Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation
The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Liquefaction Project and other facilities, and the import and export of LNG and the transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG. Although the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of three Trains and related facilities of the Liquefaction Project and Section 7 of the NGA authorizing the siting, construction and operation of the Corpus Christi Pipeline, the FERC orders require us to comply with certain ongoing conditions and obtain certain additional approvals in conjunction with ongoing construction and operations of the Liquefaction Project and Corpus Christi Pipeline. We will be required to obtain similar approvals and permits with respect to any expansion or modification of our liquefaction and pipeline facilities. We cannot control the outcome of the FERC’s or the DOE’s review and approval processes. Certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We do not know whether or when any such approvals or permits can be obtained, or whether any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, including as a result of untimely notices or filings, we may not be able to recover our investment in our projects. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our Corpus Christi Pipeline and its FERC gas tariffs is subject to FERC regulation.
The Corpus Christi Pipeline is subject to regulation by the FERC under the NGA and the NGPA. The FERC regulates the transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by the Corpus Christi Pipeline must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, the Corpus Christi Pipeline could be subject to substantial penalties and fines.
In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.3 million per day for each violation.
Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.
The PHMSA requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a “high consequence area”;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventative and mitigating actions.
We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines.
Hurricanes or other disasters could result in an interruption of our operations, a delay in the completion of the Liquefaction Project, higher construction costs and the deferral of the dates on which payments are due to us under the SPAs, all of which could adversely affect us.
In August and September of 2005, Hurricanes Katrina and Rita, respectively, damaged coastal and inland areas located in Texas, Louisiana, Mississippi and Alabama, resulting in the temporary suspension of construction of the Sabine Pass LNG terminal that is also operated by Cheniere LNG O&M Services, LLC, a wholly owned subsidiary of Cheniere. In September 2008, Hurricane Ike struck the Texas and Louisiana coasts, and the Sabine Pass LNG terminal experienced minor damage. In August 2017, Hurricane Harvey struck the Texas and Louisiana coasts. The Sabine Pass LNG terminal experienced a temporary suspension in construction and LNG loading operations, and the Corpus Christi LNG terminal experienced a temporary suspension in construction. The Corpus Christi LNG terminal did not sustain significant damage.
Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Corpus Christi LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Liquefaction Project or our other facilities. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our coastal operations.
We may not be successful in fully implementing our proposed business strategy to provide liquefaction capabilities at the Liquefaction Project.
It will take several years to construct the Liquefaction Project, and even if successfully constructed, the Liquefaction Project would be subject to the operating risks described herein. Accordingly, there are many risks associated with the Liquefaction Project, and if we are not successful in implementing our business strategy, we may not be able to generate cash flows, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may not construct or operate all of our proposed LNG facilities or Trains or any additional LNG facilities or Trains beyond those currently planned, which could limit our growth prospects.
We may not construct some of our proposed LNG facilities or Trains, whether due to lack of commercial interest or inability to obtain financing or otherwise. Our ability to develop additional liquefaction facilities will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world. Competitors may have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to sources of natural gas and LNG than we do. If we are unable or unwilling to construct and operate additional LNG facilities, our prospects for growth will be limited.
Our cost estimates for Trains are subject to change as a result of cost overruns, change orders under existing or future construction contracts, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules. In the event we experience cost overruns, delays or both, the amount of funding needed to complete a Train could exceed our available funds and result in our failure to complete such Train and thereby negatively impact our business and limit our growth prospects.
We may enter into certain arrangements to share the use and operations of our facilities with adjacent projects, which would require us to meet certain conditions under the CCH Indenture. Despite the protection provided by the CCH Indenture, the nature of such sharing arrangements is not currently known and may limit our operational flexibility, use of land and/or facilities and the ability of the security trustee under the Common Security and Account Agreement to take certain enforcement actions against the security interest in substantially all of our assets and the assets of our current and any future guarantors.
Cheniere has formed two entities, which are not owned or controlled by CCH, to develop up to seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5mpta and one storage tank adjacent to the Liquefaction Project, along with a second natural gas pipeline. If these entities ultimately construct these Trains and facilities or any additional Trains or facilities, they would not be part of the Liquefaction Project but CCL and CCP may nevertheless enter into sharing arrangements with the entities owning those Trains and related facilities that would involve sharing the use and capacity of each other’s land and facilities, including pooling of capacity of Trains, sharing of common facilities, such as storage tanks and berths,
and use of capacity of the pipeline facilities, to the extent permitted under the Common Terms Agreement and the CCH Indenture. CCL and CCP also may transfer and/or amend previously-obtained permits and other authorizations or applications such that they may be used by those entities. As future arrangements that would only be fully determined if the circumstances arise, there is uncertainty as to the full scope and impact of these sharing arrangements. The CCH Indenture requires us to meet certain conditions in respect of such sharing arrangements. These sharing arrangements would be subject to quiet enjoyment rights for CCL, CCP and the owner of the other Train(s). The nature of these sharing arrangements could limit the ability of the security trustee under the Common Security and Account Agreement to take certain enforcement action against the security interest in substantially all of our assets and the assets of our current and any future guarantors in respect of which quiet enjoyment rights have been granted to a third party.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Project to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of sufficient quantitiesnatural gas as a result of various factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply of natural gas to satisfy those obligations, which mayour pipeline and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in part mitigated by the diversification of our natural gas supply and transportation across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide affected SPA customers withcertain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the rightcriticality of natural gas supply to terminate their SPAs. Ourour production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our ability to complete development and/or construction of additional Trains, including the Midscale Trains 8 & 9 Project, will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our business strategy.
We continuously pursue liquefaction expansion opportunities and other projects along the LNG value chain. As described further in Items 1. and 2. Business and Properties, we are currently developing the Midscale Trains 8 & 9 Project. The commercial development of an LNG facility takes a number of years and requires a substantial capital investment that is dependent on sufficient funding and commercial interest, among other factors.
We will require significant additional funding to be able to commence construction of the Midscale Trains 8 & 9 Project, or any additional expansion projects, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development or construction of the Midscale Trains 8 & 9 Project, any additional Trains or any additional expansion projects, and we may not be able to complete our business plan, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
A major healthCost overruns and safety incident relating to our business could be costlydelays in terms of potential liabilities and reputational damage.
Health and safety performance is critical to the success of all areascompletion of our business. Any failureexpansion projects, including the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project, as well as difficulties in healthobtaining sufficient financing to pay for such costs 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 turndelays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are entirely dependentOur investment decision on Cheniere,the Corpus Christi Stage 3 Project and any potential future expansion of LNG facilities relies on cost estimates developed initially through front end engineering and design studies. However, due to the size and duration of construction of an LNG facility, the actual construction costs may be significantly higher than our current estimates as a result of many factors, including employeesbut not limited to changes in scope, the ability of CheniereBechtel Energy Inc. (“Bechtel”) and its subsidiaries,our other contractors to execute successfully under their agreements, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for key personnel,additional funds to be expended to maintain construction schedules or comply with existing or future environmental or other regulations. 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. Additionally, our SPAs generally provide 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 impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Significant increases in the cost of a lossliquefaction project beyond the amounts that we estimate could impact the commercial viability of key personnelthe project as well as require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays), thereby negatively impacting our business and limiting our growth prospects. While historically we have not experienced cost overruns or construction delays
that have had a significant adverse impact on our operations, factors giving rise to such events in the future may be outside of our control and could have a material adverse effect on our business.current or future 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 the Liquefaction Project are, and will be, subject to the inherent risks associated with these types of operations as discussed throughout our risk factors, 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. Although losses incurred as a result of self insured risk have not been material historically, 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.
We are dependent on our EPC partners and other contractors for the successful completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project.
Timely and cost-effective completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our EPC partners, including Bechtel, and our other contractors under their agreements. The ability of our EPC partners 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 Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 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 EPC partners 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 Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project, or result in a contractor’s unwillingness to perform further work. 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.
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 flow, 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 temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;
•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 provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources, 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 customer 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 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 our business and the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Failure of exported LNG to be a long term 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 are 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 the United States 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 LNG from the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or from our competitors’ liquefaction facilities in the United States.
As described in Market Factors and Competition, it is expected that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to alternative fossil fuel energy sources such as oil and coal. However, as a result of transitions globally from fossil-based systems of energy production and consumption to renewable energy sources, LNG may face increased competition from alternative, cleaner sources of energy as such alternative sources emerge. Additionally, 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 described in Market Factors and Competition, we have contracted through our SPAs and IPM agreements approximately 90% of the total anticipated production from the Liquefaction Project with approximately 17 years of weighted average remaining life as of December 31, 2023, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. However, as a result of the factors described above and other factors, the LNG we produce may not remain a long term competitive source of energy internationally, particularly when our existing long term contracts begin to expire. Any significant impediment to the ability to continue to secure long term commercial contracts or deliver LNG from the United States could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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.
A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Project, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our pipeline and liquefaction operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Project. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should multiple of the third party pipelines which supply our Liquefaction Project suffer similar concurrent attacks, the Liquefaction Project may not be able to obtain sufficient natural gas
to operate at full capacity, or at all. A cyber attack involving our business or operational control systems or related infrastructure, or that of third party pipelines with which we do business, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
Outbreaks of infectious diseases, such as COVID-19, at our facilities could adversely affect our operations.
Our facilities at the Corpus Christi LNG Terminal are critical infrastructure and continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including subsequent variants, had no adverse impact on our on-going operations, the risk of future variants and other infectious diseases is unknown. While we believe we can continue to mitigate any significant adverse impact to our employees and operations at our critical facilities related to the virus in its current form, the outbreak of a more potent variant or another infectious disease in the future at one or more of our facilities could adversely affect our operations.
We are entirely dependent on Cheniere for key personnel, and the unavailability of skilled workers or Cheniere’s failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our senior management or other key personnel could affect our business results.
As of JanuaryDecember 31, 2018,2023, Cheniere and its subsidiaries had 1,2301,605 full-time employees, including 231412 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 liquefactionour facilities and pipelines and to provide our customers with the highest quality service. We also compete with any other project Cheniere is developing,operating, including the Sabine Pass LiquefactionSPL Project, for the time and expertise of Cheniere’s personnel. Further, we and Cheniere facefaces 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 otherremoteness of our site locations, general inflationary pressures, or 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. In addition, we are also subject to increased competition for skilled workers from new entrants to the LNG market. 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.affiliates, including Cheniere Marketing.
We have agreements to compensate and to reimburse expenses of affiliatesCheniere’s affiliates. All 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. Thesethese agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, CheniereSPL is currently operating the SPL Project and its affiliates are 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 sitean expansion project adjacent to the LiquefactionSPL Project. Cheniere and its affiliates have entered into fixed price SPAs with third parties for the sale of LNG from the SPL Project and the adjacent expansion project, and may continue to enter into commercial arrangements with respect to these projectsthis liquefaction facility that might otherwise have been entered into with respect to Train 3 or another expansionany 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.our future Trains.
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 anticipatearrangements 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 willmay 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.
Risks Relating to Regulations
Our liquefaction projects are subject
Failure 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 usobtain and maintain approvals and permits 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, liquiditygovernmental and prospects. Factors which may negatively affect potential demand for LNG from our liquefaction projects are diverse and include, among others:
increases in worldwide LNG production capacity and availability of LNG for market supply;
increases in demand for LNG but at levels below those required to maintain current price equilibriumregulatory agencies with respect to supply;
increases in the cost to supply natural gas feedstock to our liquefaction projects;
decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
increases in capacity and utilization of nuclear power and related facilities; and
displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
competitive liquefaction capacity in North America;
insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
insufficient LNG tanker capacity;
weather conditions;
reduced demand and lower prices for natural gas;
increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
decreased oil and natural gas exploration activities, which may decrease the production of natural gas;
cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;
changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
political conditions in natural gas producing regions;
adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and
cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the Liquefaction Project will be, dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import or export LNG from or to the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction or regasification facilities in the United States.
In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in the United States.
As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or to the United States on a commercial basis. Any significant impediment to the ability to deliver LNG to or from the United States generally, or from the Liquefaction Project specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.
Thedesign, construction and operation of our LNG terminalsfacilities, and liquefaction facilities are and will be subject to the inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destructionoperation of our facilities or damage to personspipeline and property. In addition, ourthe export of LNG could impede operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
After our Liquefaction Project is placed in service, its operations will involve significant risks.
If we are successful in completing our proposed liquefaction facilities, we will still face risks associated with operating the facilities. These risks will include, but will not be limited to, the following:
the facilities performing below expected levels of efficiency;
breakdown or failures of equipment;
operational errors by vessel or tug operators;
operational errors by us or any contracted facility operator;
labor disputes; and
weather-related interruptions of operations.
We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation requirements, which could have a material adverse effect on us.
We believe that there is sufficient capacity on the Corpus Christi Pipeline to accommodate all of our natural gas feedstock transportation requirements for Trains 1 through 3. We have also entered into transportation precedent agreements with several third-party pipeline companies partially securing firm pipeline transportation capacity for the Liquefaction Project on interstate and intrastate pipelines which will connect to the Corpus Christi Pipeline for the production contemplated for Trains1 and 2. However, we cannot control the regulatory and permitting approvals or third parties’ construction times, either with respect to capacity that has been secured or capacity that will be secured. If and when we need to replace one or more of our agreements with these interconnecting pipelines or enter into additional agreements, we may not be able to do so on commercially reasonable terms or at all, which would impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Additionally,
The design, construction and operation of interstate natural gas pipelines, our LNG terminal, including the capacity onLiquefaction Project, the Corpus Christi PipelineMidscale Trains 8 & 9 Project and other facilities, as well as the export of LNG 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 interconnecting pipelines may not be sufficientCWA, are required in order to accommodate any additional Trains. Developmentconstruct and operate an LNG facility and an interstate natural gas pipeline and export LNG.
To date, the FERC has issued orders under Section 3 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,NGA authorizing the siting, construction and operation of the three Trains and related facilities of the Liquefaction Project, whichas well as the seven midscale Trains and related facilities for the Corpus Christi Stage 3 Project. Additionally, the FERC has issued orders under Section 7 of the NGA authorizing the construction and operation of the Corpus Christi Pipeline. In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for Midscale Trains 8 & 9 Project. To date, the DOE has also issued orders under Section 4 of the NGA authorizing CCL to export domestically produced LNG. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations. We do not believe such a pause will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity. The Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE, although such approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application in March 2023. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipeline on land owned by third parties. If we were to lose these rights or be required to relocate our pipeline, our business could be materially and adversely affected.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with or our inability to obtain and maintain existing or newly imposed approvals, permits and filings that may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to our operations could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges. 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. Any impediment 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 tariff are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.
Commercial development
The Corpus Christi Pipeline is subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of an LNG facility takes a number1978 (the “NGPA”). The FERC regulates the purchase and transportation of years, requires a substantial capital investmentnatural gas in interstate commerce, including the construction and mayoperation of pipelines, the rates, terms and conditions of service and the abandonment of facilities. Under the NGA, the rates charged by our Corpus Christi Pipeline must be delayed by factors such as:
increased construction costs;
economic downturns, increases in interestjust and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any potential shipper with respect to pipeline rates or other events that may affectterms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our 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 availability of sufficient financing for LNG projects on commercially reasonable terms;
decreases inEPAct, the price of LNG, which might decreaseFERC has civil penalty authority under the expected returns relating to investments in LNG projects;
the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;
political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and
any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.
There may be shortages of LNG vessels worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The construction and delivery of LNG vessels require significant capital and long construction lead times,NGA and the availabilityNGPA to impose penalties for current violations of up to $1.5 million per day for each violation.
Although the vessels could be delayedFERC has not imposed fines or penalties on us to the detriment of our businessdate, we are exposed to substantial penalties and our customers because of:fines if we fail to comply with such regulations.
an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
political or economic disturbances in the countries where the vessels are being constructed;
changes in governmental regulations or maritime self-regulatory organizations;
work stoppages or other labor disturbances at the shipyards;
bankruptcy or other financial crisis of shipbuilders;
quality or engineering problems;
weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
shortages of or delays in the receipt of necessary construction materials.
Terrorist attacks, including cyberterrorism, or military campaigns may adversely impact our business.
A terrorist, including a cyberterrorist, or military incident involving an LNG facility, our infrastructure or an LNG vessel may result in delays in, or cancellation of, construction of new LNG facilities, including one or more of the Trains, which would increase our costs and decrease our cash flows. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, including the Liquefaction Project, which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of terrorism, including cyberterrorism, or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Existing and future safety, 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 that regulateapplicable to our construction and restrict,operation activities relating to, among other things, discharges to air landquality, water quality, waste management, natural resources, and water, with particular respect to the protection of the environmenthealth and natural resources; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances.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 environmental laws and regulations authorize regulators having jurisdiction over the Corpus Christi LNGconstruction and operation of our terminal, marine berths and pipeline, including FERC, PHMSA, EPA and the United States Coast Guard, to issue compliance orders,regulatory enforcement actions, 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, difficulty obtaining and maintaining permits from regulatory agencies or toincreased capital expenditures related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and
operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.
In October 2015,The EPA has finalized or proposed multiple GHG regulations that impact our assets and supply chain. On December 2, 2023, the EPA promulgated aissued final rule to implement the Obama Administration’s Clean Power Plan, which is designedrules to reduce GHGmethane and VOC emissions from power plantsnew, existing and modified emission sources in the United States. oil and gas sector. These regulations will require monitoring of methane and VOC emissions at our compressor stations. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that will apply to our facilities beginning in calendar year 2024. In February 2016,January 2024, the U.S. Supreme Court stayed the final rule, effectively suspending the duty to comply with the rule until certain legal challenges are resolved. In March 2017, President Trump directed EPA via Executive Order to review and determine whether it is appropriate to revise or rescind the Clean Power Plan. On October 10, 2017, EPA issued a proposalproposed rule to repeal the Clean Power Plan after concluding the October 2015 final rule exceeds EPA’s statutory authorityimpose and collect methane emissions charges authorized under the CAA. The October 2017 proposal does not include regulations to replace the Clean Power Plan and EPA stated in the October 2017 proposal that it has not determined whether it will issue replacement regulations to regulate GHG emissions from existing EGUs. The Trump Administration announced in June 2017 that the United States would withdraw from the Paris Accord, anIRA. In addition, other international, agreement within the United Nations Framework Convention on Climate Change under which the Obama Administration committed the United States to reducing its economy-wide GHG emission by 26-28% below 2005 levels by 2025. Other federal and state initiatives may be considered in the future to address GHG emissions through for example, United States treaty commitments, direct regulation, market-based regulations such as a carbonGHG emissions tax or cap-and-trade programs.programs or clean energy or performance-based standards. Such initiatives including a future replacement rule for the Clean Power Plan could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals, could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels 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. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.
Our lackOn February 28, 2022, the EPA removed a stay of diversificationformaldehyde standards in the NESHAP Subpart YYYY for stationary combustion turbines located at major sources of HAP emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by such regulatory actions.
Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from the Corpus Christi LNG 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.
Total expenditures related to environmental and similar laws and governmental regulations, including capital expenditures, were immaterial to our Consolidated Financial Statements for the years ended December 31, 2023, 2022 and 2021. Revised, reinterpreted or additional laws and regulations that result in increased compliance, operating or construction
costs or restrictions could have ana material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
DuePipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.
The PHMSA requires pipeline operators to our lackdevelop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
•perform ongoing assessments of assetpipeline safety and geographic diversification, an adverse development atcompliance;
•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 Liquefaction Facility, the Corpus Christi Pipeline,pipeline as necessary; and
•implement preventative and mitigating actions.
We are required to utilize management programs that are intended to maintain pipeline integrity. Any repair, remediation, preventative or in the LNG industry would have a significantly greater impact on our financial conditionmitigating actions may require significant capital and operating results than ifexpenditures. Should we maintained more diverse assetsfail to comply with applicable statutes and operating areas.
U.S. federal income tax reform could adversely affect us.
On December 22, 2017, the Tax CutsOffice of Pipeline Safety’s rules and Jobs Act (the “TCJA”) was signed into law, significantly reforming the U.S. Internal Revenue Code. The TCJA, among other things, includes changes to U.S. federal tax rates, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures,related regulations and imposes limitations on the use of net operating losses arising in taxable years beginning after December 31, 2017. The reduction of the U.S. corporate tax rate results in a decreased valuation of our deferred tax asset and liabilities. We continue to examine the impact the TCJA may have on our business. The estimated impact of the TCJA is based on our management’s current knowledge and assumptions and recognized impactsorders, we could be materially different from current estimates based on our actual results.subject to significant penalties and fines, which for certain violations can aggregate up to as high as $2.7 million.
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ITEM 1B. | UNRESOLVED STAFF COMMENTS |
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
Cyberattacks represent a potentially significant risk to the Company and our industry. We rely on subsidiaries of Cheniere through our service agreements with them, as further discussed in Note 13—Related Party Transactions of our Notes to Consolidated Financial Statements, and Cheniere’s board of directors (the “Board”), which has oversight of our operations, to implement policies and procedures that are intended to manage and reduce this risk. | |
ITEM 3.
Risk Management and Strategy
As part of its broader approach to risk management, Cheniere’s cybersecurity program is designed to follow an “identify, protect, detect, respond and recover” approach to cybersecurity that is based off of the National Institute of Standards and Technology Cybersecurity Framework (“CSF”). Cheniere’s strategy also includes segmentation of corporate and operations networks, defense in depth and the least privileged access principle. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, Cheniere routinely evaluates opportunities to refine its cybersecurity program in order to mitigate operational network risks. Cheniere includes business continuity planning as a component of its strategy to help ensure critical systems are available to support the Company in the instance of a disruptive event. Cheniere also participates in various industry organizations to stay abreast of recent trends and developments.
On an ongoing basis, Cheniere assesses its people, processes and technology and, when necessary, adjusts the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. Cheniere conducts regular assessments and audits, cross-functional risk mitigation exercises and risk strategy sessions to identify cybersecurity risks, applicable regulatory requirements and industry standards. These engagements are also designed to exercise, assess the maturity of and enhance Cheniere’s Cyber Incident Response Plan. To support these efforts, Cheniere has contracted with third parties to perform facility and system penetration tests, compromise assessments of information technology systems, and security maturity assessments of its corporate and operational networks. Cheniere maintains a training program to help its personnel identify and assist in mitigating cybersecurity and data security risks. Cheniere’s employees and the members of the Board participate in annual training, user awareness campaigns and additional issue-specific training as needed. Cheniere also provides annual training for certain contractors who have access to its information technology networks.
With respect to third party service providers, Cheniere’s information security program includes conducting risk-based due diligence of certain service providers’ information security programs prior to onboarding. Cheniere strives to contractually require third party service providers with access to its information technology systems, sensitive business data or personal information to maintain reasonable security controls and restrict their ability to use Cheniere’s data, including personal information, for purposes other than to provide services to them, except as required by applicable law. Cheniere also strives to negotiate contractual requirements which compel its service providers to notify them of information security incidents occurring on their systems which may affect Cheniere’s systems or data, including personal information.
During the year ended December 31, 2023, cybersecurity incidents and threats did not materially affect our business, results of operations or financial condition.
Governance
We rely on Cheniere’s cybersecurity leadership team, which consists of its Director and Chief Information Security Officer (“CISO”), Vice President and Chief Information Officer and Senior Vice President of Shared Services. These individuals collectively provide the strategic oversight of Cheniere’s cybersecurity governance, cyber risk management and security operations and are responsible for maintaining Cheniere’s technology defense posture and program. They have decades of experience managing strategic technology operations, including the identification of cybersecurity risk and the defense of information technology assets from global threats. Cheniere’s CISO’s experience includes assessing risks, implementing governance programs, and responding to threats in oil and gas, electric and natural gas utilities and nuclear power generation companies. He maintains a Certified Information Security Manager certification from ISACA, secret clearance from the Department of Homeland Security and has played an active role in the development of various cybersecurity standards including the CSF.
Risks that could affect us are an integral part of Cheniere’s Board and Audit Committee deliberations throughout the year. Cybersecurity risks are integrated into Cheniere’s enterprise risk assessment process, which is reviewed by Cheniere’s Board at least annually. Cheniere’s Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management’s plan for mitigating these risks, while Cheniere’s Audit Committee has been delegated the authority to oversee and periodically review the security of Cheniere’s information technology systems and controls, including programs and defenses against cybersecurity threats. Cheniere’s Audit Committee discusses with Cheniere’s management its cybersecurity risk exposures and the steps Cheniere’s management has taken to mitigate such exposures, including its risk assessment and risk management policies. On a quarterly basis, Cheniere’s cybersecurity leadership team updates Cheniere’s Audit Committee on the overall status of its cybersecurity program, key operational metrics, current assessments, cybersecurity issues or events and pertinent events related to cybersecurity.
For additional information about cybersecurity risks, see the risk A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Project, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting under Risks Relating to Our Operations and Industry in Item 1A.Risk Factors.
ITEM 3.LEGAL PROCEEDINGS | LEGAL PROCEEDINGS |
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.
PHMSA Matter
ITEM 4. MINE SAFETY DISCLOSURE
In February 2018, PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (“the NOPV”) to CCP relating to a February 2017 inspection of the Corpus Christi Pipeline. The NOPV alleges probable
violations of federal pipeline safety regulations relating to welding during the construction of the pipeline and proposes civil penalties totaling $0.2 million. We are currently reviewing the alleged violations and do not expect that the resolution of this matter will have a material adverse impact on our financial results or operations.
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ITEM 4. | MINE SAFETY DISCLOSURE |
Not applicable.
PART II
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ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Not applicable.
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ITEM 6. | SELECTED FINANCIAL DATA |
Selected financial data set forth below are derived from audited consolidated and combined financial data for the periods indicated for CCH (in thousands). CCH was formed by Cheniere in September 2014 to hold its limited partner interest in CCP, the equity interests of CCP GP, which holds the general partner interest in CCP, and the equity interests of CCL. Prior to this date, CCP and CCL received capital contributions from other affiliated entities of Cheniere. The formation of CCH is treated as a reorganization between entities under common control. As a result, CCH’s combined financial statements for periods prior to the formation of CCH were derived from the consolidated financial statements and accounting records of Cheniere and reflect the combined historical results of operations and cash flows of CCL, CCP and CCP GP. For periods subsequent to the formation of CCH, CCH’s consolidated financial statements are presented on a consolidated basis because CCH, CCL, CCP and CCP GP became a separate consolidated group following such formation. The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report.ITEM 6. [Reserved]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Revenues | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Loss from operations | | (19,161 | ) | | (6,472 | ) | | (23,044 | ) | | (38,235 | ) | | (32,849 | ) |
Other expense | | (29,491 | ) | | (79,015 | ) | | (204,053 | ) | | (368 | ) | | (378 | ) |
Net loss | | (48,652 | ) | | (85,487 | ) | | (227,097 | ) | | (38,603 | ) | | (33,227 | ) |
|
| | | | | | | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 |
Property, plant and equipment, net | | $ | 8,261,383 |
| | $ | 6,076,672 |
| | $ | 3,924,551 |
| | $ | 44,173 |
|
Total assets | | 8,659,880 |
| | 6,636,448 |
| | 4,304,042 |
| | 68,030 |
|
Long-term debt, net | | 6,669,476 |
| | 5,081,715 |
| | 2,713,000 |
| | — |
|
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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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. Discussion of 2021 items and variance drivers between the year ended December 31, 2022 as compared to December 31, 2021 are not included herein and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the fiscal year ended December 31, 2022.
Our discussion and analysis includes the following subjects:
Overview
We are a limited liability company formed by Cheniere to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We own the natural gas liquefaction and export facility located near Corpus Christi, Texas. For further discussion of our business, see Items 1. and 2. Business and Properties.
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Through our SPAs and IPM agreements, we have contracted approximately 90% of the total anticipated production from the Liquefaction Project with approximately 17 years of weighted average remaining life as of December 31, 2023. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. We believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, will provide a foundation for additional growth in our business in the future.
Overview of Significant Events
Our significant events since January 1, 2023 and through the filing date of this Form 10-K include the following:
Strategic
•In April 2023, CCL and certain subsidiaries of Cheniere filed an application with the DOE with respect to the Midscale Trains 8 & 9 Project, requesting authorization to export LNG to FTA countries and non-FTA countries. In July 2023, we received authorization from the DOE to export LNG to FTA countries.
•In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for the Midscale Trains 8 & 9 Project.
Operational
•As of February 16, 2024, approximately 870 cumulative LNG cargoes totaling approximately 60 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
Financial
•We received the following upgrades from credit rating agencies, including S&P Global Ratings (“S&P”), Moody’s Investor Service (“Moody’s”) and Fitch Ratings (“Fitch”), each with a stable outlook:
| | | | | | | | | | | | | | | | | | | | | | | |
| Date | | Previous Rating | | Upgraded Rating | | Rating Agency |
| October 2023 | | BBB- | | BBB | | S&P |
| August 2023 | | Baa3 | | Baa2 | | Moody’s |
| July 2023 | | BBB- | | BBB | | Fitch |
•In January 2023, we prepaid with cash on hand the remaining $498 million outstanding principal amount of our 7.000% Senior Secured Notes due 2024 (the “2024 CCH Senior Notes”).
Market Environment
In 2023, the LNG market continued to rebalance with robust LNG flows to Europe maintaining the region’s underground storage inventories at high levels, and weak demand in Japan and Korea largely offsetting a modest rebound in China and other emerging economies in Asia. Price levels started moving towards pre-Russia-Ukraine war levels in the second quarter of 2023 and have for the most part normalized versus pre-war levels, as concerns about physical market tightness dissipated. However, extensive upstream maintenance in Norway and concerns about tight supply capacity amid strike threats in Australia elevated prices during the third quarter of 2023 and brought some volatility back to the market, albeit not at much lower levels than those seen in 2022. These conditions were quickly resolved, and winter prices remained within a more normal level, despite the eruption of military conflict in the Middle East in October.
The Dutch Title Transfer Facility (“TTF”)monthly settlement prices averaged $13.73/MMBtu in 2023, over 66% lower year-over-year and 4.6% lower than 2021. Similarly, the 2023 average settlement price for the Japan Korea Marker (“JKM”) decreased 53% year-over-year to an average of $16.13/MMBtu in 2023. Prices in the fourth quarter of 2023 also decreased, with TTF averaging $13.66/MMBtu and JKM $14.97/MMBtu - both significantly below levels seen in the previous two years. The Henry Hub benchmark also witnessed a similar year-over-year drop albeit from a much lower base. The Henry Hub average settlement price in 2023 was $2.74, down approximately 59% from $6.64/MMBtu in 2022 during the height of the energy crisis in Europe.
The U.S. played a significant role in balancing the global market in 2023, exporting approximately 86 million tonnes of LNG, a gain of approximately 13% from 2022, due in part to the return of Freeport LNG to operations. Exports from our Liquefaction Project reached 15 million tonnes in aggregate, representing over 17% of total U.S. exports for the year, according to Kpler data.
Global LNG demand grew by approximately 3% from 2022, adding 10.5 million tonnes to the overall market. Although overall Asian demand has increased from 2022, weakness in Japan, mainly due to improved nuclear availability, along with continued gas demand destruction in Europe, especially in the residential sector, exerted downward pressure on the market and
kept LNG and gas prices from increasing. Despite the decrease in Japanese demand, which was down approximately 8% or 6 mtpa year-over-year, Asia’s LNG imports increased roughly 4% year-over-year in 2023 to approximately 263 mtpa. This uptick was largely due to an approximately 8.4 mtpa year-over-year growth in South and Southeast Asia’s demand and a modest rebound in China’s economy, which resulted in approximately 12% or 7.5 mtpa increase in LNG imports into the country. In Europe, despite continued declines in gas demand, LNG imports were flat year-over-year as pipeline flows from Russia to the EU remained low at 27 billion cubic meters (“Bcm”), down 36 Bcm or 57% year-over-year.
The market dynamics brought on by the need to displace and replace Russian gas into Europe in 2023 resulted in a notable uptick in long-term LNG contracting and a push for LNG project FIDs. Commercial activity in 2023 continued to build on last year’s momentum with executed long-term SPAs in the U.S. reaching approximately 23 mtpa for the year, of which Cheniere’s SPAs and IPM agreements totaled approximately 6.5 mtpa. This contractual momentum over the past two years led to the positive FID of nearly 40 mtpa of U.S. LNG capacity in 2023.
Despite the global impacts of the Russia-Ukraine war, we do not believe we have significant exposure to adverse direct or indirect impacts of the war, as we do not conduct business in Russia and refrain from business dealings with Russian entities. Additionally, we are not aware of any specific adverse direct or indirect effects of the Russia-Ukraine war or the Israel-Hamas war on our supply chain. Consequently, we believe we are well positioned to help meet the increased demand of our international LNG customers to overcome their supply shortages.
Results of Operations
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
(in millions) | | | | | | | 2023 | | 2022 | | Variance |
Revenues | | | | | | | | | | | |
LNG revenues | | | | | | | $ | 3,845 | | | $ | 6,336 | | | $ | (2,491) | |
LNG revenues—affiliate | | | | | | | 1,620 | | | 3,027 | | | (1,407) | |
| | | | | | | | | | | |
Total revenues | | | | | | | 5,465 | | | 9,363 | | | (3,898) | |
| | | | | | | | | | | |
Operating costs and expenses (recoveries) | | | | | | | | | | | |
Cost (recovery) of sales (excluding items shown separately below) | | | | | | | (3,178) | | | 9,656 | | | (12,834) | |
Cost of sales—affiliate | | | | | | | 171 | | | 103 | | | 68 | |
| | | | | | | | | | | |
Operating and maintenance expense | | | | | | | 479 | | | 458 | | | 21 | |
Operating and maintenance expense—affiliate | | | | | | | 116 | | | 121 | | | (5) | |
Operating and maintenance expense—related party | | | | | | | 9 | | | 9 | | | — | |
| | | | | | | | | | | |
| | | | | | | | | | | |
General and administrative expense | | | | | | | 6 | | | 8 | | | (2) | |
General and administrative expense—affiliate | | | | | | | 45 | | | 38 | | | 7 | |
Depreciation and amortization expense | | | | | | | 449 | | | 445 | | | 4 | |
Other | | | | | | | 2 | | | 6 | | | (4) | |
Total operating costs and expenses (recoveries) | | | | | | | (1,901) | | | 10,844 | | | (12,745) | |
| | | | | | | | | | | |
Income (loss) from operations | | | | | | | 7,366 | | | (1,481) | | | 8,847 | |
| | | | | | | | | | | |
Other income (expense) | | | | | | | | | | | |
Interest expense, net of capitalized interest | | | | | | | (217) | | | (432) | | | 215 | |
Loss on modification or extinguishment of debt | | | | | | | (10) | | | (37) | | | 27 | |
| | | | | | | | | | | |
Other income, net | | | | | | | 11 | | | 8 | | | 3 | |
Total other expense | | | | | | | (216) | | | (461) | | | 245 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Net income (loss) | | | | | | | $ | 7,150 | | | $ | (1,942) | | | $ | 9,092 | |
Volumes loaded and recognized from the Liquefaction Project
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | |
(in TBtu) | | | | | | | 2023 | | 2022 | | Variance | | |
Volumes loaded during the current period | | | | | | | 763 | | | 775 | | | (12) | | | |
Volumes loaded during the prior period but recognized during the current period | | | | | | | 3 | | | — | | | 3 | | | |
Volumes loaded at our affiliate’s facility | | | | | | | 5 | | | — | | | 5 | | | |
Less: volumes loaded during the current period and in transit at the end of the period | | | | | | | — | | | (3) | | | 3 | | | |
Total volumes recognized in the current period | | | | | | | 771 | | | 772 | | | (1) | | | |
Net income (loss)
Substantially all of the favorable variance of $9.1 billion between the years ended December 31, 2023 and 2022 was attributable to favorable changes in fair value and settlements of derivatives of $9.1 billionbetween the periods, of which $7.7 billionrelated to non-cash favorable changes in fair value of our IPM agreements where we procure natural gas at a price indexed to international gas prices as a result of lower volatility in international gas prices and declines in international forward commodity curves.
The following is an additional discussion of the significant drivers of the variance in net income (loss) by line item:
Revenues
Substantially all of the $3.9 billion decrease between the years ended December 31, 2023 and 2022 was attributable to a $3.8 billion decrease from lower pricing per MMBtu as a result of decreased Henry Hub pricing.
Operating costs and expenses (recoveries)
The $12.7 billion favorable variance between the years ended December 31, 2023 and 2022, was primarily attributable to:
•$9.1 billion favorable variance from changes in fair value and settlements of derivatives included in cost of sales, from a $3.2 billion of loss in the year ended December 31, 2022 to a $5.8 billion of gain in the year ended December 31, 2023 primarily due to decreased international gas prices resulting in non-cash favorable changes in fair value of our commodity derivatives indexed to such prices and, to a lesser extent, an increase in forward notional amount of derivatives due to agreements contributed to us upon the merger of CCL Stage III with and into CCL in June 2022; and
•$3.7 billion decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of a $3.4 billion in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices.
Other income (expense)
The $245 million decrease between the years ended December 31, 2023 and 2022 was primarily attributable to a $215 million decrease in interest expense, net of capitalized interest, between the years ended December 31, 2023 and 2022, as a result of lower debt balances due to repayment of debt, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources. Additionally, the decrease in interest expense, net of capitalized interest, between the years ended December 31, 2023 and 2022 was due to a higher portion of total interest costs eligible for capitalization following the issuance of full notice to proceed to Bechtel on the Corpus Christi Stage 3 Project in June 2022. Significant factors affecting our results of operations
Below are significant factors that affect our results of operations.
Gains and losses on derivative instruments
Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risks and are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM
agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of our Liquefaction Supply Derivatives incorporates market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.
Liquidity and Capital Resources
Contractual Obligations
Results of Operations
Off-Balance Sheet Arrangements
Summary of Critical Accounting Estimates
Recent Accounting Standards
Overview of Business
We were formed in September 2014 to develop, construct, operate, maintain and own a natural gas liquefaction and export facility (the “Liquefaction Facility”) and a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline” and together with the Liquefaction Facility, the “Liquefaction Project”) on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas, through wholly-owned subsidiaries CCL and CCP, respectively.
The Liquefaction Project is being developedfollowing information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage (“Stage 1”) includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, one LNG storage tankshort term and the completionlong term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
| | | | | | | |
| December 31, 2023 | | |
| |
| | | |
| | | |
| | | |
Restricted cash and cash equivalents designated for the Liquefaction Project | $ | 175 | | | |
Available commitments under our credit facilities (1): | | | |
Term loan facility agreement (the “CCH Credit Facility”) | 3,260 | | | |
Working capital facility agreement (the “CCH Working Capital Facility”) | 1,345 | | | |
Total available commitments under our credit facilities | 4,605 | | | |
| | | |
Total available liquidity | $ | 4,780 | | | |
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2023. See Note 11—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.
Our liquidity position subsequent to December 31, 2023 will be driven by future sources of liquidity and future cash requirements as further discussed under the second partial berth. caption Future Sources and Uses of Liquidity.
Supplemental Guarantor Information
The Liquefaction Project also includes the Corpus Christi Pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines. Stage 1 and the Corpus Christi Pipeline are currently under construction, and Train 3 is being commercialized and has all necessary regulatory approvals in place. Construction of the Corpus Christi Pipeline is nearing completion.
Overview of Significant Events
Our significant accomplishments since January 1, 2017 and through the filing date of this Form 10-K include the following:
Strategic
In February 2018, CCL entered into a 20-year SPA with PetroChina International Company Limited, a subsidiary of China National Petroleum Corporation (“CNPC”), for the sale of LNG beginning in 2023.
CCL entered into an amended and restated EPC contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for Stage 2 of the Liquefaction Project. CCL also issued limited notice to proceed to Bechtel, and procurement and early site work has commenced.
Financial
In May 2017, we issued an aggregate principal amount of $1.5 billion of5.875% Senior Secured Notes due 2025, 5.125% Senior Secured Notes due 2027, (the “2027 CCH3.700% Senior Secured Notes due 2029 and the series of Senior Secured Notes due 2039 with weighted average rate of 3.788% (collectively, the “Senior Secured Notes”) are jointly and severally guaranteed by each of our consolidated subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “Guarantor” and collectively, the “Guarantors”). Net proceeds
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 offeringcapital stock or the assets of approximately $1.4 billion, after deducting commissions,
fees and expenses and after provisioning for incremental interest requiredthe Guarantors, (2) the designation of the Guarantor as an “unrestricted subsidiary” in accordance with the indentures governing the Senior Secured Notes (the “CCH Indentures”), (3) upon the legal defeasance or covenant defeasance or discharge of obligations under the 2027 CCH Senior Notes during construction, were used to prepay a portionIndentures and (4) the release and discharge of the outstanding borrowingsGuarantors 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 Senior Secured 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 Senior Secured 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 is omitted herein because such information would not be materially different from our credit facility (the “2015 CCH Credit Facility”).Consolidated Financial Statements.
Corpus Christi Stage 3 Project Liquidity and Capital Resources
The following table provides a summarysummarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:
| | | | | | | | | | | |
| | |
Overall project completion percentage | | 51.4% |
Completion percentage of: | | |
Engineering | | 83.7% |
Procurement | | 72.2% |
Subcontract work | | 66.9% |
Construction | | 11.1% |
Date of expected substantial completion | | 2Q/3Q 2025 - 2H 2026 |
Future Sources and Uses of Liquidity
The following discussion of our future sources and uses of liquidity position atincludes estimates that reflect management’s assumptions and currently known market conditions and other factors as of December 31, 20172023. Estimates are not guarantees of future performance and 2016 (in thousands):actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
|
| | | | | | | |
| December 31, |
| 2017 | | 2016 |
Cash and cash equivalents | $ | — |
| | $ | — |
|
Restricted cash designated for the Liquefaction Project | 226,559 |
| | 270,540 |
|
Available commitments under the following credit facilities: | | | |
2015 CCH Credit Facility | 2,086,714 |
| | 3,602,714 |
|
$350 million CCH Working Capital Facility (“CCH Working Capital Facility”) | 186,422 |
| | 350,000 |
|
Future Sources of Liquidity under Executed SPAs
For additional information regardingAs described in Items 1. and 2. Business and Properties, our debt agreements, see Note 7—Debtlong-term customer arrangements form the foundation of our Notesbusiness and provide us with significant, stable, long-term cash flows. Substantially all of our future revenues are contracted under SPAs and because many of these contracts have long-term durations, we are contractually entitled to significant future consideration under these contracts which has not yet been recognized as revenue. This future consideration is in most cases, not yet legally due to us and was not reflected on our Consolidated Financial Statements.Balance Sheets as of December 31, 2023. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed SPAs as of December 31, 2023 (in billions): | | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Revenues Under Executed SPAs by Period (1) (2) |
| | | | | | | | |
| | 2024 | | 2025 - 2028 | | Thereafter | | Total |
LNG revenues (fixed fees) | | $ | 2.1 | | | $ | 11.0 | | | $ | 37.4 | | | $ | 50.5 | |
| | | | | | | | |
LNG revenues (variable fees) (2) | | 2.9 | | | 20.4 | | | 80.9 | | | 104.2 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total | | $ | 5.0 | | | $ | 31.4 | | | $ | 118.3 | | | $ | 154.7 | |
(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the revenues above when the conditions are considered probable of being met.
Liquefaction Facilities(2)LNG revenues (including $1.0 billion and $28.7 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises, in certain instances, their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.
(3)LNG revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated forward prices and basis spreads as of December 31, 2023. The pricing structure of many of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices.
Through our SPAs and IPM agreements, we have contracted approximately 90% of the total anticipated production from the Liquefaction Project, with approximately 17 years of weighted average remaining life as of December 31, 2023. The majority of the contracted capacity is being developed and constructedcomprised of fixed-price, long-term SPAs we have executed with third parties to sell LNG from the Liquefaction Project. Under the SPAs, the customers purchase LNG on either an FOB basis (delivered to the customer at the Corpus Christi LNG terminal. In December 2014, we received authorization fromTerminal) or a DAT basis (delivered to the FERC to site, construct and operate Stages 1 and 2 of the Liquefaction Project. The following table summarizes the overall project status of Stage 1 of the Liquefaction Project as of December 31, 2017:
|
| | |
| Stage 1 |
Overall project completion percentage | 81.8% |
Completion percentage of: | |
Engineering | 100% |
Procurement | 100% |
Subcontract work | 62.2% |
Construction | 59.2% |
Expected date of substantial completion | Train 1 | 1H 2019 |
| Train 2 | 2H 2019 |
The DOE has authorized the export of domestically producedcustomer at their specified LNG by vessel from the Corpus Christi LNG terminal to FTA countries for a 25-year term and to non-FTA countries for a 20-year term up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas. The terms of each of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from 7 to 10 years from the date the order was issued.
Customers
CCL entered into eight fixed-price SPAs with terms of at least 20 years (plus extension rights) with seven third parties to make available an aggregate amount of LNG that is between approximately 85% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 and 2. Under these eight SPAs, the customers will purchase LNG from CCLreceiving terminal) generally 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 generally equal to approximately 115% of Henry Hub. In certain circumstances, theCertain 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 priceThe variable fees under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee price component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connectionwere generally sized with the development of Stage 1 of the Liquefaction Project was sized at the time of entry into each SPA with the intentintention to cover the costs of gas purchases, transportation and transportation related to, and operating and maintenance costsliquefaction fuel consumed to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for Train 1 or Train 2, as specified in each SPA.
In aggregate, the
annual fixed fee portion to be paid by the
third-partythird party SPA customers is approximately
$550 million$2.7 billion for
Train 1, increasingthe Liquefaction Project. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of BBB+, Baa1 and BBB+ by S&P, Moody’s and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 12—Revenues of our Notes to $1.4Consolidated Financial Statements.
In addition to the third party SPAs discussed above, CCL has executed agreements with Cheniere Marketing under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for SPAs associated with IPM agreements for which pricing is linked to international natural gas prices.
Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2023, we had $4.6 billion uponin available commitments under our credit facilities, subject to compliance with the datecovenants, to potentially meet liquidity needs. Our credit facilities mature between 2027 and 2029.
Financially Disciplined Growth
Our significant land position at the Corpus Christi LNG Terminal provides potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. In March 2023, CCL and another subsidiary of firstCheniere submitted an application with the FERC under the NGA for Midscale Trains 8 & 9 Project. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial deliveryand financing arrangements before a positive FID is made.
Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts
We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures related to our core operations under executed contracts as of December 31, 2023 (in billions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | |
| 2024 | | 2025 - 2028 | | Thereafter | | Total |
Purchase obligations (2): | | | | | | | |
Natural gas supply agreements (3) | $ | 2.2 | | | $ | 10.2 | | | $ | 20.2 | | | $ | 32.6 | |
Natural gas transportation and storage service agreements (4) | 0.2 | | | 1.0 | | | 2.8 | | | 4.0 | |
Capital expenditures | 1.2 | | | 1.7 | | | — | | | 2.9 | |
| | | | | | | |
| | | | | | | |
Other purchase obligations (5) | 0.1 | | | 1.0 | | | 6.8 | | | 7.9 | |
Total | $ | 3.7 | | | $ | 13.9 | | | $ | 29.8 | | | $ | 47.4 | |
(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023.
(2)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 contracts for which we have an early termination option if the option is not currently expected to be exercised. We include contracts with unsatisfied contractual conditions if the conditions are currently expected to be met.
(3)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us.
(4)Includes $1.0 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements with unsatisfied contractual conditions.
(5)Includes $7.6 billion of purchase obligations to affiliates under services agreements, $6.4 billion of which relates to shipping and transportation-related services agreements with Cheniere Marketing.
Natural Gas Supply, Transportation and Storage Service Agreements
We have secured natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements, including IPM agreements. Under our IPM agreements, we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. While our IPM agreements are not revenue contracts for accounting purposes, the payment structure for the purchase of natural gas under the IPM agreements generates a take-or-pay style fixed liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global gas market price paid for the natural gas feedstock purchase.
As of December 31, 2023, we have secured approximately 92% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2024. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2024. Natural gas supply is generally secured on an indexed pricing basis plus a fixed fee, with the applicable fixed fees generally starting from the date of first commercial delivery from the applicable Train.
CCL expects to sell LNG that it produces that is in excesstitle transfer occurring upon receipt of the
contract quantities committedcommodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under CCL’s third-party SPAscontracts with unsatisfied contractual conditions that are currently considered probable of being met and exclusive of extension options that were uncertain to Cheniere Marketing International LLP (“Cheniere Marketing”), an indirect wholly-owned subsidiarybe taken as of Cheniere.December 31, 2023, we have secured up to 7,625 TBtu of natural gas feedstock through agreements with remaining fixed terms of up to approximately 15 years. A discussion of our natural gas supply and IPM agreements can be found in Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements.Natural Gas Transportation, Storage and Supply
To ensure CCL isthat we are able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it hasTerminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity withfrom CCP and certain third-partythird party
interstate and intrastate pipeline companies. CCL hasWe have also entered into a firm storage services agreementagreements with a third partyparties to assist in managing volatilityvariability 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
Capital Expenditures
We enter into such agreements, in order to secure natural gas feedstock for the Liquefaction Project. We expect to enter into gas supply contracts under these enabling agreements as and when required for the Liquefaction Project. As of December 31, 2017, CCL has secured up to approximately 2,024 TBtu of natural gas feedstock through long-term natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.
Construction
CCL entered into separate lump sum turnkey contracts with Bechtelthird party contractors for the engineering, procurement and constructionEPC of Stages 1 and 2our Liquefaction Project. The future capital expenditures included in the table above primarily consist of fixed costs under the LiquefactionBechtel EPC contract for the Corpus Christi Stage 3 Project, underin which Bechtel charges a lump sum for all work performed and generally bears project cost, riskschedule and performance risks unless certain specified events occur,occurred, in which case Bechtel may cause CCLcauses us to enter into a change order, or CCL agreeswe agree with Bechtel to a change order. In addition to amounts presented in the table above, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity. See Financially Disciplined Growth section for further discussion.
The total contract price of the EPC contract for Stage 1, which does not include the Corpus Christi Pipeline, is approximately $7.8 billion, reflecting amounts incurred under change orders through December 31, 2017. Total expected capital costs for Stage 13 Project
The following table summarizes the project completion and the Corpus Christi Pipeline are estimated to be between $9.0 billion and $10.0 billion before financing costs, and between $11.0 billion and $12.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies and total expected capital costs for the Corpus Christi Pipeline of between $350 million and $400 million. The total contract price of the EPC contract for Stage 2, which was amended and restated in December 2017, is approximately $2.4 billion.
Pipeline Facilities
In December 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the Natural Gas Act of 1938, as amended, 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 status of the Corpus Christi Pipeline commenced in January 2017Stage 3 Project as ofDecember 31, 2023:
| | | | | | | | | | | |
| | |
Overall project completion percentage | | 51.4% |
Completion percentage of: | | |
Engineering | | 83.7% |
Procurement | | 72.2% |
Subcontract work | | 66.9% |
Construction | | 11.1% |
Date of expected substantial completion | | 2Q/3Q 2025 - 2H 2026 |
Additional Future Cash Requirements for Operations and is nearing completion.Capital Expenditures
Final Investment Decision on Stage 2Operational Services
We will contemplate making an FID to commence constructionhave contracts with subsidiaries of Stage 2Cheniere for operations, maintenance and management services. As of December 31, 2023, Cheniere and its subsidiaries had 1,605 full-time employees, including 412 employees who directly supported the Liquefaction Project based upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct the facility.
Capital Resources
We expect to finance the construction costs of the Liquefaction Project from one or more of the following: project debt and borrowings, operating cash flow from CCL and CCP and equity contributions from Cheniere. The following table provides a summaryProject. Full discussion of our capital resources for the Liquefaction Project, excluding any equity contributions, at December 31, 2017operations, maintenance and 2016 (in thousands):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Senior notes (1) | | $ | 4,250,000 |
| | $ | 2,750,000 |
|
Credit facilities outstanding balance (2) | | 2,484,737 |
| | 2,380,788 |
|
Letters of credit issued (2) | | 163,578 |
| | — |
|
Available commitments under credit facilities (2) | | 2,273,136 |
| | 3,952,714 |
|
Total capital resources from borrowings and available commitments | | $ | 9,171,451 |
| | $ | 9,083,502 |
|
| |
(1) | Includes 7.000% Senior Secured Notes due 2024 (the “2024 CCH Senior Notes”), 5.875% Senior Secured Notes due 2025 (the “2025 CCH Senior Notes”) and 2027 CCH Senior Notes (collectively, the “CCH Senior Notes”). |
| |
(2) | Includes 2015 CCH Credit Facility and CCH Working Capital Facility. |
For additional information regarding our debtmanagement agreements related to the Liquefaction Project, see can be found in Note 7—Debt13—Related Party Transactions of our Notes to Consolidated Financial Statements.
CCH Senior NotesFinancially Disciplined Growth
In May 2017, we issued an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, in addition to the existing 2024 CCH Senior Notes and 2025 CCH Senior Notes. The CCH Senior Notes are jointly and severally guaranteed by our subsidiaries, CCL, CCP and CCP GP (each a “Guarantor” and collectively, the “Guarantors”).
The indenture governingFID of any expansion projects will result in additional cash requirements to fund the CCH Senior Notes (the “CCH Indenture”) contains customary termsconstruction and eventsoperations of default and certain covenants that, among other things, limit our ability and the abilitysuch projects in excess of our restricted subsidiaries to: incur additional indebtedness or issue preferred stock;current contractual obligations under executed contracts discussed above. However, in connection with reaching FID, we may be required to secure financing to meet the cash needs that such project will initially require, in support of commercializing the project.
Beyond the Corpus Christi Stage 3 Project, our affiliates hold significant land positions at the Corpus Christi LNG Terminal, which provides potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources, including Midscale Trains 8 & 9 Project. We expect that any future expansion at the Corpus Christi LNG Terminal would increase cash requirements to support expanded operations, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to 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 dividendscontracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2023 (in billions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | |
| 2024 | | 2025 - 2028 | | Thereafter | | Total |
Debt | $ | — | | | $ | 2.9 | | | $ | 3.5 | | | $ | 6.4 | |
Interest payments | 0.4 | | | 0.8 | | | 0.6 | | | 1.8 | |
Total | $ | 0.4 | | | $ | 3.7 | | | $ | 4.1 | | | $ | 8.2 | |
(1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or otherestimated forward interest rates in effect at December 31, 2023. Debt and interest 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 usdo not contemplate repurchases, repayments and our restricted subsidiaries taken as a whole; or permit any Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.
At any timeretirements that we may make prior to six months before the respective dates of maturity for each series of the CCH Senior Notes, we may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the CCH Indenture, plus accrued and unpaid interest, if any, to the date of redemption. We also may at any time within six months of the respective dates of maturity for each series of the CCH Senior Notes, redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.contractual maturity.
2015 CCH Credit FacilityDebt
In May 2015, we entered into the 2015 CCH Credit Facility. Our obligations under the 2015 CCH Credit Facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in us. As of December 31, 2017 and 2016, we had $2.1 billion and $3.6 billion2023, our debt complex was comprised of available commitments and $2.5 billion and $2.4 billion of outstanding borrowings under the 2015 CCH Credit Facility, respectively.
The principal of the loans made under the 2015 CCH Credit Facility must be repaid in quarterly installments, commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following project completion and (2) a set date determined by reference to the date under which a certain LNG buyer linked to Train 2 of the Liquefaction Project is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments
will be based upon a 19-year tailored amortization, commencing the first full quarter after the project completion and designed to achieve a minimum projected fixed debt service coverage ratio of 1.55:1.
Under the 2015 CCH Credit Facility, we are required to hedge not less than 65% of the variable interest rate exposure of our senior secured debt. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, the completion of the construction of Trains 1 and 2 of the Liquefaction Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.
CCH Working Capital Facility
In December 2016, we entered into the $350 million CCH Working Capital Facility, which is intended to be used for loans (“CCH Working Capital Loans”), the issuance of letters of credit, as well as for swing line loans (“CCH Swing Line Loans”) for certain working capital requirements related to developing and placing into operation the Liquefaction Project. Loans under the CCH Working Capital Facility are guaranteed by the Guarantors. We may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed under the Common Terms Agreement that was entered into concurrentlynotes with the 2015 CCH Credit Facility. We did not have any amounts outstanding under the CCH Working Capital Facility as of both December 31, 2017 and 2016 and $163.6 million and zero aggregate amount of letters of credit were issued as of December 31, 2017 and 2016, respectively.
The CCH Working Capital Facility matures on December 14, 2021, and we may prepay the CCH Working Capital Loans, CCH Swing Line Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans”) at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. CCH Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the CCH Working Capital Facility, (2) the date that is 15 days after such CCH Swing Line Loan is made and (3) the first borrowing date for a CCH Working Capital Loan or CCH Swing Line Loan occurring at least four business days following the date the CCH Swing Line Loan is made. We are required to reduce thean aggregate outstanding principal amountbalance 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$6.4 billion and credit as well as customary affirmative and negative covenants. Our obligations under the CCH Working Capital Facility are secured by substantially all our assets and the assets of the Guarantors as well as all of our membership interests and each of the Guarantors on a pari passu basisfacilities with the CCH Senior Notes and the 2015 CCH Credit Facility.
Equity Contribution Agreement
In May 2015, we entered into an equity contribution agreement with Cheniere (the “Equity Contribution Agreement”) pursuant to which Cheniere agreed to provide tiered equity contributions of approximately $2.6 billion for Stage 1 and the Corpus Christi Pipeline. The first tier of equity funding of approximately $1.5 billion (the “First Tier Equity Funding”) was contributed to us concurrently with the closing of the 2015 CCH Credit Facility. The second tier of equity funding, up to a maximum amount of approximately $1.1 billion, will be contributed concurrently and pro rata with funding under our project financing debt starting on the date on which further disbursements of such debt would result in a senior debt to equity ratio of greater than 75/25 (the “Second Tier Pro Rata Equity Funding”).no outstanding loan balances. As of December 31, 2017, we have received $1.9 billion in contributions under the Equity Contribution Agreement, of which approximately $1.5 billion was the First Tier Equity Funding and approximately $0.4 billion was part of the Second Tier Pro Rata Equity Funding. On March 2, 2017, Cheniere entered into a $750 million senior secured revolving credit facility (the “CEI Revolving Credit Facility”). The proceeds of the CEI Revolving Credit Facility are available to Cheniere to back-stop its obligations under the Equity Contribution Agreement to provide the Second Tier Pro Rata Equity Funding to us and for general corporate purposes.
Early Works Equity Contribution Agreement
In December 2017, we entered into an early works equity contribution agreement with Cheniere pursuant to which Cheniere is obligated to provide, directly or indirectly, at our request based on amounts due and payable in respect of limited notices to proceed issued under the Stage 2 EPC Contract, cash contributions of up to $310.0 million to us for the early works related to Stage 2. The amount of cash contributions Cheniere provides may be increased by Cheniere in its sole discretion. As of December 31, 2017, we have received $35.0 million in contributions from Cheniere under this agreement.
Restrictive Debt Covenants
As of December 31, 2017,2023, we were in compliance with all covenants related to our debt agreements.
Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 11—Debt of our Notes to Consolidated Financial Statements.
Tax-Related MattersInterest
On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. The reduction in the corporate tax rate will likely reduce our effective tax rate in future periods. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets2023, our senior notes had a weighted average contractual interest rate of 4.52%. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.10% and liabilities. The result0.525%, subject to change based on our credit rating. Issued letters of credit under the remeasurement wasCCH Working Capital Facility are subject to letter of credit fees of 1.125%. We had $155 million aggregate amount of issued letters of credit under the CCH Working Capital Facility as of December 31, 2023.
Additional Future Cash Requirements for Financing
Capital Allocation Plan
In September 2022, the board of directors of Cheniere approved a $58.9 million reduction torevised long-term capital allocation plan, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of debt, including our U.S. net deferred tax assets and represents a 121.1% decrease to our effective tax rate. A corresponding change, reducing the effective tax rate, was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense.senior notes.
Results of Operations
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
(in millions) | | | | | | | 2023 | | 2022 | | Variance |
Revenues | | | | | | | | | | | |
LNG revenues | | | | | | | $ | 3,845 | | | $ | 6,336 | | | $ | (2,491) | |
LNG revenues—affiliate | | | | | | | 1,620 | | | 3,027 | | | (1,407) | |
| | | | | | | | | | | |
Total revenues | | | | | | | 5,465 | | | 9,363 | | | (3,898) | |
| | | | | | | | | | | |
Operating costs and expenses (recoveries) | | | | | | | | | | | |
Cost (recovery) of sales (excluding items shown separately below) | | | | | | | (3,178) | | | 9,656 | | | (12,834) | |
Cost of sales—affiliate | | | | | | | 171 | | | 103 | | | 68 | |
| | | | | | | | | | | |
Operating and maintenance expense | | | | | | | 479 | | | 458 | | | 21 | |
Operating and maintenance expense—affiliate | | | | | | | 116 | | | 121 | | | (5) | |
Operating and maintenance expense—related party | | | | | | | 9 | | | 9 | | | — | |
| | | | | | | | | | | |
| | | | | | | | | | | |
General and administrative expense | | | | | | | 6 | | | 8 | | | (2) | |
General and administrative expense—affiliate | | | | | | | 45 | | | 38 | | | 7 | |
Depreciation and amortization expense | | | | | | | 449 | | | 445 | | | 4 | |
Other | | | | | | | 2 | | | 6 | | | (4) | |
Total operating costs and expenses (recoveries) | | | | | | | (1,901) | | | 10,844 | | | (12,745) | |
| | | | | | | | | | | |
Income (loss) from operations | | | | | | | 7,366 | | | (1,481) | | | 8,847 | |
| | | | | | | | | | | |
Other income (expense) | | | | | | | | | | | |
Interest expense, net of capitalized interest | | | | | | | (217) | | | (432) | | | 215 | |
Loss on modification or extinguishment of debt | | | | | | | (10) | | | (37) | | | 27 | |
| | | | | | | | | | | |
Other income, net | | | | | | | 11 | | | 8 | | | 3 | |
Total other expense | | | | | | | (216) | | | (461) | | | 245 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Net income (loss) | | | | | | | $ | 7,150 | | | $ | (1,942) | | | $ | 9,092 | |
Volumes loaded and recognized from the Liquefaction Project
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | |
(in TBtu) | | | | | | | 2023 | | 2022 | | Variance | | |
Volumes loaded during the current period | | | | | | | 763 | | | 775 | | | (12) | | | |
Volumes loaded during the prior period but recognized during the current period | | | | | | | 3 | | | — | | | 3 | | | |
Volumes loaded at our affiliate’s facility | | | | | | | 5 | | | — | | | 5 | | | |
Less: volumes loaded during the current period and in transit at the end of the period | | | | | | | — | | | (3) | | | 3 | | | |
Total volumes recognized in the current period | | | | | | | 771 | | | 772 | | | (1) | | | |
Net income (loss)
Substantially all of the favorable variance of $9.1 billion between the years ended December 31, 2023 and 2022 was attributable to favorable changes in fair value and settlements of derivatives of $9.1 billionbetween the periods, of which $7.7 billionrelated to non-cash favorable changes in fair value of our IPM agreements where we procure natural gas at a price indexed to international gas prices as a result of lower volatility in international gas prices and declines in international forward commodity curves.
The following is an additional discussion of the significant drivers of the variance in net income (loss) by line item:
Revenues
Substantially all of the $3.9 billion decrease between the years ended December 31, 2023 and 2022 was attributable to a $3.8 billion decrease from lower pricing per MMBtu as a result of decreased Henry Hub pricing.
Operating costs and expenses (recoveries)
The $12.7 billion favorable variance between the years ended December 31, 2023 and 2022, was primarily attributable to:
•$9.1 billion favorable variance from changes in fair value and settlements of derivatives included in cost of sales, from a $3.2 billion of loss in the year ended December 31, 2022 to a $5.8 billion of gain in the year ended December 31, 2023 primarily due to decreased international gas prices resulting in non-cash favorable changes in fair value of our commodity derivatives indexed to such prices and, to a lesser extent, an increase in forward notional amount of derivatives due to agreements contributed to us upon the merger of CCL Stage III with and into CCL in June 2022; and
•$3.7 billion decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of a $3.4 billion in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices.
Other income (expense)
The $245 million decrease between the years ended December 31, 2023 and 2022 was primarily attributable to a $215 million decrease in interest expense, net of capitalized interest, between the years ended December 31, 2023 and 2022, as a result of lower debt balances due to repayment of debt, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources. Additionally, the decrease in interest expense, net of capitalized interest, between the years ended December 31, 2023 and 2022 was due to a higher portion of total interest costs eligible for capitalization following the issuance of full notice to proceed to Bechtel on the Corpus Christi Stage 3 Project in June 2022.
Significant factors affecting our results of operations
Below are significant factors that affect our results of operations.
Gains and losses on derivative instruments
Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risks and are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM
agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of our Liquefaction Supply Derivatives incorporates market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.
Liquidity and Capital Resources
The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
| | | | | | | |
| December 31, 2023 | | |
| |
| | | |
| | | |
| | | |
Restricted cash and cash equivalents designated for the Liquefaction Project | $ | 175 | | | |
Available commitments under our credit facilities (1): | | | |
Term loan facility agreement (the “CCH Credit Facility”) | 3,260 | | | |
Working capital facility agreement (the “CCH Working Capital Facility”) | 1,345 | | | |
Total available commitments under our credit facilities | 4,605 | | | |
| | | |
Total available liquidity | $ | 4,780 | | | |
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2023. See Note 11—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.
Our liquidity position subsequent to December 31, 2023 will be driven by future sources of liquidity and future cash requirements as further discussed under the caption Future Sources and Uses of Liquidity.
Supplemental Guarantor Information
The 5.875% Senior Secured Notes due 2025, 5.125% Senior Secured Notes due 2027, 3.700% Senior Secured Notes due 2029 and the series of Senior Secured Notes due 2039 with weighted average rate of 3.788% (collectively, the “Senior Secured Notes”) are jointly and severally guaranteed by each of our consolidated subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “Guarantor” and collectively, the “Guarantors”).
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 Senior Secured 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 Senior Secured 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 Senior Secured 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 is omitted herein because such information would not be materially different from our Consolidated Financial Statements.
Corpus Christi Stage 3 Project
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:
| | | | | | | | | | | |
| | |
Overall project completion percentage | | 51.4% |
Completion percentage of: | | |
Engineering | | 83.7% |
Procurement | | 72.2% |
Subcontract work | | 66.9% |
Construction | | 11.1% |
Date of expected substantial completion | | 2Q/3Q 2025 - 2H 2026 |
Future Sources and Uses of Liquidity
The following discussion of our future sources and uses of our cash, cash equivalentsliquidity includes estimates that reflect management’s assumptions and restricted cash for the years endedcurrently known market conditions and other factors as of December 31, 2017, 20162023. Estimates are not guarantees of future performance and 2015actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
Future Sources of Liquidity under Executed SPAs
As described in Items 1. and 2. Business and Properties, our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Substantially all of our future revenues are contracted under SPAs and because many of these contracts have long-term durations, we are contractually entitled to significant future consideration under these contracts which has not yet been recognized as revenue. This future consideration is in most cases, not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2023. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed SPAs as of December 31, 2023 (in thousands).billions): | | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Revenues Under Executed SPAs by Period (1) (2) |
| | | | | | | | |
| | 2024 | | 2025 - 2028 | | Thereafter | | Total |
LNG revenues (fixed fees) | | $ | 2.1 | | | $ | 11.0 | | | $ | 37.4 | | | $ | 50.5 | |
| | | | | | | | |
LNG revenues (variable fees) (2) | | 2.9 | | | 20.4 | | | 80.9 | | | 104.2 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total | | $ | 5.0 | | | $ | 31.4 | | | $ | 118.3 | | | $ | 154.7 | |
(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023. The table presents capital expenditurestiming of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a cash basis; therefore, these amounts differcertain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the revenues above when the conditions are considered probable of being met.
(2)LNG revenues (including $1.0 billion and $28.7 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises, in certain instances, their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.
(3)LNG revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated forward prices and basis spreads as of December 31, 2023. The pricing structure of many of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices.
Through our SPAs and IPM agreements, we have contracted approximately 90% of the total anticipated production from the amountsLiquefaction Project, with approximately 17 years of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussionweighted average remaining life as of these items follows the table.
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Operating cash flows | $ | (64,316 | ) | | $ | (41,079 | ) | | $ | (107,202 | ) |
Investing cash flows | (1,962,209 | ) | | (2,095,897 | ) | | (3,839,415 | ) |
Financing cash flows | 1,982,544 |
| | 2,360,746 |
| | 3,993,387 |
|
| | | | | |
Net increase (decrease) in cash, cash equivalents and restricted cash | (43,981 | ) | | 223,770 |
| | 46,770 |
|
Cash, cash equivalents and restricted cash—beginning of period | 270,540 |
| | 46,770 |
| | — |
|
Cash, cash equivalents and restricted cash—end of period | $ | 226,559 |
| | $ | 270,540 |
| | $ | 46,770 |
|
Operating Cash Flows
Operating cash outflows during the years ended December 31, 2017, 2016 and 2015 were $64.3 million, $41.1 million and $107.2 million, respectively.2023. The increase in operating cash outflows in 2017 compared to 2016 was primarily related to increased cash used for settlement of derivative instruments. The operating cash outflows in 2015 were higher than in 2016 primarily due to the payment of $50.1 million for contingency and syndication premiums upon meeting the contingency related to the interest rate swaps to hedge the exposure to volatility in portionmajority of the floating-rate interest payments under the 2015 CCH Credit Facility (“Interest Rate Derivatives”) in May 2015, as well as interest payments relatedcontracted capacity is comprised of fixed-price, long-term SPAs we have executed with third parties to the 2015 CCH Credit Facility.
Investing Cash Flows
Investing cash outflows during each of the years ended December 31, 2017, 2016 and 2015 were $2.0 billion, $2.1 billion and $3.8 billion, respectively, and are primarily used to fund the construction costs for Stage 1 ofsell LNG from the Liquefaction Project.
TheseUnder the SPAs, the customers purchase LNG on either an FOB basis (delivered to the customer at the Corpus Christi LNG Terminal) or a DAT basis (delivered to the customer at their specified LNG receiving terminal) generally 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 generally equal to 115% of Henry Hub. Certain 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. The variable fees under our SPAs were generally sized with the intention to cover the costs
are capitalized as construction-in-process until achievement of
substantial completion. gas purchases, transportation and liquefaction fuel consumed to produce the LNG to be sold under each such SPA. In aggregate, the annual fixed fee portion to be paid by the third party SPA customers is approximately $2.7 billion for the Liquefaction Project. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of BBB+, Baa1 and BBB+ by S&P, Moody’s and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 12—Revenues of our Notes to Consolidated Financial Statements.
In addition to cash outflowsthe third party SPAs discussed above, CCL has executed agreements with Cheniere Marketing under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for construction costsSPAs associated with IPM agreements for the Liquefaction Project, we received $36.3 million during the year endedwhich pricing is linked to international natural gas prices.
Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2017 from2023, we had $4.6 billion in available commitments under our credit facilities, subject to compliance with the returncovenants, to potentially meet liquidity needs. Our credit facilities mature between 2027 and 2029.
Financially Disciplined Growth
Our significant land position at the Corpus Christi LNG Terminal provides potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. In March 2023, CCL and another subsidiary of collateral payments previously paid forCheniere submitted an application with the Liquefaction Project, which was offset by $11.3 million paid for infrastructure to support the Liquefaction Project. During the year ended December 31, 2016, we used an additional $44.4 million primarily for infrastructure of the Liquefaction Project, which included the $36.3 million of collateral payments that were returned to us during the year ended December 31, 2017.
Financing Cash Flows
Financing cash inflows during the year ended December 31, 2017 were $2.0 billion, primarily as a result of:
$1.5 billion of borrowingsFERC under the 2015 CCH Credit Facility;
issuance of an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, which was used to prepay $1.4 billion of outstanding borrowings under the 2015 CCH Credit Facility;
$24.0 million of borrowings and $24.0 million of repayments made under the CCH Working Capital Facility;
$23.5 million of debt issuance and deferred financing costs related to up-front fees paid upon the closingNGA for Midscale Trains 8 & 9 Project. The development of these transactions;sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before a positive FID is made.
Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts
Financing cash inflows during the year ended December 31, 2016 were $2.4 billion, primarily as a result of:
$2.1 billion of borrowings under the 2015 CCH Credit Facility;
issuances of aggregate principal amounts of $1.25 billion of the 2024 CCH Senior Notes and $1.5 billion of the 2025 CCH Senior Notes in December 2016, which were used to prepay $2.4 billion of the outstanding borrowings under the 2015 CCH Credit Facility; and
$56.8 million of debt issuance costs related to up-front fees paid upon the closing of these transactions.
Financing cash inflows during the year ended December 31, 2015 were $4.0 billion, primarily as a result of:
$2.7 billion of borrowings under the 2015 CCH Credit Facility;
$0.3 billion of debt issuance costs related to up-front fees paid upon the closing of the 2015 CCH Credit Facility; and
$1.6 billion of equity contributions from Cheniere.
Contractual Obligations
We are committed to make future cash payments in the futurefor operations and capital expenditures pursuant to certain of our contracts. The following table summarizes certain contractual obligations in placeour estimate of material cash requirements for operations and capital expenditures related to our core operations under executed contracts as of December 31, 20172023 (in thousands)billions):
|
| | | | | | | | | | | | | | | | | | | | |
| | Payments Due By Period (1) |
| | Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Thereafter |
Debt (2) | | $ | 6,734,737 |
| | $ | — |
| | $ | — |
| | $ | 2,484,737 |
| | $ | 4,250,000 |
|
Interest payments (2) | | 2,476,865 |
| | 372,651 |
| | 750,493 |
| | 678,252 |
| | 675,469 |
|
Construction obligations (3) | | 1,203,076 |
| | 831,636 |
| | 371,440 |
| | — |
| | — |
|
Purchase obligations (4) | | 24,352 |
| | 22,936 |
| | 1,416 |
| | — |
| | — |
|
Operating lease obligations (5) | | 1,981 |
| | 895 |
| | 1,086 |
| | — |
| | — |
|
Obligations to affiliates (6) | | 1,098 |
| | 357 |
| | 654 |
| | 87 |
| | — |
|
Other obligations (7) | | 120,915 |
| | 3,000 |
| | 36,493 |
| | 53,989 |
| | 27,433 |
|
Total | | $ | 10,563,024 |
|
| $ | 1,231,475 |
|
| $ | 1,161,582 |
|
| $ | 3,217,065 |
|
| $ | 4,952,902 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | |
| 2024 | | 2025 - 2028 | | Thereafter | | Total |
Purchase obligations (2): | | | | | | | |
Natural gas supply agreements (3) | $ | 2.2 | | | $ | 10.2 | | | $ | 20.2 | | | $ | 32.6 | |
Natural gas transportation and storage service agreements (4) | 0.2 | | | 1.0 | | | 2.8 | | | 4.0 | |
Capital expenditures | 1.2 | | | 1.7 | | | — | | | 2.9 | |
| | | | | | | |
| | | | | | | |
Other purchase obligations (5) | 0.1 | | | 1.0 | | | 6.8 | | | 7.9 | |
Total | $ | 3.7 | | | $ | 13.9 | | | $ | 29.8 | | | $ | 47.4 | |
| |
(1) | (1)Agreements in force as of December 31, 2017 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2017. |
| |
(2) | Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2017. See Note 7—Debt of our Notes to Consolidated Financial Statements. |
| |
(3) | Construction obligations primarily relate to the EPC contracts for the Liquefaction Project. The estimated remaining cost pursuant to our EPC contracts as of December 31, 2017 is included for Trains with respect to which we have made an FID to commence construction; the EPC contract termination amount is included for Trains with respect to which we have not made an FID. A discussion of these obligations can be found at Note 11—Commitments and Contingencies of our Notes to Consolidated Financial Statements. |
| |
(4) | Purchase obligations consist of contracts for which conditions precedent have been met, and primarily relate to maintenance contracts and purchase of spare parts for the Liquefaction Project. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly. |
| |
(5) | Operating lease obligations primarily relate to land sites for the Liquefaction Project. A discussion of these obligations can be found in Note 10—Leases of our Notes to Consolidated Financial Statements. |
| |
(6) | Obligations to affiliates relate to land leased from Cheniere Land Holdings, LLC, a wholly owned subsidiary of Cheniere, for the Liquefaction Project. |
| |
(7) | Other obligations primarily relate to agreements with certain local taxing jurisdictions, and are based on estimated tax obligations as of December 31, 2017. |
In addition, in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the ordinary courseestimated dates as of business,December 31, 2023.
(2)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 contracts for which we maintain lettershave an early termination option if the option is not currently expected to be exercised. We include contracts with unsatisfied contractual conditions if the conditions are currently expected to be met.
(3)Pricing of creditnatural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us.
(4)Includes $1.0 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements with unsatisfied contractual conditions.
(5)Includes $7.6 billion of purchase obligations to affiliates under services agreements, $6.4 billion of which relates to shipping and transportation-related services agreements with Cheniere Marketing.
Natural Gas Supply, Transportation and Storage Service Agreements
We have secured natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements, including IPM agreements. Under our IPM agreements, we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain cash restricted in supportcosts incurred by us. While our IPM agreements are not revenue contracts for accounting purposes, the payment structure for the purchase of certain performance obligations of our subsidiaries. natural gas under the IPM agreements generates a take-or-pay style fixed liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global gas market price paid for the natural gas feedstock purchase.
As of December 31, 2017,2023, we have secured approximately 92% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2024. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2024. Natural gas supply is generally secured on an indexed pricing basis plus a fixed fee, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under contracts with unsatisfied contractual conditions that are currently considered probable of being met and exclusive of extension options that were uncertain to be taken as of December 31, 2023, we have secured up to 7,625 TBtu of natural gas feedstock through agreements with remaining fixed terms of up to approximately 15 years. A discussion of our natural gas supply and IPM agreements can be found in Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements.
To ensure that we are able to transport natural gas feedstock to the Corpus Christi LNG Terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity from CCP and third party
interstate and intrastate pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project.
Capital Expenditures
We enter into lump sum turnkey contracts with third party contractors for the EPC of our Liquefaction Project. The future capital expenditures included in the table above primarily consist of fixed costs under the Bechtel EPC contract for the Corpus Christi Stage 3 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occurred, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order. In addition to amounts presented in the table above, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity. See Financially Disciplined Growth section for further discussion.
Corpus Christi Stage 3 Project
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as ofDecember 31, 2023:
| | | | | | | | | | | |
| | |
Overall project completion percentage | | 51.4% |
Completion percentage of: | | |
Engineering | | 83.7% |
Procurement | | 72.2% |
Subcontract work | | 66.9% |
Construction | | 11.1% |
Date of expected substantial completion | | 2Q/3Q 2025 - 2H 2026 |
Additional Future Cash Requirements for Operations and Capital Expenditures
Operational Services
We have contracts with subsidiaries of Cheniere for operations, maintenance and management services. As of December 31, 2023, Cheniere and its subsidiaries had $163.61,605 full-time employees, including 412 employees who directly supported the Liquefaction Project. Full discussion of our operations, maintenance and management agreements can be found in Note 13—Related Party Transactions of our Notes to Consolidated Financial Statements.
Financially Disciplined Growth
The FID of any expansion projects will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above. However, in connection with reaching FID, we may be required to secure financing to meet the cash needs that such project will initially require, in support of commercializing the project.
Beyond the Corpus Christi Stage 3 Project, our affiliates hold significant land positions at the Corpus Christi LNG Terminal, which provides potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources, including Midscale Trains 8 & 9 Project. We expect that any future expansion at the Corpus Christi LNG Terminal would increase cash requirements to support expanded operations, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2023 (in billions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | |
| 2024 | | 2025 - 2028 | | Thereafter | | Total |
Debt | $ | — | | | $ | 2.9 | | | $ | 3.5 | | | $ | 6.4 | |
Interest payments | 0.4 | | | 0.8 | | | 0.6 | | | 1.8 | |
Total | $ | 0.4 | | | $ | 3.7 | | | $ | 4.1 | | | $ | 8.2 | |
(1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2023. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.
Debt
As of December 31, 2023, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $6.4 billion and credit facilities with no outstanding loan balances. As of December 31, 2023, we were in compliance with all covenants related to our debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 11—Debt of our Notes to Consolidated Financial Statements.
Interest
As of December 31, 2023, our senior notes had a weighted average contractual interest rate of 4.52%. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.10% and 0.525%, subject to change based on our credit rating. Issued letters of credit under the CCH Working Capital Facility are subject to letter of credit fees of 1.125%. We had $155 million aggregate amount of issued letters of credit under the CCH Working Capital Facility
and $226.6 millionas of
current restricted cash. For more information, see Note 3—RestrictedDecember 31, 2023.
Additional Future Cash Requirements for Financing
Capital Allocation Plan
In September 2022, the board of directors of Cheniere approved a revised long-term capital allocation plan, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of debt, including our Notes to Consolidated Financial Statements.senior notes.
Results of Operations
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
(in millions) | | | | | | | 2023 | | 2022 | | Variance |
Revenues | | | | | | | | | | | |
LNG revenues | | | | | | | $ | 3,845 | | | $ | 6,336 | | | $ | (2,491) | |
LNG revenues—affiliate | | | | | | | 1,620 | | | 3,027 | | | (1,407) | |
| | | | | | | | | | | |
Total revenues | | | | | | | 5,465 | | | 9,363 | | | (3,898) | |
| | | | | | | | | | | |
Operating costs and expenses (recoveries) | | | | | | | | | | | |
Cost (recovery) of sales (excluding items shown separately below) | | | | | | | (3,178) | | | 9,656 | | | (12,834) | |
Cost of sales—affiliate | | | | | | | 171 | | | 103 | | | 68 | |
| | | | | | | | | | | |
Operating and maintenance expense | | | | | | | 479 | | | 458 | | | 21 | |
Operating and maintenance expense—affiliate | | | | | | | 116 | | | 121 | | | (5) | |
Operating and maintenance expense—related party | | | | | | | 9 | | | 9 | | | — | |
| | | | | | | | | | | |
| | | | | | | | | | | |
General and administrative expense | | | | | | | 6 | | | 8 | | | (2) | |
General and administrative expense—affiliate | | | | | | | 45 | | | 38 | | | 7 | |
Depreciation and amortization expense | | | | | | | 449 | | | 445 | | | 4 | |
Other | | | | | | | 2 | | | 6 | | | (4) | |
Total operating costs and expenses (recoveries) | | | | | | | (1,901) | | | 10,844 | | | (12,745) | |
| | | | | | | | | | | |
Income (loss) from operations | | | | | | | 7,366 | | | (1,481) | | | 8,847 | |
| | | | | | | | | | | |
Other income (expense) | | | | | | | | | | | |
Interest expense, net of capitalized interest | | | | | | | (217) | | | (432) | | | 215 | |
Loss on modification or extinguishment of debt | | | | | | | (10) | | | (37) | | | 27 | |
| | | | | | | | | | | |
Other income, net | | | | | | | 11 | | | 8 | | | 3 | |
Total other expense | | | | | | | (216) | | | (461) | | | 245 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Net income (loss) | | | | | | | $ | 7,150 | | | $ | (1,942) | | | $ | 9,092 | |
Our consolidated
Volumes loaded and recognized from the Liquefaction Project
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | |
(in TBtu) | | | | | | | 2023 | | 2022 | | Variance | | |
Volumes loaded during the current period | | | | | | | 763 | | | 775 | | | (12) | | | |
Volumes loaded during the prior period but recognized during the current period | | | | | | | 3 | | | — | | | 3 | | | |
Volumes loaded at our affiliate’s facility | | | | | | | 5 | | | — | | | 5 | | | |
Less: volumes loaded during the current period and in transit at the end of the period | | | | | | | — | | | (3) | | | 3 | | | |
Total volumes recognized in the current period | | | | | | | 771 | | | 772 | | | (1) | | | |
Net income (loss)
Substantially all of the favorable variance of $9.1 billion between the years ended December 31, 2023 and 2022 was attributable to favorable changes in fair value and settlements of derivatives of $9.1 billionbetween the periods, of which $7.7 billionrelated to non-cash favorable changes in fair value of our IPM agreements where we procure natural gas at a price indexed to international gas prices as a result of lower volatility in international gas prices and declines in international forward commodity curves.
The following is an additional discussion of the significant drivers of the variance in net lossincome (loss) by line item:
Revenues
Substantially all of the $3.9 billion decrease between the years ended December 31, 2023 and 2022 was $48.7 millionattributable to a $3.8 billion decrease from lower pricing per MMBtu as a result of decreased Henry Hub pricing.
Operating costs and expenses (recoveries)
The $12.7 billion favorable variance between the years ended December 31, 2023 and 2022, was primarily attributable to:
•$9.1 billion favorable variance from changes in fair value and settlements of derivatives included in cost of sales, from a $3.2 billion of loss in the year ended December 31, 2017, compared2022 to a net loss$5.8 billion of $85.5 milliongain in the year ended December 31, 2016. This $36.82023 primarily due to decreased international gas prices resulting in non-cash favorable changes in fair value of our commodity derivatives indexed to such prices and, to a lesser extent, an increase in forward notional amount of derivatives due to agreements contributed to us upon the merger of CCL Stage III with and into CCL in June 2022; and
•$3.7 billion decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of a $3.4 billion in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices.
Other income (expense)
The $245 million decrease between the years ended December 31, 2023 and 2022 was primarily attributable to a $215 million decrease in interest expense, net lossof capitalized interest, between the years ended December 31, 2023 and 2022, as a result of lower debt balances due to repayment of debt, as further detailed under Financing Cash Flows in 2017Sources and Uses of Cash within Liquidity and Capital Resources. Additionally, the decrease in interest expense, net of capitalized interest, between the years ended December 31, 2023 and 2022 was due to a higher portion of total interest costs eligible for capitalization following the issuance of full notice to proceed to Bechtel on the Corpus Christi Stage 3 Project in June 2022. Significant factors affecting our results of operations
Below are significant factors that affect our results of operations.
Gains and losses on derivative instruments
Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risks and are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM
agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of our Liquefaction Supply Derivatives incorporates market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.
Liquidity and Capital Resources
The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
| | | | | | | |
| December 31, 2023 | | |
| |
| | | |
| | | |
| | | |
Restricted cash and cash equivalents designated for the Liquefaction Project | $ | 175 | | | |
Available commitments under our credit facilities (1): | | | |
Term loan facility agreement (the “CCH Credit Facility”) | 3,260 | | | |
Working capital facility agreement (the “CCH Working Capital Facility”) | 1,345 | | | |
Total available commitments under our credit facilities | 4,605 | | | |
| | | |
Total available liquidity | $ | 4,780 | | | |
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2023. See Note 11—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.
Our liquidity position subsequent to December 31, 2023 will be driven by future sources of liquidity and future cash requirements as further discussed under the caption Future Sources and Uses of Liquidity.
Supplemental Guarantor Information
The 5.875% Senior Secured Notes due 2025, 5.125% Senior Secured Notes due 2027, 3.700% Senior Secured Notes due 2029 and the series of Senior Secured Notes due 2039 with weighted average rate of 3.788% (collectively, the “Senior Secured Notes”) are jointly and severally guaranteed by each of our consolidated subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “Guarantor” and collectively, the “Guarantors”).
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 Senior Secured 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 Senior Secured 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 Senior Secured 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 is omitted herein because such information would not be materially different from our Consolidated Financial Statements.
Corpus Christi Stage 3 Project
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:
| | | | | | | | | | | |
| | |
Overall project completion percentage | | 51.4% |
Completion percentage of: | | |
Engineering | | 83.7% |
Procurement | | 72.2% |
Subcontract work | | 66.9% |
Construction | | 11.1% |
Date of expected substantial completion | | 2Q/3Q 2025 - 2H 2026 |
Future Sources and Uses of Liquidity
The following discussion of our future sources and uses of liquidity includes estimates that reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2023. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
Future Sources of Liquidity under Executed SPAs
As described in Items 1. and 2. Business and Properties, our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Substantially all of our future revenues are contracted under SPAs and because many of these contracts have long-term durations, we are contractually entitled to significant future consideration under these contracts which has not yet been recognized as revenue. This future consideration is in most cases, not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2023. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed SPAs as of December 31, 2023 (in billions): | | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Revenues Under Executed SPAs by Period (1) (2) |
| | | | | | | | |
| | 2024 | | 2025 - 2028 | | Thereafter | | Total |
LNG revenues (fixed fees) | | $ | 2.1 | | | $ | 11.0 | | | $ | 37.4 | | | $ | 50.5 | |
| | | | | | | | |
LNG revenues (variable fees) (2) | | 2.9 | | | 20.4 | | | 80.9 | | | 104.2 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total | | $ | 5.0 | | | $ | 31.4 | | | $ | 118.3 | | | $ | 154.7 | |
(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the revenues above when the conditions are considered probable of being met.
(2)LNG revenues (including $1.0 billion and $28.7 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises, in certain instances, their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.
(3)LNG revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated forward prices and basis spreads as of December 31, 2023. The pricing structure of many of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices.
Through our SPAs and IPM agreements, we have contracted approximately 90% of the total anticipated production from the Liquefaction Project, with approximately 17 years of weighted average remaining life as of December 31, 2023. The majority of the contracted capacity is comprised of fixed-price, long-term SPAs we have executed with third parties to sell LNG from the Liquefaction Project. Under the SPAs, the customers purchase LNG on either an FOB basis (delivered to the customer at the Corpus Christi LNG Terminal) or a DAT basis (delivered to the customer at their specified LNG receiving terminal) generally 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 generally equal to 115% of Henry Hub. Certain 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. The variable fees under our SPAs were generally sized with the intention to cover the costs of gas purchases, transportation and liquefaction fuel consumed to produce the LNG to be sold under each such SPA. In aggregate, the annual fixed fee portion to be paid by the third party SPA customers is approximately $2.7 billion for the Liquefaction Project. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of BBB+, Baa1 and BBB+ by S&P, Moody’s and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 12—Revenues of our Notes to Consolidated Financial Statements.
In addition to the third party SPAs discussed above, CCL has executed agreements with Cheniere Marketing under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for SPAs associated with IPM agreements for which pricing is linked to international natural gas prices.
Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2023, we had $4.6 billion in available commitments under our credit facilities, subject to compliance with the covenants, to potentially meet liquidity needs. Our credit facilities mature between 2027 and 2029.
Financially Disciplined Growth
Our significant land position at the Corpus Christi LNG Terminal provides potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for Midscale Trains 8 & 9 Project. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before a positive FID is made.
Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts
We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures related to our core operations under executed contracts as of December 31, 2023 (in billions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | |
| 2024 | | 2025 - 2028 | | Thereafter | | Total |
Purchase obligations (2): | | | | | | | |
Natural gas supply agreements (3) | $ | 2.2 | | | $ | 10.2 | | | $ | 20.2 | | | $ | 32.6 | |
Natural gas transportation and storage service agreements (4) | 0.2 | | | 1.0 | | | 2.8 | | | 4.0 | |
Capital expenditures | 1.2 | | | 1.7 | | | — | | | 2.9 | |
| | | | | | | |
| | | | | | | |
Other purchase obligations (5) | 0.1 | | | 1.0 | | | 6.8 | | | 7.9 | |
Total | $ | 3.7 | | | $ | 13.9 | | | $ | 29.8 | | | $ | 47.4 | |
(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023.
(2)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 contracts for which we have an early termination option if the option is not currently expected to be exercised. We include contracts with unsatisfied contractual conditions if the conditions are currently expected to be met.
(3)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us.
(4)Includes $1.0 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements with unsatisfied contractual conditions.
(5)Includes $7.6 billion of purchase obligations to affiliates under services agreements, $6.4 billion of which relates to shipping and transportation-related services agreements with Cheniere Marketing.
Natural Gas Supply, Transportation and Storage Service Agreements
We have secured natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements, including IPM agreements. Under our IPM agreements, we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. While our IPM agreements are not revenue contracts for accounting purposes, the payment structure for the purchase of natural gas under the IPM agreements generates a take-or-pay style fixed liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global gas market price paid for the natural gas feedstock purchase.
As of December 31, 2023, we have secured approximately 92% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2024. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2024. Natural gas supply is generally secured on an indexed pricing basis plus a fixed fee, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under contracts with unsatisfied contractual conditions that are currently considered probable of being met and exclusive of extension options that were uncertain to be taken as of December 31, 2023, we have secured up to 7,625 TBtu of natural gas feedstock through agreements with remaining fixed terms of up to approximately 15 years. A discussion of our natural gas supply and IPM agreements can be found in Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements.
To ensure that we are able to transport natural gas feedstock to the Corpus Christi LNG Terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity from CCP and third party
interstate and intrastate pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project.
Capital Expenditures
We enter into lump sum turnkey contracts with third party contractors for the EPC of our Liquefaction Project. The future capital expenditures included in the table above primarily consist of fixed costs under the Bechtel EPC contract for the Corpus Christi Stage 3 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occurred, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order. In addition to amounts presented in the table above, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity. See Financially Disciplined Growth section for further discussion.
Corpus Christi Stage 3 Project
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as ofDecember 31, 2023:
| | | | | | | | | | | |
| | |
Overall project completion percentage | | 51.4% |
Completion percentage of: | | |
Engineering | | 83.7% |
Procurement | | 72.2% |
Subcontract work | | 66.9% |
Construction | | 11.1% |
Date of expected substantial completion | | 2Q/3Q 2025 - 2H 2026 |
Additional Future Cash Requirements for Operations and Capital Expenditures
Operational Services
We have contracts with subsidiaries of Cheniere for operations, maintenance and management services. As of December 31, 2023, Cheniere and its subsidiaries had 1,605 full-time employees, including 412 employees who directly supported the Liquefaction Project. Full discussion of our operations, maintenance and management agreements can be found in Note 13—Related Party Transactions of our Notes to Consolidated Financial Statements.
Financially Disciplined Growth
The FID of any expansion projects will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above. However, in connection with reaching FID, we may be required to secure financing to meet the cash needs that such project will initially require, in support of commercializing the project.
Beyond the Corpus Christi Stage 3 Project, our affiliates hold significant land positions at the Corpus Christi LNG Terminal, which provides potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources, including Midscale Trains 8 & 9 Project. We expect that any future expansion at the Corpus Christi LNG Terminal would increase cash requirements to support expanded operations, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2023 (in billions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | |
| 2024 | | 2025 - 2028 | | Thereafter | | Total |
Debt | $ | — | | | $ | 2.9 | | | $ | 3.5 | | | $ | 6.4 | |
Interest payments | 0.4 | | | 0.8 | | | 0.6 | | | 1.8 | |
Total | $ | 0.4 | | | $ | 3.7 | | | $ | 4.1 | | | $ | 8.2 | |
(1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2023. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.
Debt
As of December 31, 2023, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $6.4 billion and credit facilities with no outstanding loan balances. As of December 31, 2023, we were in compliance with all covenants related to our debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 11—Debt of our Notes to Consolidated Financial Statements.
Interest
As of December 31, 2023, our senior notes had a weighted average contractual interest rate of 4.52%. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.10% and 0.525%, subject to change based on our credit rating. Issued letters of credit under the CCH Working Capital Facility are subject to letter of credit fees of 1.125%. We had $155 million aggregate amount of issued letters of credit under the CCH Working Capital Facility as of December 31, 2023.
Additional Future Cash Requirements for Financing
Capital Allocation Plan
In September 2022, the board of directors of Cheniere approved a revised long-term capital allocation plan, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of debt, including our senior notes.
Sources and Uses of Cash
The following table summarizes the sources and uses of our restricted cash and cash equivalents (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, |
| | 2023 | | 2022 | | |
| | | | | | |
Net cash provided by operating activities | | $ | 1,765 | | | $ | 1,734 | | | |
Net cash used in investing activities | | (1,722) | | | (980) | | | |
Net cash used in financing activities | | (606) | | | (60) | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
Net increase (decrease) in restricted cash and cash equivalents | | $ | (563) | | | $ | 694 | | | |
| | | | | | |
| | | | | | |
Operating Cash Flows
Operating cash flows between the years ended December 31, 2023 and 2022 remained relatively flat due to lower cash receipts from the sale of LNG cargoes from lower pricing per MMBtu as a result of decreased loss on early extinguishmentHenry Hub pricing, which was largely offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.
Investing Cash Flows
Our consolidatedinvesting net loss was $227.1cash outflows in both years primarily were for the construction costs for the Liquefaction Project. The $742 million increase in the year ended December 31, 2015. This $141.6 million decrease in net loss in 20162023 compared to 20152022 was primarily a resultdue to $1.5 billion of decreased derivative loss, net and decreased interest expense, net of amounts capitalized, which were partially offset by increased loss on early extinguishment of debt.
In August 2017, Hurricane Harvey struck the Texas and Louisiana coasts, and the Corpus Christi LNG terminal experienced a temporary suspension in construction. The terminal did not sustain significant damage, and the effects of Hurricane Harvey did not have a material impact on our Consolidated Financial Statements.
Loss from operations
|
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
(in thousands) | | 2017 | | 2016 | | Change | | 2015 | | Change |
Revenues | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | |
|
| | | |
|
|
Operating and maintenance expense | | 3,115 |
| | 1,372 |
| | 1,743 |
| | 572 |
| | 800 |
|
Operating and maintenance expense—affiliate | | 2,401 |
| | 95 |
| | 2,306 |
| | — |
| | 95 |
|
Development expense (recovery) | | 516 |
| | (81 | ) | | 597 |
| | 13,690 |
| | (13,771 | ) |
Development expense (recovery)—affiliate | | 8 |
| | (10 | ) | | 18 |
| | 5,525 |
| | (5,535 | ) |
General and administrative expense | | 5,551 |
| | 4,240 |
| | 1,311 |
| | 3,189 |
| | 1,051 |
|
General and administrative expense—affiliate | | 1,173 |
| | 607 |
| | 566 |
| | 13 |
| | 594 |
|
Depreciation and amortization expense | | 892 |
| | 249 |
| | 643 |
| | 55 |
| | 194 |
|
Impairment expense and loss on disposal of assets | | 5,505 |
| | — |
| | 5,505 |
| | — |
| | — |
|
| | | | | |
|
| | | | |
Loss from operations | | $ | (19,161 | ) | | $ | (6,472 | ) | | $ | (12,689 | ) | | $ | (23,044 | ) | | $ | (16,572 | ) |
2017 vs. 2016
Our loss from operations increased $12.7 millioncash outflows during the year ended December 31, 2017 from2023 related to construction of the Corpus Christi Stage 3 Project following our issuance of full notice to proceed to Bechtel in June 2022 compared to $880 million in the comparable period of 2022. We expect to incur a similar level of capital expenditures in the upcoming year as construction work progresses on the Corpus Christi Stage 3 Project.
Financing Cash Flows
The following table summarizes our financing activities (in millions):
| | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 |
Proceeds from issuances of debt | | $ | — | | | $ | 440 | |
Repayments of debt | | (498) | | | (2,419) | |
| | | | |
| | | | |
Contributions | | 180 | | | 2,182 | |
Distributions | | (280) | | | (200) | |
Other | | (8) | | | (63) | |
Net cash used in financing activities | | $ | (606) | | | $ | (60) | |
Debt Issuances and Related Financing Costs
During the year ended December 31, 2016 primarily as a result2022, we had $440 million of increased operating and maintenance expense and general and administrative expensedebt issuances from increased professional fees and labor costs.
2016 vs. 2015
Our loss from operations decreased $16.6 millionthe CCH Credit Facility. We did not have any debt issuances during the year ended December 31, 2017 from2023.
Repayments and Related Extinguishment Costs
The following table shows the yearrepayments of debt, including intra-year repayments (in millions):
| | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | |
CCH Credit Facility | | $ | — | | | $ | (2,169) | | | |
CCH Working Capital Facility | | — | | | (250) | | | |
2024 CCH Senior Notes | | (498) | | | — | | | |
Total repayments of debt | | $ | (498) | | | $ | (2,419) | | | |
Capital Contributions and Distributions
During the years ended December 31, 20162023 and 2022, we received cash capital contributions of $180 million and $2.2 billion, respectively, from Cheniere, used to fund working capital and in 2022 to primarily as a result of decreased development expenses from decreased professional feespay down our outstanding debt, and labor costs.
Other expense (income)
|
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
(in thousands) | | 2017 | | 2016 | | Change | | 2015 | | Change |
Interest expense, net of capitalized interest | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 25,680 |
| | $ | (25,680 | ) |
Loss on early extinguishment of debt | | 32,480 |
| | 63,318 |
| | (30,838 | ) | | 16,498 |
| | 46,820 |
|
Derivative loss (gain), net | | (3,249 | ) | | 15,571 |
| | (18,820 | ) | | 161,917 |
| | (146,346 | ) |
Other expense (income) | | 260 |
| | 126 |
| | 134 |
| | (42 | ) | | 168 |
|
Total other expense (income) | | $ | 29,491 |
| | $ | 79,015 |
| | $ | (49,524 | ) | | $ | 204,053 |
| | $ | (125,038 | ) |
2017 vs. 2016
Loss on early extinguishment of debt decreased during the yearyears ended December 31, 2017, as compared2023 and 2022, we made cash distributions of $280 million and $200 million, respectively, to the year ended December 31, 2016. Loss on early extinguishment of debt recognized in 2017 was attributable to the write-offs of debt issuance costs of $32.5 million in May 2017 upon the prepayment of approximately $1.4 billion of outstanding borrowings under the 2015 CCH Credit Facility in connection with the issuance of the 2027 CCH Senior Notes. Loss on early extinguishment of debt during the year ended December 31, 2016 was primarily attributable to a $63.3 million write-off of debt issuance costs related to the $2.4 billion prepayment of outstanding borrowings under the 2015 CCH Credit Facility in connection with the issuance of the 2024 CCH Senior Notes and the 2025 CCH Senior Notes.Cheniere.
Derivative gain, net increased from a net loss during the year ended December 31, 2016 to a net gain during the year ended December 31, 2017. The increase in 2017 was primarily due to a favorable shift in the long-term forward LIBOR curve between the periods, which was partially offset by a $13.0 million loss in May 2017 upon the settlement of interest rate swaps associated with approximately $1.4 billion of commitments that were terminated under the 2015 CCH Credit Facility.
2016 vs. 2015
Interest expense, net of capitalized interest, decreased from $25.7 million in the year ended December 31, 2015 to zero in the year ended December 31, 2016 as we were able to capitalize total interest expense, which was directly related to the construction of the Liquefaction Project.
Loss on early extinguishment of debt increased during the year ended December 31, 2016, as compared to the year ended December 31, 2015. Loss on early extinguishment of debt during the year ended December 31, 2015 was attributable to $16.5 million associated with the termination of a portion of the original commitments under the 2015 CCH Credit Facility.
Derivative loss, net decreased during the year ended December 31, 2016, as compared to the year ended December 31, 2015, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods. Included in derivative loss, net recognized during the year ended December 31, 2015 was a $50.1 million loss recognized upon meeting the contingency related to the Interest Rate Derivatives.
Off-Balance Sheet Arrangements
As of December 31, 2017, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.
Summary of Critical Accounting Estimates
The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments, properties, plant and equipment and income taxes.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.
Derivative InstrumentsFair Value of Level 3 Physical Liquefaction Supply Derivatives
All of our derivative instruments are recorded at fair value.value, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. We record changes in the fair value of our derivative positions
through earnings, based on the value for which the derivative instrument could be exchanged between willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation approaches. Such evaluations may involve significant judgment and the results are based on expected future events or conditions, particularly for those valuations using inputs unobservable in the market.
Our derivative instruments consist of interest rate swaps and index-based physical commodity contracts. We value our interest rate swaps using observable inputs including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. Valuation of our
index-based physical
commodityliquefaction supply derivative contracts is
often developed through the use of internal models which
includes significant unobservable inputs representing Level 3 fair value measurements as further described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability.To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be impacteda significant unobservable input to estimated net fair value.In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data.Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments.We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing.Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure.Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.
Our fair value estimates incorporate market participant-based assumptions pertaining to applicable contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.
Additionally, the valuation of certain physical liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of instruments valued through the use of internal models which incorporate significant unobservable inputs thatfor the years ended December 31, 2023 and 2022 (in millions), which entirely consisted of physical liquefaction supply derivatives. The changes in fair value shown are unobservablelimited to instruments still held at the end of each respective period.
| | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 |
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period | | $ | 4,382 | | | $ | (3,664) | |
The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the marketplace, market transactionsestimated and other relevant data.observable forward international LNG commodity prices on our IPM agreements during the years ended December 31, 2023 and 2022.
Gains and losses on derivative instruments areThe estimated fair value of level 3 derivatives recognized in earnings. our Consolidated Balance Sheets as of December 31, 2023 and 2022 amounted to a liability of $0.5 billion and $6.2 billion, respectively, consisting entirely of physical liquefaction supply derivatives.
The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as interest rates andit relates to commodity prices change.
Impairmentgiven the level of Long-Lived Assets
A long-lived asset, including an intangible asset, is evaluatedvolatility in the current year. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for potential impairment whenever events orfurther analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in circumstances indicate that its carrying value may not be recoverable. Recoverability generally is determined by comparing the carrying valueunderlying prices.
Recent Accounting Standards
Income Taxes
Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance if, based on all available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. In determining the need for a valuation allowance we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We have recorded a full valuation allowance on our net federal and state deferred tax assets as of both December 31, 2017 and 2016. We intend to maintain a valuation allowance on our net federal and state deferred tax assets until there is sufficient evidence to support the reversal of these allowances.
We recognize the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. The largest amount of the tax benefit that is greater than 50 percent likely of being effectively settled is recorded. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Recent Accounting Standards
| |
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Marketing and Trading Commodity Price Risk
We have entered intoCCL has commodity derivatives consisting of natural gas supply contracts to secure natural gas feedstock for the commissioning and operation of the Liquefaction Project (“(the “Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in thousands)millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 | | December 31, 2022 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
Liquefaction Supply Derivatives | $ | (460) | | | $ | 1,165 | | | $ | (6,278) | | | $ | 1,684 | |
|
| | | | | | | | | | | | | | | |
| December 31, 2017 | | December 31, 2016 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
Liquefaction Supply Derivatives | $ | (91 | ) | | $ | 10 |
| | $ | — |
| | $ | — |
|
Interest Rate Risk
We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 CCH Credit Facility. In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining terms of the Interest Rate Derivatives as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| December 31, 2017 | | December 31, 2016 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
Interest Rate Derivatives | $ | (32,258 | ) | | $ | 43,994 |
| | $ | (86,488 | ) | | $ | 52,047 |
|
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
| |
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, 2017,2023, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.
This annual report does not include an attestation report of Corpus Christi Holdings’ registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Corpus Christi Holdings’ registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
Management’s Certifications
The certifications of Corpus Christi Holdings’ Principal Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Sabine Pass Liquefaction’sCheniere Corpus Christi Holdings’ Form 10-K.
| | | | | | | | |
| | |
| By: | | /s/ Zach Davis |
| | Zach Davis |
| | By: | /s/ Michael J. Wortley |
| | Michael J. Wortley |
| | President and Chief Financial Officer
(Principal Executive and Financial Officer) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 20172023 and 2016,2022, the related consolidated statements of operations, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2017,2023, 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, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2023, 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 liquefaction supply derivatives
As discussed in Notes 2 and 8 to the consolidated financial statements, the Company recorded fair value of level 3 liquefaction supply derivatives of $(502) million as of December 31, 2023, which included the fair value of IPM agreements. The IPM agreements are natural gas supply contracts for the operation of the liquefied natural gas facilities. The fair value of the IPM agreements is developed using internal models, including option pricing models. The models incorporate significant unobservable inputs, including future prices of energy units in unobservable periods and volatility.
We identified the evaluation of the fair value of the level 3 liquefaction supply derivatives for certain IPM agreements as a critical audit matter. Specifically, complex auditor judgment and specialized skills and knowledge were required to evaluate the appropriateness and application of the option pricing model as well as the assumptions for future prices of energy units in unobservable periods and 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 related to the valuation of liquefaction supply derivatives,
including those under certain IPM agreements. This included controls related to the appropriateness and application of the option pricing model and the evaluation of assumptions for future prices of energy units in unobservable periods and volatility. We involved valuation professionals with specialized skills and knowledge who assisted in testing management’s process for developing the fair value of certain IPM agreements by:
•evaluating the design and testing the operating effectiveness of certain internal controls related to the appropriateness and application of the option pricing model
•evaluating the appropriateness and application of the option pricing model by inspecting the contractual agreements and model documentation to determine whether the model is suitable for its intended use
•evaluating the reasonableness of management’s assumptions for future prices of energy units in unobservable periods and volatility by comparing to market data.
We have served as the Company’s auditor since 2015.
Houston, Texas
February 20, 201821, 2024
CHENIERE CORPUS CHRISTI HOLDINGS, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | | | 2023 | | 2022 | | 2021 |
Revenues | | | | | | | | | |
LNG revenues | | | | | $ | 3,845 | | | $ | 6,336 | | | $ | 3,907 | |
LNG revenues—affiliate | | | | | 1,620 | | | 3,027 | | | 1,887 | |
| | | | | | | | | |
Total revenues | | | | | 5,465 | | | 9,363 | | | 5,794 | |
| | | | | | | | | |
Operating costs and expenses (recoveries) | | | | | | | | | |
Cost (recovery) of sales (excluding items shown separately below) | | | | | (3,178) | | | 9,656 | | | 4,326 | |
Cost of sales—affiliate | | | | | 171 | | | 103 | | | 50 | |
Cost of sales—related party | | | | | — | | | — | | | 146 | |
Operating and maintenance expense | | | | | 479 | | | 458 | | | 423 | |
Operating and maintenance expense—affiliate | | | | | 116 | | | 121 | | | 106 | |
Operating and maintenance expense—related party | | | | | 9 | | | 9 | | | 9 | |
| | | | | | | | | |
| | | | | | | | | |
General and administrative expense | | | | | 6 | | | 8 | | | 7 | |
General and administrative expense—affiliate | | | | | 45 | | | 38 | | | 28 | |
Depreciation and amortization expense | | | | | 449 | | | 445 | | | 420 | |
Other | | | | | 2 | | | 6 | | | 2 | |
Total operating costs and expenses (recoveries) | | | | | (1,901) | | | 10,844 | | | 5,517 | |
| | | | | | | | | |
Income (loss) from operations | | | | | 7,366 | | | (1,481) | | | 277 | |
| | | | | | | | | |
Other income (expense) | | | | | | | | | |
Interest expense, net of capitalized interest | | | | | (217) | | | (432) | | | (447) | |
Loss on modification or extinguishment of debt | | | | | (10) | | | (37) | | | (9) | |
| | | | | | | | | |
Other income (expense), net | | | | | 11 | | | 8 | | | (1) | |
Total other expense | | | | | (216) | | | (461) | | | (457) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Net income (loss) | | | | | $ | 7,150 | | | $ | (1,942) | | | $ | (180) | |
The accompanying notes are an integral part of these consolidated financial statements.
41
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)millions)
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2023 | | 2022 |
ASSETS | | | | |
Current assets | | | | |
| | | | |
Restricted cash and cash equivalents | | $ | 175 | | | $ | 738 | |
Trade and other receivables, net of current expected credit losses | | 180 | | | 348 | |
Trade receivables—affiliate | | 213 | | | 240 | |
Advances to affiliate | | 116 | | | 132 | |
Inventory | | 124 | | | 178 | |
Current derivative assets | | 19 | | | 12 | |
| | | | |
Margin deposits | | 3 | | | 76 | |
Other current assets, net | | 15 | | | 18 | |
| | | | |
Total current assets | | 845 | | | 1,742 | |
| | | | |
| | | | |
Property, plant and equipment, net of accumulated depreciation | | 14,992 | | | 13,673 | |
Debt issuance costs, net of accumulated amortization | | 33 | | | 40 | |
Derivative assets | | 823 | | | 7 | |
| | | | |
| | | | |
Other non-current assets, net | | 283 | | | 225 | |
| | | | |
Total assets | | $ | 16,976 | | | $ | 15,687 | |
| | | | |
LIABILITIES AND MEMBER’S EQUITY | | | | |
Current liabilities | | | | |
Accounts payable | | $ | 105 | | | $ | 85 | |
| | | | |
Accrued liabilities | | 595 | | | 901 | |
Accrued liabilities—related party | | 1 | | | 1 | |
Current debt, net of discount and debt issuance costs | | — | | | 495 | |
Due to affiliates | | 49 | | | 43 | |
Current derivative liabilities | | 455 | | | 1,374 | |
Other current liabilities | | 20 | | | 1 | |
| | | | |
Total current liabilities | | 1,225 | | | 2,900 | |
| | | | |
Long-term debt, net of discount and debt issuance costs | | 6,311 | | | 6,698 | |
Derivative liabilities | | 847 | | | 4,923 | |
| | | | |
Other non-current liabilities | | 58 | | | 78 | |
Other non-current liabilities—affiliate | | 3 | | | 4 | |
| | | | |
Commitments and contingencies (see Note 14) | | | | |
| | | | |
Member’s equity | | 8,532 | | | 1,084 | |
Total liabilities and member’s equity | | $ | 16,976 | | | $ | 15,687 | |
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
ASSETS | | | | |
Current assets | | | | |
Cash and cash equivalents | | $ | — |
| | $ | — |
|
Restricted cash | | 226,559 |
| | 197,201 |
|
Advances to affiliate | | 31,486 |
| | 20,108 |
|
Other current assets | | 1,494 |
| | 37,195 |
|
Other current assets—affiliate | | 190 |
| | 141 |
|
Total current assets | | 259,729 |
| | 254,645 |
|
| | | | |
Non-current restricted cash | | — |
| | 73,339 |
|
Property, plant and equipment, net | | 8,261,383 |
| | 6,076,672 |
|
Debt issuance and deferred financing costs, net | | 98,175 |
| | 155,847 |
|
Non-current advances under long-term contracts | | — |
| | 46,398 |
|
Other non-current assets, net | | 40,593 |
| | 29,547 |
|
Total assets | | $ | 8,659,880 |
| | $ | 6,636,448 |
|
| | | | |
LIABILITIES AND MEMBER’S EQUITY | | | | |
Current liabilities | | | | |
Accounts payable | | $ | 6,461 |
| | $ | 9,120 |
|
Accrued liabilities | | 258,060 |
| | 137,648 |
|
Due to affiliates | | 23,789 |
| | 7,050 |
|
Derivative liabilities | | 19,609 |
| | 43,383 |
|
Total current liabilities | | 307,919 |
| | 197,201 |
|
| | | | |
Long-term debt, net | | 6,669,476 |
| | 5,081,715 |
|
Non-current derivative liabilities | | 15,209 |
| | 43,105 |
|
Other non-current liabilities—affiliate | | — |
| | 618 |
|
| | | | |
Commitments and contingencies (see Note 11) | |
|
| |
|
|
| | | | |
Member’s equity | | 1,667,276 |
| | 1,313,809 |
|
Total liabilities and member’s equity | | $ | 8,659,880 |
| | $ | 6,636,448 |
|
The accompanying notes are an integral part of these consolidated financial statements.
4042
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Revenues | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | |
Expenses | | | | | |
Operating and maintenance expense | 3,115 |
| | 1,372 |
| | 572 |
|
Operating and maintenance expense—affiliate | 2,401 |
| | 95 |
| | — |
|
Development expense (recovery) | 516 |
| | (81 | ) | | 13,690 |
|
Development expense (recovery)—affiliate | 8 |
| | (10 | ) | | 5,525 |
|
General and administrative expense | 5,551 |
| | 4,240 |
| | 3,189 |
|
General and administrative expense—affiliate | 1,173 |
| | 607 |
| | 13 |
|
Depreciation and amortization expense | 892 |
| | 249 |
| | 55 |
|
Impairment expense and loss on disposal of assets | 5,505 |
| | — |
| | — |
|
Total expenses | 19,161 |
| | 6,472 |
| | 23,044 |
|
| | | | | |
Loss from operations | (19,161 | ) | | (6,472 | ) | | (23,044 | ) |
| | | | | |
Other income (expense) | | | | | |
Interest expense, net of capitalized interest | — |
| | — |
| | (25,680 | ) |
Loss on early extinguishment of debt | (32,480 | ) | | (63,318 | ) | | (16,498 | ) |
Derivative gain (loss), net | 3,249 |
| | (15,571 | ) | | (161,917 | ) |
Other income (expense) | (260 | ) | | (126 | ) | | 42 |
|
Total other expense | (29,491 | ) | | (79,015 | ) | | (204,053 | ) |
| | | | | |
Net loss | $ | (48,652 | ) | | $ | (85,487 | ) | | $ | (227,097 | ) |
The accompanying notes are an integral partTable of these consolidated financial statements.
41
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
(in thousands)millions)
| | | | | | | | | | | |
| | | |
| Cheniere CCH HoldCo I, LLC | | Total Member’s Equity |
Balance at December 31, 2020 | $ | 2,624 | | | $ | 2,624 | |
| | | |
Distributions | (1,163) | | | (1,163) | |
Net loss | (180) | | | (180) | |
Balance at December 31, 2021 | 1,281 | | | 1,281 | |
Contributions (excluding items shown separately below) | 2,182 | | | 2,182 | |
Non-cash contribution of CCL Stage III entity from affiliate (see Note 3) | (1,482) | | | (1,482) | |
Other non-cash contribution from affiliate (see Note 11) | 1,245 | | | 1,245 | |
Distributions | (200) | | | (200) | |
Net loss | (1,942) | | | (1,942) | |
Balance at December 31, 2022 | 1,084 | | | 1,084 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
Contributions (excluding item shown separately below) | 180 | | | 180 | |
Non-cash contribution from affiliate (see Note 11) | 398 | | | 398 | |
Distributions | (280) | | | (280) | |
Net income | 7,150 | | | 7,150 | |
Balance at December 31, 2023 | $ | 8,532 | | | $ | 8,532 | |
|
| | | | | | | |
| Cheniere CCH HoldCo I, LLC | | Total Member’s Equity |
Balance at December 31, 2014 | $ | 65,532 |
| | $ | 65,532 |
|
Capital contributions | 1,560,915 |
| | 1,560,915 |
|
Net loss | (227,097 | ) | | (227,097 | ) |
Balance at December 31, 2015 | 1,399,350 |
| | 1,399,350 |
|
Capital contributions | 91 |
| | 91 |
|
Noncash capital contribution from affiliate | 143 |
| | 143 |
|
Distribution to affiliate | (288 | ) | | (288 | ) |
Net loss | (85,487 | ) | | (85,487 | ) |
Balance at December 31, 2016 | 1,313,809 |
| | 1,313,809 |
|
Capital contributions | 402,119 |
| | 402,119 |
|
Net loss | (48,652 | ) | | (48,652 | ) |
Balance at December 31, 2017 | $ | 1,667,276 |
| | $ | 1,667,276 |
|
The accompanying notes are an integral part of these consolidated financial statements.
4243
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)millions)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
Cash flows from operating activities | | | | | |
Net income (loss) | $ | 7,150 | | | $ | (1,942) | | | $ | (180) | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
Depreciation and amortization expense | 449 | | | 445 | | | 420 | |
Amortization of discount and debt issuance costs | 11 | | | 20 | | | 24 | |
Loss on modification or extinguishment of debt | 10 | | | 37 | | | 9 | |
Total losses (gains) on derivative instruments, net | (5,825) | | | 3,243 | | | 1,241 | |
Total gains on derivatives, net—related party | — | | | — | | | (11) | |
Net cash provided by (used for) settlement of derivative instruments | 7 | | | (155) | | | (107) | |
| | | | | |
Other | 6 | | | 33 | | | 3 | |
Changes in operating assets and liabilities: | | | | | |
Trade and other receivables | 168 | | | (68) | | | (84) | |
Trade receivables—affiliate | 26 | | | 76 | | | (273) | |
Advances to affiliate | 26 | | | (58) | | | 14 | |
Inventory | 50 | | | (22) | | | (62) | |
Margin deposits | 73 | | | (63) | | | (8) | |
Accounts payable and accrued liabilities | (347) | | | 184 | | | 468 | |
Accrued liabilities—related party | — | | | — | | | (14) | |
Due to affiliates | 3 | | | 7 | | | 9 | |
Total deferred revenue | (1) | | | 42 | | | 35 | |
Other, net | (40) | | | (44) | | | (60) | |
Other, net—affiliate | (1) | | | (1) | | | — | |
Net cash provided by operating activities | 1,765 | | | 1,734 | | | 1,424 | |
| | | | | |
Cash flows from investing activities | | | | | |
Property, plant and equipment, net | (1,711) | | | (981) | | | (238) | |
Other | (11) | | | 1 | | | (2) | |
Net cash used in investing activities | (1,722) | | | (980) | | | (240) | |
| | | | | |
Cash flows from financing activities | | | | | |
Proceeds from issuances of debt | — | | | 440 | | | 1,150 | |
Repayments of debt | (498) | | | (2,419) | | | (1,188) | |
| | | | | |
| | | | | |
Contributions | 180 | | | 2,182 | | | — | |
Distributions | (280) | | | (200) | | | (1,163) | |
Other | (8) | | | (63) | | | (9) | |
Net cash used in financing activities | (606) | | | (60) | | | (1,210) | |
| | | | | |
Net increase (decrease) in restricted cash and cash equivalents | (563) | | | 694 | | | (26) | |
Restricted cash and cash equivalents—beginning of period | 738 | | | 44 | | | 70 | |
Restricted cash and cash equivalents—end of period | $ | 175 | | | $ | 738 | | | $ | 44 | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Cash flows from operating activities | | | | | |
Net loss | $ | (48,652 | ) | | $ | (85,487 | ) | | $ | (227,097 | ) |
Adjustments to reconcile net loss to net cash used in operating activities: | | | | | |
Depreciation and amortization expense | 892 |
| | 249 |
| | 55 |
|
Amortization of debt issuance costs, net of capitalization | — |
| | — |
| | 6,340 |
|
Loss on early extinguishment of debt | 32,480 |
| | 63,318 |
| | 16,498 |
|
Total losses (gains) on derivatives, net | (3,158 | ) | | 15,571 |
| | 161,917 |
|
Net cash used for settlement of derivative instruments | (50,981 | ) | | (34,082 | ) | | (56,918 | ) |
Impairment expense and loss on disposal of assets | 5,505 |
| | — |
| | — |
|
Changes in operating assets and liabilities: | | | | | |
Accounts payable and accrued liabilities | 152 |
| | 415 |
| | 1,002 |
|
Due to affiliates | 1,567 |
| | (331 | ) | | 275 |
|
Advances to affiliate | — |
| | — |
| | (10,073 | ) |
Other, net | (1,454 | ) | | (745 | ) | | 301 |
|
Other, net—affiliate | (667 | ) | | 13 |
| | 498 |
|
Net cash used in operating activities | (64,316 | ) | | (41,079 | ) | | (107,202 | ) |
| | | | | |
Cash flows from investing activities | |
| | | | |
Property, plant and equipment, net | (1,987,254 | ) | | (2,051,530 | ) | | (3,820,947 | ) |
Other | 25,045 |
| | (44,367 | ) | | (18,468 | ) |
Net cash used in investing activities | (1,962,209 | ) | | (2,095,897 | ) | | (3,839,415 | ) |
| | | | | |
Cash flows from financing activities | |
| | | | |
Proceeds from issuances of debt | 3,040,000 |
| | 4,838,000 |
| | 2,713,000 |
|
Repayments of debt | (1,436,050 | ) | | (2,420,212 | ) | | — |
|
Debt issuance and deferred financing costs | (23,496 | ) | | (56,783 | ) | | (280,528 | ) |
Capital contributions | 402,119 |
| | 91 |
| | 1,560,915 |
|
Distributions | — |
| | (288 | ) | | — |
|
Other | (29 | ) | | (62 | ) | | — |
|
Net cash provided by financing activities | 1,982,544 |
| | 2,360,746 |
| | 3,993,387 |
|
| | | | | |
Net increase (decrease) in cash, cash equivalents and restricted cash | (43,981 | ) | | 223,770 |
| | 46,770 |
|
Cash, cash equivalents and restricted cash—beginning of period | 270,540 |
| | 46,770 |
| | — |
|
Cash, cash equivalents and restricted cash—end of period | $ | 226,559 |
| | $ | 270,540 |
| | $ | 46,770 |
|
Balances per Consolidated Balance Sheets:
|
| | | | | | | |
| December 31, |
| 2017 | | 2016 |
Cash and cash equivalents | $ | — |
| | $ | — |
|
Restricted cash | 226,559 |
| | 197,201 |
|
Non-current restricted cash | — |
| | 73,339 |
|
Total cash, cash equivalents and restricted cash | $ | 226,559 |
| | $ | 270,540 |
|
The accompanying notes are an integral part of these consolidated financial statements.
4344
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
CCH is a Houston-based Delaware limited liability company formed in September 2014 by Cheniere to hold its limited partner interest in CCP and its equity interests in CCL and CCP GP. We are developing and constructingoperate a natural gas liquefaction and export facility at the Corpus Christi LNG terminal (the “Liquefaction Facility”), which is on nearly 2,000 acres of land that we own or controllocated near Corpus Christi, Texas and a 23-mile natural gas supply pipeline (the “Corpus“Corpus Christi Pipeline” and together with the Liquefaction Facility, the “Liquefaction Project”LNG Terminal”) through wholly owned subsidiaries CCL, and CCP, respectively. The Liquefaction Project is being developed in stageswhich has three operational Trains for up to three Trains, with expected aggregate nominala total production capacity which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 13.515 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vesselsberths. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for seven midscale Trains with nominalan expected total production capacity of up to 266,000 cubic meters. The first stage (“Stage 1”) includesover 10 mtpa of LNG.
Through our subsidiary CCP, we also own a 21.5-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 Trains, 1 and 2, two LNG storage tanks, one completeand marine berth and a second partial berth and all ofberths at the Liquefaction Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, oneCorpus Christi LNG storage tank and the completion of the second partial berth. Stage 1Terminal and the Corpus Christi PipelineStage 3 Project, the “Liquefaction Project”).
We are currently under construction,pursuing a certain expansion project to provide additional liquefaction capacity, and Train 3 is being commercializedwe have commenced commercialization to support the additional liquefaction capacity associated with this expansion project.
We do not have employees and has all necessary regulatory approvalsthus we have various services agreements with affiliates of Cheniere in place. Constructionthe ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. See Note 13—Related Party Transactions for additional details of the Corpus Christi Pipelineactivity under these services agreements during the years ended December 31, 2023, 2022 and 2021.
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 nearing completion.included in the consolidated federal income tax return of Cheniere. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Consolidated Financial Statements have been prepared in accordance with GAAP. Our Consolidated Financial Statements include the accounts of CCH and its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.
Use of Estimates
The preparation of our 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 thefair value measurements of derivatives and other instruments useful lives of property, plant and equipment derivative instruments,and certain valuations including asset retirement obligations (“(“AROs”), income taxes including valuation allowances for deferred tax assets and fair value measurements.each 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 other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability.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
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
participants would take into account in measuring fair value. We attempt to maximize theour use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
The carrying amount of restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, contract assets, margin deposits, accounts payable and accrued liabilities reported on the Consolidated Balance Sheets approximates fair value. DebtThe fair values, as disclosed in Note 7—Debt,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. Refer to Note 11—Debt for our debt fair value estimates, including our estimation methods.
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. See Note 12—Revenues for further discussion of our revenue streams and accounting policies related to revenue recognition. Restricted Cash and Cash Equivalents
Restricted cash and cash equivalents consist 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. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Current Expected Credit Losses
Current expected credit losses consider the risk of loss based on quoted market pricespast 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.We record charges and reversals of current expected credit losses in general and administrative in our Consolidated Statements of Operations.
The following table reflects the changes in our current expected credit losses (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
Current expected credit losses, beginning of period | | $ | 4 | | | $ | 3 | | | $ | 2 | |
Charges (reversals) | | (1) | | | 1 | | | 1 | |
Current expected credit losses, end of period | | $ | 3 | | | $ | 4 | | | $ | 3 | |
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. Inventory is charged to expense when sold, or, for identical instruments, if available, or based on valuationscertain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.
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 similar debt instruments using observable or unobservable inputs.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.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Restricted Cash
Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and will not become available to us as cash and cash equivalents. We have presented restricted cash separately from cash and cash equivalents on our Consolidated Balance Sheets.
Accounting for LNG Activities
Generally, we begin capitalizing the costs of our LNG terminal and related pipeline once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineeringpreliminary review and design work,selection of equipment alternatives, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminal and related pipeline.terminal.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease optionacquisition costs, that are capitalized as property, plant and equipmentdetailed engineering design work and certain permits that are capitalized as other non-current assets. The
We realize offsets to LNG terminal costs for sales of lease options are amortized overcommissioning cargoes that were earned or loaded prior to the lifestart of commercial operations of the lease once obtained. If no lease is obtained, the costs are expensed.
We capitalize interest and other related debt costsrespective Train during the construction period of our LNG terminal and related pipeline. Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset. testing phase for its construction.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We depreciate our property, plant and equipment using the straight-line depreciation method.method over assigned useful lives, except land which is not depreciated. Refer to Note 7—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. 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 on disposal are recorded in other operating costs and expenses. Substantially all of our long-lived assets are located in the United States.Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there is identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. During the year ended December 31, 2017, we recognized $5.5 million of impairment expense related to damaged infrastructure as an effect of Hurricane Harvey. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2016 or 2015.
Regulated Natural Gas Pipelines
The Corpus Christi Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as deferred
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
preliminary survey and investigation costs, other assets and other liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities.
Items that may influence our assessment are:
inability to recover cost increases due to rate caps and rate case moratoriums;
inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;
excess capacity;
increased competition and discounting in the markets we serve; and
impacts of ongoing regulatory initiatives in the natural gas industry.
Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from interest rate. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.
Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. See Note 5—Derivative Instruments for additional details about our derivative instruments.
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.
CCL has entered into eight fixed price SPAs with terms of at least 20 years with seven unaffiliated third parties. CCL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.
Debt
Our debt consists of long-term secured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.
Debt is recorded on our Consolidated Balance Sheets at par value net of unamortized debt issuance costs related to term notes. Debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the extinguishment of debt on our Consolidated Statements of Operations.
Debt issuance and deferred financing costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. Debt issuance costs are recorded as a direct deduction from the debt liability unless incurred in connection with a line of credit arrangement, in which case they are presented as an asset on our Consolidated Balance Sheets along with deferred financing costs. Debt issuance and deferred financing costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on early extinguishment of debt.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement is conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our assessment of AROs is described below.
We have not recorded an ARO associated with the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.
Income Taxes
We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. The provision for income taxes, taxes payable and deferred income tax balances have been recorded as if we had filed all tax returns on a separate return basis from Cheniere. Deferred tax assets and liabilities are included in our Consolidated Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable.
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the tax position.
Business Segment
Our liquefaction and pipeline business at the Corpus Christi LNG terminal represents a single reportable segment. Our chief operating decision maker reviews the financial results of CCH in total when evaluating financial performance and for purposes of allocating resources.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 3—RESTRICTED CASH
Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2017 and 2016, restricted cash consisted of the following (in thousands):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Current restricted cash | | | | |
Liquefaction Project | | $ | 226,559 |
| | $ | 197,201 |
|
| | | | |
Non-current restricted cash | | | | |
Liquefaction Project | | $ | — |
| | $ | 73,339 |
|
Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.
NOTE 4—PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in thousands):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
LNG terminal costs | | | | |
LNG terminal construction-in-process | | $ | 8,242,520 |
| | $ | 6,060,299 |
|
LNG site and related costs | | 13,844 |
| | 14,006 |
|
Total LNG terminal costs | | 8,256,364 |
| | 6,074,305 |
|
Fixed assets | | | | |
Fixed assets | | 6,042 |
| | 2,620 |
|
Accumulated depreciation | | (1,023 | ) | | (253 | ) |
Total fixed assets, net | | 5,019 |
| | 2,367 |
|
Property, plant and equipment, net | | $ | 8,261,383 |
| | $ | 6,076,672 |
|
Depreciation expense was $0.8 million, $0.2 million and $0.1 million in the years ended December 31, 2017, 2016 and 2015, respectively.
Fixed Assets
Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.
NOTE 5—DERIVATIVE INSTRUMENTS
We have entered into the following derivative instruments that are reported at fair value:
interest rate swaps (“Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable-rate interest payments on our credit facility (the “2015 CCH Credit Facility”) and
natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”).
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Interest Rate Derivatives
As of December 31, 2017, we had the following Interest Rate Derivatives outstanding:
|
| | | | | | | | | | | | |
| | Initial Notional Amount | | Maximum Notional Amount | | Effective Date | | Maturity Date | | Weighted Average Fixed Interest Rate Paid | | Variable Interest Rate Received |
Interest Rate Derivatives | | $28.8 million | | $4.9 billion | | May 20, 2015 | | May 31, 2022 | | 2.29% | | One-month LIBOR |
Our Interest Rate Derivatives are categorized within Level 2 of the fair value hierarchy and are required to be measured at fair value on a recurring basis. We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.
In May 2017, we settled a portion of our Interest Rate Derivatives and recognized a derivative loss of $13.0 million in conjunction with the termination of approximately $1.4 billion of commitments under the 2015 CCH Credit Facility, as discussed in Note 7—Debt.
The following table shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets (in thousands):
|
| | | | | | | | |
| | December 31, |
Balance Sheet Location | | 2017 | | 2016 |
Non-current derivative assets | | $ | 2,469 |
| | $ | — |
|
| | | | |
Derivative liabilities | | (19,609 | ) | | (43,383 | ) |
Non-current derivative liabilities | | (15,118 | ) | | (43,105 | ) |
Total derivative liabilities | | (34,727 | ) | | (86,488 | ) |
| | | | |
Derivative liability, net | | $ | (32,258 | ) | | $ | (86,488 | ) |
The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in thousands):
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Interest Rate Derivatives gain (loss) | $ | 3,249 |
| | $ | (15,571 | ) | | $ | (161,917 | ) |
Liquefaction Supply Derivatives
CCL entered into all of its Liquefaction Supply Derivatives during the year ended December 31, 2017. The fair value of the Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of any associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.
CCL has entered into index-based physical natural gas supply contracts to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the physical natural gas supply contracts range from approximately three to seven years, most of which commence upon the satisfaction of certain conditions precedent, if applicable, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.
Our Liquefaction Supply Derivatives are categorized within Level 3 of the fair value hierarchy and are required to be measured at fair value on a recurring basis. The fair value of our Liquefaction Supply Derivatives is determined using a market-based approach incorporating present value techniques, as needed, and is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The curves used to generate the fair value of the Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. As of December 31, 2017, some of the Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow. As of December 31, 2017, CCL had secured up to approximately 2,024 TBtu of natural gas feedstock through natural gas supply contracts supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent. The forward notional natural gas buy position of the Liquefaction Supply Derivatives was approximately 1,019 TBtu as of December 31, 2017.
The Level 3 fair value measurements of our Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Liquefaction Supply Derivatives as of December 31, 2017:
|
| | | | | | | | |
| | Net Fair Value Liability
(in thousands)
| | Valuation Approach | | Significant Unobservable Input | | Significant Unobservable Inputs Range |
Liquefaction Supply Derivatives | | $(91) | | Market approach incorporating present value techniques | | Basis Spread | | $(0.703) - $(0.002) |
Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.
The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in thousands):
|
| | | | | | | | |
| | December 31, |
Balance Sheet Location | | 2017 | | 2016 |
Non-current derivative liabilities | | $ | (91 | ) | | $ | — |
|
The following table shows the changes in the fair value from the mark-to-market gains of our Liquefaction Supply Derivatives recorded in our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in thousands):
|
| | | | | | | | | | | | | |
| | | Year Ended December 31, |
| Statement of Operations Location | | 2017 | | 2016 | | 2015 |
Liquefaction Supply Derivatives loss | Operating and maintenance expense | | $ | 91 |
| | $ | — |
| | $ | — |
|
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Balance Sheet Presentation
Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in thousands):
|
| | | | | | | | | | | | |
| | Gross Amounts Recognized | | Gross Amounts Offset in the Consolidated Balance Sheets | | Net Amounts Presented in the Consolidated Balance Sheets |
Offsetting Derivative Assets (Liabilities) | | | |
As of December 31, 2017 | | | | | | |
Interest Rate Derivatives | | $ | 2,808 |
| | $ | (339 | ) | | $ | 2,469 |
|
Interest Rate Derivatives | | (34,747 | ) | | 20 |
| | (34,727 | ) |
Liquefaction Supply Derivatives | | (130 | ) | | 39 |
| | (91 | ) |
As of December 31, 2016 | | | | | | |
Interest Rate Derivatives | | (95,923 | ) | | 9,435 |
| | (86,488 | ) |
NOTE 6—ACCRUED LIABILITIES
As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in thousands):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Interest costs and related debt fees | | $ | 136,283 |
| | $ | 59,994 |
|
Liquefaction Project costs | | 107,055 |
| | 73,150 |
|
Other | | 14,722 |
| | 4,504 |
|
Total accrued liabilities | | $ | 258,060 |
| | $ | 137,648 |
|
NOTE 7—DEBT
As of December 31, 2017 and 2016, our debt consisted of the following (in thousands):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Long-term debt | | | | |
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”) | | $ | 1,250,000 |
| | $ | 1,250,000 |
|
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”) | | 1,500,000 |
| | 1,500,000 |
|
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”) | | 1,500,000 |
| | — |
|
2015 CCH Credit Facility | | 2,484,737 |
| | 2,380,788 |
|
Unamortized debt issuance costs | | (65,261 | ) | | (49,073 | ) |
Total long-term debt, net | | 6,669,476 |
| | 5,081,715 |
|
| | | | |
Current debt | | | | |
$350 million CCH Working Capital Facility (“CCH Working Capital Facility”) | | — |
| | — |
|
Total debt, net | | $ | 6,669,476 |
| | $ | 5,081,715 |
|
Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2017 (in thousands):
|
| | | | |
Years Ending December 31, | | Principal Payments |
2018 | | $ | — |
|
2019 | | — |
|
2020 | | — |
|
2021 | | — |
|
2022 | | 2,484,737 |
|
Thereafter | | 4,250,000 |
|
Total | | $ | 6,734,737 |
|
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Senior Notes
In May 2017, we issued an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, which are jointly and severally guaranteed by our subsidiaries CCL, CCP and CCP GP (each a “Guarantor” and collectively, the “Guarantors”). Net proceeds of the offering of approximately $1.4 billion, after deducting commissions, fees and expenses and provisioning for incremental interest required under the 2027 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the 2015 CCH Credit Facility, resulting in a write-off of debt issuance costs associated with the 2015 CCH Credit Facility of $32.5 million during the year ended December 31, 2017. Borrowings under the 2027 CCH Senior Notes accrue interest at a fixed rate of 5.125%.
The 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes (collectively, the “CCH Senior Notes”) are jointly and severally guaranteed by the Guarantors. The indenture governing the CCH Senior Notes (the “CCH Indenture”) contains customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a whole; or permit any Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets. Interest on the CCH Senior Notes is payable semi-annually in arrears.
At any time prior to six months before the respective dates of maturity for each series of the CCH Senior Notes, CCH may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the CCH Indenture, plus accrued and unpaid interest, if any, to the date of redemption. CCH also may at any time within six months of the respective dates of maturity for each series of the CCH Senior Notes, redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
Credit Facilities
Below is a summary of our credit facilities outstanding as of December 31, 2017 (in thousands):
|
| | | | | | | | |
| | 2015 CCH Credit Facility | | CCH Working Capital Facility |
Original facility size | | $ | 8,403,714 |
| | $ | 350,000 |
|
Less: | | | | |
Outstanding balance | | 2,484,737 |
| | — |
|
Commitments terminated | | 3,832,263 |
| | — |
|
Letters of credit issued | | — |
| | 163,578 |
|
Available commitment | | $ | 2,086,714 |
|
| $ | 186,422 |
|
| | | | |
Interest rate | | LIBOR plus 2.25% or base rate plus 1.25% (1) | | LIBOR plus 1.50% - 2.00% or base rate plus 0.50% - 1.00% |
Maturity date | | Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date | | December 14, 2021, with various terms for underlying loans |
| |
(1) | There is a 0.25% step-up for both LIBOR and base rate loans following the completion of Trains 1 and 2 of the Liquefaction Project as defined in the common terms agreement. |
2015 CCH Credit Facility
In May 2015, we entered into the 2015 CCH Credit Facility, which is being used to fund a portion of the costs associated with the development, construction, operation and maintenance of Stage 1 of the Liquefaction Project. Borrowings under the 2015 CCH Credit Facility may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The principal of the loans made under the 2015 CCH Credit Facility must be repaid in quarterly installments, commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following project completion and (2) a set date determined by reference to the date under which a certain LNG buyer linked to Train 2 of the Liquefaction Project is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the project completion and designed to achieve a minimum projected fixed debt service coverage ratio of 1.55:1.
Loans under the 2015 CCH Credit Facility accrue interest at a variable rate per annum equal to, at our election, LIBOR or the base rate, plus the applicable margin. The applicable margins for LIBOR loans are 2.25% prior to completion of Trains 1 and 2 of the Liquefaction Project and 2.50% on completion and thereafter. The applicable margins for base rate loans are 1.25% prior to completion of Trains 1 and 2 of the Liquefaction Project and 1.50% on completion and thereafter. Interest on LIBOR loans is due and payable at the end of each applicable interest period and interest on base rate loans is due and payable at the end of each quarter. The 2015 CCH Credit Facility also requires us to pay a commitment fee at a rate per annum equal to 40% of the margin for LIBOR loans, multiplied by the outstanding undrawn debt commitments.
Our obligations under the 2015 CCH Credit Facility are secured by a first priority lien on substantially all our assets and our subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in us.
Under the 2015 CCH Credit Facility, we are required to hedge not less than 65% of the variable interest rate exposure of our senior secured debt. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, the completion of the construction of Trains 1 and 2 of the Liquefaction Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.
CCH Working Capital Facility
In December 2016, we entered into the $350 million CCH Working Capital Facility, which is intended to be used for loans (“CCH Working Capital Loans”), the issuance of letters of credit, as well as for swing line loans (“CCH Swing Line Loans”) for certain working capital requirements related to developing and placing into operation the Liquefaction Project. Loans under the CCH Working Capital Facility are guaranteed by the Guarantors. We may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed under the Common Terms Agreement that was entered into concurrently with the 2015 CCH Credit Facility.
Loans under the CCH Working Capital Facility, including CCH Working Capital Loans, CCH Swing Line Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans” and collectively, the “Revolving Loans”) accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of (1) the federal funds rate, plus 0.50%, (2) the prime rate and (3) one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR Revolving Loans ranges from 1.50% to 2.00% per annum, and the applicable margin for base rate Revolving Loans ranges from 0.50% to 1.00% per annum. Interest on CCH Working Capital Loans, CCH Swing Line Loans and CCH LC Loans is due and payable on the date the loan becomes due. Interest on LIBOR Revolving Loans is due and payable at the end of each LIBOR period, and interest on base rate Revolving Loans is due and payable at the end of each quarter.
We pay (1) a commitment fee equal to an annual rate of 40% of the applicable margin for LIBOR Revolving Loans on the average daily amount of the excess of the total commitment amount over the principal amount outstanding without giving effect to any outstanding CCH Swing Line Loans, (2) a letter of credit fee equal to an annual rate equal to the applicable margin for LIBOR Revolving Loans on the undrawn portion of all letters of credit issued under the CCH Working Capital Facility and (3) a letter of credit fronting fee equal to an annual rate of 0.20% of the undrawn portion of all letters of credit. Each of these fees is payable quarterly in arrears.
If draws are made upon a letter of credit issued under the CCH Working Capital Facility and we do not elect for such draw (a “CCH LC Draw”) to be deemed an CCH LC Loan, we are required to pay the full amount of the CCH LC Draw on or prior to the business day following the notice of the CCH LC Draw. A CCH LC Draw accrues interest at an annual rate of 2.00% plus the base rate.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The CCH Working Capital Facility matures on December 14, 2021, and we may prepay the Revolving Loans at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. CCH Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the CCH Working Capital Facility, (2) the date that is 15 days after such CCH Swing Line Loan is made and (3) the first borrowing date for a CCH Working Capital Loan or CCH Swing Line Loan occurring at least four business days following the date the CCH Swing Line Loan is made. We are required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.
The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the Guarantors as well as all of our membership interests and each of the Guarantors on a pari passu basis with the CCH Senior Notes and the 2015 CCH Credit Facility.
Restrictive Debt Covenants
As of December 31, 2017, we were in compliance with all covenants related to our debt agreements.
Interest Expense
Total interest expense consisted of the following (in thousands):
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
Total interest cost | | $ | 360,932 |
| | $ | 221,865 |
| | $ | 110,156 |
|
Capitalized interest, including amounts capitalized as AFUDC | | (360,932 | ) | | (221,865 | ) | | (84,476 | ) |
Total interest expense, net | | $ | — |
| | $ | — |
| | $ | 25,680 |
|
Fair Value Disclosures
The following table shows the carrying amount and estimated fair value of our debt (in thousands):
|
| | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value |
Senior notes (1) | | $ | 4,250,000 |
| | $ | 4,590,625 |
| | $ | 2,750,000 |
| | $ | 2,901,563 |
|
Credit facilities (2) | | 2,484,737 |
| | 2,484,737 |
| | 2,380,788 |
| | 2,380,788 |
|
| |
(1) | Includes 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes (collectively, the “CCH Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the CCH Senior Notes and other similar instruments. |
| |
(2) | Includes 2015 CCH Credit Facility and CCH Working Capital Facility. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty. |
NOTE 8—RELATED PARTY TRANSACTIONS
We had $23.8 million and $7.1 million due to affiliates and zero and $0.6 million of other non-current liabilities—affiliate as of December 31, 2017 and 2016, respectively, under agreements with affiliates, as described below.
LNG Sale and Purchase Agreements
CCL had two fixed price 20-year SPAs with Cheniere Marketing International LLP (“Cheniere Marketing”) as of December 31, 2017. The first SPA (the “Cheniere Marketing Base SPA”) allows Cheniere Marketing to purchase, at its option, (1) up to a cumulative total of 150 TBtu of LNG within the commissioning periods for Trains 1 through 3, (2) any LNG produced from the end of the commissioning period for Train 1 until the date of first commercial delivery of LNG from Train 1 and (3) any excess LNG produced by the Liquefaction Facility that is not committed to customers under third-party SPAs or to Cheniere
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Marketing under the second SPA (the “Amended Cheniere Marketing Foundation SPA”), as determined by CCL in each contract year, in each case for a price consisting of a fixed fee of $3.00 per MMBtu of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. Under the Cheniere Marketing Base SPA, Cheniere Marketing may, without charge, elect to suspend deliveries of cargoes (other than commissioning cargoes) scheduled for any month under the applicable annual delivery program by providing specified notice in advance.
Under the Amended Cheniere Marketing Foundation SPA Cheniere Marketing was allowed to purchase LNG from CCL for a price consisting of a fixed fee of $3.50 per MMBtu (a portion of which is subject to annual adjustment for inflation) of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. The Amended Cheniere Marketing Foundation SPA commencement date, at the option of Cheniere Marketing, was the date of first commercial delivery for Train 2 and included an annual contract quantity of 40 TBtu of LNG. The Amended Cheniere Marketing Foundation SPA was terminated in January 2018.
Services Agreements
We recorded aggregate expenses from affiliates on our Consolidated Statements of Operations of $3.3 million, $0.6 million and $5.5 million for the years ended December 31, 2017, 2016 and 2015, respectively, under the services agreements below.
Gas and Power Supply Services Agreement (“G&P Agreement”)
CCL has a G&P Agreement with Cheniere Energy Shared Services, Inc. (“Shared Services”), a wholly owned subsidiary of Cheniere, pursuant to which Shared Services will manage the gas and power procurement requirements of CCL. The services include, among other services, exercising the day-to-day management of CCL’s natural gas and power supply requirements, negotiating agreements on CCL’s behalf and providing other administrative services. Prior to the substantial completion of each Train of the Liquefaction Facility, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facility, for services performed while the Liquefaction Facility is operational, CCL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train.
Operation and Maintenance Agreements (“O&M Agreements”)
CCL has an O&M Agreement (“CCL O&M Agreement”) with Cheniere LNG O&M Services, LLC (“O&M Services”), a wholly owned subsidiary of Cheniere, pursuant to which CCL receives all of the necessary services required to construct, operate and maintain the Liquefaction Facility. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors, administering various agreements and other services required to operate and maintain the Liquefaction Facility. Prior to the substantial completion of each Train of the Liquefaction Facility, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facility, for services performed while the Liquefaction Facility is operational, CCL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train.
CCP has an O&M Agreement (“CCP O&M Agreement”) with O&M Services pursuant to which CCP receives all of the necessary services required to construct, operate and maintain the Corpus Christi Pipeline. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors and other services required to operate and maintain the Corpus Christi Pipeline. CCP is required to reimburse O&M Services for all operating expenses incurred on behalf of CCP.
Management Services Agreements (“MSAs”)
CCL has an MSA with Shared Services pursuant to which Shared Services manages the construction and operation of the Liquefaction Facility, excluding those matters provided for under the G&P Agreement and the CCL O&M Agreement. The services include, among other services, exercising the day-to-day management of CCL’s affairs and business, managing CCL’s regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Liquefaction Facility and obtaining insurance. Prior to the substantial completion of each Train of the Liquefaction Facility, no monthly fee payment is required except for reimbursement of expenses. After substantial completion of each Train, CCL will pay, in addition
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
to the reimbursement of related expenses, a monthly fee equal to 3% of the capital expenditures incurred in the previous month and a fixed monthly fee of $375,000 for services with respect to such Train.
CCP has an MSA with Shared Services pursuant to which Shared Services manages CCP’s operations and business, excluding those matters provided for under the CCP O&M Agreement. The services include, among other services, exercising the day-to-day management of CCP’s affairs and business, managing CCP’s regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Corpus Christi Pipeline and obtaining insurance. CCP is required to reimburse Shared Services for the aggregate of all costs and expenses incurred in the course of performing the services under the MSA.
Lease Agreements
CCL has agreements with Cheniere Land Holdings, LLC (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, to lease approximately 60 acres of land owned by Cheniere Land Holdings for the Liquefaction Facility. The total annual lease payment, paid in advance upon 30 days of the effective date of the respective leases, is $0.4 million, and the terms of the agreements range from three to five years. We recorded $0.3 million, $0.1 million and zero of lease expense related to these agreements as operating and maintenance expense—affiliate for the years ended December 31, 2017, 2016 and 2015, respectively. We had $0.2 million and $0.1 million as of December 31, 2017 and 2016, respectively, of prepaid expense related to this agreement in other current assets—affiliate.
In September 2016, CCP entered into a pipeline right of way easement agreement with Cheniere Land Holdings granting CCP the right to construct, install and operate a natural gas pipeline on land owned by Cheniere Land Holdings. Under this agreement, Cheniere Land Holdings conveyed to CCP $0.1 million of assets during the year ended December 31, 2016. CCP also made a one-time payment of $0.3 million to Cheniere Land Holdings for the permanent easement of this land as of December 31, 2016.
Dredge Material Disposal Agreement
CCL has a dredge material disposal agreement with Cheniere Land Holdings that terminates in 2025 which grants CCL permission to use land owned by Cheniere Land Holdings for the deposit of dredge material from the construction and maintenance of the Liquefaction Facility. Under the terms of the agreement, CCL will pay Cheniere Land Holdings $0.50 per cubic yard of dredge material deposits up to 5.0 million cubic yards.
Tug Hosting Agreement
In February 2017, CCL entered into a tug hosting agreement with Corpus Christi Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of Cheniere, to provide certain marine structures, support services and access necessary at the Liquefaction Facility for Tug Services to provide its customers with tug boat and marine services. Tug Services is required to reimburse CCL for any third party costs incurred by CCL in connection with providing the goods and services.
State Tax Sharing Agreements
CCL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CCL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CCL will pay to Cheniere an amount equal to the state and local tax that CCL would be required to pay if CCL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CCL under this agreement; therefore, Cheniere has not demanded any such payments from CCL. The agreement is effective for tax returns due on or after May 2015.
CCP has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CCP and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CCP will pay to Cheniere an amount equal to the state and local tax that CCP would be required to pay if CCP’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CCP under
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
this agreement; therefore, Cheniere has not demanded any such payments from CCP. The agreement is effective for tax returns due on or after May 2015.
Equity Contribution Agreements
Equity Contribution Agreement
We have an equity contribution agreement with Cheniere pursuant to which Cheniere has agreed to provide, directly or indirectly, at our request based on reaching specified milestones of the Liquefaction Project, cash contributions up to approximately $2.6 billion for Stage 1. As of December 31, 2017, we have received $1.9 billion in contributions from Cheniere under this agreement.
Early Works Equity Contribution Agreement
In December 2017, we entered into an early works equity contribution agreement with Cheniere pursuant to which Cheniere is obligated to provide, directly or indirectly, at our request based on amounts due and payable in respect of limited notices to proceed issued under the Stage 2 EPC Contract, cash contributions of up to $310.0 million to us for the early works related to Stage 2. The amount of cash contributions Cheniere provides may be increased by Cheniere in its sole discretion. As of December 31, 2017, we have received $35.0 million in contributions from Cheniere under this agreement.
NOTE 9—INCOME TAXES
The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:
|
| | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
U.S. federal statutory tax rate | | 35.0 | % | | 35.0 | % | | 35.0 | % |
U.S. tax reform rate change | | (121.1 | )% | | — | % | | — | % |
Other | | (0.2 | )% | | — | % | | — | % |
Valuation allowance | | 86.3 | % | | (35.0 | )% | | (35.0 | )% |
Effective tax rate | | — | % | | — | % | | — | % |
Significant components of our deferred tax assets at December 31, 2017 and 2016 are as follows (in thousands):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Deferred tax assets | | | | |
Federal net operating loss carryforward | | $ | 49,194 |
| | $ | 53,618 |
|
Derivative instruments | | 15,487 |
| | 46,754 |
|
Long-term debt | | 14,270 |
| | 15,953 |
|
Property, plant and equipment | | 9,143 |
| | 13,680 |
|
Other | | 303 |
| | 393 |
|
Less: valuation allowance | | (88,397 | ) | | (130,398 | ) |
Total net deferred tax asset | | $ | — |
| | $ | — |
|
At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of approximately $234 million. These NOL carryforwards will expire between 2035 and 2037.
We did not have any uncertain tax positions which required accrual or disclosure as of December 31, 2017 and 2016. We have elected to report future interest and penalties related to unrecognized tax benefits, if any, as income tax expense in our Consolidated Statements of Operations.
Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal deferred tax assets as of December 31, 2017 and 2016. We will continue to evaluate the realizability of our deferred tax assets in the future. The decrease in the valuation allowance was $41.4 million for the year ended December 31, 2017.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. The result of the remeasurement was a $58.9 million reduction to our U.S. net deferred tax assets and represents a 121.1% decrease to our effective tax rate. A corresponding change, reducing the effective tax rate, was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense.
Our taxable income or loss is included in the consolidated federal income tax return of Cheniere. Cheniere’s federal and state tax returns for the years after 2013 remain open for examination. Tax authorities may have the ability to review and adjust carryover attributes that were generated prior to these periods if utilized in an open tax year.
Cheniere experienced an ownership change within the provisions of U.S. Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysis of the annual limitation on the utilization of Cheniere’s NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of Cheniere’s NOLs in full over the carryover period. Cheniere will continue to monitor trading activity in its respective shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize Cheniere’s existing NOL carryforwards.
NOTE 10—LEASES
During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $1.2 million, $1.0 million and $1.0 million, respectively, related primarily to land sites for the Corpus Christi LNG terminal. CCL and CCP have agreements with Cheniere Land Holdings to lease land owned by Cheniere Land Holdings for the Liquefaction Project. See Note 8—Related Party Transactions for additional information regarding these lease agreements.Future annual minimum lease payments, excluding inflationary adjustments, for operating leases are as follows (in thousands):
|
| | | |
Years Ending December 31, | Operating Leases |
2018 | $ | 895 |
|
2019 | 841 |
|
2020 | 245 |
|
2021 | — |
|
2022 | — |
|
Thereafter | — |
|
Total | $ | 1,981 |
|
NOTE 11—COMMITMENTS AND CONTINGENCIES
We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2017, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.
LNG Terminal Commitments and Contingencies
Obligations under EPC Contracts
CCL has lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of three Trains and related facilities for the Liquefaction Project. The EPC contract for Stage 2 or the Liquefaction Project was amended and restated in December 31, 2017. The EPC contract prices for Stage 1 of the Liquefaction Project and Stage 2 of the Liquefaction Project are approximately $7.8 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through December 31, 2017. CCL has the right to terminate each of the EPC contracts for its convenience, in which case Bechtel will be paid the portion of the contract price for the work performed plus costs reasonably incurred by Bechtel on account of such termination and demobilization. If the EPC contract for Stage 1 of the Liquefaction Project is terminated, Bechtel will also be paid a lump sum of up to $30.0 million depending on the termination date. If the amended and restated EPC contract for Stage 2 of the Liquefaction Project is terminated, Bechtel will be paid a lump sum of up to $2.5 million if the termination date
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
is prior to the issuance of the notice to proceed, or Bechtel will be paid a lump sum of up to $30.0 million if the termination date is after the issuance of the notice to proceed, depending on the termination date.
Obligations under SPAs
CCL has third-party SPAs which obligate CCL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project. CCL has also entered into SPAs with Cheniere Marketing, as further described in Note 8—Related Party Transactions.
Services Agreements
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 and meet the definition of a commitment as of December 31, 2017. Additionally, we have various operating lease commitments, as disclosed in Note 10—Leases.Legal Proceedings
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2017, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.
NOTE 12—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in thousands):
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Cash paid during the period for interest, net of amounts capitalized | $ | — |
| | $ | — |
| | $ | 17,456 |
|
Noncash capital contribution for conveyance of asset from affiliate | — |
| | 143 |
| | — |
|
The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $274.3 million, $145.6 million and $81.1 million as of December 31, 2017, 2016 and 2015 respectively.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 13—RECENT ACCOUNTING STANDARDS
The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:
|
| | | | | | |
Standard | | Description | | Expected Date of Adoption | | Effect on our Consolidated Financial Statements or Other Significant Matters |
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto
| | This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”). | | January 1, 2018 | | We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard.
|
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto
| | This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients. | | January 1, 2019
| | We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we expect that the requirement to recognize all leases on our Consolidated Balance Sheets will be a significant change from current practice but will not have a material impact upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition. |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | |
Standard | | Description | | Expected Date of Adoption | | Effect on our Consolidated Financial Statements or Other Significant Matters |
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
| | This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach. | | January 1, 2018
| | We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures. |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 14—SUPPLEMENTAL GUARANTOR INFORMATION
Our CCH Senior Notes are jointly and severally guaranteed by our subsidiaries, CCL, CCP and CCP GP (each a “Guarantor” and collectively, the “Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) the designation of the Guarantor as an “unrestricted subsidiary” in accordance with the CCH Indenture, (3) upon the legal defeasance or covenant defeasance or discharge of obligations under the CCH Indenture and (4) the release and discharge of the Guarantors pursuant to the Common Security and Account Agreement. See Note 7—Debt for additional information regarding the CCH Senior Notes.
The following is condensed consolidating financial information for CCH (“Parent Issuer”) and the Guarantors. We did not have any non-guarantor subsidiaries as of December 31, 2017.
|
| | | | | | | | | | | | | | | |
Condensed Consolidating Balance Sheet |
December 31, 2017 |
(in thousands) |
| | | | | | | |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
ASSETS | | | | | | | |
Current assets | | | | | | | |
Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Restricted cash | 226,559 |
| | — |
| | — |
| | 226,559 |
|
Advances to affiliate | — |
| | 31,486 |
| | — |
| | 31,486 |
|
Other current assets | 246 |
| | 1,248 |
| | — |
| | 1,494 |
|
Other current assets—affiliate | — |
| | 191 |
| | (1 | ) | | 190 |
|
Total current assets | 226,805 |
| | 32,925 |
| | (1 | ) | | 259,729 |
|
| | | | | | | |
Property, plant and equipment, net | 651,687 |
| | 7,609,696 |
| | — |
| | 8,261,383 |
|
Debt issuance and deferred financing costs, net | 98,175 |
| | — |
| | — |
| | 98,175 |
|
Investments in subsidiaries | 7,648,111 |
| | — |
| | (7,648,111 | ) | | — |
|
Other non-current assets, net | 2,469 |
| | 38,124 |
| | — |
| | 40,593 |
|
Total assets | $ | 8,627,247 |
| | $ | 7,680,745 |
| | $ | (7,648,112 | ) | | $ | 8,659,880 |
|
| | | | | | | |
LIABILITIES AND MEMBER’S EQUITY | | | | | | | |
Current liabilities | | | | | | | |
Accounts payable | $ | 82 |
| | $ | 6,379 |
| | $ | — |
| | $ | 6,461 |
|
Accrued liabilities | 136,389 |
| | 121,671 |
| | — |
| | 258,060 |
|
Due to affiliates | — |
| | 23,789 |
| | — |
| | 23,789 |
|
Derivative liabilities | 19,609 |
| | — |
| | — |
| | 19,609 |
|
Total current liabilities | 156,080 |
| | 151,839 |
| | — |
| | 307,919 |
|
| | | | | | | |
Long-term debt, net | 6,669,476 |
| | — |
| | — |
| | 6,669,476 |
|
Non-current derivative liabilities | 15,118 |
| | 91 |
| | — |
| | 15,209 |
|
Deferred tax liability | — |
| | 2,983 |
| | (2,983 | ) | | — |
|
| | | | | | | |
Member’s equity | 1,786,573 |
| | 7,525,832 |
| | (7,645,129 | ) | | 1,667,276 |
|
Total liabilities and member’s equity | $ | 8,627,247 |
| | $ | 7,680,745 |
| | $ | (7,648,112 | ) | | $ | 8,659,880 |
|
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | | | | | | | | | | |
Condensed Consolidating Balance Sheet |
December 31, 2016 |
(in thousands) |
| | | | | | | |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
ASSETS | | | | | | | |
Current assets | | | | | | | |
Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Restricted cash | 197,201 |
| | — |
| | — |
| | 197,201 |
|
Advances to affiliate | — |
| | 20,108 |
| | — |
| | 20,108 |
|
Other current assets | 152 |
| | 37,043 |
| | — |
| | 37,195 |
|
Other current assets—affiliate | — |
| | 142 |
| | (1 | ) | | 141 |
|
Total current assets | 197,353 |
| | 57,293 |
| | (1 | ) | | 254,645 |
|
| | | | | | | |
Non-current restricted cash | 73,339 |
| | — |
| | — |
| | 73,339 |
|
Property, plant and equipment, net | 306,342 |
| | 5,770,330 |
| | — |
| | 6,076,672 |
|
Debt issuance and deferred financing costs, net | 155,847 |
| | — |
| | — |
| | 155,847 |
|
Investments in subsidiaries | 5,927,833 |
| | — |
| | (5,927,833 | ) | | — |
|
Non-current advances under long-term contracts | — |
| | 46,398 |
| | — |
| | 46,398 |
|
Other non-current assets, net | 50 |
| | 29,497 |
| | — |
| | 29,547 |
|
Total assets | $ | 6,660,764 |
| | $ | 5,903,518 |
| | $ | (5,927,834 | ) | | $ | 6,636,448 |
|
| | | | | | | |
LIABILITIES AND MEMBER’S EQUITY | | | | | | | |
Current liabilities | | | | | | | |
Accounts payable | $ | 332 |
| | $ | 8,788 |
| | $ | — |
| | $ | 9,120 |
|
Accrued liabilities | 61,328 |
| | 76,320 |
| | — |
| | 137,648 |
|
Due to affiliates | — |
| | 7,050 |
| | — |
| | 7,050 |
|
Derivative liabilities | 43,383 |
| | — |
| | — |
| | 43,383 |
|
Total current liabilities | 105,043 |
| | 92,158 |
| | — |
| | 197,201 |
|
| | | | | | | |
Long-term debt, net | 5,081,715 |
| | — |
| | — |
| | 5,081,715 |
|
Non-current derivative liabilities | 43,105 |
| | — |
| | — |
| | 43,105 |
|
Other non-current liabilities—affiliate | — |
| | 618 |
| | — |
| | 618 |
|
| | | | | | | |
Member’s equity | 1,430,901 |
| | 5,810,742 |
| | (5,927,834 | ) | | 1,313,809 |
|
Total liabilities and member’s equity | $ | 6,660,764 |
| | $ | 5,903,518 |
| | $ | (5,927,834 | ) | | $ | 6,636,448 |
|
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | | | | | | | | | | |
Condensed Consolidating Statement of Operations |
Year Ended December 31, 2017 |
(in thousands) |
| | | | | | | |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
| | | | | | | |
Revenues | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | |
Expenses | | | | | | | |
Operating and maintenance expense | — |
| | 3,115 |
| | — |
| | 3,115 |
|
Operating and maintenance expense—affiliate | — |
| | 2,401 |
| | — |
| | 2,401 |
|
Development expense | — |
| | 516 |
| | — |
| | 516 |
|
Development expense—affiliate | — |
| | 8 |
| | — |
| | 8 |
|
General and administrative expense | 1,360 |
| | 4,191 |
| | — |
| | 5,551 |
|
General and administrative expense—affiliate | — |
| | 1,173 |
| | — |
| | 1,173 |
|
Depreciation and amortization expense | 13 |
| | 879 |
| | — |
| | 892 |
|
Impairment expense and loss on disposal of assets | — |
| | 5,505 |
| | — |
| | 5,505 |
|
Total expenses | 1,373 |
| | 17,788 |
| | — |
| | 19,161 |
|
| | | | | | | |
Loss from operations | (1,373 | ) | | (17,788 | ) | | — |
| | (19,161 | ) |
| | | | | | | |
Other income (expense) | | | | | | | |
Loss on early extinguishment of debt | (32,480 | ) | | — |
| | — |
| | (32,480 | ) |
Derivative gain, net | 3,249 |
| | — |
| | — |
| | 3,249 |
|
Other income (expense) | (265 | ) | | 15,580 |
| | (15,575 | ) | | (260 | ) |
Total other income (expense) | (29,496 | ) | | 15,580 |
| | (15,575 | ) | | (29,491 | ) |
| | | | | | | |
Loss before income taxes | (30,869 | ) | | (2,208 | ) | | (15,575 | ) | | (48,652 | ) |
Income tax provision | — |
| | (2,983 | ) | | 2,983 |
| | — |
|
| | | | | | | |
Net loss | $ | (30,869 | ) | | $ | (5,191 | ) | | $ | (12,592 | ) | | $ | (48,652 | ) |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | | | | | | | | | | |
Condensed Consolidating Statement of Operations |
Year Ended December 31, 2016 |
(in thousands) |
| | | | | | | |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
| | | | | | | |
Revenues | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | |
Expenses | | | | | | | |
Operating and maintenance expense | — |
| | 1,372 |
| | — |
| | 1,372 |
|
Operating and maintenance expense—affiliate | — |
| | 95 |
| | — |
| | 95 |
|
Development expense recovery | — |
| | (81 | ) | | — |
| | (81 | ) |
Development expense recovery—affiliate | — |
| | (10 | ) | | — |
| | (10 | ) |
General and administrative expense | 709 |
| | 3,531 |
| | — |
| | 4,240 |
|
General and administrative expense—affiliate | — |
| | 607 |
| | — |
| | 607 |
|
Depreciation and amortization expense | — |
| | 249 |
| | — |
| | 249 |
|
Total expenses | 709 |
| | 5,763 |
| | — |
| | 6,472 |
|
| | | | | | | |
Loss from operations | (709 | ) | | (5,763 | ) | | — |
| | (6,472 | ) |
| | | | | | | |
Other income (expense) | | | | | | | |
Loss on early extinguishment of debt | (63,318 | ) | | — |
| | — |
| | (63,318 | ) |
Derivative loss, net | (15,571 | ) | | — |
| | — |
| | (15,571 | ) |
Other income (expense) | (131 | ) | | 5 |
| | — |
| | (126 | ) |
Total other income (expense) | (79,020 | ) | | 5 |
| | — |
| | (79,015 | ) |
| | | | | | | |
Net loss | $ | (79,729 | ) | | $ | (5,758 | ) | | $ | — |
| | $ | (85,487 | ) |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | | | | | | | | | | |
Condensed Consolidating Statement of Operations |
Year Ended December 31, 2015 |
(in thousands) |
| | | | | | | |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
| | | | | | | |
Revenues | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | |
Expenses | | | | | | | |
Operating and maintenance expense | — |
| | 572 |
| | — |
| | 572 |
|
Development expense | — |
| | 13,690 |
| | — |
| | 13,690 |
|
Development expense—affiliate | — |
| | 5,525 |
| | — |
| | 5,525 |
|
General and administrative expense | 724 |
| | 2,465 |
| | — |
| | 3,189 |
|
General and administrative expense—affiliate | — |
| | 13 |
| | — |
| | 13 |
|
Depreciation and amortization expense | — |
| | 55 |
| | — |
| | 55 |
|
Total expenses | 724 |
| | 22,320 |
| | — |
| | 23,044 |
|
| | | | | | | |
Loss from operations | (724 | ) | | (22,320 | ) | | — |
| | (23,044 | ) |
| | | | | | | |
Other income (expense) | | | | | | | |
Interest expense, net of capitalized interest | (25,680 | ) | | — |
| | — |
| | (25,680 | ) |
Loss on early extinguishment of debt | (16,498 | ) | | — |
| | — |
| | (16,498 | ) |
Derivative loss, net | (161,917 | ) | | — |
| | — |
| | (161,917 | ) |
Other income | 36 |
| | 6 |
| | — |
| | 42 |
|
Total other income (expense) | (204,059 | ) | | 6 |
| | — |
| | (204,053 | ) |
| | | | | | | |
Net loss | $ | (204,783 | ) | | $ | (22,314 | ) | | $ | — |
| | $ | (227,097 | ) |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | | | | | | | | | | |
Condensed Consolidating Statement of Cash Flows |
Year Ended December 31, 2017 |
(in thousands) |
| | | | | | | |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
Cash flows from operating activities | | | | | | | |
Net loss | $ | (30,869 | ) | | $ | (5,191 | ) | | $ | (12,592 | ) | | $ | (48,652 | ) |
Adjustments to reconcile net loss to net cash used in operating activities: | | | | | | | |
Depreciation and amortization expense | 13 |
| | 879 |
| | — |
| | 892 |
|
Allowance for funds used during construction | — |
| | (15,575 | ) | | 15,575 |
| | — |
|
Deferred income taxes | — |
| | 2,983 |
| | (2,983 | ) | | — |
|
Loss on early extinguishment of debt | 32,480 |
| | — |
| | — |
| | 32,480 |
|
Total losses (gains) on derivatives, net | (3,249 | ) | | 91 |
| | — |
| | (3,158 | ) |
Net cash used for settlement of derivative instruments | (50,981 | ) | | — |
| | — |
| | (50,981 | ) |
Impairment expense and loss on disposal of assets | — |
| | 5,505 |
| | — |
| | 5,505 |
|
Changes in operating assets and liabilities: | | | | | | | |
Accounts payable and accrued liabilities | 68 |
| | 84 |
| | — |
| | 152 |
|
Due to affiliates | — |
| | 1,567 |
| | — |
| | 1,567 |
|
Other, net | (95 | ) | | (1,359 | ) | | — |
| | (1,454 | ) |
Other, net—affiliate | — |
| | (667 | ) | | — |
| | (667 | ) |
Net cash used in operating activities | (52,633 | ) | | (11,683 | ) | | — |
| | (64,316 | ) |
| | | | | | | |
Cash flows from investing activities | | | | | | | |
Property, plant and equipment, net | (253,612 | ) | | (1,733,642 | ) | | — |
| | (1,987,254 | ) |
Investments in subsidiaries | (1,720,280 | ) | | — |
| | 1,720,280 |
| | — |
|
Other | — |
| | 25,045 |
| | — |
| | 25,045 |
|
Net cash used in investing activities | (1,973,892 | ) | | (1,708,597 | ) | | 1,720,280 |
| | (1,962,209 | ) |
| | | | | | | |
Cash flows from financing activities | | | | | | | |
Proceeds from issuances of debt | 3,040,000 |
| | — |
| | — |
| | 3,040,000 |
|
Repayments of debt | (1,436,050 | ) | | — |
| | — |
| | (1,436,050 | ) |
Debt issuance and deferred financing costs | (23,496 | ) | | — |
| | — |
| | (23,496 | ) |
Capital contributions | 402,119 |
| | 1,720,437 |
| | (1,720,437 | ) | | 402,119 |
|
Distributions | — |
| | (157 | ) | | 157 |
| | — |
|
Other | (29 | ) | | — |
| | — |
| | (29 | ) |
Net cash provided by financing activities | 1,982,544 |
| | 1,720,280 |
| | (1,720,280 | ) | | 1,982,544 |
|
| | | | | | | |
Net decrease in cash, cash equivalents and restricted cash | (43,981 | ) | | — |
| | — |
| | (43,981 | ) |
Cash, cash equivalents and restricted cash—beginning of period | 270,540 |
| | — |
| | — |
| | 270,540 |
|
Cash, cash equivalents and restricted cash—end of period | $ | 226,559 |
| | $ | — |
| | $ | — |
| | $ | 226,559 |
|
Balances per Condensed Consolidating Balance Sheet:
|
| | | | | | | | | | | | | | | |
| December 31, 2017 |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Restricted cash | 226,559 |
| | — |
| | — |
| | 226,559 |
|
Total cash, cash equivalents and restricted cash | $ | 226,559 |
| | $ | — |
| | $ | — |
| | $ | 226,559 |
|
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | | | | | | | | | | |
Condensed Consolidating Statement of Cash Flows |
Year Ended December 31, 2016 |
(in thousands) |
| | | | | | | |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
Cash flows from operating activities | | | | | | | |
Net loss | $ | (79,729 | ) | | $ | (5,758 | ) | | $ | — |
| | $ | (85,487 | ) |
Adjustments to reconcile net loss to net cash used in operating activities: | | | | | | | |
Depreciation and amortization expense | — |
| | 249 |
| | — |
| | 249 |
|
Loss on early extinguishment of debt | 63,318 |
| | — |
| | — |
| | 63,318 |
|
Total losses on derivatives, net | 15,571 |
| | — |
| | — |
| | 15,571 |
|
Net cash used for settlement of derivative instruments | (34,082 | ) | | — |
| | — |
| | (34,082 | ) |
Changes in operating assets and liabilities: | | | | | | | |
Accounts payable and accrued liabilities | 121 |
| | 294 |
| | — |
| | 415 |
|
Due to affiliates | — |
| | (331 | ) | | — |
| | (331 | ) |
Other, net | (153 | ) | | (592 | ) | | — |
| | (745 | ) |
Other, net—affiliate | — |
| | 13 |
| | — |
| | 13 |
|
Net cash used in operating activities | (34,954 | ) | | (6,125 | ) | | — |
| | (41,079 | ) |
| | | | | | | |
Cash flows from investing activities | | | | | | | |
Property, plant and equipment, net | (126,547 | ) | | (1,924,983 | ) | | — |
| | (2,051,530 | ) |
Investments in subsidiaries | (1,975,474 | ) | | — |
| | 1,975,474 |
| | — |
|
Other | — |
| | (44,367 | ) | | — |
| | (44,367 | ) |
Net cash used in investing activities | (2,102,021 | ) | | (1,969,350 | ) | | 1,975,474 |
| | (2,095,897 | ) |
| | | | | | | |
Cash flows from financing activities | | | | | | | |
Proceeds from issuances of debt | 4,838,000 |
| | — |
| | — |
| | 4,838,000 |
|
Repayments of debt | (2,420,212 | ) | | — |
| | — |
| | (2,420,212 | ) |
Debt issuance and deferred financing costs | (56,783 | ) | | — |
| | — |
| | (56,783 | ) |
Capital contributions | 90 |
| | 1,975,475 |
| | (1,975,474 | ) | | 91 |
|
Distribution to affiliate | (288 | ) | | — |
| | — |
| | (288 | ) |
Other | (62 | ) | | — |
| | — |
| | (62 | ) |
Net cash provided by financing activities | 2,360,745 |
| | 1,975,475 |
| | (1,975,474 | ) | | 2,360,746 |
|
| | | | | | | |
Net increase in cash, cash equivalents and restricted cash | 223,770 |
| | — |
| | — |
| | 223,770 |
|
Cash, cash equivalents and restricted cash—beginning of period | 46,770 |
| | — |
| | — |
| | 46,770 |
|
Cash, cash equivalents and restricted cash—end of period | $ | 270,540 |
| | $ | — |
| | $ | — |
| | $ | 270,540 |
|
Balances per Condensed Consolidating Balance Sheet:
|
| | | | | | | | | | | | | | | |
| December 31, 2016 |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Restricted cash | 197,201 |
| | — |
| | — |
| | 197,201 |
|
Non-current restricted cash | 73,339 |
| | — |
| | — |
| | 73,339 |
|
Total cash, cash equivalents and restricted cash | $ | 270,540 |
| | $ | — |
| | $ | — |
| | $ | 270,540 |
|
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | | | | | | | | | | |
Condensed Consolidating Statement of Cash Flows |
Year Ended December 31, 2015 |
(in thousands) |
| | | | | | | |
| Parent Issuer | | Guarantors | | Eliminations | | Consolidated |
Cash flows from operating activities | | | | | | | |
Net loss | $ | (204,783 | ) | | $ | (22,314 | ) | | $ | — |
| | $ | (227,097 | ) |
Adjustments to reconcile net loss to net cash used in operating activities: | | | | | | | |
Depreciation and amortization expense | — |
| | 55 |
| | — |
| | 55 |
|
Amortization of debt issuance costs, net of capitalization | 6,340 |
| | — |
| | — |
| | 6,340 |
|
Loss on early extinguishment of debt | 16,498 |
| | — |
| | — |
| | 16,498 |
|
Total losses on derivatives, net | 161,917 |
| | — |
| | — |
| | 161,917 |
|
Net cash used for settlement of derivative instruments | (56,918 | ) | | — |
| | — |
| | (56,918 | ) |
Changes in operating assets and liabilities: | | | | | | | |
Accounts payable and accrued liabilities | 453 |
| | 549 |
| | — |
| | 1,002 |
|
Due to affiliates | (860 | ) | | 1,135 |
| | — |
| | 275 |
|
Advances to affiliate | — |
| | (10,073 | ) | | — |
| | (10,073 | ) |
Other, net | — |
| | 301 |
| | — |
| | 301 |
|
Other, net—affiliate | — |
| | 498 |
| | — |
| | 498 |
|
Net cash used in operating activities | (77,353 | ) | | (29,849 | ) | | — |
| | (107,202 | ) |
| | | | | | | |
Cash flows from investing activities | | | | | | | |
Property, plant and equipment, net | (63,783 | ) | | (3,757,164 | ) | | — |
| | (3,820,947 | ) |
Investments in subsidiaries | (3,804,848 | ) | | — |
| | 3,804,848 |
| | — |
|
Other | (633 | ) | | (17,835 | ) | | — |
| | (18,468 | ) |
Net cash used in investing activities | (3,869,264 | ) | | (3,774,999 | ) | | 3,804,848 |
| | (3,839,415 | ) |
| | | | | | | |
Cash flows from financing activities | | | | | | | |
Proceeds from issuances of long-term debt | 2,713,000 |
| | — |
| | — |
| | 2,713,000 |
|
Debt issuance and deferred financing costs | (280,528 | ) | | — |
| | — |
| | (280,528 | ) |
Capital contributions | 1,560,915 |
| | 3,804,848 |
| | (3,804,848 | ) | | 1,560,915 |
|
Net cash provided by financing activities | 3,993,387 |
| | 3,804,848 |
| | (3,804,848 | ) | | 3,993,387 |
|
| | | | | | | |
Net increase in cash, cash equivalents and restricted cash | 46,770 |
| | — |
| | — |
| | 46,770 |
|
Cash, cash equivalents and restricted cash—beginning of period | — |
| | — |
| | — |
| | — |
|
Cash, cash equivalents and restricted cash—end of period | $ | 46,770 |
| | $ | — |
| | $ | — |
| | $ | 46,770 |
|
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
SUMMARIZED QUARTERLY FINANCIAL DATA
(unaudited)
Summarized Quarterly Financial Data—(in thousands)
|
| | | | | | | | | | | | | | | | |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
Year ended December 31, 2017: | | | | | | | | |
Revenues | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Loss from operations | | (2,719 | ) | | (3,138 | ) | | (5,576 | ) | | (7,728 | ) |
Net income (loss) | | (1,757 | ) | | (68,758 | ) | | (8,577 | ) | | 30,440 |
|
| | | | | | | | |
Year ended December 31, 2016: | | | | | | | | |
Revenues | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Loss from operations | | (733 | ) | | (1,672 | ) | | (1,809 | ) | | (2,258 | ) |
Net income (loss) | | (160,884 | ) | | (106,585 | ) | | 18,230 |
| | 163,752 |
|
| |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| |
ITEM 9A.
| CONTROLS AND PROCEDURES |
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December 31, 2017, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our Management’s Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements on page 38 and is incorporated herein by reference.
| |
ITEM 9B. | OTHER INFORMATION |
None.
PART III
| |
ITEM 10. | MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE |
Omitted pursuant to Instruction I of Form 10-K.
| |
ITEM 11. | EXECUTIVE COMPENSATION
|
Omitted pursuant to Instruction I of Form 10-K.
| |
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS |
Omitted pursuant to Instruction I of Form 10-K.
| |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE |
Omitted pursuant to Instruction I of Form 10-K.
| |
ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
KPMG LLP served as our independent auditor for the fiscal years ended December 31, 2017 and 2016. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 2017 and 2016 (in thousands):
|
| | | | | | | | |
| | Fiscal 2017 | | Fiscal 2016 |
Audit Fees | | $ | 1,050 |
| | $ | 1,070 |
|
Tax Fees | | 89 |
| | 29 |
|
Total | | $ | 1,139 |
| | $ | 1,099 |
|
Audit Fees—Audit fees for 2017 and 2016 include fees associated with the audit of our annual Consolidated Financial Statements, reviews of our interim Consolidated Financial Statements and services performed in connection with registration statements and debt offerings, including comfort letters and consents.
Audit-Related Fees—There were no audit-related fees in 2017 and 2016.
Tax Fees—Tax fees for 2017 and 2016 were for tax consultation services with respect to a sales and use tax analysis for the Liquefaction Project.
Other Fees—There were no other fees in 2017 and 2016.
Auditor Pre-Approval Policy and Procedures
We are not a public company and we are not listed on any stock exchange. As a result, we are not required to, and do not, have an independent audit committee, a financial expert or a majority of independent directors. The audit committee of Cheniere has approved all audit and non-audit services to be provided by the independent accountants and the fees for such services during the fiscal years ended December 31, 2017 and 2016.
PART IV
| |
ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
| |
(a) | Financial Statements and Exhibits |
| |
(1) | Financial Statements—Cheniere Corpus Christi Holdings, LLC: |
| |
(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.
Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;
may apply standards of materiality that differ from those of a reasonable investor; and
were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.
|
| | |
Exhibit No. | | Description |
3.1 | | |
3.2 | | |
3.3 | | |
3.4 | | |
|
| | |
Exhibit No. | | Description |
3.5 | | |
3.6 | | |
3.7 | | |
3.8 | | |
3.9 | | |
3.10 | | |
3.11 | | |
4.1 | | Indenture, dated as of May 18, 2016, among the Company, as Issuer, CCL, CCP and CCP GP, as Guarantors, and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 18, 2016) |
4.2 | | |
4.3 | | First Supplemental Indenture, dated as of December 9, 2016, among the Company, as Issuer, CCL, CCP and CCP GP, as Guarantors, and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 9, 2016) |
4.4 | | |
4.5 | | Second Supplemental Indenture, dated as of May 19, 2017, among the Company, as issuer, CCL, CCP and CCP GP, as Guarantors, and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (SEC File No. 333-215435), filed on May 19, 2017) |
4.6 | | |
10.1 | | Corpus Christi Liquefied Natural Gas Project Term Loan Facility Agreement, dated May 13, 2015, among the Company, as Borrower, CCL, CCP, and CCP GP, as Guarantors, Term Lenders party thereto from time to time, and Société Générale, as Term Loan Facility Agent (Incorporated by reference to Exhibit 10.4 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 13, 2015) |
10.2 | | Common Security and Account Agreement, dated May 13, 2015, among the Company, as Company, CCL, CCP, and CCP GP, as Guarantors, the Senior Creditor Group Representatives party thereto from time to time, Société Générale, as Intercreditor Agent and Security Trustee, and Mizuho Bank, Ltd., as Account Bank (Incorporated by reference to Exhibit 10.2 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 13, 2015) |
10.3 | | Consent for Amendment to the Common Security and Account Agreement, dated September 7, 2017, among the Company, as Company, CCL, CCP, and CCP GP, as Guarantors, the Senior Creditor Group Representatives party thereto from time to time, Société Générale, as Intercreditor Agent and Security Trustee, and Mizuho Bank, Ltd., as Account Bank (Incorporated by reference to Exhibit 10.51 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-221307), filed on November 2, 2017) |
10.4 | | Common Terms Agreement, dated May 13, 2015, among the Company, as Borrower, CCL, CCP, and CCP GP, as Guarantors, Société Générale, as Term Loan Facility Agent and Intercreditor Agent and any other facility agents party thereto from time to time (Incorporated by reference to Exhibit 10.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 13, 2015) |
10.5 | | Consent for Amendment to the Common Terms Agreement, dated September 7, 2017, among the Company, as Borrower, CCL, CCP, and CCP GP, as Guarantors, Société Générale, as Term Loan Facility Agent and Intercreditor Agent and any other facility agents party thereto from time to time (Incorporated by reference to Exhibit 10.52 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-221307), filed on November 2, 2017) |
10.6 | | |
|
| | |
Exhibit No. | | Description |
10.7 | | Working Capital Facility Agreement, dated as of December 14, 2016, among CCH, as Borrower, CCL, CCP, and CCP GP, as Guarantors, The Bank of Nova Scotia, as Working Capital Facility Agent, The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation, as Issuing Banks, Mizuho Bank, Ltd., as Swing Line Lender, and the lenders party thereto from time to time (Incorporated by reference to Exhibit 10.1 to the Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 20, 2016) |
10.8 | | First Amendment to Working Capital Facility Agreement, dated December 20, 2016, among CCH, as Borrower, CCL, CCP, and CCP GP, as Guarantors, The Bank of Nova Scotia, as Working Capital Facility Agent, The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation, as Issuing Banks, Mizuho Bank, Ltd., as Swing Line Lender, and the lenders party thereto from time to time (Incorporated by reference to Exhibit 10.42 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017) |
10.9 | | |
10.10 | | Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Cost Impacts Associated with Delay in NTP, dated March 9, 2015, (ii) the Change Order CO-00002 DLE/IAC Scope Change, dated March 25, 2015, (iii) the Change Order CO-00003 Currency and Fuel Provisional Sum Closures, dated May 13, 2015 and (iv) the Change Order CO-00004 Bridging Extension Through May 17, 2015, dated May 12, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.22 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on July 30, 2015) |
10.11 | | Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00005 Revised Buildings to Include Jetty and Geo-Tech Impact to Buildings, dated June 4, 2015, (ii) the Change Order CO-00006 Marine and Dredging Execution Change, dated June 16, 2015, (iii) the Change Order CO-00007 Temporary Laydown Areas, AEP Substation Relocation, Power Monitoring System for Substation, Bollards for Power Line Poles, Multiplex Interface for AEP Hecker Station, dated June 30, 2015, (iv) the Change Order CO-00008 West Jetty Shroud and Fencing, Temporary Strainers on Loading Arms, Breasting and Mooring Analysis, Addition of Crossbar from Platform at Ethylene Bullets to Platform for PSV Deck, Reduction of Vapor Fence at Bed 22, Relocation of Gangway Tower, Changes in Dolphin Size, dated July 28, 2015, (v) the Change Order CO-00009 Post FEED Studies, dated July 1, 2015, (vi) the Change Order CO-00010 Additional Post FEED Studies, Feed Gas ESD Valve Bypass, Flow Meter on Bog Line, Additional Simulations, FERC #43, dated July 1, 2015, (vii) the Change Order CO-00011 Credit to EPC Contract Value for TSA Work, dated July 7, 2015, and (viii) the Change Order CO-00012 Reduction of Provisional Sum for Operating Spares, Liquid Condensate Tie-In, Automatic Shut-Off Valve in Condensate Truck Fill Line, Firewater Monitor and Hydrant Coverage Test, dated August 11, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.4 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on October 30, 2015) |
10.12 | | Change order to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00013 Change in FEED Gas Tie-In, Utility Water and Potable Water Tie-In Changes, Ditch Design at Permanent Buildings, Koch Pipeline Cover, Monitoring of Raw Water Lake During Piling, Card Readers and Muster Points, Additional Asphalt in the Temporary Facilities Area, FAA Lighting and Marking, FERC Condition 84, dated October 13, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.134 to Cheniere’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 19, 2016) |
10.13 | | Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00014 Stage 1 Isolation, dated January 11, 2016, (ii) the Change Order CO-00015 IAC Conversion to Lump Sum, dated January 20, 2016, and (iii) the Change Order CO-00016 Permanent Plant Buildings, dated January 20, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.6 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 5, 2016) |
|
| | |
Exhibit No. | | Description |
10.14 | | Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00017 Process and Utility Tie-Ins Studies and Associated Scopes (138 kV Pricing, Transfer Line, Connections for Future LNG Truck Loading Facility), dated May 24, 2016, (ii) the Change Order CO-00018 FERC Conditions 40, 63, 64, 80, dated May 4, 2016, (iii) the Change Order CO-00019 Trelleborg Marine Equipment, BOG Compressor Tie-In, Multiplexer Credit, Additional FERC Hours, dated May 4, 2016, and (iv) the Change Order CO-00020 Impact Due to Overhead Power Transmission Lines on La Quinta Road and Flare System Modification Evaluation, dated May 31, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.8 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 9, 2016) |
10.15 | | Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00022 Permanent Plant Building Modifications, dated June 20, 2016 and (ii) the Change Order CO-00024 N2 Dewar Interface, Temporary Power to Air Cooler, Condensate Pipeline Maximum Allowable Operating Pressure, dated June 28, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.5 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 3, 2016) |
10.16 | | Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00026 Changes to Outfall (P1, P2, and P5) to LaQuinta Ditch, dated August 31, 2016, (ii) the Change Order CO-00028 Anti-Dumping Duties, dated September 26, 2016, and (iii) the Change Order CO-00029 Additional Flare System Evaluation, dated September 26, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment) (Incorporated by reference to Exhibit 10.12 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-215435), filed on January 5, 2017) |
10.17 | | Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00021 Secondary Access Road, DMPA-1 Scope and Use, Credit for Material Disposal, Power Pole Relocation, dated June 29, 2016, (ii) the Change Order CO-00023 Differing Soil Conditions and Bed 24 Over-Excavation Due to Differing Soil Conditions, dated June 29, 2016, (iii) the Change Order CO-00025 Priority 6 Roads Differing Soil Conditions and 102-J01 Over-Excavation due to Differing Soil Conditions, dated August 23, 2016, (iv) the Change Order CO-00027 Lines Traversing Laydown Area Access Road and Underground Utilities for Temporary Facilities, dated September 26, 2016, and (v) the Change Order CO-00032 Integrated Security System, dated February 3, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.45 to Amendment No. 1 to the Company’s Registration Statement on Form S-4/A (SEC File No. 333-215435), filed on March 8, 2017) |
10.18 | | Change order to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00030, dated November 1, 2016 (Incorporated by reference to Exhibit 10.46 to Amendment No. 1 to the Company’s Registration Statement on Form S-4/A (SEC File No. 333-215435), filed on March 8, 2017) |
10.19 | | Change order to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00031 Flare System Modification Implementation, dated January 17, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.48 to Amendment No. 2 to the Company’s Registration Statement on Form S-4/A (SEC File No. 333-215435), filed on March 23, 2017) |
10.20 | | Change order to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00033 Marine Ground Flare, dated February 27, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-215435), filed on May 4, 2017) |
|
| | |
Exhibit No. | | Description |
10.21 | | Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00034 Condensate Tie-In, Utility Water Tie-In, and Feed Gas Tie-In Relocation, dated April 18, 2017 and (ii) the Change Order CO-00035 Nitrogen Tie-In Relocation, dated April 21, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 333-215435), filed on August 8, 2017) |
10.22 | | Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00036 Security Fencing Revisions, 138kV Overhead Power Stop Work, Additional Permanent Plant Access Control System Changes, and Wet/Dry Flare Expansion Loop Relocation, dated August 3, 2017 and (ii) the Change Order CO-00037 9% Nickel Lump Sum Conversion, dated September 14, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.50 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-221307), filed on November 2, 2017) |
10.23* | | |
10.24 | | |
10.25 | | |
10.26 | | |
10.27 | | |
10.28 | | |
10.29 | | |
10.30 | | |
10.31 | | |
10.32 | | |
10.33 | | |
10.34 | | |
10.35 | | |
|
| | |
Exhibit No. | | Description |
10.36 | | |
10.37 | | |
10.38 | | |
10.39 | | |
10.40 | | |
10.41 | | |
10.42 | | |
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 |
|
| |
* | Filed herewith. |
** | Furnished herewith. |
(c) Financial statements of affiliates whose securities are pledged as collateral — See Index to Financial Statements on page S-1.
The accompanying Financial Statements of our subsidiaries, CCL, CCP and CCP GP, are being provided pursuant to Rule 3-16 of Regulation S-X, which requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities.
| |
ITEM 16. | FORM 10-K SUMMARY |
None.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | |
| CHENIERE CORPUS CHRISTI HOLDINGS, LLC |
| |
| By: | /s/ Michael J. Wortley |
| | Michael J. Wortley |
| | President and Chief Financial Officer
(Principal Executive and Financial Officer) |
| Date: | February 20, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
| | |
Signature | Title | Date |
| | |
/s/ Michael J. Wortley | Manager, President and Chief Financial Officer
(Principal Executive and Financial Officer) | February 20, 2018 |
Michael J. Wortley |
| | |
/s/ Doug Shanda | Manager | February 20, 2018 |
Doug Shanda |
| | |
/s/ Leonard Travis | Chief Accounting Officer
(Principal Accounting Officer) | February 20, 2018 |
Leonard Travis |
| | |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS OF SUBSIDIARIES INCLUDED
PURSUANT TO RULE 3-16 OF REGULATION S-X
Corpus Christi Liquefaction, LLC
Financial Statements
As of December 31, 2017 and 2016
and for the years ended December 31, 2017, 2016 and 2015
CORPUS CHRISTI LIQUEFACTION, LLC
FINANCIAL STATEMENTS
DEFINITIONS
As used in these Financial Statements, the terms listed below have the following meanings:
Common Industry and Other Terms
|
| | |
Bcfe | | billion cubic feet equivalent |
EPC | | engineering, procurement and construction |
GAAP | | generally accepted accounting principles in the United States |
LNG | | liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state |
MMBtu | | million British thermal units, an energy unit |
mtpa | | million tonnes per annum |
SEC | | U.S. Securities and Exchange Commission |
SPA | | LNG sale and purchase agreement |
TBtu | | trillion British thermal units, an energy unit |
Train | | an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG |
Abbreviated Legal Entity Structure
The following diagram depicts our abbreviated legal entity structure as of December 31, 2017 and the references to these entities used in these Financial Statements:
Unless the context requires otherwise, references to “the Company,” “we,” “us,” and “our” refer to Corpus Christi Liquefaction, LLC.
Independent Auditors’ Report
To the Member
Corpus Christi Liquefaction, LLC:
We have audited the accompanying financial statements of Corpus Christi Liquefaction, LLC, which comprise the balance sheets as of December 31, 2017 and 2016, and the related statements of operations, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Corpus Christi Liquefaction, LLC as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in accordance with U.S. generally accepted accounting principles.
Houston, Texas
February 20, 2018
CORPUS CHRISTI LIQUEFACTION, LLC
BALANCE SHEETS
(in thousands)
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
ASSETS | | | | |
Current assets | | | | |
Cash and cash equivalents | | $ | — |
| | $ | — |
|
Restricted cash | | — |
| | — |
|
Advances to affiliate | | 11,414 |
| | 2,184 |
|
Other current assets | | 1,237 |
| | 37,014 |
|
Other current assets—affiliate | | 190 |
| | 141 |
|
Total current assets | | 12,841 |
| | 39,339 |
|
| | | | |
Property, plant and equipment, net | | 7,259,438 |
| | 5,640,973 |
|
Non-current advances under long-term contracts | | — |
| | 46,398 |
|
Other non-current assets, net | | 37,854 |
| | 26,285 |
|
Total assets | | $ | 7,310,133 |
| | $ | 5,752,995 |
|
| | | | |
LIABILITIES AND MEMBER’S EQUITY | | | | |
Current liabilities | | | | |
Accounts payable | | $ | 4,456 |
| | $ | 1,105 |
|
Accrued liabilities | | 96,886 |
| | 57,924 |
|
Due to affiliates | | 21,741 |
| | 5,836 |
|
Total current liabilities | | 123,083 |
| | 64,865 |
|
| | | | |
Non-current derivative liabilities | | 91 |
| | — |
|
Other non-current liabilities—affiliate | | — |
| | 618 |
|
| | | | |
Commitments and contingencies (see Note 8) | | | | |
| | | | |
Member’s equity | | 7,186,959 |
| | 5,687,512 |
|
Total liabilities and member’s equity | | $ | 7,310,133 |
| | $ | 5,752,995 |
|
The accompanying notes are an integral part of these financial statements.
S-5
CORPUS CHRISTI LIQUEFACTION, LLC
STATEMENTS OF OPERATIONS
(in thousands)
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
Revenues | | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | |
Expenses | | | | |
| | |
Operating and maintenance expense | | 3,099 |
| | 1,350 |
| | 572 |
|
Operating and maintenance expense—affiliate | | 2,331 |
| | 92 |
| | — |
|
Development expense (recovery) | | 516 |
| | (81 | ) | | 13,690 |
|
Development expense (recovery)—affiliate | | 8 |
| | (10 | ) | | 5,525 |
|
General and administrative expense | | 3,951 |
| | 3,231 |
| | 2,353 |
|
General and administrative expense—affiliate | | 1,127 |
| | 600 |
| | — |
|
Depreciation and amortization expense | | 810 |
| | 239 |
| | 55 |
|
Impairment expense and loss on disposal of assets | | 5,500 |
| | — |
| | — |
|
Total expenses | | 17,342 |
| | 5,421 |
| | 22,195 |
|
| | | | | | |
Loss from operations | | (17,342 | ) | | (5,421 | ) | | (22,195 | ) |
| | | | | | |
Other income | | | | | | |
Other income | | 5 |
| | 5 |
| | 6 |
|
Other income—affiliate | | 12 |
| | 12 |
| | — |
|
Total other income | | 17 |
| | 17 |
| | 6 |
|
| | | | | | |
Net loss | | $ | (17,325 | ) | | $ | (5,404 | ) | | $ | (22,189 | ) |
The accompanying notes are an integral part of these financial statements.
S-6
CORPUS CHRISTI LIQUEFACTION, LLC
STATEMENTS OF MEMBER'S EQUITY
(in thousands)
|
| | | | | | | |
| Cheniere Corpus Christi Holdings, LLC | | Total Member’s Equity |
Balance at December 31, 2014 | $ | 51,921 |
| | $ | 51,921 |
|
Capital contributions | 3,790,251 |
| | 3,790,251 |
|
Net loss | (22,189 | ) | | (22,189 | ) |
Balance at December 31, 2015 | 3,819,983 |
| | 3,819,983 |
|
Capital contributions | 1,872,933 |
| | 1,872,933 |
|
Net loss | (5,404 | ) | | (5,404 | ) |
Balance at December 31, 2016 | 5,687,512 |
| | 5,687,512 |
|
Capital contributions | 1,516,772 |
| | 1,516,772 |
|
Net loss | (17,325 | ) | | (17,325 | ) |
Balance at December 31, 2017 | $ | 7,186,959 |
| | $ | 7,186,959 |
|
The accompanying notes are an integral part of these financial statements.
S-7
CORPUS CHRISTI LIQUEFACTION, LLC
STATEMENTS OF CASH FLOWS
(in thousands)
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
Cash flows from operating activities | | | | | | |
Net loss | | $ | (17,325 | ) | | $ | (5,404 | ) | | $ | (22,189 | ) |
Adjustments to reconcile net loss to net cash used in operating activities: | | | | | | |
Depreciation and amortization expense | | 810 |
| | 239 |
| | 55 |
|
Total losses on derivatives, net | | 91 |
| | — |
| | — |
|
Impairment expense and loss on disposal of assets | | 5,500 |
| | — |
| | — |
|
Changes in operating assets and liabilities: | | | | | | |
Accounts payable and accrued liabilities | | 58 |
| | 369 |
| | 529 |
|
Due to affiliates | | 1,561 |
| | (241 | ) | | 1,139 |
|
Advances to affiliate | | — |
| | — |
| | (3,122 | ) |
Other, net | | (1,202 | ) | | (580 | ) | | 430 |
|
Other, net—affiliate | | (667 | ) | | 13 |
| | 498 |
|
Net cash used in operating activities | | (11,174 | ) | | (5,604 | ) | | (22,660 | ) |
| | | | | | |
Cash flows from investing activities | | |
| | |
| | |
Property, plant and equipment, net | | (1,530,642 | ) | | (1,822,962 | ) | | (3,753,264 | ) |
Other | | 25,045 |
| | (44,367 | ) | | (14,327 | ) |
Net cash used in investing activities | | (1,505,597 | ) | | (1,867,329 | ) | | (3,767,591 | ) |
| | | | | | |
Cash flows from financing activities | | |
| | |
| | |
Capital contributions | | 1,516,771 |
| | 1,872,933 |
| | 3,790,251 |
|
Net cash provided by financing activities | | 1,516,771 |
| | 1,872,933 |
| | 3,790,251 |
|
| | | | | | |
Net increase (decrease) in cash, cash equivalents and restricted cash | | — |
| | — |
| | — |
|
Cash, cash equivalents and restricted cash—beginning of period | | — |
| | — |
| | — |
|
Cash, cash equivalents and restricted cash—end of period | | $ | — |
| | $ | — |
| | $ | — |
|
Balances per Balance Sheets:
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Cash and cash equivalents | | $ | — |
| | $ | — |
|
Restricted cash | | — |
| | — |
|
Total cash, cash equivalents and restricted cash | | $ | — |
| | $ | — |
|
The accompanying notes are an integral part of these financial statements.
S-8
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
CCL is a Delaware limited liability company formed by Cheniere in 2011 to own, develop and operate a natural gas liquefaction and export facility at the Corpus Christi LNG terminal, which is on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas (the “Liquefaction Facility”). CCP is developing a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline” and together with the Liquefaction Facility, the “Liquefaction Project”) that will interconnect the Liquefaction Facility with several interstate and intrastate natural gas pipelines. The Liquefaction Project is being developed in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage, which is being constructed concurrently with the Corpus Christi Pipeline, includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). Trains 1 and 2 are currently under construction, Train 3 is being commercialized and has all necessary regulatory approvals in place and the Corpus Christi Pipeline is nearing completion.
NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Financial Statements have been prepared in accordance with GAAP.
We have evaluated subsequent events through February 20, 2018, the date the Financial Statements were available to be issued.
Use of Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, derivative instruments, income taxes including valuation allowances for deferred tax assets and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 4—Derivative Instruments. The carrying amount of accounts payable reported on the Balance Sheets approximates fair value.
Cash, Cash Equivalents and Restricted Cash
We did not have any cash and cash equivalents or restricted cash as of December 31, 2017, since our operations are funded through contributions from CCH.
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Accounting for LNG Activities
Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in other operating costs and expenses. Substantially all of our long-lived assets are located in the United States.
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. During the year ended December 31, 2017, we recognized $5.5 million of impairment expense related to damaged infrastructure as an effect of Hurricane Harvey. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2016 or 2015.
Derivative Instruments
Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.
Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. See Note 4—Derivative Instruments for additional details about our derivative instruments.
Concentration of Credit Risk
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.
We have entered into eight fixed price SPAs with terms of at least 20 years with seven unaffiliated third parties. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Income Taxes
We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Statements of Operations, is included in the consolidated federal income tax return of Cheniere. The provision for income taxes, taxes payable and deferred income tax balances have been recorded as if we had filed all tax returns on a separate return basis from Cheniere. Deferred tax assets and liabilities are included in our Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable.
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the tax position.
Business Segment
Our liquefaction business at the Corpus Christi LNG terminal represents a single reportable segment. Our chief operating decision maker reviews the financial results of CCL in total when evaluating financial performance and for purposes of allocating resources.
NOTE 3—PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in thousands):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
LNG terminal costs | | | | |
LNG terminal construction-in-process | | $ | 7,244,447 |
| | $ | 5,628,320 |
|
LNG site and related costs | | 11,662 |
| | 11,662 |
|
Total LNG terminal costs | | 7,256,109 |
| | 5,639,982 |
|
Fixed assets | | | | |
Fixed assets | | 4,261 |
| | 1,234 |
|
Accumulated depreciation | | (932 | ) | | (243 | ) |
Total fixed assets, net | | 3,329 |
| | 991 |
|
Property, plant and equipment, net | | $ | 7,259,438 |
| | $ | 5,640,973 |
|
Depreciation expense during the years ended December 31, 2017, 2016 and 2015 was $0.7 million, $0.2 million and $0.1 million, respectively.
Fixed Assets
Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.
NOTE 4—DERIVATIVE INSTRUMENTS
During the year ended December 31, 2017, we entered into all of our commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). The Liquefaction Supply Derivatives are not designated as cash flow hedging instruments, and changes in fair value are recorded within our Statements of Operations to the extent not utilized for the commissioning process.
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. The fair value of the Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of any associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts. The terms of the physical natural gas supply contracts range from approximately three to seven years, most of which commence upon the satisfaction of certain conditions precedent, if applicable, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.
Our Liquefaction Supply Derivatives are categorized within Level 3 of the fair value hierarchy and are required to be measured at fair value on a recurring basis. The fair value of our Liquefaction Supply Derivatives is determined using a market-based approach incorporating present value techniques, as needed, and is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of the Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. As of December 31, 2017, we have secured up to approximately 2,024 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent. The forward notional natural gas buy position of the Liquefaction Supply Derivatives was approximately 1,019 TBtu as of December 31, 2017.
The Level 3 fair value measurements of our Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Liquefaction Supply Derivatives as of December 31, 2017:
|
| | | | | | | | |
| | Net Fair Value Liability
(in thousands)
| | Valuation Approach | | Significant Unobservable Input | | Significant Unobservable Inputs Range |
Liquefaction Supply Derivatives | | $(91) | | Market approach incorporating present value techniques | | Basis Spread | | $(0.703) - $(0.002) |
Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.
The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in thousands):
|
| | | | | | | | |
| | December 31, |
Balance Sheet Location | | 2017 | | 2016 |
Non-current derivative liabilities | | $ | (91 | ) | | $ | — |
|
The following table shows the changes in the fair value from the mark-to-market losses of our Liquefaction Supply Derivatives recorded in our Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in thousands):
|
| | | | | | | | | | | | | |
| | | Year Ended December 31, |
| Statement of Operations Location | | 2017 | | 2016 | | 2015 |
Liquefaction Supply Derivatives loss | Operating and maintenance expense | | $ | 91 |
| | $ | — |
| | $ | — |
|
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Balance Sheet Presentation
Our derivative instruments are presented on a net basis on our Balance Sheets as described above. The following table shows the fair value of our Liquefaction Supply Derivatives outstanding on a gross and net basis (in thousands):
|
| | | | | | | | | | | | |
| | Gross Amounts Recognized | | Gross Amounts Offset in the Balance Sheets | | Net Amounts Presented in the Balance Sheets |
Offsetting Derivative Assets (Liabilities) | | | |
As of December 31, 2017 | | | | | | |
Liquefaction Supply Derivatives | | $ | (130 | ) | | $ | 39 |
| | $ | (91 | ) |
As of December 31, 2016 | | | | | | |
Liquefaction Supply Derivatives | | — |
| | — |
| | — |
|
NOTE 5—RELATED PARTY TRANSACTIONS
We had $21.7 million and $5.8 million due to affiliates and zero and $0.6 million of other non-current liabilities—affiliate as of December 31, 2017 and 2016, respectively, under agreements with affiliates, as described below.
LNG Sale and Purchase Agreements
We had two fixed price 20-year SPAs with Cheniere Marketing International LLP (“Cheniere Marketing”) as of December 31, 2017. The first SPA (the “Cheniere Marketing Base SPA”) allows Cheniere Marketing to purchase, at its option, (1) up to a cumulative total of 150 TBtu of LNG within the commissioning periods for Trains 1 through 3, (2) any LNG produced from the end of the commissioning period for Train 1 until the date of first commercial delivery of LNG from Train 1 and (3) any excess LNG produced by the Liquefaction Facility that is not committed to customers under third-party SPAs or to Cheniere Marketing under the second SPA (the “Amended Cheniere Marketing Foundation SPA”), as determined by us in each contract year, in each case for a price consisting of a fixed fee of $3.00 per MMBtu of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. Under the Cheniere Marketing Base SPA, Cheniere Marketing may, without charge, elect to suspend deliveries of cargoes (other than commissioning cargoes) scheduled for any month under the applicable annual delivery program by providing specified notice in advance.
Under the Amended Cheniere Marketing Foundation SPA Cheniere Marketing was allowed to purchase LNG from us for a price consisting of a fixed fee of $3.50 per MMBtu (a portion of which is subject to annual adjustment for inflation) of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. The Amended Cheniere Marketing Foundation SPA commencement date, at the option of Cheniere Marketing, was the date of first commercial delivery for Train 2 and included an annual contract quantity of 40 TBtu of LNG. The Amended Cheniere Marketing Foundation SPA was terminated in January 2018.
Services Agreements
We recorded aggregate expenses from affiliates on our Statements of Operations of $3.1 million, $0.6 million and $5.5 million for the years ended December 31, 2017, 2016 and 2015, respectively, under the services agreements below.
Gas and Power Supply Services Agreement (“G&P Agreement”)
We have a G&P Agreement with Cheniere Energy Shared Services, Inc. (“Shared Services”), a wholly owned subsidiary of Cheniere, pursuant to which Shared Services will manage our gas and power procurement requirements. The services include, among other services, exercising the day-to-day management of our natural gas and power supply requirements, negotiating agreements on our behalf and providing other administrative services. Prior to the substantial completion of each Train of the Liquefaction Facility, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facility, for services performed while the Liquefaction Facility is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train.
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Operation and Maintenance Agreement (“O&M Agreement”)
We have an O&M Agreement with Cheniere LNG O&M Services, LLC (“O&M Services”), a wholly owned subsidiary of Cheniere, pursuant to which we receive all of the necessary services required to construct, operate and maintain the Liquefaction Facility. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors, administering various agreements and other services required to operate and maintain the Liquefaction Facility. Prior to the substantial completion of each Train of the Liquefaction Facility, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facility, for services performed while the Liquefaction Facility is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train.
Management Services Agreement (“MSA”)
We have an MSA with Shared Services pursuant to which Shared Services manages the construction and operation of the Liquefaction Facility, excluding those matters provided for under the G&P Agreement and the O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Liquefaction Facility and obtaining insurance. Prior to the substantial completion of each Train of the Liquefaction Facility, no monthly fee payment is required except for reimbursement of expenses. After substantial completion of each Train, we will pay, in addition to the reimbursement of related expenses, a monthly fee equal to 3% of the capital expenditures incurred in the previous month and a fixed monthly fee of $375,000 for services with respect to such Train.
Lease Agreements
We have agreements with Cheniere Land Holdings, LLC (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, to lease approximately 60 acres of land owned by Cheniere Land Holdings for the Liquefaction Facility. The total annual lease payment, paid in advance of the effective date of the respective leases, is $0.4 million, and the terms of the agreements range from three to five years. We recorded $0.3 million, $1.0 million and zero of lease expense related to these agreements as operating and maintenance expense—affiliate for the years ended December 31, 2017, 2016 and 2015, respectively. We had $0.2 million and $0.1 million as of December 31, 2017 and 2016, respectively, of prepaid expense related to this agreement in other current assets—affiliate.
In September 2016, we entered into an agreement with CCP to lease a portion of the Liquefaction Facility site for the purpose of the construction and operation of a meter station to measure the amount of natural gas delivered to the Liquefaction Facility. The annual lease payment is $12,000. The initial term of the lease is 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In conjunction with this lease, we also entered into a pipeline right of way easement agreement with CCP granting CCP the right to construct, install and operate a natural gas pipeline on the Liquefaction Facility site. CCP made a one-time payment of $0.1 million to us for the permanent easement of this land as of December 31, 2016, which was recorded in capital contributions on our Statements of Partners’ Equity.
Dredge Material Disposal Agreement
We have a dredge material disposal agreement with Cheniere Land Holdings that terminates in 2025 which grants us permission to use land owned by Cheniere Land Holdings for the deposit of dredge material from the construction and maintenance of the Liquefaction Facility. Under the terms of the agreement, we will pay Cheniere Land Holdings $0.50 per cubic yard of dredge material deposits up to 5.0 million cubic yards.
Tug Hosting Agreement
In February 2017, we entered into a tug hosting agreement with Corpus Christi Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of Cheniere, to provide certain marine structures, support services and access necessary at the Liquefaction Facility for Tug Services to provide its customers with tug boat and marine services. Tug Services is required to reimburse us for any third party costs incurred by us in connection with providing the goods and services.
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Transportation Precedent Agreement (“TPA”)
We have an amended TPA with CCP for firm gas transportation capacity for up to three Trains on both a forward and back haul basis from the interstate and intrastate pipeline grid to the Liquefaction Facility. Subject to receipt of certain authorizations, under the TPA, CCP agrees to construct and place into service a pipeline, add compression, and provide interconnections to the Liquefaction Facility. We also have a firm transportation service agreement with CCP and a negotiated rate agreement (collectively, the “FTSA”). CCP has agreed to provide us, and we agree to receive from CCP, firm transportation services pursuant to the FTSA.
State Tax Sharing Agreement
We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after May 2015.
CCH Equity Contribution Agreements
CCH is expected to contribute a portion of the contributions received from the equity contribution agreements below, in addition to proceeds received from its debt obligations, to fund a portion of the costs associated with the development, construction, operation and maintenance of the Liquefaction Project.
CCH Equity Contribution Agreement
CCH has an equity contribution agreement with Cheniere (the “CCH Equity Contribution Agreement”) pursuant to which Cheniere has agreed to provide, directly or indirectly, at CCH’s request based on reaching specified milestones of the Liquefaction Project, cash contributions up to approximately $2.6 billion for Stage 1. As of December 31, 2017, CCH had received $1.9 billion in contributions from Cheniere under this agreement.
CCH Early Works Equity Contribution Agreement
In December 2017, CCH entered into an early works equity contribution agreement with Cheniere pursuant to which Cheniere is obligated to provide, directly or indirectly, at CCH’s request based on amounts due and payable in respect of limited notices to proceed issued under the Stage 2 EPC Contract, cash contributions of up to $310.0 million to CCH for the early works related to Stage 2. The amount of cash contributions Cheniere provides may be increased by Cheniere in its sole discretion. As of December 31, 2017, CCH had received $35.0 million in contributions from Cheniere under this agreement.
NOTE 6—INCOME TAXES
The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:
|
| | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
U.S. federal statutory tax rate | | 35.0 | % | | 35.0 | % | | 35.0 | % |
U.S. tax reform rate change | | (100.8 | )% | | — | % | | — | % |
Other | | (0.5 | )% | | (0.1 | )% | | — | % |
Valuation allowance | | 66.3 | % | | (34.9 | )% | | (35.0 | )% |
Effective tax rate | | — | % | | — | % | | — | % |
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Significant components of our deferred tax assets at December 31, 2017 and 2016 are as follows (in thousands):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Deferred tax assets | | | | |
Federal net operating loss carryforward | | $ | 5,788 |
| | $ | 7,721 |
|
Property, plant and equipment | | 20,069 |
| | 29,560 |
|
Other | | 327 |
| | 394 |
|
Less: valuation allowance | | (26,184 | ) | | (37,675 | ) |
Total net deferred tax asset | | $ | — |
| | $ | — |
|
At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of approximately $28 million. These NOL carryforwards will expire between 2033 and 2037.
We did not have any uncertain tax positions which required accrual or disclosure as of December 31, 2017 or 2016. We have elected to report future interest and penalties related to unrecognized tax benefits, if any, as income tax expense in our Statements of Operations.
Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal net deferred tax assets as of December 31, 2017 and 2016. We will continue to evaluate the realizability of our deferred tax assets in the future. The decrease in the valuation allowance was $11.5 million for the year ended December 31, 2017.
On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. The result of the remeasurement was a $17.5 million reduction to our U.S net deferred tax assets and represents a 100.8% decrease to our effective tax rate. A corresponding change, reducing the effective tax rate, was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense.
Our taxable income or loss is included in the consolidated federal income tax return of Cheniere. Cheniere’s federal and state tax returns for the years after 2013 remain open for examination. Tax authorities may have the ability to review and adjust carryover attributes that were generated prior to these periods if utilized in an open tax year.
Cheniere experienced an ownership change within the provisions of U.S. Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysis of the annual limitation on the utilization of Cheniere’s NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of Cheniere’s NOLs in full over the carryover period. Cheniere will continue to monitor trading activity in its respective shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize Cheniere’s existing NOL carryforwards.
NOTE 7—LEASES
During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $1.2 million, $1.0 million and $1.0 million, respectively, related primarily to land sites for the Corpus Christi LNG terminal. We have agreements with Cheniere Land Holdings to lease land owned by Cheniere Land Holdings for the Liquefaction Project. See Note 5—Related Party Transactions for additional information regarding this lease agreement.
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Future annual minimum lease payments, excluding inflationary adjustments and payments to affiliates, for operating leases are as follows (in thousands):
|
| | | |
Years Ending December 31, | Operating Leases |
2018 | $ | 895 |
|
2019 | 841 |
|
2020 | 245 |
|
2021 | — |
|
2022 | — |
|
Thereafter | — |
|
Total | $ | 1,981 |
|
NOTE 8—COMMITMENTS AND CONTINGENCIES
We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2017, are not recognized as liabilities but require disclosures in our Financial Statements.
LNG Terminal Commitments and Contingencies
Obligations under EPC Contracts
We have lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of three Trains and related facilities for the Liquefaction Project. The EPC contract for Stage 2 or the Liquefaction Project was amended and restated in December 31, 2017. The EPC contract prices for Stage 1 of the Liquefaction Project and Stage 2 of the Liquefaction Project are approximately $7.8 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through December 31, 2017. We have the right to terminate each of the EPC contracts for our convenience, in which case Bechtel will be paid the portion of the contract price for the work performed plus costs reasonably incurred by Bechtel on account of such termination and demobilization. If the EPC contract for Stage 1 of the Liquefaction Project is terminated, Bechtel will also be paid a lump sum of up to $30.0 million depending on the termination date. If the amended and restated EPC contract for Stage 2 of the Liquefaction Project is terminated, Bechtel will be paid a lump sum of up to $2.5 million if the termination date is prior to the issuance of the notice to proceed, or Bechtel will be paid a lump sum of up to $30.0 million if the termination date is after the issuance of the notice to proceed, depending on the termination date.
Obligations under SPAs
We have third-party SPAs which obligate us to purchase and liquefy sufficient quantities of natural gas to deliver of contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project. We have also entered into SPAs with Cheniere Marketing, as further described in Note 5—Related Party Transactions.
Services Agreements
State Tax Sharing Agreement
Obligations under Guarantee Contract
The subsidiaries of CCH, including us, have jointly and severally guaranteed the debt obligations of CCH. See Note 11—Guarantees for information regarding these guarantees.
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Other Commitments
In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position and meet the definition of a commitment as of December 31, 2017. Additionally, we have various operating lease commitments, as disclosed in Note 7—Leases.
Legal Proceedings
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2017, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.
NOTE 9—SUPPLEMENTAL CASH FLOW INFORMATION
The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $110.3 million, $59.4 million and $72.9 million, as of December 31, 2017, 2016 and 2015, respectively.
NOTE 10—RECENT ACCOUNTING STANDARDS
The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:
|
| | | | | | |
Standard | | Description | | Expected Date of Adoption | | Effect on our Financial Statements or Other Significant Matters |
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto
| | This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”). | | January 1, 2018 | | We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard.
|
CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
|
| | | | | | |
Standard | | Description | | Expected Date of Adoption | | Effect on our Financial Statements or Other Significant Matters |
ASU 2016-02, Leases (Topic 842)
| | This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients. | | January 1, 2019
| | We continue to evaluate the effect of this standard on our Financial Statements. Preliminarily, we expect that the requirement to recognize all leases on our Balance Sheets will be a significant change from current practice but will not have a material impact upon our Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows, or which, if any, practical expedients we will elect upon transition. |
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
| | This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach. | | January 1, 2018
| | We are currently evaluating the impact of the provisions of this guidance on our Financial Statements and related disclosures. |
NOTE 11—GUARANTEES
The subsidiaries of CCH, including us, have jointly and severally guaranteed the debt obligations of CCH, including: (1) $1.25 billion of the 7.000% Senior Secured Notes due 2024, (2) $1.5 billion of the 5.875% Senior Secured Notes due 2025, (3) $1.5 billion of the 5.125% Senior Secured Notes due 2027, (4) a term loan facility of which CCH had approximately $2.1 billion and $3.6 billion of available commitments and approximately $2.5 billion and $2.4 billion of outstanding borrowings as of December 31, 2017 and 2016, respectively, and (5) a $350.0 million working capital facility of which CCH had $186.4 million and $350.0 million of available commitments as of December 31, 2017 and 2016, respectively, and no outstanding borrowings as of both December 31, 2017 and 2016. CCH entered into the above debt instruments and its use is solely to fund a portion of the costs associated with the development, construction, operation and maintenance of the Liquefaction Project. As of December 31, 2017 and 2016, there was no liability that was recorded related to these guarantees.
Cheniere Corpus Christi Pipeline, L.P.
Financial Statements
As of December 31, 2017 and 2016
and for the years ended December 31, 2017, 2016 and 2015
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
FINANCIAL STATEMENTS
DEFINITIONS
As used in these Financial Statements, the terms listed below have the following meanings:
Common Industry and Other Terms
|
| | |
Bcfe | | billion cubic feet equivalent |
GAAP | | generally accepted accounting principles in the United States |
LNG | | liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state |
MMBtu | | million British thermal units, an energy unit |
mtpa | | million tonnes per annum |
SEC | | U.S. Securities and Exchange Commission |
Train | | an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG |
Abbreviated Legal Entity Structure
The following diagram depicts our abbreviated legal entity structure as of December 31, 2017 and the references to these entities used in these Financial Statements:
Unless the context requires otherwise, references to “CCP,” “the Partnership,” “we,” “us,” and “our” refer to Cheniere Corpus Christi Pipeline, L.P.
Independent Auditors’ Report
To the Managers of Corpus Christi Pipeline GP, LLC and
Partners of Cheniere Corpus Christi Pipeline, L.P.:
We have audited the accompanying financial statements of Cheniere Corpus Christi Pipeline, L.P., which comprise the balance sheets as of December 31, 2017 and 2016, and the related statements of operations, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cheniere Corpus Christi Pipeline, L.P. as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in accordance with U.S. generally accepted accounting principles.
Houston, Texas
February 20, 2018
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
BALANCE SHEETS
(in thousands)
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
ASSETS | | | | |
Current assets | | | | |
Cash and cash equivalents | | $ | — |
| | $ | — |
|
Restricted cash | | — |
| | — |
|
Advances to affiliate | | 20,072 |
| | 17,924 |
|
Other current assets | | 11 |
| | 29 |
|
Total current assets | | 20,083 |
| | 17,953 |
|
| | | | |
Property, plant and equipment, net | | 350,258 |
| | 129,357 |
|
Other non-current assets | | 270 |
| | 3,212 |
|
Total assets | | $ | 370,611 |
| | $ | 150,522 |
|
| | | | |
LIABILITIES AND PARTNERS’ EQUITY | | | | |
Current liabilities | | | | |
Accounts payable | | $ | 1,923 |
| | $ | 7,683 |
|
Accrued liabilities | | 24,785 |
| | 18,396 |
|
Due to affiliates | | 2,048 |
| | 1,214 |
|
Total current liabilities | | 28,756 |
| | 27,293 |
|
| | | | |
Deferred tax liability | | 2,983 |
| | — |
|
| | | | |
Commitments and contingencies (see Note 6) | | | | |
| | | | |
Partners’ equity | | 338,872 |
| | 123,229 |
|
Total liabilities and partners’ equity | | $ | 370,611 |
| | $ | 150,522 |
|
The accompanying notes are an integral part of these financial statements.
S-23
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
STATEMENTS OF OPERATIONS
(in thousands)
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
| | | | | |
Revenues | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | |
Expenses | | | | | |
|
Operating and maintenance expense | 16 |
| | 22 |
| | — |
|
Operating and maintenance expense—affiliate | 82 |
| | 15 |
| | — |
|
General and administrative expense | 234 |
| | 295 |
| | 111 |
|
General and administrative expense—affiliate | 46 |
| | 7 |
| | 13 |
|
Depreciation and amortization expense | 69 |
| | 10 |
| | — |
|
Loss on disposal of assets | 5 |
| | — |
| | — |
|
Total expenses | 452 |
| | 349 |
| | 124 |
|
| | | | | |
Loss from operations | (452 | ) | | (349 | ) | | (124 | ) |
| | | |
| | |
Other income | 15,575 |
| | — |
| | — |
|
| | | | | |
Income (loss) before income taxes | 15,123 |
| | (349 | ) | | (124 | ) |
Income tax provision | (2,983 | ) | | — |
| | — |
|
| | | | | |
Net income (loss) | $ | 12,140 |
| | $ | (349 | ) | | $ | (124 | ) |
The accompanying notes are an integral part of these financial statements.
S-24
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
STATEMENTS OF PARTNERS’ EQUITY
(in thousands)
|
| | | | | | | | | | | | |
| | Corpus Christi Pipeline GP, LLC | | Cheniere Corpus Christi Holdings, LLC | | Total Partners’ Equity |
Balance at December 31, 2014 | | $ | 1 |
| | $ | 6,425 |
| | $ | 6,426 |
|
Capital contributions | | — |
| | 14,596 |
| | 14,596 |
|
Net loss | | — |
| | (124 | ) | | (124 | ) |
Balance at December 31, 2015 | | 1 |
| | 20,897 |
| | 20,898 |
|
Capital contributions | | — |
| | 102,537 |
| | 102,537 |
|
Non-cash capital contribution from affiliate | | — |
| | 143 |
| | 143 |
|
Net loss | | — |
| | (349 | ) | | (349 | ) |
Balance at December 31, 2016 | | 1 |
| | 123,228 |
| | 123,229 |
|
Capital contributions | | — |
| | 203,660 |
| | 203,660 |
|
Distributions | | — |
| | (157 | ) | | (157 | ) |
Net income | | — |
| | 12,140 |
| | 12,140 |
|
Balance at December 31, 2017 | | $ | 1 |
| | $ | 338,871 |
| | $ | 338,872 |
|
The accompanying notes are an integral part of these financial statements.
S-25
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
STATEMENTS OF CASH FLOWS
(in thousands)
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Cash flows from operating activities | | | | | |
Net income (loss) | $ | 12,140 |
| | $ | (349 | ) | | $ | (124 | ) |
Adjustments to reconcile net income (loss) to net cash used in operating activities: | | | | | |
Depreciation and amortization expense | 69 |
| | 10 |
| | — |
|
Allowance for funds used during construction | (15,575 | ) | | — |
| | — |
|
Deferred income taxes | 2,983 |
| | — |
| | — |
|
Loss on disposal of assets | 5 |
| | — |
| | — |
|
Changes in operating assets and liabilities: | | | | | |
Accounts payable and accrued liabilities | 26 |
| | (75 | ) | | 20 |
|
Due to affiliates | 6 |
| | (90 | ) | | (4 | ) |
Advances to affiliate | — |
| | — |
| | (6,951 | ) |
Other, net | (157 | ) | | (12 | ) | | (129 | ) |
Net cash used in operating activities | (503 | ) | | (516 | ) | | (7,188 | ) |
| | | | | |
Cash flows from investing activities | |
| | |
| | |
Property, plant and equipment, net | (203,000 | ) | | (102,021 | ) | | (3,900 | ) |
Other | — |
| | — |
| | (3,508 | ) |
Net cash used in investing activities | (203,000 | ) | | (102,021 | ) | | (7,408 | ) |
| | | | | |
Cash flows from financing activities | |
| | |
| | |
Capital contributions | 203,660 |
| | 102,537 |
| | 14,596 |
|
Distributions | (157 | ) | | — |
| | — |
|
Net cash provided by financing activities | 203,503 |
| | 102,537 |
| | 14,596 |
|
| | | | | |
Net increase (decrease) in cash, cash equivalents and restricted cash | — |
| | — |
| | — |
|
Cash, cash equivalents and restricted cash—beginning of period | — |
| | — |
| | — |
|
Cash, cash equivalents and restricted cash—end of period | $ | — |
| | $ | — |
| | $ | — |
|
Balances per Balance Sheets:
|
| | | | | | | |
| December 31, |
| 2017 | | 2016 |
Cash and cash equivalents | $ | — |
| | $ | — |
|
Restricted cash | — |
| | — |
|
Total cash, cash equivalents and restricted cash | $ | — |
| | $ | — |
|
The accompanying notes are an integral part of these financial statements.
S-26
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
NOTES TO FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
CCP, a Delaware limited partnership, is a Houston based partnership formed by Cheniere. In November 2014, Cheniere contributed CCP to CCP GP as the general partner, and CCH as the limited partner, both of which are wholly owned subsidiaries of Cheniere. CCH was formed in September 2014 by Cheniere to hold its limited partner interest in us and its equity interests in CCL and CCP GP.
We are developing and constructing a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline”) that will interconnect the natural gas liquefaction and export facility at the Corpus Christi LNG terminal being developed by CCL (the “Liquefaction Facility” and together with the Corpus Christi Pipeline, the “Liquefaction Project”) with several interstate and intrastate natural gas pipelines. The Liquefaction Project is being developed in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage, which is being constructed concurrently with the Corpus Christi Pipeline, includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). Trains 1 and 2 are currently under construction, Train 3 is being commercialized and has all necessary regulatory approvals in place and construction of the Corpus Christi Pipeline is nearing completion.
CCL has entered into a transportation precedent agreement and other agreements to secure firm pipeline capacity with us for up to three Trains. Commencement of service under the agreements is conditioned upon the satisfaction or waiver by us of certain conditions precedent, including: (1) our receipt of all required permits, including FERC authorization, (2) our receipt of full notice to proceed from CCL, (3) our receipt of sufficient funding to pay for the costs of the Corpus Christi Pipeline and (4) our construction and placement of the Corpus Christi Pipeline into service.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Financial Statements have been prepared in accordance with GAAP, which for regulated companies, includes specific accounting guidance for regulated operations.
We have evaluated subsequent events through February 20, 2018, the date the Financial Statements were available to be issued.
Use of Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, asset retirement obligations (“AROs”), income taxes including valuation allowances for deferred tax assets and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Cash, Cash Equivalents and Restricted Cash
We did not have any cash and cash equivalents or restricted cash as of December 31, 2017, since our operations are funded through contributions from CCH.
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Accounting for Pipeline Activities
Generally, we begin capitalizing the costs associated with our pipeline once the individual project meets the following criteria: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our pipeline.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as intangible assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in operations. Substantially all of our long-lived assets are located in the United States.
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.
Regulated Natural Gas Pipelines
The Corpus Christi Pipeline is subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Balance Sheets as deferred preliminary survey and investigation costs, other assets and other liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities.
Items that may influence our assessment are:
inability to recover cost increases due to rate caps and rate case moratoriums;
inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;
excess capacity;
increased competition and discounting in the markets we serve; and
impacts of ongoing regulatory initiatives in the natural gas industry.
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Allowance for Funds Used During Construction
Allowance for Funds Used During Construction (“AFUDC”) represents the cost capitalized on debt funds related to the construction of long-lived assets. AFUDC is calculated based on the average cost of debt of CCH, which is contributed to us to fund the construction of the Corpus Christi Pipeline. AFUDC is included in “other income” on our Statements of Operations and was $15.6 million for the year ended December 31, 2017. We did not recognizerecord any incomematerial impairments related to AFUDCproperty, plant and equipment during the years ended December 31, 20162023, 2022 and 2015.2021.
Advances of Cash and Conveyed Assets to Service Providers
We may convey cash or physical assets to service providers in support of infrastructure maintained by them, which is necessary to support our own operations. Such conveyances are recognized within other non-current assets on our Consolidated Balance Sheets and amortized within depreciation and amortization expense on our Consolidated Statements of Operations over the shorter of the contractual term of the arrangement with the service provider or the useful life of the physical asset. The weighted average amortization period of these assets was approximately 35 years as of both December 31, 2023 and 2022.
Interest Capitalization
We capitalize interest costs mainly during the construction period of our LNG terminal and related assets. Upon placing the underlying asset in service, these costs are depreciated over the estimated useful life of the corresponding assets which interest costs were incurred, except for capitalized interest associated with land, which is not depreciated.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement. When we have the contractual right and intent 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. We did not have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2023, 2022 and 2021. See Note 8—Derivative Instruments for additional details about our derivative instruments.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable and contract assets related to our long-term SPAs, as discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash 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 margin deposits on our Consolidated Balance Sheets. 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.
As of December 31, 2023, CCL had SPAs with terms of 10 or more years with a total of 15 third parties and had 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.
Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.
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, printing costs and in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs 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.
We classify debt on our Consolidated Balance Sheets based on contractual maturity, with the following exceptions:
•We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.
•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.
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 isare conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our assessment of AROs is described below.
We have not recorded an ARO associated with the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.
Income Taxes
We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Statements of Operations, is included in the consolidated federal income tax return of Cheniere. The provision for income taxes, taxes payable and deferred income tax balances have been recorded as if we had filed all tax returns on a separate return basis from Cheniere. Deferred tax assets and liabilities are included in our Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. This assessment requires significant judgment and is based upon our assessment of our ability to generate future taxable income among other factors.
Business Segment
Our pipeline business at the Corpus Christi LNG terminal representsWe have determined that we operate as a single operating and reportable segment. Substantially all of our long-lived assets are located in the United States. Our chief operating decision maker reviewsis regularly provided with consolidated financial information to makes resource allocation decisions and assesses performance in the delivery of an integrated source of LNG to our customers. The financial results of CCPmeasures regularly provided to the chief operating decision maker that are most consistent with GAAP are net income (loss) and total consolidated assets, as presented in totalour Consolidated Financial Statements.
Recent Accounting Standards
ASU 2023-07
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280). This guidance requires a public entity, including entities with single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. We plan to adopt this guidance and conform with the applicable disclosures retrospectively when evaluating financial performance andit becomes mandatorily effective for purposes of allocating resources.our annual report for the year ending December 31, 2024.
NOTE 3—CCL STAGE III CONTRIBUTION AND MERGER
In June 2022, Cheniere’s board of directors made a positive FID with respect to the investment in the construction and operation of the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to Bechtel Energy Inc. (“Bechtel”) effective June 16, 2022.In connection with the positive FID, CCL Stage III, through which Cheniere was developing and constructing the Corpus Christi Stage 3 Project, was contributed to us from Cheniere (the “Contribution”) on June 15, 2022.Immediately following the Contribution, CCL Stage III was merged with and into CCL (the “Merger”), the surviving entity of the merger and our wholly owned subsidiary.
The Contribution was accounted for as a common control transaction as the assets and liabilities were transferred between entities under Cheniere’s control. As a result, the net liability transferred to us was recognized as a contribution in our Consolidated Statements of Member’s Equity and at the historical basis of Cheniere on June 15, 2022 in our Consolidated Balance Sheets. The Contribution was presented prospectively as we have concluded that the Contribution did not represent a change in our reporting entity, primarily as we concluded that CCL Stage III did not constitute a business under FASB topic Accounting Standards Codification 805, Business Combinations. The Merger had no impact on our Consolidated Financial Statements as it occurred between our consolidated subsidiaries.
NOTE 4—RESTRICTED CASH AND CASH EQUIVALENTS
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.
As of December 31, 2023 and 2022, we had $175 million and $738 million of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is contractually or legally restricted to the payment of liabilities related to the Liquefaction Project as required under certain debt arrangements. Additionally, as of December 31, 2022, the balance included $498 million related to the cash contributed from Cheniere, which was restricted for the redemption of the
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
remaining outstanding principal balance of the 7.000% Senior Notes due 2024 (the “2024 CCH Senior Notes”) in January 2023.
NOTE 5—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES
Trade and other receivables, net of current expected credit losses, consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2023 | | 2022 |
Trade receivables | | $ | 164 | | | $ | 319 | |
Other receivables | | 16 | | | 29 | |
Total trade and other receivables, net of current expected credit losses | | $ | 180 | | | $ | 348 | |
NOTE 6—INVENTORY
Inventory consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2023 | | 2022 |
Materials | | $ | 97 | | | $ | 92 | |
LNG | | 12 | | | 53 | |
| | | | |
Natural gas | | 13 | | | 31 | |
Other | | 2 | | | 2 | |
Total inventory | | $ | 124 | | | $ | 178 | |
NOTE 7—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION
Property, plant and equipment, net consists of natural gas pipeline costs and fixed assets, as followsaccumulated depreciation consisted of the following (in thousands)millions):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Natural gas pipeline costs | | | | |
Natural gas pipeline construction-in-process | | $ | 346,526 |
| | $ | 125,637 |
|
Land | | 2,182 |
| | 2,344 |
|
Total natural gas pipeline costs | | 348,708 |
| | 127,981 |
|
Fixed assets | | | | |
Fixed assets | | 1,628 |
| | 1,386 |
|
Accumulated depreciation | | (78 | ) | | (10 | ) |
Total fixed assets, net | | 1,550 |
| | 1,376 |
|
Property, plant and equipment, net | | $ | 350,258 |
| | $ | 129,357 |
|
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2023 | | 2022 |
LNG terminal | | | | |
Terminal and interconnecting pipeline facilities | | $ | 13,333 | | | $ | 13,299 | |
Land | | 302 | | | 302 | |
Construction-in-process | | 3,207 | | | 1,486 | |
Accumulated depreciation | | (1,858) | | | (1,421) | |
Total LNG terminal, net of accumulated depreciation | | 14,984 | | | 13,666 | |
Fixed assets | | | | |
Fixed assets | | 30 | | | 26 | |
Accumulated depreciation | | (22) | | | (19) | |
Total fixed assets, net of accumulated depreciation | | 8 | | | 7 | |
Property, plant and equipment, net of accumulated depreciation | | $ | 14,992 | | | $ | 13,673 | |
The following table shows depreciation expense and offsets to LNG terminal costs (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2023 | | 2022 | | 2021 |
Depreciation expense | | | | | | $ | 448 | | | $ | 444 | | | $ | 419 | |
Offsets to LNG terminal costs (1) | | | | | | — | | | — | | | 143 | |
(1)We recognize 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 respective Trains of the Liquefaction Project during the testing phase for its construction.
CHENIERE CORPUS CHRISTI PIPELINE, L.P. HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
LNG Terminal Costs
Depreciation expense during
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 6 and 50 years, ended December 31, 2017, 2016 and 2015 was $68 thousand, $10 thousand and zero, respectively.as follows:
| | | | | | | | |
Components | | Useful life (years) |
LNG storage tanks | | 50 |
Natural gas pipeline facilities | | 40 |
Marine berth, electrical, facility and roads | | 35 |
Water pipelines | | 30 |
Liquefaction processing equipment | | 6-50 |
Other | | 15-30 |
Fixed Assets
Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.
NOTE 4—8—DERIVATIVE INSTRUMENTS
CCL has entered into commodity derivatives consisting of natural gas and power supply contracts, including those under the IPM agreements, for the development, commissioning and operation of the Liquefaction Project and expansion project, as well as the associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).
We recognize CCL’s derivative instruments as either assets or liabilities and measure those instruments at fair value. None of CCL’s derivative instruments are designated as cash flow, fair value or net investment hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process, in which case such changes are capitalized.
The following table shows the fair value of our derivative instruments, which are required to be measured at fair value on a recurring basis, by the fair value hierarchy levels prescribed by GAAP (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements as of |
| December 31, 2023 | | December 31, 2022 |
| Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Liquefaction Supply Derivatives asset (liability) | $ | 7 | | | $ | 35 | | | $ | (502) | | | $ | (460) | | | $ | (54) | | | $ | (19) | | | $ | (6,205) | | | $ | (6,278) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
We value the Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, which incorporates observable commodity price curves, when available, and other relevant data.
We include a significant portion of our 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 may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility includes the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control. Our fair value estimates incorporate market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.
The Level 3 fair value measurements of the natural gas positions within the 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 the Level 3 Liquefaction Supply Derivatives as of December 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net Fair Value Liability (in millions) | | Valuation Approach | | Significant Unobservable Input | | Range of Significant Unobservable Inputs / Weighted Average (1) |
Liquefaction Supply Derivatives | | $(502) | | Market approach incorporating present value techniques | | Henry Hub basis spread | | $(1.090) - $0.505 / $(0.145) |
| | | | Option pricing model | | International LNG pricing spread, relative to Henry Hub (2) | | 87% - 379% / 197% |
(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 the Liquefaction Supply Derivatives.
The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2023 | | 2022 | | 2021 |
Balance, beginning of period | | | | | | $ | (6,205) | | | $ | (1,221) | | | $ | 12 | |
Realized and change in fair value gains (losses) included in net income (loss) (1): | | | | | | | | | | |
Included in cost of sales, existing deals (2) | | | | | | 4,383 | | | (1,492) | | | (1,276) | |
Included in cost of sales, new deals (3) | | | | | | (1) | | | (2,172) | | | — | |
Purchases and settlements: | | | | | | | | | | |
Purchases (4) | | | | | | — | | | (1,938) | | | 9 | |
Settlements (5) | | | | | | 1,321 | | | 618 | | | 34 | |
| | | | | | | | | | |
| | | | | | | | | | |
Transfers out of level 3 (6) | | | | | | — | | | — | | | — | |
Balance, end of period | | | | | | $ | (502) | | | $ | (6,205) | | | $ | (1,221) | |
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period | | | | | | $ | 4,382 | | | $ | (3,664) | | | $ | (1,276) | |
(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.
(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.
(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
period and continuing to exist at the end of the period.
(5)Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.
(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.
All existing counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from those derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes CCL to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when the derivative instruments are in an asset position. Additionally, counterparties are at risk that CCL will be unable to meet its commitments in instances where the derivative instruments are in a liability position. We incorporate both CCL’s nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of the 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.
Liquefaction Supply Derivatives
CCL holds Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of December 31, 2023, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.
The forward notional amount for the Liquefaction Supply Derivatives was approximately 7,774 TBtu and 8,532 TBtu as of December 31, 2023 and 2022, respectively, inclusive of amounts under contracts with unsatisfied contractual conditions, and exclusive of extension options that were uncertain to be taken as of December 31, 2023.
The following table shows the effect and location of the Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations (in millions):
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Gain (Loss) Recognized in Consolidated Statements of Operations |
Consolidated Statements of Operations Location (1) | | | | Year Ended December 31, |
| | | | | 2023 | | 2022 | | 2021 |
LNG revenues | | | | | | $ | (5) | | | $ | 1 | | | $ | 4 | |
Recovery (cost) of sales | | | | | | 5,830 | | | (3,246) | | | (1,244) | |
Cost of sales—related party (2) | | | | | | — | | | — | | | 11 | |
(1)Does not include the realized value associated with Liquefaction Supply Derivatives 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.
(2)Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement during 2021 as discussed in Note 13—Related Party Transactions.
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 the Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | |
| | | | | Fair Value Measurements as of (1) |
| | | | | December 31, 2023 | | December 31, 2022 |
Consolidated Balance Sheets Location | | | | | | | |
Current derivative assets | | | | | $ | 19 | | | $ | 12 | |
| | | | | | | |
Derivative assets | | | | | 823 | | | 7 | |
| | | | | | | |
Total derivative assets | | | | | 842 | | | 19 | |
| | | | | | | |
Current derivative liabilities | | | | | (455) | | | (1,374) | |
Derivative liabilities | | | | | (847) | | | (4,923) | |
Total derivative liabilities | | | | | (1,302) | | | (6,297) | |
| | | | | | | |
Derivative liability, net | | | | | $ | (460) | | | $ | (6,278) | |
(1)Does not include collateral posted with counterparties by CCL of $3 million and $76 million as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets.
Consolidated Balance Sheets Presentation
The following table shows the fair value of the derivatives outstanding on a gross and net basis (in millions) for the derivative instruments that are presented on a net basis on our Consolidated Balance Sheets:
| | | | | | | | | | | | | | |
| | Liquefaction Supply Derivatives |
| | December 31, 2023 | | December 31, 2022 |
Gross assets | | $ | 1,184 | | | $ | 19 | |
Offsetting amounts | | (342) | | | — | |
Net assets | | $ | 842 | | | $ | 19 | |
| | | | |
Gross liabilities | | $ | (1,349) | | | $ | (6,622) | |
Offsetting amounts | | 47 | | | 325 | |
Net liabilities | | $ | (1,302) | | | $ | (6,297) | |
NOTE 9—OTHER NON-CURRENT ASSETS, NET
Other non-current assets, net consisted of the following (in millions):
| | | | | | | | | | | |
| December 31, |
| | | |
| 2023 | | 2022 |
Contract assets, net of current expected credit losses | $ | 184 | | | $ | 142 | |
Advances of cash and conveyed assets to service providers for infrastructure to support LNG terminal, net of accumulated amortization | 34 | | | 62 | |
| | | |
| | | |
| | | |
| | | |
Other | 65 | | | 21 | |
Total other non-current assets, net | $ | 283 | | | $ | 225 | |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 10—ACCRUED LIABILITIES
Accrued liabilities consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2023 | | 2022 |
Natural gas purchases | | $ | 260 | | | $ | 597 | |
Interest costs and related debt fees | | 128 | | | 150 | |
Liquefaction Project costs | | 158 | | | 103 | |
Other accrued liabilities | | 49 | | | 51 | |
Total accrued liabilities | | $ | 595 | | | $ | 901 | |
NOTE 11—DEBT
Debt consisted of the following (in millions):
| | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2023 | | 2022 |
Senior Secured Notes: | | | | |
2024 CCH Senior Notes | | $ | — | | | $ | 498 | |
5.875% due 2025 | | 1,491 | | | 1,491 | |
5.125% due 2027 | | 1,201 | | | 1,271 | |
3.700% due 2029 | | 1,125 | | | 1,361 | |
3.788% weighted average rate due 2039 | | 2,539 | | | 2,633 | |
Total Senior Secured Notes | | 6,356 | | | 7,254 | |
Term loan facility agreement (the “CCH Credit Facility”) | | — | | | — | |
Working capital facility agreement (the “CCH Working Capital Facility”) (1) | | — | | | — | |
Total debt | | 6,356 | | | 7,254 | |
| | | | |
Current debt, net of discount and debt issuance costs | | — | | | (495) | |
| | | | |
Long-term portion of unamortized discount and debt issuance costs, net | | (45) | | | (61) | |
Total long-term debt, net of discount and debt issuance costs | | $ | 6,311 | | | $ | 6,698 | |
(1)The CCH Working Capital Facility is classified as short-term debt as we are required to reduce the aggregate outstanding principal amount to zero for a period of five consecutive business days at least once each year.
Senior Secured Notes
The Senior Secured Notes, are jointly and severally guaranteed by our subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “CCH Guarantor” and collectively, the “CCH Guarantors”). The Senior Secured 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 Senior Secured 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 Senior Secured Notes. The Senior Secured Notes are secured by a first-priority security interest in substantially all of our and the CCH Guarantors’ assets. We may, at any time, redeem all or part of the Senior Secured Notes at specified prices set forth in the respective indentures governing the Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption. The series of Senior Secured Notes due in 2039 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.
Cancellation of Senior Secured Notes Contributed from Cheniere
During the years ended December 31, 2023 and 2022, Cheniere repurchased $400 million and $1,217 million, respectively, of certain series of our Senior Secured Notes, with all of such repurchases immediately contributed to us from Cheniere for no consideration under the equity contribution agreements described in Note 13—Related Party Transactions, and cancelled by us. It was determined that for accounting purposes, Cheniere repurchased the bonds on our behalf as a principal as opposed to as an agent, and thus the debt extinguishment was accounted for as an extinguishment directly with Cheniere.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the year ended December 31, 2023, we recorded a net distribution to Cheniere totaling $2 million from associated operating activities, inclusive of a $4 million distribution to Cheniere associated with write off of associated debt issuance costs and discount, offset by a $2 million contribution from Cheniere associated with interest paid by Cheniere on our behalf that was due at the time of the debt repayment. During the year ended December 31, 2022, we recorded a net contribution from Cheniere totaling $21 million from associated operating activities, inclusive of $30 million of interest due to the extinguishment of debt at the time of repayment offset by our write off of associated debt issuance costs and discount of $9 million.
The total contribution from Cheniere of $398 million and $1,238 million for the years ended December 31, 2023 and 2022, respectively, associated with the aforementioned activity is reflected within our Consolidated Statements of Member’s Equity.
Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2023 (in millions):
| | | | | | | | |
Years Ending December 31, | | Principal Payments |
2024 | | $ | — | |
2025 | | 1,491 | |
2026 | | — | |
2027 | | 1,277 | |
2028 | | 123 | |
Thereafter | | 3,465 | |
Total | | $ | 6,356 | |
Credit Facilities
Below is a summary of our credit facilities outstanding as of December 31, 2023 (in millions):
| | | | | | | | | | | | | | |
| | CCH Credit Facility (1) | | CCH Working Capital Facility (2) |
Total facility size | | $ | 3,260 | | | $ | 1,500 | |
| | | | |
Less: | | | | |
Outstanding balance | | — | | | — | |
| | | | |
Letters of credit issued | | — | | | 155 | |
Available commitment | | $ | 3,260 | | | $ | 1,345 | |
| | | | |
Priority ranking | | Senior secured | | Senior secured |
Interest rate on available balance (3) | | SOFR plus credit spread adjustment of 0.1%, plus margin of 1.5% or base rate plus 0.5% | | SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.5% or base rate plus 0.0% - 0.5% |
| | | | |
Commitment fees on undrawn balance (3) | | 0.525% | | 0.10% - 0.20% |
Maturity date | | (4) | | June 15, 2027 |
(1)Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and our subsidiaries and by a pledge by Cheniere CCH Holdco I, our direct parent company, of its 100% ownership of our limited liability company interests.
(2)Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the CCH Guarantors, as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the Senior Secured Notes and the CCH Credit Facility.
(3)The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.
(4)The CCH Credit Facility matures the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project.
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
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.
As of December 31, 2023, 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, |
| | | | | 2023 | | 2022 | | 2021 |
Total interest cost | | | | | $ | 323 | | | $ | 465 | | | $ | 473 | |
Capitalized interest | | | | | (106) | | | (33) | | | (26) | |
Total interest expense, net of capitalized interest | | | | | $ | 217 | | | $ | 432 | | | $ | 447 | |
Fair Value Disclosures
The following table shows the carrying amount and estimated fair value of our senior notes (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2023 | | December 31, 2022 |
| | Carrying Amount | | Estimated Fair Value (1) | | Carrying Amount | | Estimated Fair Value (1) |
Senior Secured Notes | | $ | 6,356 | | | $ | 5,961 | | | $ | 7,254 | | | $ | 6,752 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
(1)As of both December 31, 2023 and 2022, $1.7 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.
The estimated fair value of our credit facilities approximates the principal amount outstanding 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 12—REVENUES
The following table represents a disaggregation of revenue earned (in millions):
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2023 | | 2022 | | 2021 |
Revenues from contracts with customers | | | | | | | | | | |
LNG revenues | | | | | | $ | 3,850 | | | $ | 6,335 | | | $ | 3,903 | |
LNG revenues—affiliate | | | | | | 1,620 | | | 3,027 | | | 1,887 | |
Total revenues from contracts with customers | | | | | | 5,470 | | | 9,362 | | | 5,790 | |
Net derivative gain (loss) (1) | | | | | | (5) | | | 1 | | | 4 | |
Total revenues | | | | | | $ | 5,465 | | | $ | 9,363 | | | $ | 5,794 | |
LNG Revenues
We have entered into numerous SPAs with third party customers for the sale of LNG on an FOB basis (delivered to the customer at the Corpus Christi LNG Terminal) or a DAT basis (delivered to the customer at their specified LNG receiving terminal). 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 generally equal to 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
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 13—Related Party Transactions for additional information regarding these agreements.
Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer based on the delivery terms described above, 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. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of 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.
When we sell LNG on a DAT basis, we rely on our agreement with our marketing affiliate for all fulfillment costs. We expense fulfillment costs as incurred unless otherwise dictated by GAAP.
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.
Sales of natural gas where, in the delivery of the natural gas to the end customer, we have concluded that we acted as a principal are presented within revenues in our Consolidated Statements of Operations, and where we have concluded that we acted as an agent are netted within cost of sales in our Consolidated Statements of Operations.
Contract Assets and Liabilities
The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2023 | | 2022 |
Contract assets, net of current expected credit losses | | $ | 186 | | | $ | 144 | |
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. The change in contract assets between the years ended December 31, 2023 and 2022 was primarily attributable to additional revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.
The following table reflects the changes in our contract liabilities, which we classify as other current liabilities and other non-current liabilities on our Consolidated Balance Sheets (in millions):
| | | | | | | | | | |
| | |
| | Year Ended December 31, 2023 | | |
Deferred revenue, beginning of period | | $ | 76 | | | |
Cash received but not yet recognized in revenue | | — | | | |
Revenue recognized from prior period deferral | | — | | | |
Deferred revenue, end of period | | $ | 76 | | | |
We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2023 | | December 31, 2022 |
| | Unsatisfied Transaction Price (in billions) | | Weighted Average Recognition Timing (years) (1) | | Unsatisfied Transaction Price (in billions) | | Weighted Average Recognition Timing (years) (1) |
LNG revenues (2) | | $ | 49.5 | | | 10 | | $ | 50.9 | | | 10 |
LNG revenues—affiliate | | 1.0 | | | 9 | | 1.2 | | | 8 |
Total revenues | | $ | 50.5 | | | | | $ | 52.1 | | | |
(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.
(2)We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID 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 and consideration is not otherwise constrained from ultimate pricing and receipt.
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Additionally, we have excluded variable consideration related to volumes that contractually are subject to additional liquefaction capacity beyond what is currently in construction or operation. The following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:
| | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2023 | | 2022 | | |
| LNG revenues | | | | | 49 | % | | 70 | % | | |
| LNG revenues—affiliate | | | | | 80 | % | | 86 | % | | |
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 13—RELATED PARTY TRANSACTIONS
Below is a summary of our related party transactions, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | | | 2023 | | 2022 | | 2021 |
LNG revenues—affiliate | | | | | | | | | |
SPAs and Letter Agreements with Cheniere Marketing, LLC (“Cheniere Marketing”) (1) | | | | | $ | 1,620 | | | $ | 2,993 | | | $ | 1,837 | |
Contracts for Sale and Purchase of Natural Gas and LNG with other affiliates (2) | | | | | — | | | 34 | | | 50 | |
Total LNG revenues—affiliate | | | | | 1,620 | | | 3,027 | | | 1,887 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Cost of sales—affiliate | | | | | | | | | |
Contracts for Sale and Purchase of Natural Gas and LNG (2) | | | | | 55 | | | 103 | | | 19 | |
Cheniere Marketing Agreements (1) (3) | | | | | 116 | | | — | | | 31 | |
Total cost of sales—affiliate | | | | | 171 | | | 103 | | | 50 | |
| | | | | | | | | |
Cost of sales—related party | | | | | | | | | |
Natural Gas Supply Agreement (4) | | | | | — | | | — | | | 146 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Operating and maintenance expense—affiliate | | | | | | | | | |
Services Agreements (5) | | | | | 116 | | | 120 | | | 105 | |
Land Agreements (6) | | | | | — | | | 1 | | | 1 | |
| | | | | | | | | |
Total operating and maintenance expense—affiliate | | | | | 116 | | | 121 | | | 106 | |
| | | | | | | | | |
Operating and maintenance expense—related party | | | | | | | | | |
Natural Gas Transportation Agreements (7) | | | | | 9 | | | 9 | | | 9 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
General and administrative expense—affiliate | | | | | | | | | |
Services Agreements (5) | | | | | 45 | | | 38 | | | 28 | |
(1)CCL primarily sells LNG to Cheniere Marketing International LLP (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for SPAs associated with IPM agreements for which pricing is linked to international natural gas prices. In addition, CCL has 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 the greater of: (a) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price. As of December 31, 2023 and 2022, CCL had $213 million and $223 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing.
(2)CCL has an agreement with Sabine Pass Liquefaction, LLC (“SPL”) that allows the parties 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. As of December 31, 2023 and 2022, CCL had zero and $16 million of accounts receivable—affiliate, respectively, under these agreements with SPL.
(3)CCL and Cheniere Marketing have entered into Shipping Services Agreements (“SSAs”) for the provision of certain shipping and transportation-related services associated with certain SPAs between CCL and third-party customers that are delivered to the customer at their specified LNG receiving terminal. Under the SSAs, CCL pays Cheniere Marketing a fee of 3% to 7% of Henry Hub plus a fixed fee for the shipping services provided. Deliveries under the SSAs commenced in 2023.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(4)CCL was party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. The related party entity was acquired by a non-related party on November 1, 2021, therefore, as of such date, this agreement ceased to be considered a related party agreement. CCL also has an agreement with Midship Pipeline Company, LLC that allows them to sell and purchase natural gas with each other.
(5)We do not have employees and thus our subsidiaries have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements are primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2023 and 2022, we had $116 million and $132 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.
(6)CCL has agreements with Cheniere Land Holdings, LLC, a wholly owned subsidiary of Cheniere, to rent, obtain easements and license to enter the land owned by CLH for the Liquefaction Project.
(7)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. CCL recorded accrued liabilities—related party of $1 million as of both December 31, 2023 and 2022 with this related party.
We had $2.0$49 million and $1.2$43 million due to affiliates as of December 31, 20172023 and 2016,2022, respectively, under agreements with affiliates as described below.above.
Other Agreements
We recorded aggregate expenses from affiliates on our Statements of Operations of $116 thousand, $10 thousand and $13 thousand for the years ended December 31, 2017, 2016 and 2015, respectively, under the services agreements below.
Operation and Maintenance Agreement (“O&M Agreement”)
We have an O&M Agreement with Cheniere LNG O&M Services, LLC (“O&M Services”) pursuant to which we receive all of the necessary services required to construct, operate and maintain the Corpus Christi Pipeline. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors and other services required to operate and maintain the Corpus Christi Pipeline. We are required to reimburse O&M Services for all operating expenses incurred on our behalf.
Management Services Agreement (“MSA”)
We have an MSA with Cheniere Energy Shared Services, Inc. (“Shared Services”) pursuant to which Shared Services manages our operations and business, excluding those matters provided for under the O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Corpus Christi Pipeline and obtaining insurance. We are required to reimburse Shared Services for the aggregate of all costs and expenses incurred in the course of performing the services under the MSA.
Lease Agreements
In September 2016, we entered into an agreement with CCL to lease from them a portion of the Liquefaction Facility site for the purpose of the construction and operation of a meter station to measure the amount of natural gas delivered to the Liquefaction Facility. The annual lease payment, paid in advance upon 30 days of the effective date, is $12 thousand and is recorded as operating and maintenance expense—affiliate. The initial term of the lease is 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In conjunction with this lease, we also entered into a pipeline right of way easement agreement with CCL granting us the right to construct, install and operate a natural gas pipeline on the Liquefaction Facility site. We made a one-time payment of $0.1 million to CCL for the permanent easement of this land as of December 31, 2016, which was recorded as a reduction to capital contributions on our Statements of Partners’ Equity.
In September 2016, we entered into a pipeline right of way easement agreement with Cheniere Land Holdings, LLC (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, which granted us the right to construct, install and operate a natural gas pipeline on land owned by Cheniere Land Holdings. Under this agreement, Cheniere Land Holdings conveyed to us $0.1 million of assets during the year ended December 31, 2016, which was recorded as a non-cash capital contribution from affiliate. We also made a one-time payment of $0.3 million to Cheniere Land Holdings for the permanent easement of this land as of December 31, 2016, which was recorded as a reduction to capital contributions.
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Transportation Precedent Agreement (“TPA”)
We have an amended TPA with CCL for firm gas transportation capacity for up to three Trains on both a forward and back haul basis from the interstate and intrastate pipeline grid to the Liquefaction Facility. Subject to receipt of certain authorizations, under the TPA, we agree to construct and place into service a pipeline, add compression, and provide interconnections to the Liquefaction Facility. We also have a firm transportation service agreement with CCL and a negotiated rate agreement (collectively, the “FTSA”). We agree to provide CCL, and CCL agrees to receive from us, firm transportation services pursuant to the FTSA.
State Tax Sharing AgreementAgreements
We
CCL and CCP each have a state tax sharing agreement with Cheniere. Under this agreement,these agreements, Cheniere has agreed to prepare and file all state and local tax returns which weeach of the entities 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, weeach of the respective entities will pay to Cheniere an amount equal to the state and local tax that weeach of the entities would be required to pay if ourits state and local tax liability were calculated on a separate company basis. ThereTo date, there have been no state and local taxes paidtax payments demanded by Cheniere under the tax sharing agreements. The agreements for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement isboth CCL and CCP were effective for tax returns due on or after May 2015.
CCH Equity Contribution Agreements
CCH is expected to contribute a portion of the contributions received from theWe have equity contribution agreements below, in addition to proceeds received fromwith Cheniere and certain of its debt obligations, to fund a portion of the costs associated with the development, construction, operation and maintenance of the Liquefaction Project.
CCH subsidiaries (the “Equity Contribution Agreement
CCH has an equity contribution agreement with Cheniere (the “CCH Equity Contribution Agreement”Agreements”) pursuant to which Cheniere has agreed to provide, directly or indirectly, at CCH’s request based on reaching specified milestones of the Liquefaction Project, cash contributions up to approximately $2.6 billion for Stage 1. As of December 31, 2017, CCH had received $1.9 billion in contributions from Cheniere under this agreement.
CCH Early Works Equity Contribution Agreement
In December 2017, CCH entered into an early works equity contribution agreement with Cheniere pursuant to which Cheniere is obligated to provide, directly or indirectly, at CCH’s request based on amounts due and payable in respect of limited notices to proceed issued under the Stage 2 EPC Contract, cash contributions of up to $310.0 million to CCH for the early works related to Stage 2. The amount of cash contributions Cheniere provides may be increased by Cheniere in its sole discretion. As of December 31, 2017, CCH had received $35.0 million in contributions from Cheniere under this agreement.
NOTE 5—INCOME TAXES
Income tax provision included in our reported net income (loss) consisted of the following (in thousands):
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
Current: | | | | | | |
Federal | | $ | — |
| | $ | — |
| | $ | — |
|
State | | — |
| | — |
| | — |
|
Total current | | — |
| | — |
| | — |
|
| | | | | | |
Deferred: | | | | | | |
Federal | | 2,983 |
| | — |
| | — |
|
State | | — |
| | — |
| | — |
|
Total deferred | | 2,983 |
| | — |
| | — |
|
Total income tax provision | | $ | 2,983 |
| | $ | — |
| | $ | — |
|
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
NOTES TO FINANCIAL STATEMENTS—CONTINUED
The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:
|
| | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
U.S. federal statutory tax rate | | 35.0 | % | | 35.0 | % | | 35.0 | % |
U.S. tax reform rate change | | (13.2 | )% | | — | % | | — | % |
Other | | — | % | | (0.2 | )% | | (0.1 | )% |
Valuation allowance | | (2.1 | )% | | (34.8 | )% | | (34.9 | )% |
Effective tax rate | | 19.7 | % | | — | % | | — | % |
Significant componentscontribute any of our deferred tax assets and liabilities at December 31, 2017 and 2016 are as follows (in thousands):
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Deferred tax assets | | | | |
Federal net operating loss carryforward | | $ | 4 |
| | $ | — |
|
Property, plant and equipment | | — |
| | 322 |
|
Less: valuation allowance | | — |
| | (322 | ) |
Total net deferred tax assets | | 4 |
| | — |
|
| | | | |
Deferred tax liabilities | | | | |
Property, plant and equipment | | (2,982 | ) | | — |
|
Other | | (5 | ) | | — |
|
Total deferred tax liabilities | | (2,987 | ) | | — |
|
| | | | |
Net deferred tax liabilities | | $ | (2,983 | ) | | $ | — |
|
At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of approximately $17 thousand. This NOL carryforward will expire in 2036.
We did not have any uncertain tax positions which required accrual or disclosure as of December 31, 2017 or 2016. We have electedSenior Secured Notes that Cheniere has repurchased to report future interest and penalties related to unrecognized tax benefits, if any, as income tax expense in our Statements of Operations.
We moved from a deferred tax asset of $322 thousand in 2016 to a net deferred tax liability of $3.0 million in 2017. Because we are in a net deferred tax liability position a valuation allowance isus for no longer required. The decrease inconsideration. During the valuation allowance was $322 thousand for the yearyears ended December 31, 2017.2023 and 2022, Cheniere repurchased a total of $400 million and $1,217 million, respectively, of certain series of our Senior Secured Notes, which were immediately contributed under the Equity Contribution Agreements to us from Cheniere and cancelled by us.
On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. The result of the remeasurement was a $2.0 million reduction to our U.S. net deferred tax liabilities and represents a 13.2% decrease to our effective tax rate.
Our taxable income or loss is included in the consolidated federal income tax return of Cheniere. Cheniere’s federal and state tax returns for the years after 2013 remain open for examination. Tax authorities may have the ability to review and adjust carryover attributes that were generated prior to these periods if utilized in an open tax year.
Cheniere experienced an ownership change within the provisions of U.S. Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysis of the annual limitation on the utilization of Cheniere’s NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of Cheniere’s NOLs in full over the carryover period. Cheniere will continue to monitor trading activity in its respective shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize Cheniere’s existing NOL carryforwards.
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 6—14—COMMITMENTS AND CONTINGENCIES
Commitments
We have various contractualfuture commitments under executed contracts that include unconditional purchase obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain commitments and other executed contractscommitments which do not meet the definition of a liability as of December 31, 2017,2023 and thus are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.
ServicesCHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
EPC Contract
CCL has a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of the Corpus Christi Stage 3 Project. The total contract price of the EPC contract is approximately $5.7 billion, inclusive of amounts incurred under change orders through December 31, 2023. As of December 31, 2023, we had approximately $2.9 billion remaining obligations under this contract.
Natural Gas Supply, Transportation and Storage Service Agreements
We haveCCL has physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2023, the remaining fixed terms of these contracts ranged up to 15 years, with renewal options for certain services agreements with affiliates. See Note 4—Related Party Transactions for information regarding such agreements.contracts and some of which commence upon the satisfaction of certain events or states of affairs.State Tax Sharing Agreement
Obligations under Guarantee Contract
The subsidiaries of CCH, including us, have jointlyAdditionally, CCL has natural gas transportation and severally guaranteed the debt obligations of CCH. See Note 9—Guarantees for information regarding these guarantees.
Other Commitments
In the ordinary course of business, we have entered into certain multi-year licensing andstorage service agreements nonefor the Liquefaction Project. The initial fixed terms of the natural gas transportation agreements range up 20 years, with renewal options for certain contracts and some of which commence upon the satisfaction of certain events or states of affairs. The initial fixed term of the natural gas storage service agreements ranges up to five years.
As of December 31, 2023, CCL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which contractual conditions were met or are considered materialcurrently expected to our financial positionbe met were as follows (in billions):
| | | | | | | | | | | |
Years Ending December 31, | Payments Due to Third Parties (1) | | Payments Due to Related Party (1) |
2024 | $ | 2.4 | | | $ | — | |
2025 | 2.9 | | | — | |
2026 | 3.0 | | | 0.1 | |
2027 | 2.9 | | | 0.1 | |
2028 | 2.1 | | | 0.1 | |
Thereafter | 22.3 | | | 0.7 | |
Total | $ | 35.6 | | | $ | 1.0 | |
(1)Pricing of natural gas supply agreements is based on estimated forward prices and meet the definition of a commitmentbasis spreads as of December 31, 2017. Additionally, we2023. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Global gas market prices are based on estimates as of December 31, 2023 to the extent forward prices are not available and assume the highest price in cases of price optionality available under the agreement.Some of our contracts may not have operating leasebeen negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.
Services Agreements
CCL and CCP have certain fixed commitments under services agreements, SSAs and other agreements of $0.3 billion with affiliates, as disclosed in third parties and $7.6 billion with affiliates. See Note 4—13—Related Party Transactions. for additional information regarding such agreements.
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. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
the opinion of management, as of December 31, 2017,2023, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.
NOTE 7—15—CUSTOMER CONCENTRATION
The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Percentage of Total Revenues from External Customers | | Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers |
| | | | Year Ended December 31, | | December 31, |
| | | | | | | | | | |
| | | | | | 2023 | | 2022 | | 2021 | | 2023 | | 2022 |
Customer A | | | | | | 22% | | 21% | | 21% | | 13% | | 17% |
Customer B | | | | | | 15% | | 14% | | 16% | | * | | * |
Customer C | | | | | | 14% | | 14% | | 15% | | * | | * |
Customer D | | | | | | * | | * | | * | | 48% | | 33% |
Customer E | | | | | | * | | 10% | | * | | * | | * |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
* Less than 10%
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, |
| 2023 | | 2022 | | 2021 |
Spain | $ | 1,355 | | | $ | 2,192 | | | $ | 1,432 | |
Singapore | 590 | | | 1,248 | | | 694 | |
Indonesia | 558 | | | 889 | | | 618 | |
France | 543 | | | 940 | | | 423 | |
Ireland | 538 | | | 868 | | | 599 | |
China | 180 | | | — | | | — | |
United States | 81 | | | 199 | | | 141 | |
Total | $ | 3,845 | | | $ | 6,336 | | | $ | 3,907 | |
NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in thousands)millions):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
Cash paid during the period for interest on debt, net of amounts capitalized | $ | 223 | | | $ | 280 | | | $ | 423 | |
Right-of-use assets obtained in exchange for new operating lease liabilities | 1 | | | 3 | | | — | |
Non-cash investing and financing activity: | | | | | |
Unpaid purchases of property, plant and equipment, net and other non-current assets, net | 148 | | | 78 | | | 38 | |
Conveyance of property, plant and equipment in exchange for other non-current assets | — | | | 17 | | | — | |
Equity contribution of property, plant and equipment from affiliate | — | | | 7 | | | — | |
| | | | | |
Cancellation of Senior Secured Notes contributed to us from Cheniere (see Note 11 ) | 400 | | | 1,217 | | | — | |
| | | | | |
|
| | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Non-cash capital contribution for conveyance of asset from affiliate | — |
| | 143 |
| | — |
|
The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $28.5 million, $27.1 million and $7.1 million, as of December 31, 2017, 2016 and 2015, respectively.
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 8—RECENT ACCOUNTING STANDARDS
The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:
|
| | | | | | |
Standard | | Description | | Expected Date of Adoption | | Effect on our Financial Statements or Other Significant Matters |
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto
| | This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”). | | January 1, 2018 | | We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard.
|
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto
| | This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients. | | January 1, 2019
| | We continue to evaluate the effect of this standard on our Financial Statements. Preliminarily, we do not anticipate a material impact from the requirement to recognize all leases upon our Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition. |
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
| | This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach. | | January 1, 2018
| | We are currently evaluating the impact of the provisions of this guidance on our Financial Statements and related disclosures. |
CHENIERE CORPUS CHRISTI PIPELINE, L.P.
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 9—GUARANTEES
The subsidiaries of CCH, including us, have jointly and severally guaranteed the debt obligations of CCH, including: (1) $1.25 billion of the 7.000% Senior Secured Notes due 2024, (2)We recorded $1.5 billion of the 5.875% Senior Secured Notes due 2025, (3) $1.5 billion of the 5.125% Senior Secured Notes due 2027, (4) a term loan facility of which CCH had approximately $2.1 billion and $3.6 billion of available commitments and approximately $2.5 billion and $2.4 billion of outstanding borrowings as of December 31, 2017 and 2016, respectively, and (5) a $350.0 million working capital facility of which CCH had $186.4 million and $350.0 million of available commitments as of December 31, 2017 and 2016, respectively, and no outstanding borrowings as of both December 31, 2017 and 2016. CCH entered into the above debt instruments and its use is solely to fund a portion of the costs associated with the development, construction, operation and maintenance of the Liquefaction Project. As of December 31, 2017 and 2016, there was no liability that was recorded related to these guarantees.
Corpus Christi Pipeline GP, LLC
Financial Statements
As of December 31, 2017 and 2016
and for the years ended December 31, 2017, 2016 and 2015
CORPUS CHRISTI PIPELINE GP, LLC
FINANCIAL STATEMENTS
DEFINITIONS
As usedcontributions in these Financial Statements, the terms listed below have the following meanings:
Common Industry and Other Terms
|
| | |
Bcfe | | billion cubic feet equivalent |
GAAP | | generally accepted accounting principles in the United States |
LNG | | liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state |
mtpa | | million tonnes per annum |
SEC | | U.S. Securities and Exchange Commission |
Train | | an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG |
Abbreviated Legal Entity Structure
The following diagram depicts our abbreviated legal entity structure as of December 31, 2017 and the references to these entities used in these Financial Statements:
Unless the context requires otherwise, references to “CCP GP,” “the Company,” “we,” “us,” and “our” refer to Corpus Christi Pipeline GP, LLC.
Independent Auditors’ Report
To the Member
Corpus Christi Pipeline GP, LLC:
We have audited the accompanying financial statements of Corpus Christi Pipeline GP, LLC, which comprise the balance sheets as of December 31, 2017 and 2016, and the related statements of operations, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Corpus Christi Pipeline GP, LLC as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in accordance with U.S. generally accepted accounting principles.
Houston, Texas
February 20, 2018
CORPUS CHRISTI PIPELINE GP, LLC
BALANCE SHEETS
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | | | |
ASSETS | | | | |
Cash and cash equivalents | | $ | — |
| | $ | — |
|
Restricted cash | | — |
| | — |
|
Receivable—affiliate | | 1,000 |
| | 1,000 |
|
Total assets | | $ | 1,000 |
| | $ | 1,000 |
|
| | | | |
LIABILITIES AND MEMBER’S EQUITY | | | | |
Liabilities | | $ | — |
| | $ | — |
|
| | | | |
Member’s equity | | 1,000 |
| | 1,000 |
|
| | | | |
Total liabilities and member’s equity | | $ | 1,000 |
| | $ | 1,000 |
|
The accompanying notes are an integral part of these financial statements.
S-39
CORPUS CHRISTI PIPELINE GP, LLC
STATEMENTS OF OPERATIONS
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
Revenues | | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | |
General and administrative expense | | 5,585 |
| | 5,300 |
| | 1,207 |
|
| | | | | | |
Net loss | | $ | (5,585 | ) | | $ | (5,300 | ) | | $ | (1,207 | ) |
The accompanying notes are an integral part of these financial statements.
S-40
CORPUS CHRISTI PIPELINE GP, LLC
STATEMENTS OF MEMBER'S EQUITY
|
| | | | | | | | |
| | Cheniere Corpus Christi Holdings, LLC | | Total Member’s Equity |
Balance at December 31, 2014 | | $ | 1,000 |
| | $ | 1,000 |
|
Capital contributions | | 1,207 |
| | 1,207 |
|
Net loss | | (1,207 | ) | | (1,207 | ) |
Balance at December 31, 2015 | | 1,000 |
| | 1,000 |
|
Capital contributions | | 5,300 |
| | 5,300 |
|
Net loss | | (5,300 | ) | | (5,300 | ) |
Balance at December 31, 2016 | | 1,000 |
| | 1,000 |
|
Capital contributions | | 5,585 |
| | 5,585 |
|
Net loss | | (5,585 | ) | | (5,585 | ) |
Balance at December 31, 2017 | | $ | 1,000 |
| | $ | 1,000 |
|
The accompanying notes are an integral part of these financial statements.
S-41
CORPUS CHRISTI PIPELINE GP, LLC
STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
Cash flows from operating activities | | | | | | |
Net loss | | $ | (5,585 | ) | | $ | (5,300 | ) | | $ | (1,207 | ) |
| | | | | | |
Cash flows from investing activities | | — |
| | — |
| | — |
|
| | | | | | |
Cash flows from financing activities | | | | | | |
Capital contributions | | 5,585 |
| | 5,300 |
| | 1,207 |
|
| | | | | | |
Net increase (decrease) in cash, cash equivalents and restricted cash | | — |
| | — |
| | — |
|
Cash, cash equivalents and restricted cash—beginning of period | | — |
| | — |
| | — |
|
Cash, cash equivalents and restricted cash—end of period | | $ | — |
| | $ | — |
| | $ | — |
|
Balances per Balance Sheets:
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Cash and cash equivalents | | $ | — |
| | $ | — |
|
Restricted cash | | — |
| | — |
|
Total cash, cash equivalents and restricted cash | | $ | — |
| | $ | — |
|
The accompanying notes are an integral part of these financial statements.
S-42
CORPUS CHRISTI PIPELINE GP, LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF BUSINESS
CCP GP is a Houston-based Delaware limited liability company formed on September 11, 2014 by CCH, which is a wholly owned subsidiary of Cheniere (NYSE American: LNG). Cheniere contributed CCP to us on November 7, 2014. CCP is developing and constructing a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline”) that will interconnect the natural gas liquefaction and export facility at the Corpus Christi LNG terminal (the “Liquefaction Facility” and together with the Corpus Christi Pipeline, the “Liquefaction Project”) with several interstate and intrastate natural gas pipelines. The Liquefaction Project is being developed by CCL in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage (“Stage 1”) is in construction and includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, one LNG storage tank and the completion of the second partial berth. Trains 1 and 2 are currently under construction, Train 3 is being commercialized and has all necessary regulatory approvals in place and construction of the Corpus Christi Pipeline is nearing completion.
Our only business consists of owning and holding CCP’s general partner interest. As the sole general partner, we have complete responsibility and discretion in the day-to-day management of CCP. Since we control but have only a non-economic interest in CCP, we have determined that CCP is a variable interest entity. As we are not the primary beneficiary of CCP, we do not consolidate CCP into our Financial Statements. We have no indebtedness, although we do guarantee certain debt of our immediate parent, CCH, and we do not have any publicly traded equity.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Financial Statements have been prepared in accordance with GAAP. We have evaluated subsequent events through February 20, 2018, the date the Financial Statements were available to be issued.
Use of Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the collectability of accounts receivable and income taxes including valuation allowances for deferred tax assets. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Cash, Cash Equivalents and Restricted Cash
We did not have any cash and cash equivalents or restricted cash as of December 31, 2017, since our operations are funded through contributions from CCH.
Income Taxes
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 ourConsolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. The provision for income taxes, taxes payable and deferred income tax balances have been recorded as if we had filed all tax returns on a separate return basis from Cheniere. Deferred tax assets and liabilities are included in our Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable.
CORPUS CHRISTI PIPELINE GP, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the tax position.
NOTE 3—INCOME TAXES
The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:
|
| | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
U.S. federal statutory tax rate | | 35.0 | % | | 35.0 | % | | 35.0 | % |
U.S. tax reform rate change | | (30.3 | )% | | — | % | | — | % |
Valuation allowance | | (4.7 | )% | | (35.0 | )% | | (35.0 | )% |
Effective tax rate | | — | % | | — | % | | — | % |
Significant components of our deferred tax assets and liabilities at December 31, 2017 and 2016 are as follows:
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Deferred tax assets | | | | |
Federal net operating loss carryforward | | $ | 2,539 |
| | $ | 2,277 |
|
Less: valuation allowance | | (2,539 | ) | | (2,277 | ) |
Total net deferred tax asset | | $ | — |
| | $ | — |
|
At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of approximately $12,000. These NOL carryforwards will expire between 2035 and 2037.
We did not have any uncertain tax positions which required accrual or disclosure as of December 31, 2017 or 2016. We have elected to report future interest and penalties related to unrecognized tax benefits, if any, as income tax expense in our Statements of Operations.
Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal net deferred tax assets as of December 31, 2017 and 2016. We will continue to evaluate the realizability of our deferred tax assets in the future. The increase in the valuation allowance was $262 forMember’s Equity during the year ended December 31,
2017.2022 related to the contribution of the CCL Stage III entity to us from Cheniere on June 15, 2022, with such contribution representing a non-cash financing activity. See Note 3—CCL Stage III Contribution and Merger for further discussion.On
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 22, 2017,31, 2023, 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 U.S. government enacted comprehensiveExchange 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.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
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
Our independent registered public accounting firm is KPMG LLP, Houston, Texas, Auditor Firm ID 185. The following table sets forth the fees billed by KPMG LLP for professional services rendered for 2023 and 2022 (in millions):
| | | | | | | | | | | | | | |
| | Fiscal 2023 | | Fiscal 2022 |
Audit Fees | | $ | 1 | | | $ | 1 | |
| | | | |
| | | | |
Audit Fees—Audit fees for 2023 and 2022 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 2023 and 2022.
Tax Fees—There were no tax legislation (Tax Cutsfees in 2023 and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%.2022.
Other Fees—There were no other fees in 2023 and 2022.
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 legislation, we remeasured ourindependent accountants and the fees for such services during the fiscal years ended December 31, 2017 U.S. deferred tax assets2023 and liabilities. The result2022.
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 remeasurement was a $1,700 reduction to our U.S. net deferred tax assets and represents a 30.3% decrease to our effective tax rate. This remeasurement is fully offset by a corresponding change to our valuation allowance, and therefore there was no impact to current period income tax expense.
Our taxable income or loss isrequired information has been included in the consolidated federal income tax returnfinancial statements and accompanying notes included in this Form 10-K.
(3) Exhibits:
Certain of Cheniere. Cheniere’s federalthe agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and state tax returnsconditions by the parties to the agreements that have been made solely for the years after 2013 remain open for examination. Tax authorities 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 the ability to review and adjust carryover attributesbeen qualified by disclosures that were generated priormade to these periods if utilizedthe other parties in an open tax year.
Cheniere experienced an ownership change withinconnection with the provisions of U.S. Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysisnegotiation of the annual limitationagreements, 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 | | Indenture, dated as of May 18, 2016, among the Company, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee | | Cheniere | | 8-K | | 4.1 | | 5/18/2016 |
4.2 | | First Supplemental Indenture, dated as of December 9, 2016, among the Company, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee | | Cheniere | | 8-K | | 4.1 | | 12/9/2016 |
4.3 | | | | Cheniere | | 8-K | | 4.1 | | 12/9/2016 |
4.4 | | Second Supplemental Indenture, dated as of May 19, 2017, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as trustee | | CCH | | 8-K | | 4.1 | | 5/19/2017 |
4.5 | | | | CCH | | 8-K | | 4.1 | | 5/19/2017 |
4.6 | | Third Supplemental Indenture, dated September 6, 2019, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee | | CCH | | 8-K | | 4.1 | | 9/12/2019 |
4.7 | | Indenture, dated as of September 27, 2019, among the Company, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and the Bank of New York Mellon, as trustee | | CCH | | 8-K | | 4.1 | | 9/30/2019 |
4.8 | | | | CCH | | 8-K | | 4.1 | | 9/30/2019 |
4.9 | | Indenture, dated as of October 17, 2019, among the Company, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee | | CCH | | 8-K | | 4.1 | | 10/18/2019 |
4.10 | | | | CCH | | 8-K | | 4.1 | | 10/18/2019 |
4.11 | | Fourth Supplemental Indenture, dated as of November 13, 2019, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee | | CCH | | 8-K | | 4.1 | | 11/13/2019 |
4.12 | | | | CCH | | 8-K | | 4.1 | | 11/13/2019 |
4.13 | | Fifth Supplemental Indenture, dated as of August 24, 2021, among the Company, as issuer, CCL, CCP, and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee | | CCH | | 8-K | | 4.1 | | 8/24/2021 |
4.14 | | | | CCH | | 8-K | | 4.1 | | 8/24/2021 |
4.15 | | Indenture, dated as of August 20, 2020, among the Company, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee | | CCH | | 8-K | | 4.1 | | 8/21/2020 |
4.16 | | | | CCH | | 8-K | | 4.1 | | 8/21/2020 |
10.1 | | | | CCH | | 8-K | | 10.1 | | 6/22/2022 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | | Form | | Exhibit | | Filing Date |
10.2 | | Second Amended and Restated Common Terms Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, 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 | | 10.3 | | 6/22/2022 |
10.3 | | Second Amended and Restated Common Security and Account Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, the Senior Creditor Group Representatives, Société Générale as the Intercreditor Agent, Société Générale as Security Trustee and Mizuho Bank, Ltd as the Account Bank | | CCH | | 8-K | | 10.4 | | 6/22/2022 |
10.4 | | | | CCH | | 8-K | | 10.4 | | 5/24/2018 |
10.5 | | | | CCH | | 8-K | | 10.5 | | 5/24/2018 |
10.6 | | Second Amended and Restated Working Capital Facility Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, the lenders party thereto from time to time, the issuing banks party thereto from time to time, the swing line lenders 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 | | 10.2 | | 6/22/2022 |
10.7 | | | | CEI | | 10-Q | | 10.1 | | 5/4/2022 |
10.8 | | Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL Stage III and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Maintaining Elevated Ground Flare Option, dated March 28, 2022, (ii) the Change Order CO-00002 Package 7 Pre-Investment of Trains 8 and 9 (Without Site Work), dated April 29, 2022 and (iii) the Change Order CO-00003 Modifications to Insurance Language, dated June 13, 2022 (Portions of this exhibit have been omitted.) | | CCH | | 10-Q | | 10.6 | | 8/4/2022 |
10.9 | | Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00004 Currency Conversion, dated June 27, 2022, (ii) the Change Order CO-00005 Fuel Adjustment, dated July 15, 2022, (iii) the Change Order CO-00006 Removal of Laydown Yard Scope Option, dated August 2, 2022, (iv) the Change Order CO-00007 Removal of Air Bridges Scope Option, dated August 22, 2022, (v) the Change Order CO-00008 Acid Gas Flare K/O Drum, dated August 16, 2022, and (vi) the Change Order CO-00009 Package 7A (Without Site Work), dated August 16, 2022 (Portions of this exhibit have been omitted.) | | CCH | | 10-Q | | 10.1 | | 11/3/2022 |
10.10 | | | | CCH | | 10-K | | 10.10 | | 2/23/2023 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | | Form | | Exhibit | | Filing Date |
10.11 | | Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction Stage III, LLC and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00012 Chart License Fee Provisional Sum Closure, dated September 16, 2022, (ii) the Change Order CO-00013 HRU Nozzles and Block Headers, dated September 21, 2022, (iii) the Change Order CO-00014 Addition of Nitrogen Receiver, dated December 13, 2022, (iv) the Change Order CO-00015 Package 6 Feed Gas Pipeline Interfaces, dated December 14, 2022, (v) the Change Order CO-00016 Old Sherwin Building Security, dated November 23, 2022, (vi) the Change Order CO-00017 Remote Monitoring Diagnostic for Mixed Refrigerant (MR) Compressors, dated December 14, 2022, (vii) the Change Order CO-00018 EFG Package #1, dated January 9, 2023, (viii) the Change Order CO-00019 Q3 2022 Commodity Price Rise and Fall (ATT MM), dated January 17, 2023, (ix) the Change Order CO-00020 ICSS Vendor Selection and EPC Warranty (Yokogawa), dated September 21, 2022 and (x) the Change Order CO-00021 Laydown Development Package, dated February 6, 2023 (Portions of this exhibit have been omitted.) | | CCH | | 10-Q | | 10.1 | | 5/2/2023 |
10.12 | | Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction, LLC and Bechtel Energy, Inc.: (i) the Change Order CO-00022 Refrigerant Storage Packages 1 and 2, dated February 13, 2023, (ii) the Change Order CO-00023 EFG Package #2, dated February 21, 2023, (iii) the Change Order CO-00024 Defrost Improvements (Cold Box), dated February 23, 2023, (iv) the Change Order CO-00025 Miscellaneous Design Improvements, dated February 23, 2023, (v) the Change Order CO-00026 EFG Package #3, dated February 23, 2023, (vi) the Change Order CO-00027 Addition of 86 Lockout Relay on Transformers, dated February 14, 2023, (vii) the Change Order CO-00028 Additional Duct Banks, dated September 15, 2022, (viii) the Change Order CO-00029 2022 FERC Support Hours Interim Adjustment, dated March 13, 2023, (ix) the Change Order CO-00030 Drainage Blanket (A Street), dated April 6, 2023, (x) the Change Order CO-00031 Refrigerant Storage Interface Package #3, dated April 7, 2023, (xi) the Change Order CO-00032 Q4 2022 Commodity Price Rise and Fall (ATT MM), dated April 24, 2023, (xii) the Change Order CO-00033 Lift Owner-Provided Dewar System (Nitrogen Receiver Facility), dated March 1, 2022, (xiii) the Change Order CO-00034 HAZOP Package #1 - Addition of Flame Arrestors for Oil Mist Eliminator Vent, dated April 25, 2023 and (xiv) the Change Order CO-00035 EFG Package #4 (Water Pipeline Pipe Bridge), dated May 19, 2023 (Portions of this exhibit have been omitted.) | | CCH | | 10-Q | | 10.1 | | 8/3/2023 |
10.13 | | Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00036 Payment Milestone Updates (Schedule C-1), dated June 19, 2023, (ii) the Change Order CO-00037 Geotechnical Soils Investigation Period & Security Division of Responsibility Change, dated June 20, 2023, (iii) the Change Order CO-00038 Power Monitoring System (ETAP HMI), dated June 29, 2023 and (iv) the Change Order CO-00039 EFG Firewater Connection, dated June 30, 2023 (Portions of this exhibit have been omitted.) | | CCH | | 10-Q | | 10.1 | | 11/2/2023 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | | Form | | Exhibit | | Filing Date |
10.14* | | Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00040 Q1 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (ii) the Change Order CO-00041 Q2 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (iii) the Change Order CO-00042 HAZOP Package #2 – Additional IPL (Pressure Transmitter Across the Strainer), dated July 5, 2023, (iv) the Change Order CO-00043 Total Condensate Flowmeter on Three (3) Inch Condensate Line, dated August 31, 2023, (v) the Change Order CO-00044 FERC Package #1 ISA 84 (Accommodation for Two Hundred and Fifty (250) Fire and Gas Detectors), dated August 31, 2023, (vi) the Change Order CO-00045 Increase LNG Rundown Line Check Valve Bypass Size to Six (6) Inches, dated August 31, 2023, (vii) the Change Order CO-00046 Add Manual Bypass Valves Around 31XV-13071, dated September 13, 2023, (viii) the Change Order CO-00047 Relocate Existing 16” Process Water Line and Provide Tie-In, dated September 8, 2023, (ix) the Change Order CO-00048 Future HRU Bypass Tie-In and Thermowell Updates, dated September 12, 2023, (x) the Change Order CO-00049 Butterfly Valves for Flare Drums, dated September 5, 2023, (xi) the Change Order CO-00050 Condensate Shroud on Condensate Rundown Line (Blue Engineering Report), dated September 12, 2023, (xii) the Change Order CO-00051 EFG Package #5 (138KV Feeder Cable), dated September 8, 2023, (xiii) the Change Order CO-00052 Defect Correction Period for Cementitious Fireproofing, dated August 7, 2023, (xiv) the Change Order CO-00053 Chart Transition Joint Spares, dated October 5, 2023, (xv) the Change Order CO-00054 CCL Tank(s) “A” and “C” Tie-In Study & Long Lead Item Purchases, dated September 19, 2023, (xvi) the Change Order CO-00055 FERC Package #2 Firewater Layout, dated September 13, 2023, (xvii) the Change Order CO-00056 HAZOP Package #3 – Stainless Steel C And D Pass Piping / Two Temperature Transmitters per Train, dated February 14, 2023, (xviii) the Change Order CO-00057 HAZOP Package #4 (“Phase Two Items”), dated October 10, 2023, (xix) the Change Order CO-00058 E-HAZOP Package #1 (“LV MCC Ride Through”), dated September 8, 2023, (xx) the Change Order CO-00059 Level Transmitter on Stand Pipe Inside Liquefaction Cold Boxes, dated October 13, 2023, (xxi) the Change Order CO-00060 Small Spill Containment (Additional Curbs), dated July 5, 2023, (xxii) the Change Order CO-00061 Remote Input/Output (RIO) Junction Box Grounding, dated October 10, 2023, (xxiii) the Change Order CO-00062 Geomembrane Liner and Geocell for Laydown 6 Channel, dated August 31, 2023, (xxiv) the Change Order CO-00063 Phased Surfacing of Permanent Plant Roads, dated August 7, 2023, (xxv) the Change Order CO-00064 Provisional Sum Interim Adjustment - Schedule KK-1 12-Month COVID Countermeasures, dated July 24, 2023, (xxvi) the Change Order CO-00065 Modification to FTZ Zone Site (Exhibit A of Attachment LL), dated August 3, 2023, (xxvii) the Change Order CO-00066 Attachment B (Contract Deliverables), dated June 2, 2023, (xxviii) the Change Order CO-00067 Sheet Pile Joint Sealing 310Q02 Sump, dated October 5, 2023, (xxix) the Change Order CO-00068 E-HAZOP Package #2 (“Phase One Items”), dated October 19, 2023, (xxx) the Change Order CO-00069 Package 6 Feed Gas Pipeline and Pig Receiver DMM, dated August 3, 2023, (xxxi) the Change Order CO-00070 Dry Flare Knockout Drum Spill Pad Drain Specification Change, dated October 5, 2023, (xxxii) the Change Order CO-00071 Viewing Platform Piles, dated October 18, 2023, (xxxiii) the Change Order CO-00072 Site Plan Update Package #1 – Re-Route Contractor’S Utility Water & Nitrogen Pipelines and Provide Power & Fiber Cables To Nitrogen Tie-In Point, dated November 2, 2023, (Portions of this exhibit have been omitted.) | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | | Form | | Exhibit | | Filing Date |
10.15 | | | | CCH | | S-4 | | 10.14 | | 1/5/2017 |
10.16 | | | | CCH | | S-4 | | 10.15 | | 1/5/2017 |
10.17 | | | | Cheniere | | 8-K | | 10.1 | | 4/2/2014 |
10.18 | | | | Cheniere | | 8-K | | 10.1 | | 4/8/2014 |
10.19 | | | | Cheniere | | 10-Q | | 10.3 | | 5/1/2014 |
10.20 | | | | Cheniere | | 10-Q | | 10.9 | | 10/30/2015 |
10.21 | | | | Cheniere | | 10-Q | | 10.10 | | 10/30/2015 |
10.22 | | | | CCH | | 10-Q | | 10.2 | | 8/3/2023 |
10.23 | | | | CCH | | 10-Q | | 10.3 | | 8/3/2023 |
10.24 | | | | Cheniere | | 10-Q | | 10.5 | | 4/30/2015 |
10.25 | | | | CCH | | S-4 | | 10.22 | | 1/5/2017 |
10.26 | | | | CCH | | 10-Q | | 10.1 | | 11/1/2019 |
10.27 | | | | Cheniere | | 8-K | | 10.1 | | 6/2/2014 |
10.28 | | | | CCH | | 10-Q | | 10.5 | | 5/4/2018 |
10.29 | | | | CCH | | 8-K | | 10.6 | | 6/22/2022 |
10.30 | | | | CCH | | 10-K | | 10.34 | | 2/25/2020 |
10.31 | | | | CCH | | 10-Q | | 10.50 | | 11/3/2022 |
10.32 | | | | CCH | | 10-Q | | 10.4 | | 8/3/2023 |
10.33 | | | | CCH | | 8-K | | 10.50 | | 6/22/2022 |
10.34 | | | | CCH | | 10-Q | | 10.40 | | 11/3/2022 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exhibit No. | | | | Incorporated by Reference (1) |
| Description | | Entity | | Form | | Exhibit | | Filing Date |
10.35 | | | | CCH | | 10-Q | | 10.20 | | 11/3/2022 |
10.36 | | | | CCH | | 10-Q | | 10.30 | | 11/3/2022 |
10.37 | | | | CCH | | 10-Q | | 10.10 | | 5/4/2022 |
10.38 | | | | CCH | | 8-K | | 10.70 | | 6/22/2022 |
10.39 | | | | CCH | | 10-Q | | 10.60 | | 11/3/2022 |
10.40 | | | | CCH | | 10-Q | | 10.70 | | 11/3/2022 |
22.1* | | | | | | | | | | |
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) | | | | | | | | |
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(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. |
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(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.
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| | CHENIERE CORPUS CHRISTI HOLDINGS, LLC |
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| | By: | /s/ Zach Davis |
| | | Zach Davis |
| | | President and Chief Financial Officer (Principal Executive and Financial Officer) |
| | Date: | February 21, 2024 |
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 utilization of Cheniere’s NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of Cheniere’s NOLs in full over the carryover period. Cheniere will continue to monitor trading activity in its respective shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize Cheniere’s existing NOL carryforwards.dates indicated.
NOTE 4—GUARANTEES
The subsidiaries of CCH, including us, have jointly and severally guaranteed the debt obligations of CCH, including: (1) $1.25 billion of the 7.000% Senior Secured Notes due 2024, (2) $1.5 billion of the 5.875% Senior Secured Notes due 2025, (3) $1.5 billion of the 5.125% Senior Secured Notes due 2027, (4) a term loan facility of which CCH had approximately $2.1 | | | | | | | | |
Signature | Title | Date |
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/s/ Zach Davis | Manager, President and Chief Financial Officer (Principal Executive and Financial Officer) | February 21, 2024 |
Zach Davis | |
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/s/ Corey Grindal | Manager | February 21, 2024 |
Corey Grindal | | |
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/s/ David Slack | Chief Accounting Officer (Principal Accounting Officer) | February 21, 2024 |
David Slack | |
CORPUS CHRISTI PIPELINE GP, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
73
billion and $3.6 billion of available commitments and approximately $2.5 billion and $2.4 billion of outstanding borrowings as of December 31, 2017 and 2016, respectively, and (5) a $350.0 million working capital facility of which CCH had $186.4 million and $350.0 million of available commitments as of December 31, 2017 and 2016, respectively, and no outstanding borrowings as of December 31, 2017 and 2016. As of December 31, 2017 and 2016, there was no liability that was recorded related to these guarantees.