH Credit Facility matures on June 30, 2024, with principal payments due quarterly commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following the completion of the Liquefaction Project as defined in the common terms agreement and (2) a set date determined by reference to the date under which a certain LNG buyer linked to the last Train of the Liquefaction Project to become operational is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the completion of Trains 1 through 3 and designed to achieve a minimum projected fixed debt service coverage ratio of 1.50:1.
Under the CCH Credit Facility, we are required to hedge not less than 65% of the variable interest rate exposure of our senior secured debt. We are restricted from making certain distributions under agreements governing our indebtedness generally until, among other requirements, the completion of the construction of Trains 1 through 3 of the Liquefaction Project,
funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.
CCH Working Capital Facility
In June 2018, we amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility from $350 million to $1.2 billion. The CCH Working Capital Facility is intended to be used for loans (“CCH Working Capital Loans”) and the issuance of letters of credit for certain working capital requirements related to developing and operating the Liquefaction Project and for related business purposes. Loans under the CCH Working Capital Facility are guaranteed by the Guarantors. We may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed for working capital under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility. As of December 31, 2020 and 2019, we had $767 million and $729 million of available commitments, $293 million and $471 million aggregate amount of issued letters of credit and $140 million and zero of loans outstanding under the CCH Working Capital Facility, respectively.
The CCH Working Capital Facility matures on June 29, 2023, and we may prepay the CCH Working Capital Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans”) at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. We are required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.
The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the assets of the Guarantors as well as all of our membership interests and the membership interest in each of the Guarantors on a pari passu basis with the CCH Senior Notes and the CCH Credit Facility.
Equity Contribution Agreement
In May 2018, we amended and restated the existing equity contribution agreement with Cheniere (the “Equity Contribution Agreement”) pursuant to which Cheniere agreed to provide cash contributions up to approximately $1.1 billion, not including $2.0 billion previously contributed under the original equity contribution agreement. As of December 31, 2020, we have received $703 million in contributions under the Equity Contribution Agreement and Cheniere has posted $124 million of letters of credit on our behalf under its revolving credit facility. Cheniere is only required to make additional contributions under the Equity Contribution Agreement after the commitments under the CCH Credit Facility have been reduced to zero and to the extent cash flows from operations of the Liquefaction Project are unavailable for Liquefaction Project costs.
Restrictive Debt Covenants
As of December 31, 2020, we were in compliance with all covenants related to our debt agreements.
LIBOR
The use of LIBOR is expected to be phased out by the end of 2021. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue working with our lenders and counterparties to pursue any amendments to our debt and derivative agreements that are currently subject to LIBOR and will continue to monitor, assess and plan for the phase out of LIBOR.
Sources and Uses of Cash
The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the years ended December 31, 2020, 2019 and 2018 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Sources of cash, cash equivalents and restricted cash: | | | | | | |
| Net cash provided by (used in) operating activities | | $ | 396 | | | $ | (33) | | | $ | (61) | |
| Proceeds from issuances of debt | | 1,050 | | | 4,203 | | | 3,115 | |
| Capital contributions | | 145 | | | 711 | | | 324 | |
| Other | | — | | | — | | | 3 | |
| | $ | 1,591 | | | $ | 4,881 | | | $ | 3,381 | |
| | | | | | |
| Uses of cash, cash equivalents and restricted cash: | | | | | | |
| Property, plant and equipment, net | | $ | (790) | | | $ | (1,517) | | | $ | (2,963) | |
| Repayments of debt | | (797) | | | (3,544) | | | (301) | |
| Debt issuance and deferred financing costs | | (8) | | | (16) | | | (46) | |
| Debt extinguishment cost | | — | | | (11) | | | (9) | |
| Other | | (6) | | | (2) | | | — | |
| | (1,601) | | | (5,090) | | | (3,319) | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | | $ | (10) | | | $ | (209) | | | $ | 62 | |
Operating Cash Flows
Operating cash flows during the years ended December 31, 2020, 2019 and 2018 were net inflows of $396 million and net outflows of $33 million and $61 million, respectively. The increase in operating cash net inflows was primarily due to additional LNG volume available to be sold as a result of the commencement of operations of Trains 1 and 2 of the Liquefaction Project in February 2019 and August 2019, respectively, a portion of which the customers elected not to take delivery but were required to pay a fixed fee with respect to the contracted volumes. The decrease in operating cash net outflows in 2019 compared to 2018 was primarily due to increased cash receipts from the sale of LNG cargoes as a result of the commencement of operations of Trains 1 and 2 of the Liquefaction Project.
Proceeds from Issuance of Debt, Repayments of Debt, Debt Issuance and Other Financing Costs and Debt Modification or Extinguishment Costs
During the year ended December 31, 2020, we issued an aggregate principal amount of $769 million of the 3.52% CCH Senior Secured Notes, which the proceeds were partly used to repay a portion of the outstanding borrowings under the CCH Credit Facility. We incurred $8 million of debt issuance costs primarily related to up-front fees paid upon the closing of this transaction. Additionally, borrowings of $281 million under the CCH Working Capital Facility were used to fund our working capital requirements.
Property, Plant and Equipment, net
Cash outflows for property, plant and equipment were primarily for the construction costs for the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion.
Capital Contributions
During the years ended December 31, 2020, 2019 and 2018, we received $145 million, $711 million and $324 million of capital 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, 2020 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due By Period (1) |
| | | Total | | 2021 | | 2022-2023 | | 2024-2025 | | Thereafter |
| Debt (2) | | $ | 10,487 | | | $ | 271 | | | $ | 190 | | | $ | 5,056 | | | $ | 4,970 | |
| Interest payments (2) | | 2,966 | | | 440 | | | 876 | | | 607 | | | 1,043 | |
| Operating lease obligations (3) | | 5 | | | 1 | | | 3 | | | 1 | | | — | |
| Purchase obligations: (4) | | | | | | | | | | |
| Construction obligations (5) | | 37 | | | 37 | | | — | | | — | | | — | |
| Natural gas supply, transportation and storage service agreements (6) | | 5,527 | | | 1,528 | | | 1,349 | | | 856 | | | 1,794 | |
| | | | | | | | | | |
| | | | | | | | | | |
| Other purchase obligations (7) | | 491 | | | 25 | | | 50 | | | 50 | | | 366 | |
| Total | | $ | 19,513 | | | $ | 2,302 | | | $ | 2,468 | | | $ | 6,570 | | | $ | 8,173 | |
(1)Agreements in force as of December 31, 2020 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2020.
(2)Based on the total debt balance, scheduled maturities and fixed or estimated forward interest rates in effect at December 31, 2020. Interest payment obligations exclude adjustments for interest rate swap agreements. A discussion of our debt obligations can be found in Note 10—Debt of our Notes to Consolidated Financial Statements. (3)Operating lease obligations primarily relate to land sites for the Liquefaction Project.
(4)Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. We include only contracts for which conditions precedent have been met. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly. We include contracts for which we have an early termination option if the option is not expected to be exercised.
(5)Construction obligations consist of the estimated remaining cost pursuant to our EPC contracts as of December 31, 2020 for Trains with respect to which we have made a final investment decision to commence construction. A discussion of these obligations can be found at Note 13—Commitments and Contingencies of our Notes to Consolidated Financial Statements. (6)Pricing of natural gas supply agreements are based on estimated forward prices and basis spreads as of December 31, 2020. Natural gas supply, transportation and storage service agreements include $1.1 billion in payments under agreements with related parties as discussed in Note 12—Related Party Transactions of our Notes to Consolidated Financial Statements. (7)Relates primarily to services agreements for the operation of the Liquefaction Project, including services agreements with affiliates of $318 million as discussed in Note 12—Related Party Transactions of our Notes to Consolidated Financial Statements.
In addition, as of December 31, 2020, we had $293 million aggregate amount of issued letters of credit under the CCH Working Capital Facility. We also had tax agreements with certain local taxing jurisdictions for an aggregate amount of $196 million to be paid through 2033, based on estimated tax obligations as of December 31, 2020.
Off-Balance Sheet Arrangements
As of December 31, 2020, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.
Summary of Critical Accounting Estimates
The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.
Fair Value of Derivative Instruments
All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. We record changes in the fair value of our derivative positions based on the value for which the derivative instrument could be exchanged between willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation approaches. Such evaluations may involve significant judgment and the results are based on expected future events or conditions, particularly for those valuations using inputs unobservable in the market.
Our derivative instruments consist of interest rate swaps, financial commodity derivative contracts transacted in an over-the-counter market physical commodity contracts. We value our interest rate swaps using observable inputs including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. Valuation of our financial commodity derivative contracts is determined using observable commodity price curves and other relevant data.
Valuation of our physical commodity contracts is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our physical commodity contracts incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. A portion of our physical commodity contracts require us to make critical accounting estimates that involve significant judgment, as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.
Gains and losses on derivative instruments are recognized in earnings. The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a change in the estimated fair value could occur in the near future as interest rates and commodity prices change.
Recent Accounting Standards
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
| Liquefaction Supply Derivatives | $ | 11 | | | $ | 77 | | | $ | 48 | | | $ | 63 | |
Interest Rate Risk
We are exposed to interest rate risk primarily when we incur debt related to project financing. Interest rate risk is managed in part by replacing outstanding floating-rate debt with fixed-rate debt with varying maturities. We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the CCH Credit Facility (“CCH Interest Rate Derivatives”) and to hedge against changes in interest rates that could impact our anticipated future issuance of debt (“CCH Interest Rate Forward Start Derivatives” and, collectively with the CCH Interest Rate Derivatives, the “Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward one-month LIBOR curve across the remaining terms of the CCH Interest Rate Derivatives and CCH Interest Rate Forward Start Derivatives as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
| CCH Interest Rate Derivatives | $ | (140) | | | $ | 1 | | | $ | (81) | | | $ | 19 | |
| CCH Interest Rate Forward Start Derivatives | — | | | — | | | (8) | | | 15 | |
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
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, 2020, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.
This annual report does not include an attestation report of Corpus Christi Holdings’ registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Corpus Christi Holdings’ registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
Management’s Certifications
The certifications of Corpus Christi Holdings’ Principal Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere Corpus Christi Holdings’ Form 10-K.
| | | | | | | | |
| | |
| By: | /s/ Zach Davis |
| | Zach Davis |
| | President and Chief Financial Officer
(Principal Executive and Financial Officer) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Member and Managers of Cheniere Corpus Christi Holdings, LLC
Cheniere Corpus Christi Holdings, LLC:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Cheniere Corpus Christi Holdings, LLC and subsidiaries (the Company) as of December 31, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Fair value of the level 3 physical liquefaction supply derivatives
As discussed in Notes 2 and 7 to the consolidated financial statements, the Company recorded fair value of level 3 physical liquefaction supply derivatives of $12 million, as of December 31, 2020. The physical liquefaction supply derivatives consist of natural gas supply contracts for the operation of the liquefied natural gas facility. The fair value of the level 3 physical liquefaction supply derivatives is developed through the use of internal models which incorporate significant unobservable inputs.
We identified the evaluation of the fair value of the level 3 physical liquefaction supply derivatives as a critical audit matter. Specifically, there is subjectivity in certain assumptions used to estimate the fair value, including assumptions for future prices of energy units for unobservable periods and liquidity. Additionally, the fair value for certain of the liquefaction supply derivatives is derived through the use of complex models, which also include assumptions for volatility.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the valuation of the level 3 physical liquefaction supply derivatives. This included controls related to the assumptions for significant unobservable inputs and the fair value models. For the level 3 liquefaction supply derivatives selected, we involved valuation professionals with specialized skills who assisted in:
•assessing the models and volatility used by the Company in its valuation by developing independent fair value estimates and comparing the independently developed estimates to the Company’s fair value estimates
•testing the future prices of energy units for unobservable periods and liquidity assumptions by comparing to market data, including quoted or published forward prices for similar commodities.
In addition, we evaluated the Company’s assumptions for future prices of energy units for unobservable periods and liquidity by comparing to market or third-party data, including adjustments for third party quoted transportation prices.
We have served as the Company’s auditor since 2015.
Houston, Texas
February 23, 2021
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | | | 2020 | | 2019 | | 2018 |
| Revenues | | | | | | | | | |
| LNG revenues | | | | | $ | 2,046 | | | $ | 679 | | | $ | 0 | |
| LNG revenues—affiliate | | | | | 483 | | | 726 | | | 0 | |
| | | | | | | | | |
| Total revenues | | | | | 2,529 | | | 1,405 | | | 0 | |
| | | | | | | | | |
| Operating costs and expenses | | | | | | | | | |
| Cost of sales (excluding items shown separately below) | | | | | 901 | | | 691 | | | 0 | |
| Cost of sales—affiliate | | | | | 30 | | | 3 | | | 0 | |
| Cost of sales—related party | | | | | 114 | | | 86 | | | 0 | |
| Operating and maintenance expense | | | | | 347 | | | 242 | | | 0 | |
| Operating and maintenance expense—affiliate | | | | | 90 | | | 59 | | | 4 | |
| Operating and maintenance expense—related party | | | | | 6 | | | 0 | | | 0 | |
| Development expense | | | | | 0 | | | 1 | | | 1 | |
| | | | | | | | | |
| General and administrative expense | | | | | 7 | | | 6 | | | 5 | |
| General and administrative expense—affiliate | | | | | 20 | | | 11 | | | 2 | |
| Depreciation and amortization expense | | | | | 342 | | | 231 | | | 10 | |
| Impairment expense and loss on disposal of assets | | | | | 1 | | | 0 | | | 0 | |
| Total operating costs and expenses | | | | | 1,858 | | | 1,330 | | | 22 | |
| | | | | | | | | |
| Income (loss) from operations | | | | | 671 | | | 75 | | | (22) | |
| | | | | | | | | |
| Other income (expense) | | | | | | | | | |
| Interest expense, net of capitalized interest | | | | | (365) | | | (278) | | | 0 | |
| Loss on modification or extinguishment of debt | | | | | (9) | | | (41) | | | (15) | |
| Interest rate derivative gain (loss), net | | | | | (233) | | | (134) | | | 43 | |
| Other income (expense), net | | | | | (1) | | | 4 | | | 0 | |
| Total other income (expense) | | | | | (608) | | | (449) | | | 28 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Net income (loss) | | | | | $ | 63 | | | $ | (374) | | | $ | 6 | |
The accompanying notes are an integral part of these consolidated financial statements.
46
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions)
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2020 | | 2019 |
| ASSETS | | | | |
| Current assets | | | | |
| Cash and cash equivalents | | $ | 0 | | | $ | 0 | |
| Restricted cash | | 70 | | | 80 | |
| Accounts and other receivables, net | | 198 | | | 58 | |
| Accounts receivable—affiliate | | 42 | | | 57 | |
| Advances to affiliate | | 144 | | | 115 | |
| Inventory | | 89 | | | 69 | |
| Derivative assets | | 10 | | | 74 | |
| Derivative assets—related party | | 3 | | | 3 | |
| Other current assets | | 17 | | | 15 | |
| Other current assets—affiliate | | 1 | | | 0 | |
| Total current assets | | 574 | | | 471 | |
| | | | |
| | | | |
| Property, plant and equipment, net | | 12,853 | | | 12,507 | |
| Debt issuance and deferred financing costs, net | | 11 | | | 15 | |
| Non-current derivative assets | | 114 | | | 61 | |
| Non-current derivative assets—related party | | 1 | | | 2 | |
| | | | |
| Other non-current assets, net | | 87 | | | 56 | |
| | | | |
| Total assets | | $ | 13,640 | | | $ | 13,112 | |
| | | | |
| LIABILITIES AND MEMBER’S EQUITY | | | | |
| Current liabilities | | | | |
| Accounts payable | | $ | 19 | | | $ | 7 | |
| | | | |
| Accrued liabilities | | 318 | | | 370 | |
| Accrued liabilities—related party | | 16 | | | 3 | |
| Current debt | | 269 | | | 0 | |
| Due to affiliates | | 32 | | | 27 | |
| Derivative liabilities | | 143 | | | 46 | |
| | | | |
| Other current liabilities—affiliate | | 0 | | | 1 | |
| Total current liabilities | | 797 | | | 454 | |
| | | | |
| Long-term debt, net | | 10,101 | | | 10,093 | |
| Non-current derivative liabilities | | 114 | | | 135 | |
| | | | |
| Other non-current liabilities | | 4 | | | 11 | |
| Other non-current liabilities—affiliate | | 0 | | | 1 | |
| | | | |
| Commitments and contingencies (see Note 13) | | 0 | | 0 |
| | | | |
| Member’s equity | | 2,624 | | | 2,418 | |
| Total liabilities and member’s equity | | $ | 13,640 | | | $ | 13,112 | |
The accompanying notes are an integral part of these consolidated financial statements.
47
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
(in millions)
| | | | | | | | | | | |
| Year Ended December 31, 2020 | | | |
| Cheniere CCH HoldCo I, LLC | | Total Member’s Equity |
| Balance at December 31, 2017 | $ | 1,667 | | | $ | 1,667 | |
| Capital contributions | 408 | | | 408 | |
| | | |
| Net income | 6 | | | 6 | |
| Balance at December 31, 2018 | 2,081 | | | 2,081 | |
| Capital contributions | 711 | | | 711 | |
| Net loss | (374) | | | (374) | |
| Balance at December 31, 2019 | 2,418 | | | 2,418 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Capital contributions | 145 | | | 145 | |
| | | |
| Distributions | (2) | | | (2) | |
| Net income | 63 | | | 63 | |
| Balance at December 31, 2020 | $ | 2,624 | | | $ | 2,624 | |
The accompanying notes are an integral part of these consolidated financial statements.
48
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| Cash flows from operating activities | | | | | |
| Net income (loss) | $ | 63 | | | $ | (374) | | | $ | 6 | |
| Adjustments to reconcile net loss to net cash used in operating activities: | | | | | |
| Depreciation and amortization expense | 342 | | | 231 | | | 10 | |
| Amortization of discount and debt issuance costs | 20 | | | 16 | | | 0 | |
| Loss on modification or extinguishment of debt | 9 | | | 41 | | | 15 | |
| Total losses (gains) on derivatives, net | 261 | | | 88 | | | (43) | |
| Total losses on derivatives, net—related party | 1 | | | 1 | | | 0 | |
| Net cash used for settlement of derivative instruments | (174) | | | (30) | | | (7) | |
| Impairment expense and loss on disposal of assets | 1 | | | 0 | | | 0 | |
| Other | 3 | | | 2 | | | 0 | |
| Changes in operating assets and liabilities: | | | | | |
| Accounts receivable | (138) | | | (58) | | | 0 | |
| Accounts receivable—affiliate | 15 | | | (57) | | | 0 | |
| Advances to affiliate | (11) | | | (53) | | | (11) | |
| Inventory | (18) | | | (37) | | | (25) | |
| Accounts payable and accrued liabilities | 63 | | | 174 | | | 10 | |
| Accrued liabilities—related party | 11 | | | 3 | | | 0 | |
| Due to affiliates | 5 | | | 15 | | | 1 | |
| Other, net | (56) | | | 5 | | | (17) | |
| Other, net—affiliate | (1) | | | 0 | | | 0 | |
| Net cash provided by (used in) operating activities | 396 | | | (33) | | | (61) | |
| | | | | |
| Cash flows from investing activities | | | | | |
| Property, plant and equipment, net | (790) | | | (1,517) | | | (2,963) | |
| Other | (6) | | | (2) | | | 3 | |
| Net cash used in investing activities | (796) | | | (1,519) | | | (2,960) | |
| | | | | |
| Cash flows from financing activities | | | | | |
| Proceeds from issuances of debt | 1,050 | | | 4,203 | | | 3,115 | |
| Repayments of debt | (797) | | | (3,544) | | | (301) | |
| Debt issuance and deferred financing costs | (8) | | | (16) | | | (46) | |
| Debt extinguishment cost | 0 | | | (11) | | | (9) | |
| Capital contributions | 145 | | | 711 | | | 324 | |
| | | | | |
| Net cash provided by financing activities | 390 | | | 1,343 | | | 3,083 | |
| | | | | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | (10) | | | (209) | | | 62 | |
| Cash, cash equivalents and restricted cash—beginning of period | 80 | | | 289 | | | 227 | |
| Cash, cash equivalents and restricted cash—end of period | $ | 70 | | | $ | 80 | | | $ | 289 | |
Balances per Consolidated Balance Sheets:
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| Cash and cash equivalents | $ | 0 | | | $ | 0 | |
| Restricted cash | 70 | | | 80 | |
| | | |
| Total cash, cash equivalents and restricted cash | $ | 70 | | | $ | 80 | |
The accompanying notes are an integral part of these consolidated financial statements.
49
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
CCH is a Houston-based Delaware limited liability company formed in September 2014 by Cheniere to hold its limited partner interest in CCP and its equity interests in CCL and CCP GP. We are operating and constructing a natural gas liquefaction and export facility (the “Liquefaction Facilities”) and operating a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) near Corpus Christi, Texas, through our subsidiaries CCL and CCP, respectively. We are currently operating 2 Trains and 1 additional Train is undergoing commissioning that is expected to be substantially completed in the first quarter of 2021, for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain 3 LNG storage tanks and 2 marine berths.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Consolidated Financial Statements have been prepared in accordance with GAAP. Our Consolidated Financial Statements include the accounts of CCH and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Recent Accounting Standards
In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.
Use of Estimates
The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements, revenue recognition, property, plant and equipment, derivative instruments and asset retirement obligations (“AROs”), as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include AROs.
Revenue Recognition
We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash
Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets.
Accounts Receivable
Accounts receivable is reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Consolidated Statements of Operations. We did 0t have any current expected credit losses on our accounts receivable as of December 31, 2020 and 2019.
Inventory
LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued.
Accounting for LNG Activities
Generally, we begin capitalizing the costs of our LNG terminal once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminal.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets.
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We did 0t record any impairments related to property, plant and equipment during the years ended December 31, 2020, 2019 and 2018.
Interest Capitalization
We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset.
Regulated Natural Gas Pipelines
The Corpus Christi Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities.
Items that may influence our assessment are:
•inability to recover cost increases due to rate caps and rate case moratoriums;
•inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;
•excess capacity;
•increased competition and discounting in the markets we serve; and
•impacts of ongoing regulatory initiatives in the natural gas industry.
Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipeline. Under regulatory rate practices, we
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipeline is placed in service.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.
Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did 0t have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2020, 2019 and 2018. See Note 7—Derivative Instruments for additional details about our derivative instruments.
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of restricted cash, derivative instruments and accounts receivable. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.
CCL has entered into fixed price long-term SPAs generally with terms of 20 years with 9 third parties and have entered into agreements with Cheniere Marketing International LLP (“Cheniere Marketing”). CCL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 14—Customer Concentration for additional details about our customer concentration.
Debt
Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.
Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, they are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in gain (loss) on modification or extinguishment of debt on our Consolidated Statements of Operations.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
We have 0t recorded an ARO associated with the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.
Income Taxes
We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. Accordingly, 0 provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.
Business Segment
Our liquefaction and pipeline business at the Corpus Christi LNG terminal represents a single reportable segment. Our chief operating decision maker reviews the financial results of CCH in total when evaluating financial performance and for purposes of allocating resources.
NOTE 3—RESTRICTED CASH
Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2020 and 2019, we had $70 million and $80 million of current restricted cash, respectively.
Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.
NOTE 4—ACCOUNTS AND OTHER RECEIVABLES
As of December 31, 2020 and 2019, accounts and other receivables, net consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2020 | | 2019 |
| Trade receivable | | $ | 182 | | | $ | 44 | |
| Other accounts receivable | | 16 | | | 14 | |
| Total accounts and other receivables, net | | $ | 198 | | | $ | 58 | |
NOTE 5—INVENTORY
As of December 31, 2020 and 2019, inventory consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2020 | | 2019 |
| Natural gas | | $ | 9 | | | $ | 7 | |
| LNG | | 11 | | | 6 | |
| Materials and other | | 69 | | | 56 | |
| Total inventory | | $ | 89 | | | $ | 69 | |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 6—PROPERTY, PLANT AND EQUIPMENT
As of December 31, 2020 and 2019, property, plant and equipment, net consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2020 | | 2019 |
| LNG terminal costs | | | | |
| LNG terminal and interconnecting pipeline facilities | | $ | 10,176 | | | $ | 10,027 | |
| LNG site and related costs | | 276 | | | 276 | |
| LNG terminal construction-in-process | | 2,960 | | | 2,425 | |
| Accumulated depreciation | | (568) | | | (232) | |
| Total LNG terminal costs, net | | 12,844 | | | 12,496 | |
| Fixed assets | | | | |
| Fixed assets | | 22 | | | 19 | |
| Accumulated depreciation | | (13) | | | (8) | |
| Total fixed assets, net | | 9 | | | 11 | |
| Property, plant and equipment, net | | $ | 12,853 | | | $ | 12,507 | |
The following table shows depreciation expense and offsets to LNG terminal costs during the years ended December 31, 2020, 2019 and 2018 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2020 | | 2019 | | 2018 |
| Depreciation expense | | | | | | $ | 341 | | | $ | 230 | | | $ | 10 | |
| Offsets to LNG terminal costs (1) | | | | | | 32 | | | 156 | | | 49 | |
(1) We realize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the Liquefaction Project during the testing phase for its construction.
LNG Terminal Costs
LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 10 and 50 years, as follows:
| | | | | | | | |
| Components | | Useful life (yrs) |
| Water pipelines | | 30 |
| Natural gas pipeline facilities | | 40 |
| Liquefaction processing equipment | | 10-50 |
| Other | | 15-30 |
Fixed Assets and Other
Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 7—DERIVATIVE INSTRUMENTS
We have entered into the following derivative instruments that are reported at fair value:
•interest rate swaps (“CCH Interest Rate Derivatives”) to hedge the exposure to volatility in a portion of the floating-rate interest payments on our amended and restated credit facility (the “CCH Credit Facility”) and to hedge against changes in interest rates that could impact anticipated future issuance of debt (“CCH Interest Rate Forward Start Derivatives” and, collectively with the CCH Interest Rate Derivatives, the “Interest Rate Derivatives”) and
•commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.
The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2020 and 2019, which are classified as derivative assets, derivative assets—related party, non-current derivative assets, non-current derivative assets—related party, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements as of |
| December 31, 2020 | | December 31, 2019 |
| Quoted Prices in Active Markets
(Level 1) | | Significant Other Observable Inputs
(Level 2) | | Significant Unobservable Inputs
(Level 3) | | Total | | Quoted Prices in Active Markets
(Level 1) | | Significant Other Observable Inputs
(Level 2) | | Significant Unobservable Inputs
(Level 3) | | Total |
| CCH Interest Rate Derivatives liability | $ | 0 | | | $ | (140) | | | $ | 0 | | | $ | (140) | | | $ | 0 | | | $ | (81) | | | $ | 0 | | | $ | (81) | |
| CCH Interest Rate Forward Start Derivatives liability | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (8) | | | 0 | | | (8) | |
| Liquefaction Supply Derivatives asset (liability) | 4 | | | (5) | | | 12 | | | 11 | | | 3 | | | 10 | | | 35 | | | 48 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
We value our Interest Rate Derivatives using an income-based approach utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.
The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of December 31, 2020 and 2019, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.
We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net Fair Value Asset
(in millions) | | Valuation Approach | | Significant Unobservable Input | | Range of Significant Unobservable Inputs / Weighted Average (1) |
| Physical Liquefaction Supply Derivatives | | $12 | | Market approach incorporating present value techniques | | Henry Hub basis spread | | $(0.532) - $0.092 / $(0.056) |
| | | | Option pricing model | | International LNG pricing spread, relative to Henry Hub (2) | | 117% - 480% / 154% |
(1) Unobservable inputs were weighted by the relative fair value of the instruments.
(2) Spread contemplates U.S. dollar-denominated pricing.
Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.
The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives, including those with related parties, during the years ended December 31, 2020, 2019 and 2018 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2020 | | 2019 | | 2018 |
| Balance, beginning of period | | | | | | $ | 35 | | | $ | (4) | | | $ | 0 | |
| Realized and mark-to-market gains (losses): | | | | | | | | | | |
| Included in cost of sales | | | | | | 28 | | | (83) | | | (10) | |
| Purchases and settlements: | | | | | | | | | | |
| Purchases | | | | | | 0 | | | 121 | | | 6 | |
| Settlements | | | | | | (58) | | | 1 | | | 0 | |
| Transfers into Level 3, net (1) | | | | | | 7 | | | 0 | | | 0 | |
| Balance, end of period | | | | | | $ | 12 | | | $ | 35 | | | $ | (4) | |
| Change in unrealized gain (loss) relating to instruments still held at end of period | | | | | | $ | 28 | | | $ | (83) | | | $ | (10) | |
(1) Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.
Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.
Interest Rate Derivatives
We have entered into interest rate swaps to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the CCH Credit Facility. We previously also had interest rate swaps to hedge against changes in interest rates that could impact anticipated future issuance of debt. In August 2020, we settled the outstanding CCH Interest Rate Forward Start Derivatives.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
As of December 31, 2020, we had the following Interest Rate Derivatives outstanding:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Notional Amounts | | | | | | |
| | December 31, 2020 | | December 31, 2019 | | Maturity Date | | Weighted Average Fixed Interest Rate Paid | | Variable Interest Rate Received |
| CCH Interest Rate Derivatives | | $4.6 billion | | $4.5 billion | | May 31, 2022 | | 2.30% | | One-month LIBOR |
| | | | | | | | | | |
| | | | | | | | | | |
The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in interest rate derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2020, 2019 and 2018 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2020 | | 2019 | | 2018 |
| CCH Interest Rate Derivatives gain (loss) | | | | | | $ | (138) | | | $ | (101) | | | $ | 43 | |
| CCH Interest Rate Forward Start Derivatives loss | | | | | | (95) | | | (33) | | | 0 | |
Liquefaction Supply Derivatives
CCL has entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain conditions precedent.
The forward notional for our Liquefaction Supply Derivatives was approximately 3,152 TBtu and 3,153 TBtu as of December 31, 2020 and 2019, respectively, of which 60 TBtu and 120 TBtu, respectively, were for a natural gas supply contract CCL has with a related party.
The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2020, 2019 and 2018 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Statements of Operations Location (1) | | | Year Ended December 31, |
| | | | | 2020 | | 2019 | | 2018 |
| Liquefaction Supply Derivatives loss | LNG revenues | | | | | $ | (1) | | | $ | 0 | | | $ | 0 | |
| Liquefaction Supply Derivatives gain (loss) | Cost of sales | | | | | (27) | | | 46 | | | 0 | |
| Liquefaction Supply Derivatives loss | Cost of sales—related party | | | | | (1) | | | (1) | | | 0 | |
(1) Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets
The following table shows the fair value and location of our derivative instruments on our Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 |
| CCH Interest Rate Derivatives | | CCH Interest Rate Forward Start Derivatives | | Liquefaction Supply Derivatives (1) | | Total |
| Consolidated Balance Sheets Location | | | | | | | |
| Derivative assets | $ | 0 | | | $ | 0 | | | $ | 10 | | | $ | 10 | |
| Derivative assets—related party | 0 | | | 0 | | | 3 | | | 3 | |
| Non-current derivative assets | 0 | | | 0 | | | 114 | | | 114 | |
| Non-current derivative assets—related party | 0 | | | 0 | | | 1 | | | 1 | |
| Total derivative assets | 0 | | | 0 | | | 128 | | | 128 | |
| | | | | | | |
| Derivative liabilities | (100) | | | 0 | | | (43) | | | (143) | |
| Non-current derivative liabilities | (40) | | | 0 | | | (74) | | | (114) | |
| Total derivative liabilities | (140) | | | 0 | | | (117) | | | (257) | |
| | | | | | | |
| Derivative asset (liability), net | $ | (140) | | | $ | 0 | | | $ | 11 | | | $ | (129) | |
| | | | | | | |
| December 31, 2019 |
| CCH Interest Rate Derivatives | | CCH Interest Rate Forward Start Derivatives | | Liquefaction Supply Derivatives (1) | | Total |
| Consolidated Balance Sheets Location | | | | | | | |
| Derivative assets | $ | 0 | | | $ | 0 | | | $ | 74 | | | $ | 74 | |
| Derivative assets—related party | 0 | | | 0 | | | 3 | | | 3 | |
| Non-current derivative assets | 0 | | | 0 | | | 61 | | | 61 | |
| Non-current derivative assets—related party | 0 | | | 0 | | | 2 | | | 2 | |
| Total derivative assets | 0 | | | 0 | | | 140 | | | 140 | |
| | | | | | | |
| Derivative liabilities | (32) | | | (8) | | | (6) | | | (46) | |
| Non-current derivative liabilities | (49) | | | 0 | | | (86) | | | (135) | |
| Total derivative liabilities | (81) | | | (8) | | | (92) | | | (181) | |
| | | | | | | |
| Derivative asset (liability), net | $ | (81) | | | $ | (8) | | | $ | 48 | | | $ | (41) | |
(1) Does not include collateral posted with counterparties by us of $5 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of both December 31, 2020 and 2019.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Consolidated Balance Sheets Presentation
Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | CCH Interest Rate Derivatives | | CCH Interest Rate Forward Start Derivatives | | Liquefaction Supply Derivatives |
| | | |
| As of December 31, 2020 | | | | | | |
| Gross assets | | $ | 0 | | | $ | 0 | | | $ | 132 | |
| Offsetting amounts | | 0 | | | 0 | | | (4) | |
| Net assets | | $ | 0 | | | $ | 0 | | | $ | 128 | |
| | | | | | |
| Gross liabilities | | $ | (140) | | | $ | 0 | | | $ | (136) | |
| Offsetting amounts | | 0 | | | 0 | | | 19 | |
| Net liabilities | | $ | (140) | | | $ | 0 | | | $ | (117) | |
| | | | | | |
| As of December 31, 2019 | | | | | | |
| Gross assets | | $ | 0 | | | $ | 0 | | | $ | 145 | |
| Offsetting amounts | | 0 | | | 0 | | | (5) | |
| Net assets | | $ | 0 | | | $ | 0 | | | $ | 140 | |
| | | | | | |
| Gross liabilities | | $ | (81) | | | $ | (8) | | | $ | (98) | |
| Offsetting amounts | | 0 | | | 0 | | | 6 | |
| Net liabilities | | $ | (81) | | | (8) | | | $ | (92) | |
NOTE 8—OTHER NON-CURRENT ASSETS
As of December 31, 2020 and 2019, other non-current assets, net consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2020 | | 2019 |
| Advances and other asset conveyances to third parties to support LNG terminal | | $ | 22 | | | $ | 19 | |
| Operating lease assets | | 5 | | | 7 | |
| Tax-related payments and receivables | | 3 | | | 3 | |
| Information technology service prepayments | | 3 | | | 3 | |
| Advances made under EPC and non-EPC contracts | | 0 | | | 14 | |
| Contract assets, net | | 48 | | | 0 | |
| Other | | 6 | | | 10 | |
| Total other non-current assets, net | | $ | 87 | | | $ | 56 | |
NOTE 9—ACCRUED LIABILITIES
As of December 31, 2020 and 2019, accrued liabilities consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2020 | | 2019 |
| Interest costs and related debt fees | | $ | 7 | | | $ | 8 | |
| Accrued natural gas purchases | | 186 | | | 132 | |
| Liquefaction Project costs | | 76 | | | 192 | |
| Other | | 49 | | | 38 | |
| Total accrued liabilities | | $ | 318 | | | $ | 370 | |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 10—DEBT
As of December 31, 2020 and 2019, our debt consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2020 | | 2019 |
| Long-term debt: | | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| 3.520% to 7.000% senior secured notes due between 2024 and 2039 and CCH Credit Facility | | $ | 10,217 | | | $ | 10,235 | |
| Unamortized debt issuance costs | | (116) | | | (142) | |
| Total long-term debt, net | | 10,101 | | | 10,093 | |
| | | | |
| Current debt: | | | | |
| $1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) and current portion of CCH Credit Facility | | 271 | | | 0 | |
| Unamortized premium, discount and debt issuance costs, net | | (2) | | | 0 | |
| Total current debt | | 269 | | | 0 | |
| | | | |
| Total debt, net | | $ | 10,370 | | | $ | 10,093 | |
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, 2020 (in millions):
| | | | | | | | |
| Years Ending December 31, | | Principal Payments |
| 2021 | | $ | 271 | |
| 2022 | | 89 | |
| 2023 | | 101 | |
| 2024 | | 3,556 | |
| 2025 | | 1,500 | |
| Thereafter | | 4,971 | |
| Total | | $ | 10,488 | |
Issuances and Repayments
The following table shows the issuances and repayments of long-term debt during the year ended December 31, 2020 (in millions):
| | | | | | | | | | | | |
| Issuances | | | | | | Principal Amount Issued |
| | | | | | |
| 3.52% Senior Secured Notes due 2039 (the “3.52% Senior Secured Notes”) (1) | | | | | | $ | 769 | |
| | | | | | |
| Year Ended December 31, 2020 total | | | | | | $ | 769 | |
| | | | | | |
| Repayments | | | | | | Amount Repaid |
| CCH Credit Facility (1) | | $ | (656) | |
| | | | | | |
| Year Ended December 31, 2020 total | | | | | | $ | (656) | |
(1)Proceeds of the 3.52% Senior Secured Notes were used to repay a portion of the outstanding borrowings under the CCH Credit Facility, pay costs associated with certain interest rate derivative instruments that were settled and pay certain fees, costs and expenses incurred in connection with these transactions. The repayment of the CCH Credit Facility resulted in the recognition of debt extinguishment costs of $9 million for the year ended December 31, 2020 relating to the write off of unamortized debt discounts and issuance costs.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Credit Facilities
Below is a summary of our credit facilities outstanding as of December 31, 2020 (in millions):
| | | | | | | | | | | | | | |
| | CCH Credit Facility (1) | | CCH Working Capital Facility |
| Original facility size | | $ | 8,404 | | | $ | 350 | |
| Incremental commitments | | 1,566 | | | 850 | |
| Less: | | | | |
| Outstanding balance | | 2,627 | | | 140 | |
| Commitments terminated | | 7,343 | | | 0 | |
| Letters of credit issued | | 0 | | | 293 | |
| Available commitment | | $ | 0 | | | $ | 767 | |
| | | | |
| Priority ranking | | Senior secured | | Senior secured |
| Interest rate on available balance | | LIBOR plus 1.75% or base rate plus 0.75% | | LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75% |
| Weighted average interest rate of outstanding balance | | 1.90% | | 1.40% |
| Maturity date | | June 30, 2024 | | June 29, 2023 |
(1)We prepaid $656 million of outstanding borrowings under the CCH Credit Facility during the year ended December 31, 2020 using proceeds from the issuance of the 3.52% Senior Secured Notes.
Restrictive Debt Covenants
The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us and our restricted subsidiaries’ ability to make certain investments or pay dividends or distributions.
As of December 31, 2020, we were in compliance with all covenants related to our debt agreements.
Interest Expense
Total interest expense, net of capitalized interest consisted of the following (in millions):
| | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | 2020 | | 2019 | | 2018 |
| Total interest cost | | | | | $ | 484 | | | $ | 539 | | | $ | 451 | |
| Capitalized interest, including amounts capitalized as an Allowance for Funds Used During Construction | | | | | (119) | | | (261) | | | (451) | |
| Total interest expense, net of capitalized interest | | | | | $ | 365 | | | $ | 278 | | | $ | 0 | |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Fair Value Disclosures
The following table shows the carrying amount and estimated fair value of our debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2020 | | December 31, 2019 |
| | | Carrying
Amount | | Estimated
Fair Value | | Carrying
Amount | | Estimated
Fair Value |
| Senior notes — Level 2 (1) | | $ | 5,750 | | | $ | 6,669 | | | $ | 5,750 | | | $ | 6,329 | |
| Senior notes — Level 3 (2) | | 1,971 | | | 2,387 | | | 1,202 | | | 1,325 | |
| | | | | | | | |
| Credit facilities (3) | | 2,767 | | | 2,767 | | | 3,283 | | | 3,283 | |
(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
(3)The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.
NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS
The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2020, 2019 and 2018 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2020 | | 2019 | | 2018 |
| LNG revenues (1) | | | | | | $ | 2,047 | | | $ | 679 | | | $ | 0 | |
| LNG revenues—affiliate | | | | | | 483 | | | 726 | | | 0 | |
| Total revenues from customers | | | | | | 2,530 | | | 1,405 | | | 0 | |
| Net derivative losses (2) | | | | | | (1) | | | 0 | | | 0 | |
| Total revenues | | | | | | $ | 2,529 | | | $ | 1,405 | | | $ | 0 | |
(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized subsequent to December 31, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.
LNG Revenues
We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at the Corpus Christi LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 12—Related Party Transactions for additional information regarding these agreements.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Corpus Christi LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price.
Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.
Contract Assets
The following table shows our contract assets, net, which are classified as other non-current assets, net on our Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2020 | | 2019 |
| Contract assets, net | | $ | 48 | | | $ | 0 | |
Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the year ended December 31, 2020 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.
Transaction Price Allocated to Future Performance Obligations
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2020 | | December 31, 2019 |
| | Unsatisfied
Transaction Price
(in billions) | | Weighted Average Recognition Timing (years) (1) | | Unsatisfied
Transaction Price
(in billions) | | Weighted Average Recognition Timing (years) (1) |
| LNG revenues | | $ | 32.3 | | | 10 | | $ | 33.6 | | | 11 |
| LNG revenues—affiliate | | 1.0 | | | 12 | | 1.0 | | | 13 |
| Total revenues | | $ | 33.3 | | | | | $ | 34.6 | | | |
(1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 33% and 44% of our LNG revenues from contracts included in the table above during the years ended December 31, 2020 and 2019, respectively, were related to variable consideration received from customers.
We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.
NOTE 12—RELATED PARTY TRANSACTIONS
Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | | | 2020 | | 2019 | | 2018 |
| LNG revenues—affiliate | | | | | | | | | |
| Cheniere Marketing Agreements | | | | | $ | 468 | | | $ | 719 | | | $ | 0 | |
| Contracts for Sale and Purchase of Natural Gas and LNG | | | | | 15 | | | 7 | | | 0 | |
| Total LNG revenues—affiliate | | | | | 483 | | | 726 | | | 0 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Cost of sales—affiliate | | | | | | | | | |
| Contracts for Sale and Purchase of Natural Gas and LNG | | | | | 30 | | | 3 | | | 0 | |
| | | | | | | | | |
| Cost of sales—related party | | | | | | | | | |
| Natural Gas Supply Agreement | | | | | 114 | | | 85 | | | 0 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Operating and maintenance expense—affiliate | | | | | | | | | |
| Services Agreements | | | | | 89 | | | 58 | | | 3 | |
| Land Agreements | | | | | 1 | | | 1 | | | 1 | |
| | | | | | | | | |
| Total operating and maintenance expense—affiliate | | | | | 90 | | | 59 | | | 4 | |
| | | | | | | | | |
| Operating and maintenance expense—related party | | | | | | | | | |
| Natural Gas Transportation Agreements | | | | | 6 | | | 0 | | | 0 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| General and administrative expense—affiliate | | | | | | | | | |
| Services Agreements | | | | | 20 | | | 12 | | | 3 | |
We had $32 million and $27 million due to affiliates as of December 31, 2020 and 2019, respectively, under agreements with affiliates, as described below.
Cheniere Marketing Agreements
Cheniere Marketing SPA
CCL has a fixed price SPA with Cheniere Marketing (the “Cheniere Marketing Base SPA”) with a term of 20 years which allows Cheniere Marketing to purchase, at its option, (1) up to a cumulative total of 150 TBtu of LNG within the commissioning periods for Trains 1 through 3 and (2) any excess LNG produced by the Liquefaction Facilities that is not committed to customers under third-party SPAs. Under the Cheniere Marketing Base SPA, Cheniere Marketing may, without charge, elect to suspend deliveries of cargoes (other than commissioning cargoes) scheduled for any month under the applicable annual delivery program by providing specified notice in advance. Additionally, CCL has: (1) a fixed price SPA with an approximate term of 23 years with Cheniere Marketing which allows them to purchase volumes of approximately 15 TBtu per annum of LNG and (2) an SPA for approximately 44 TBtu of LNG with a term of up to seven years associated with the integrated production marketing gas supply agreement between CCL and EOG Resources, Inc. As of December 31, 2020 and
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
2019, CCL had $39 million and $57 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing.
Train 3 Commissioning Letter Agreement
Under the Cheniere Marketing Base SPA, CCL entered into a letter agreement with Cheniere Marketing for the sale of commissioning cargoes from Train 3 of the Liquefaction Project. Under the agreement, CCL paid a one-time shipping fee to Cheniere Marketing of $1 million after the commissioning of Train 3 in December 2020.
Facility Swap Agreement
We have entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.
Services Agreements
Gas and Power Supply Services Agreement (“G&P Agreement”)
CCL has a G&P Agreement with Cheniere Energy Shared Services, Inc. (“Shared Services”), a wholly owned subsidiary of Cheniere, pursuant to which Shared Services will manage the gas and power procurement requirements of CCL. The services include, among other services, exercising the day-to-day management of CCL’s natural gas and power supply requirements, negotiating agreements on CCL’s behalf and providing other administrative services. Prior to the substantial completion of each Train of the Liquefaction Facilities, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facilities, for services performed while the Liquefaction Facilities is operational, CCL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train.
Operation and Maintenance Agreements (“O&M Agreements”)
CCL has an O&M Agreement (“CCL O&M Agreement”) with Cheniere LNG O&M Services, LLC (“O&M Services”), a wholly owned subsidiary of Cheniere, pursuant to which CCL receives all of the necessary services required to construct, operate and maintain the Liquefaction Facilities. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors, administering various agreements, information technology services and other services required to operate and maintain the Liquefaction Facilities. Prior to the substantial completion of each Train of the Liquefaction Facilities, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facilities, for services performed while the Liquefaction Facilities is operational, CCL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train.
CCP has an O&M Agreement (“CCP O&M Agreement”) with O&M Services pursuant to which CCP receives all of the necessary services required to construct, operate and maintain the Corpus Christi Pipeline. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors, information technology services and other services required to operate and maintain the Corpus Christi Pipeline. CCP is required to reimburse O&M Services for all operating expenses incurred on behalf of CCP.
Management Services Agreements (“MSAs”)
CCL has a MSA with Shared Services pursuant to which Shared Services manages the construction and operation of the Liquefaction Facilities, excluding those matters provided for under the G&P Agreement and the CCL O&M Agreement. The services include, among other services, exercising the day-to-day management of CCL’s affairs and business, managing CCL’s regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Liquefaction Facilities and obtaining insurance. Prior to the substantial completion of each Train of the Liquefaction Facilities,
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
no monthly fee payment is required except for reimbursement of expenses. After substantial completion of each Train, CCL will pay, in addition to the reimbursement of related expenses, a monthly fee equal to 3% of the capital expenditures incurred in the previous month and a fixed monthly fee of $375,000 for services with respect to such Train.
CCP has a MSA with Shared Services pursuant to which Shared Services manages CCP’s operations and business, excluding those matters provided for under the CCP O&M Agreement. The services include, among other services, exercising the day-to-day management of CCP’s affairs and business, managing CCP’s regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Corpus Christi Pipeline and obtaining insurance. CCP is required to reimburse Shared Services for the aggregate of all costs and expenses incurred in the course of performing the services under the MSA.
Natural Gas Supply Agreement
CCL is party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain feed gas for the operation of the Liquefaction Project through March 2022. In addition to the amounts recorded on our Consolidated Statements of Operations in the table above, CCL recorded accrued liabilities—related party of $13 million and $3 million, derivative assets—related party of $3 million and $3 million and non-current derivative assets—related party of $1 million and $2 million as of December 31, 2020 and 2019, respectively, related to this agreement.
Natural Gas Transportation Agreements
Agreements with Related Party
CCL is party to natural gas transportation agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project, for a period of 10 years beginning in May 2020. In addition to the amounts recorded on our Consolidated Statements of Operations in the table above, CCL recorded accrued liabilities—related party of $1 million and 0 as of December 31, 2020 and 2019, respectively, related to this agreement.
Agreements with Cheniere Corpus Christi Liquefaction Stage III, LLC
Cheniere Corpus Christi Liquefaction Stage III, LLC, a wholly owned subsidiary of Cheniere, has a transportation precedent agreement with CCP to secure firm pipeline transportation capacity for the transportation of natural gas feedstock to the expansion of the Corpus Christi LNG terminal it is constructing adjacent to the Liquefaction Project. The agreement will have a primary term of 20 years from the service commencement date with right to extend the term for 2 successive five-year terms.
Contracts for Sale and Purchase of Natural Gas and LNG
CCL has an agreement with Sabine Pass Liquefaction, LLC that allows them to sell and purchase natural gas with each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under this agreement is recorded as LNG revenues—affiliate.
CCL also has an agreement with Midship Pipeline Company, LLC that allows them to sell and purchase natural gas with each other.
Land Agreements
Lease Agreements
CCL has agreements with Cheniere Land Holdings, LLC (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, to lease the land owned by Cheniere Land Holdings for the Liquefaction Facilities. The total annual lease payment is $0.6 million, and the terms of the agreements range from three to seven years.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Easement Agreements
CCL has agreements with Cheniere Land Holdings which grant CCL easements on land owned by Cheniere Land Holdings for the Liquefaction Facilities. The total annual payment for easement agreements is $0.1 million, excluding any previously paid one-time payments, and the terms of the agreements range from three to five years.
Dredge Material Disposal Agreement
CCL has a dredge material disposal agreement with Cheniere Land Holdings that terminates in 2042 which grants CCL permission to use land owned by Cheniere Land Holdings for the deposit of dredge material from the construction and maintenance of the Liquefaction Facilities. Under the terms of the agreement, CCL will pay Cheniere Land Holdings $0.50 per cubic yard of dredge material deposits up to 5.0 million cubic yards and $4.62 per cubic yard for any quantities above that.
Tug Hosting Agreement
In February 2017, CCL entered into a tug hosting agreement with Corpus Christi Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of Cheniere, to provide certain marine structures, support services and access necessary at the Liquefaction Facilities for Tug Services to provide its customers with tug boat and marine services. Tug Services is required to reimburse CCL for any third party costs incurred by CCL in connection with providing the goods and services.
State Tax Sharing Agreements
CCL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CCL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CCL will pay to Cheniere an amount equal to the state and local tax that CCL would be required to pay if CCL’s state and local tax liability were calculated on a separate company basis. There have been 0 state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CCL under this agreement; therefore, Cheniere has not demanded any such payments from CCL. The agreement is effective for tax returns due on or after May 2015.
CCP has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CCP and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CCP will pay to Cheniere an amount equal to the state and local tax that CCP would be required to pay if CCP’s state and local tax liability were calculated on a separate company basis. There have been 0 state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CCP under this agreement; therefore, Cheniere has not demanded any such payments from CCP. The agreement is effective for tax returns due on or after May 2015.
Equity Contribution Agreements
Equity Contribution Agreement
In May 2018, we amended and restated the existing equity contribution agreement with Cheniere (the “Equity Contribution Agreement”) pursuant to which Cheniere agreed to provide cash contributions up to approximately $1.1 billion, not including $2.0 billion previously contributed under the original equity contribution agreement. As of December 31, 2020, we have received $703 million in contributions under the Equity Contribution Agreement and Cheniere has posted $124 million of letters of credit on our behalf. Cheniere is only required to make additional contributions under the Equity Contribution Agreement after the commitments under the CCH Credit Facility have been reduced to 0 and to the extent cash flows from operations of the Liquefaction Project are unavailable for Liquefaction Project costs.
NOTE 13—COMMITMENTS AND CONTINGENCIES
We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2020, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
LNG Terminal Commitments and Contingencies
Obligations under EPC Contracts
CCL has a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Train 3 of the Liquefaction Project. The EPC contract price for Train 3 of the Liquefaction Project is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2020. As of December 31, 2020, we have incurred $2.4 billion under this contract. CCL has the right to terminate each of the EPC contracts for its convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.
Obligations under SPAs
CCL has third-party SPAs which obligate CCL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project. CCL has also entered into SPAs with Cheniere Marketing, as further described in Note 12—Related Party Transactions.
Obligations under Natural Gas Supply, Transportation and Storage Service Agreements
CCL has physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. As of December 31, 2020, CCL had secured up to approximately 2,938 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the certain events or states of affairs are satisfied.
Additionally, CCL has natural gas transportation and storage service agreements for the Liquefaction Project. The initial terms of the natural gas transportation agreements range up 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The initial term of the natural gas storage service agreements ranges up to five years.
As of December 31, 2020, CCL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions):
| | | | | |
| Years Ending December 31, | Payments Due (1) |
| 2021 | $ | 1,528 | |
| 2022 | 782 | |
| 2023 | 567 | |
| 2024 | 483 | |
| 2025 | 373 | |
| Thereafter | 1,794 | |
| Total | $ | 5,527 | |
(1)Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2020. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.
Services Agreements
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
State Tax Sharing Agreement
Other Commitments
In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.
Environmental and Regulatory Matters
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.
Legal Proceedings
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2020, there were 0 pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.
NOTE 14—CUSTOMER CONCENTRATION
The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable, net and contract assets, net balances of 10% or greater of total accounts receivable, net and contract assets, net from external customers:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Percentage of Total Revenues from External Customers | | Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers |
| | | | Year Ended December 31, | | December 31, |
| | | | | | | | | | |
| | | | | | 2020 | | 2019 | | 2018 | | 2020 | | 2019 |
| Customer A | | | | | | 31% | | 57% | | 0% | | 15% | | 38% |
| Customer B | | | | | | 16% | | 23% | | 0% | | * | | 39% |
| Customer C | | | | | | 14% | | 0% | | 0% | | 10% | | 0% |
| Customer D | | | | | | * | | * | | 0% | | 16% | | 0% |
| Customer E | | | | | | * | | 0% | | 0% | | 11% | | * |
| Customer F | | | | | | * | | 0% | | 0% | | 27% | | 0% |
* Less than 10%
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.
| | | | | | | | | | | | | | | | | |
| Revenues from External Customers |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| Spain | $ | 1,001 | | | $ | 451 | | | $ | 0 | |
| Indonesia | 336 | | | 155 | | | 0 | |
| Ireland | 285 | | | 0 | | | 0 | |
| United States | 154 | | | 73 | | | 0 | |
| France | 136 | | | 0 | | | 0 | |
| Singapore | 134 | | | 0 | | | 0 | |
| Total | $ | 2,046 | | | $ | 679 | | | $ | 0 | |
NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in millions):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| Cash paid during the period for interest, net of amounts capitalized | $ | 345 | | | $ | 258 | | | $ | 105 | |
| Non-cash distributions to affiliates for conveyance of assets | 2 | | | 0 | | | 83 | |
The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $86 million, $187 million and $178 million as of December 31, 2020, 2019 and 2018, respectively.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
SUMMARIZED QUARTERLY FINANCIAL DATA
(unaudited)
Summarized Quarterly Financial Data—(in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | First
Quarter | | Second
Quarter | | Third
Quarter | | Fourth
Quarter |
| Year Ended December 31, 2020: | | | | | | | | |
| Revenues | | $ | 533 | | | $ | 654 | | | $ | 443 | | | $ | 899 | |
| Income from operations | | 255 | | | 272 | | | 9 | | | 135 | |
| Net income (loss) | | (51) | | | 156 | | | (88) | | | 46 | |
| | | | | | | | |
| Year Ended December 31, 2019: | | | | | | | | |
| Revenues | | $ | 106 | | | $ | 300 | | | $ | 387 | | | $ | 612 | |
| Income (loss) from operations | | (25) | | | (44) | | | (91) | | | 235 | |
| Net income (loss) | | (71) | | | (189) | | | (273) | | | 159 | |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December 31, 2020, 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
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, 2020 and 2019. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 2020 and 2019 (in millions):
| | | | | | | | | | | | | | |
| | | Fiscal 2020 | | Fiscal 2019 |
| Audit Fees | | $ | 1 | | | $ | 2 | |
| | | | |
| | | | |
Audit Fees—Audit fees for 2020 and 2019 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 2020 and 2019.
Tax Fees—Tax fees for 2019 was for tax consultation services with respect to a sales and use tax analysis for the Liquefaction Project. There were no tax fees in 2020.
Other Fees—There were no other fees in 2020 and 2019.
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, 2020 and 2019.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements and Exhibits
(1) Financial Statements—Cheniere Corpus Christi Holdings, LLC:
(2) Financial Statement Schedules:
All financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.
(3) Exhibits:
Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:
•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
•may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;
•may apply standards of materiality that differ from those of a reasonable investor; and
•were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.
| | | | | | | | | | | | | | | | | | | | | | | |
| Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | Form | Exhibit | Filing Date |
| 3.1 | | | | CCH | S-4 | 3.1 | 1/5/2017 |
| 3.2 | | | | CCH | S-4 | 3.2 | 1/5/2017 |
| 3.3 | | | | CCH | S-4 | 3.3 | 1/5/2017 |
| 3.4 | | | | CCH | S-4 | 3.4 | 1/5/2017 |
| 3.5 | | | | CCH | S-4 | 3.5 | 1/5/2017 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | Form | Exhibit | Filing Date |
| 3.6 | | | | CCH | S-4 | 3.6 | 1/5/2017 |
| 3.7 | | | | CCH | S-4 | 3.7 | 1/5/2017 |
| 3.8 | | | | CCH | S-4 | 3.8 | 1/5/2017 |
| 3.9 | | | | CCH | S-4 | 3.9 | 1/5/2017 |
| 3.10 | | | | CCH | S-4 | 3.10 | 1/5/2017 |
| 3.11 | | | | CCH | S-4 | 3.11 | 1/5/2017 |
| 4.1 | | | | Cheniere | 8-K | 4.1 | 5/18/2016 |
| 4.2 | | | | Cheniere | 8-K | 4.1 | 5/18/2016 |
| 4.3 | | | | Cheniere | 8-K | 4.1 | 12/9/2016 |
| 4.4 | | | | Cheniere | 8-K | 4.1 | 12/9/2016 |
| 4.5 | | | | CCH | 8-K | 4.1 | 5/19/2017 |
| 4.6 | | | | CCH | 8-K | 4.1 | 5/19/2017 |
| 4.7 | | | | CCH | 8-K | 4.1 | 9/12/2019 |
| 4.8 | | | | CCH | 8-K | 4.1 | 9/30/2019 |
| 4.9 | | | | CCH | 8-K | 4.1 | 10/18/2019 |
| 4.10 | | | | CCH | 8-K | 4.1 | 11/13/2019 |
| 4.11 | | | | CCH | 8-K | 4.1 | 8/21/2020 |
| 10.1 | | | | CCH | 8-K | 10.4 | 5/24/2018 |
| 10.2 | | Amended and Restated Common Terms Agreement, dated May 22, 2018, among the Company, CCP, CCP GP, CCL, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, and Société Générale as Intercreditor Agent, and any other facility lenders party thereto from time to time | | CCH | 8-K | 10.2 | 5/24/2018 |
| 10.3 | | | | CCH | 10-K | 10.3 | 2/26/2019 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | Form | Exhibit | Filing Date |
| 10.4 | | | | CCH | 10-Q | 10.2 | 11/1/2019 |
| 10.5* | | Third Amendment to the Amended and Restated Common Terms Agreement, dated as of November 8, 2019, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent | | | | | |
| 10.6* | | Fourth Amendment to the Amended and Restated Common Terms Agreement, dated as of November 26, 2019, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent | | | | | |
| 10.7* | | Fifth Amendment to the Amended and Restated Common Terms Agreement, dated as of November 16, 2020, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent | | | | | |
| 10.8 | | Amended and Restated Common Security and Account Agreement, dated May 22, 2018, among the Company, CCP, CCP GP, CCL, the Senior Creditor Group Representatives, Société Générale as the Intercreditor Agent, Société Générale as Security Trustee and Mizuho Bank, Ltd as the Account Bank | | CCH | | | 5/24/2018 |
| 10.9 | | First Amendment to the Amended and Restated Common Security and Account Agreement, dated as of November 28, 2018, by and among the Company, CCL, CCP and CCP GP, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank | | CCH | 10-K | 10.5 | 2/26/2019 |
| 10.10 | | Second Amendment to Common Security and Account Agreement, dated as of August 30, 2019, by and among the Company, CCL, CCP, CCP GP, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd; as Account Bank | | CCH | 10-Q | 10.3 | 11/1/2019 |
| 10.11* | | Third Amendment to Common Security and Account Agreement, dated as of November 16, 2020, by and among the Company, CCL, CCP, Corpus Christi Pipeline GP, LLC, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd; as Account Bank | | | | | |
| 10.12 | | | | CCH | 8-K | 10.4 | 5/24/2018 |
| 10.13 | | | | CCH | 8-K | 10.5 | 5/24/2018 |
| 10.14 | | Amended and Restated Working Capital Facility Agreement, dated June 29, 2018, among the Company, CCP, CCP GP, CCL, the lenders party thereto from time to time, the issuing banks party thereto from time to time, the Bank of Nova Scotia as Working Capital Facility Agent, and Société Générale as Security Trustee | | CCH | 8-K | 10.1 | 7/2/2018 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | Form | Exhibit | Filing Date |
| 10.15 | | | | CCH | 8-K | 10.10 | 11/13/2019 |
| 10.16 | | | | CCH | 10-K/A | 10.23 | 4/27/2018 |
| 10.17 | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Stage 2 EPC Agreement Revised Table A-2, dated May 18, 2018, (ii) the Change Order CO-00002 Stage 2 EPC Agreement Amended and Restated Attachment C, dated May 18, 2018, (iii) the Change Order CO-00003 Fuel Provisional Sum Adjustment, dated May 24, 2018, (iv) the Change Order CO-00004 Currency Provisional Sum Adjustment, dated May 29, 2018, (v) the Change Order CO-00005 JT Valve Modifications, dated July 10, 2018 and (vi) the Change Order CO-00006 Tank B Soil Conditions, International Building Code, and East Jetty Marine Facility Schedule Acceleration, dated September 5, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) | | CCH | 10-Q | 10.10 | 11/8/2018 |
| 10.18 | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00007 Tell-Tale Signs, Additional Tie-Ins, and System Inspection Isometrics, dated October 15, 2018, (ii) the Change Order CO-00008 Insurance Provisional Sum Interim Adjustment, dated November 19, 2018 and (iii) the Change Order CO-00009 Traffic and Logistics Impacts Due to Enforcement of Electronic Logging Devices, dated November 28, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) | | CCH | 10-K | 10.28 | 2/26/2019 |
| 10.19 | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-000010 OSHA Handrail Requirement Changes Impact, dated January 25, 2019, (ii) the Change Order CO-00011 Differing Soil Conditions - Train 3, dated March 7, 2019 and (iii) the Change Order CO-00012 Tank B Logo Deletion, dated March 25, 2019 (Portions of this exhibit have been omitted.) | | CCH | 10-Q | 10.20 | 5/9/2019 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | Form | Exhibit | Filing Date |
| 10.20 | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-000013 Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD), dated May 2, 2019, (ii) the Change Order CO-00014 Tank B Jump-over Tie-In Interface - Long Lead Items, dated May 2, 2019 and (iii) the Change Order CO-00015 Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing (CVD) Q1_2019, dated June 4, 2019 (Portions of this exhibit have been omitted.) | | CCH | 10-Q | 10.20 | 8/8/2019 |
| 10.21 | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-000016 Tank B Jump-over Tie-In (Part 1) and Deletion of East Jetty Shroud, dated August 5, 2019, (ii) the Change Order CO-00017 H2S Removal Skid PSVs Modifications and Revision to Chemical Cleaning Milestones, dated August 5, 2019 and (iii) the Change Order CO-00018 Cold Box Redesign Major Permanent Plant Materials and Ethylene Cold Box’s E-1504 Partial Mockup, dated September 6, 2019 (Portions of this exhibit have been omitted.) | | CCH | 10-Q | 10.50 | 11/1/2019 |
| 10.22 | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00019 Aircraft Warning Lights, dated September 23, 2019, (ii) the Change Order CO-00020 Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD) Q2_2019, dated October 8, 2019, (iii) the Change Order CO-00021 Spare Transition Joints for Potential Future Cold Box Modifications, dated October 8, 2019, (iv) the Change Order CO-00022 Modification of the Train 3 Methane Cold Box, dated December 6, 2019 and (v) the Change Order Co-00023 Section 232 Steel & Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD) Q3_2019, dated December 10, 2019 (Portions of this exhibit have been omitted.) | | CCH | 10-K | 10.18 | 2/25/2020 |
| 10.23 | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00024 East Jetty Cooldown Line & Simultaneous Ship Loading, dated January 6, 2020, (ii) the Change Order CO-00025 East Jetty Manual Gas Sampler, dated January 7, 2020, (iii) the Change Order CO-00026 Study for Adding Valve Actuator for E-W Jetty Flow Segregation, dated January 8, 2020, (iv) the Change Order CO-00027 Tank B Isolation of Proposed Fourth In-Tank LNG Pump - Long Lead Items, dated January 8, 2020, (v) the Change Order CO-00028 Tank B Rundown Line (Part I), dated January 31, 2020, (vi) the Change Order CO-00029 9% Nickel and Cryogenic Rebar Provisional Sum Closeout, dated February 18, 2020 and (vii) the Change Order CO-00030 Additional Valve for Isolation in CCL Stage 2 to CCL Stage 3 from Tank B, dated February 18, 2020 (Portions of this exhibit have been omitted) | | CCH | 10-Q | 10.10 | 4/30/2020 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | Form | Exhibit | Filing Date |
| 10.24 | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00031 Tank B Isolation of Proposed 4th In-Tank LNG Pump (Post Start-Up of Tank B) - EPC, dated April 1, 2020, (ii) the Change Order CO-00032 Train 3 Thermowell Upgrades, dated April 3, 2020, (iii) the Change Order CO-00033 Tank B Rundown Line (Part 2) Development Costs, dated April 29, 2020 and (iv) the Change Order CO-00034 Train 3 UPS Modification of MV Motors, dated May 21, 2020 (Portions of this exhibit have been omitted) | | CCH | 10-Q | 10.10 | 8/6/2020 |
| 10.25 | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00035 Spill Conveyance from Flare KO Drum Area, dated July 6, 2020, (ii) the Change Order CO-00036 Tie-Ins for Heavy Hydrocarbon Removal Modifications (E&P) Rev 1, dated August 5, 2020, (iii) the Change Order CO-00037 Train 3 PV-16002 Valve Trim Change - Rev 1, dated August 14, 2020, (iv) the Change Order CO-00038 Hot Oil Overpressure Relief, dated August 14, 2020, (v) the Change Order CO-00039 Supply of Nitrogen for Commissioning Units 16, 17 and Feed Gas, dated August 20, 2020 and (vi) the Change Order CO-00040 COVID-19 Impacts, dated September 15, 2020 (Portions of this exhibit have been omitted) | | CCH | 10-Q | 10.10 | 11/6/2020 |
| 10.26* | | Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00041 Additional O&M Support (COVID-19), dated October 2, 2020 and (ii) the Change Order CO-00042 Replacement of Owner Spare Parts, dated December 31, 2020 (Portions of this exhibit have been omitted) | | | | | |
| 10.27 | | | | CCH | S-4 | 10.14 | 1/5/2017 |
| 10.28 | | | | CCH | S-4 | 10.15 | 1/5/2017 |
| 10.29 | | | | Cheniere | 8-K | 10.10 | 4/2/2014 |
| 10.30 | | | | Cheniere | 8-K | 10.10 | 4/8/2014 |
| 10.31 | | | | Cheniere | 10-Q | 10.30 | 5/1/2014 |
| 10.32 | | | | Cheniere | 10-Q | 10.90 | 10/30/2015 |
| 10.33 | | | | Cheniere | 10-Q | 10.10 | 10/30/2015 |
| 10.34 | | | | Cheniere | 10-Q | 10.50 | 4/30/2015 |
| 10.35 | | | | CCH | S-4 | 10.22 | 1/5/2017 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | Form | Exhibit | Filing Date |
| 10.36 | | | | CCH | 10-Q | 10.10 | 11/1/2019 |
| 10.37 | | | | Cheniere | 8-K | 10.10 | 6/2/2014 |
| 10.38 | | | | CCH | 10-Q | 10.50 | 5/4/2018 |
| 10.39 | | | | CCH | S-4 | 10.32 | 1/5/2017 |
| 10.40 | | | | CCH | S-4 | 10.33 | 1/5/2017 |
| 10.41 | | | | CCH | S-4 | 10.34 | 1/5/2017 |
| 10.42 | | | | CCH | 10-K | 10.34 | 2/25/2020 |
| 21.1* | | | | | | | |
| 31.1* | | | | | | | |
| 32.1** | | | | | | | |
| 101.INS* | | XBRL Instance Document | | | | | |
| 101.SCH* | | XBRL Taxonomy Extension Schema Document | | | | | |
| 101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase Document | | | | | |
| 101.DEF* | | XBRL Taxonomy Extension Definition Linkbase Document | | | | | |
| 101.LAB* | | XBRL Taxonomy Extension Labels Linkbase Document | | | | | |
| 101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase Document | | | | | |
| 104* | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | | | | | |
| | | | | |
| (1) | Exhibits are incorporated by reference to reports of Cheniere (SEC File No. 001-16383) and CCH (SEC File No. 333-215435), as applicable. |
| * | Filed herewith. |
| ** | Furnished herewith. |
| |
(c) Financial statements of affiliates whose securities are pledged as collateral
All financial statements have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.
ITEM 16. FORM 10-K SUMMARY
None.
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 |
| | | |
| Date: | | By: | /s/ Zach Davis |
| | | Zach Davis |
| | | President and Chief Financial Officer |
| | | (Principal Executive and Financial Officer) |
| | | |
| | Date: | February 23, 2021 |
| | | |
| | | |
| | | |
| | | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| | | | | | | | |
| Signature | Title | Date |
| | |
| /s/ Zach Davis | Manager, President and Chief Financial Officer
(Principal Executive and Financial Officer) | February 23, 2021 |
| Zach Davis | |
| | |
| /s/ Aaron Stephenson | Manager | February 23, 2021 |
| Aaron Stephenson | | |
| | |
| /s/ Leonard E. Travis | Chief Accounting Officer
(Principal Accounting Officer) | February 23, 2021 |
| Leonard E. Travis | |
| | |
