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What changed in Cheniere Energy, Inc.'s 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of Cheniere Energy, Inc.'s 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+253 added−456 removedSource: 10-K (2024-02-22) vs 10-K (2023-02-23)

Top changes in Cheniere Energy, Inc.'s 2023 10-K

253 paragraphs added · 456 removed · 173 edited across 5 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

69 edited+15 added−211 removed87 unchanged
Biggest changeAdditionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we fail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs, upon the occurrence of certain events of force majeure. 18 Table of Contents Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses.
Biggest changeWhile substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse. 17 Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we fail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs, upon the occurrence of certain events of force majeure.
Our efforts to manage commodity and financial risks through derivative instruments, including our IPM agreements, could adversely affect our earnings reported under GAAP and affect our liquidity. We use derivative instruments to manage commodity, currency and financial market risks.
Our efforts to manage commodity and financial risks through derivative instruments, including our IPM agreements, could adversely affect our earnings reported under GAAP and our liquidity. We use derivative instruments to manage commodity, currency and financial market risks.
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 flow, liquidity and prospects.
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 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.
Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel other than our employment agreement with our President and Chief Executive Officer binding them to provide services for any particular term.
Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term, other than our employment agreement with our President and Chief Executive Officer.
To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the SPL Project, the three Trains and related facilities of the CCL Project and the seven midscale Trains and related facilities for the Corpus Christi Stage 3 Project, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline, the Corpus Christi Pipeline and the pipeline for the Corpus Christi Stage 3 Project.
To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the SPL Project, the three Trains and related facilities of the CCL Project and the seven midscale Trains and related facilities for the Corpus Christi Stage 3 Project, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline and the Corpus Christi Pipeline.
Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.
Revised, reinterpreted or additional laws and regulations that result in increased compliance, operating or construction costs or restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.
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 CCL Midscale Trains 8 and 9, 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.
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 CCL Midscale Trains 8 & 9 Project and the SPL Expansion 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.
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 CCL Midscale Trains 8 and 9, or result in a contractor’s unwillingness to perform further work.
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 CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, or result in a contractor’s unwillingness to perform further work.
Prior to completion of the Corpus Christi Stage 3 Project, CCH is also required to confirm that it has sufficient funds, including senior debt commitments, equity funding and projected contracted cash flows from the fixed price component of its third party SPAs, to meet remaining expenditures required for the Corpus Christi Stage 3 Project in order to achieve completion by a specified date certain.
In addition, prior to completion of the Corpus Christi Stage 3 Project, CCH is also required to confirm that it has sufficient funds, including senior debt commitments, equity funding and projected contracted cash flows from the fixed price component of its third party SPAs, to meet remaining expenditures required for the Corpus Christi Stage 3 Project in order to achieve completion by a certain specified date.
Cost overruns and delays in the completion of our expansion projects, including the Corpus Christi Stage 3 Project and CCL Midscale Trains 8 and 9, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Cost overruns and delays in the completion of our expansion projects, including the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
A shortage in the labor pool of skilled workers, remoteness of our site locations or other general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs.
A shortage in the labor pool of skilled workers, remoteness of our site locations, general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs.
It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. On February 28, 2022, the EPA removed a stay of formaldehyde standards in the NESHAP Subpart YYYY for stationary combustion turbines located at major sources of HAP emissions.
It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. 27 On February 28, 2022, the EPA removed a stay of formaldehyde standards in the NESHAP Subpart YYYY for stationary combustion turbines located at major sources of HAP emissions.
Timely and cost-effective completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including CCL Midscale Trains 8 and 9, 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.
Timely and cost-effective completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion 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.
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 to capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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 increased capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our interstate natural gas pipelines and their FERC gas tariffs are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.
Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. 26 Our interstate natural gas pipelines and their FERC gas tariffs are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.
We sell a significant amount of our LNG under delivered at terminal (“DAT”) terms requiring delivery to international destinations. To fulfill our transportation requirements, including those under long term SPAs, we depend on the ability to secure chartered vessels often through long term lease arrangements.
We sell a significant amount of our LNG under delivered at terminal ( “DAT” ) terms requiring delivery to international destinations. To fulfill our transportation requirements under these arrangements, including those under long term SPAs, we depend on the ability to secure chartered vessels often through long term lease arrangements.
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.
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. 21 We do not, nor do we intend to, maintain insurance against all of these risks and losses.
Our investment decision on the Corpus Christi Stage 3 Project and any potential future expansion of LNG facilities, including CCL Midscale Trains 8 and 9, relies on cost estimates developed initially through front end engineering and design studies.
Our investment decision on the Corpus Christi Stage 3 Project and any potential future expansion of LNG facilities, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, relies on cost estimates developed initially through front end engineering and design studies.
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 LNG, natural gas or alternative energy sources, which may reduce the demand for imported LNG and/or natural gas; • political conditions in customer regions; 24 Table of Contents • sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events; • adverse relative demand for LNG compared to other markets, which may decrease LNG imports from North America; and • cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
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; 23 • 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 LNG, natural gas or alternative energy sources, which may reduce the demand for imported 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 imports from North America; and • cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
The loss of the services of any of these individuals could have a material adverse effect on our business. Outbreaks of infectious diseases, such as the outbreak of COVID-19, at one or more of our facilities could adversely affect our operations.
The loss of the services of any of these individuals could have a material adverse effect on our business. Outbreaks of infectious diseases, such as COVID-19, at one or more of our facilities could adversely affect our operations.
Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also adversely affect our business, contracts, financial condition, operating results, cash flows, 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 CCL Midscale Trains 8 and 9.
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 CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project.
Our subsidiaries’ inability to pay distributions to CQP or us or to incur additional indebtedness as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit CQP’s ability to pay or increase distributions to us and its other unitholders or inhibit our access to cash flows from the CCL Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our subsidiaries’ inability to pay distributions to CQP or us as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit CQP’s ability to pay or increase distributions to us and its other unitholders or inhibit our access to cash flows from the CCL Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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, 2022 and 2021.
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.
The inability to achieve acceptable funding may cause a delay in the development or construction of CCL Midscale Trains 8 and 9 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.
The inability to achieve acceptable funding may cause a delay in the development or construction of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project 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.
Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.4 million per day for each violation. Although the FERC has not imposed fines or penalties on us to date, we are exposed to substantial penalties and fines if we fail to comply with such regulations.
Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.5 million per day for each violation. Although the FERC has not imposed fines or penalties on us to date, we are exposed to substantial penalties and fines if we fail to comply with such regulations.
Our risk is in part mitigated by the diversification of our natural gas supply and transport across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events.
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 certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events.
For example, SPL is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a debt service coverage ratio of 1.25:1.00 is satisfied.
For example, SPL is restricted from making distributions under agreements governing its indebtedness generally unless, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a debt service coverage ratio of 1.25:1.00 is satisfied.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals 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 28 Table of Contents 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.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national or international 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.
Any downward revision in the amount of dividends we pay to stockholders or the number of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock. 20 Table of Contents Risks Relating to Our Operations and Industry Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Projects, damage to our Liquefaction Projects and increased insurance costs, all of which could adversely affect us.
Any downward revision in the amount of dividends we pay to stockholders or the number of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock. 19 Risks Relating to Our Operations and Industry Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Projects, damage to our Liquefaction Projects and increased insurance costs, all of which could adversely affect us.
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 22 Table of Contents could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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.
While our chartered vessels are operated by the ship owners and we are exposed to risks outside of our own control, we are generally protected through provisions in our charter agreements from transportation disruptions on the part of the ship owner, including disruptions due to offhire and downtime periods or shipping delays.
While our chartered vessels are operated by the ship owners and we are exposed to risks outside of our own control, we are generally protected through provisions in our charter agreements from transportation disruptions on the part of the ship owner, including disruptions due to off-hire and downtime periods or shipping delays.
Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant customer fails to perform its contractual obligations for any reason.
Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant portion of our customers fails to perform its contractual obligations for any reason.
We will require significant additional funding to be able to commence construction of CCL Midscale Trains 8 and 9, and any additional expansion projects, which we may not be able to obtain at a cost that results in positive economics, or at all.
We will require significant additional funding to be able to commence construction of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project and any additional expansion projects, which we may not be able to obtain at a cost that results in positive economics, or at all.
Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA”). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including 27 Table of Contents the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities.
Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA” ). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities.
The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Liquefaction Projects, CCL Midscale Trains 8 and 9 and other facilities, as well as the import and export of LNG and the purchase and transportation of natural gas, are highly regulated activities.
The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Liquefaction Projects, the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project and other facilities, as well as the import and export of LNG and the purchase and transportation of natural gas, are highly regulated activities.
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 criticality of natural gas supply to our 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. 21 Table of Contents Our ability to complete development and/or construction of additional Trains, including CCL Midscale Trains 8 and 9, will be contingent on our ability to obtain additional funding.
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 criticality of natural gas supply to our 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. 20 Our ability to complete development and/or construction of additional Trains, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, will be contingent on our ability to obtain additional funding.
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. 25 Table of Contents We face competition based upon the international market price for LNG.
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. 24 We face competition based upon the international market price for LNG.
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.
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.
Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2022, we had SPAs with terms of 10 or more years with a total of 28 different third party customers.
Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2023, we had SPAs with initial terms of 10 or more years with a total of 29 different third party customers.
The agreements governing our subsidiaries’ indebtedness restrict payments that our subsidiaries can make to CQP or us in certain events and limit the indebtedness that our subsidiaries can incur.
The agreements governing our subsidiaries’ indebtedness restrict payments that our subsidiaries can make to CQP or us in certain events.
As of December 31, 2022 and 2021, we had collateral posted with counterparties by us of $134 million and $765 million, respectively, which are included in margin deposits in our Consolidated Balance Sheets. 19 Table of Contents Restrictions in agreements governing us and our subsidiaries’ indebtedness may prevent us and our subsidiaries from engaging in certain beneficial transactions, which could materially and adversely affect us.
As of December 31, 2023 and 2022, we had collateral posted with counterparties by us of $18 million and $134 million, respectively, which are included in margin deposits in our Consolidated Balance Sheets. 18 Restrictions in agreements governing us and our subsidiaries’ indebtedness may prevent us and our subsidiaries from engaging in certain beneficial transactions, which could materially and adversely affect us.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, our net income (loss) for the years ended December 31, 2022 and 2021 includes $5.7 billion and $4.3 billion, respectively, of losses resulting from changes in the fair values of our derivatives, of which substantially all of such losses were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreements.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, our net income for the year ended December 31, 2022 included $5.7 billion of losses resulting from changes in the fair values of our derivatives, of which substantially all of such losses were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreements.
CCH is generally restricted from making distributions under agreements governing its indebtedness unless, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and it achieves a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.
CCH is restricted from making distributions under agreements governing its indebtedness generally unless, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a debt service coverage ratio of 1.25:1.00 is satisfied.
A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations and the repricing of market risks and volatility in capital and financial markets.
A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, lending institutions’ evolving policies on financing businesses linked to fossil fuels and the repricing of market risks and volatility in capital and financial markets.
We incur, and will incur, significant interest expense relating to financing the assets at the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, and we anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of the Corpus Christi Stage 3 Project and CCL Midscale Trains 8 and 9.
We incur, and will incur, significant interest expense relating to financing the assets at the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, and we anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of the Corpus Christi Stage 3 Project, as well as the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project if a positive FID is made on these expansion projects.
Risks Relating to Regulations Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipelines and the export of LNG could impede operations and construction and could have a material adverse effect on us.
Risks Relating to Regulations Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipelines and the export of LNG could impede operations and construction and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
While the COVID-19 pandemic, including the Delta and Omicron variants, has had no adverse impact on our on-going operations, the risk of future variants is unknown.
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.
Additionally as of December 31, 2022, $3.6 billion of repurchase authority remained under our share repurchase program our Board had authorized.
Additionally as of December 31, 2023, $2.1 billion of repurchase authority remained under our share repurchase program our Board had authorized.
We are currently in compliance with such conditions; however, failure to comply or our inability to obtain and maintain existing or newly imposed approvals and permits, filings, which 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 the siting of LNG facilities due to safety, environmental or security concerns, could impede the operation and construction of our infrastructure.
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.
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.
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 January 2024, the EPA issued a proposed rule to impose and collect methane emissions charges authorized under the IRA.
Risks Relating to Our Financial Matters Our existing level of cash resources and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Risks Relating to Our Financial Matters An inability to source capital to supplement our available cash resources and existing credit facilities could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Although we actively manage our vessel requirements in response to the market and our customer contracts, the availability of LNG vessels and transportation costs could be impacted to the detriment of our business and our customers because of: • an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards; • shortages of or delays in the receipt of necessary construction materials; 23 Table of Contents • political or economic disturbances; • acts of war or piracy; • changes in governmental regulations or maritime self-regulatory organizations; • work stoppages or other labor disturbances; • bankruptcy or other financial crisis of shipbuilders or shipowners; • quality or engineering problems; • disruptions to maritime transportation routes; and • weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.
The construction and delivery of LNG vessels require significant capital and long construction lead times, and we may execute charters several years before the lease arrangements commence. 22 Although we actively manage our vessel requirements in response to the market and our customer contracts, the availability of LNG vessels and transportation costs could be impacted to the detriment of our business and our customers because of: • an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards; • shortages of or delays in the receipt of necessary construction materials; • political or economic disturbances; • acts of war or piracy; • changes in governmental regulations or maritime self-regulatory organizations; • work stoppages or other labor disturbances; • bankruptcy or other financial crisis of shipbuilders or shipowners; • quality or engineering problems; • disruptions to maritime transportation routes, such as the recent security situation in the Gulf of Aden and congestion at the Panama Canal resulting from decreased water levels caused by prolonged drought conditions; and • weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.
Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile. As described in Results of Operations in Item 7.
Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile, which could have a significant adverse effect on our earnings reported under GAAP. For example, as described in Results of Operations in Item 7.
As of December 31, 2022, we had $1.4 billion of cash and cash equivalents, $1.1 billion of restricted cash and cash equivalents, a total of $7.5 billion of available commitments under our credit facilities and $25.1 billion of total debt outstanding on a consolidated basis (before unamortized premium, discount and debt issuance costs).
As of December 31, 2023, we had, on a consolidated basis, $4.1 billion of cash and cash equivalents (of which $575 million was held by CQP), $459 million of restricted cash and cash equivalents (of which $56 million was held by CQP), a total of $7.6 billion of available commitments under our credit facilities and $23.9 billion of total debt outstanding (before unamortized discount and debt issuance costs).
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.
Business and Properties , we are currently developing the CCL Midscale Trains 8 & 9 Project and the SPL Expansion 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.
Although no fines or penalties have been imposed on us to date, 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, which for certain violations can aggregate up to as high as $2.6 million.
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, which for certain violations can aggregate up to as high as $2.7 million. Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity.
Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity. We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact.
We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact.
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 but not limited to changes in scope, the ability of Bechtel and 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 additional funds to be expended to maintain construction schedules or comply with existing or future environmental or other regulations.
( “Bechtel” ) and 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 additional funds to be expended to maintain construction schedules or comply with existing or future environmental or other regulations.
We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, other than certain derivatives for which we have elected to apply accrual accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
The extent of our derivative position at any given time depends on our assessments of the markets for these commodities and related exposures. We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with.
If we were to lose these rights or be required to relocate our pipelines, 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.
In September 2022, certain of our subsidiaries entered the pre-filing review process with the FERC under the National Environmental Policy Act for CCL Midscale Trains 8 and 9.
In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project and in March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project.
We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.
As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.
As described in Market Factor s and Competition , we have contracted through our SPAs and IPM agreements approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s, inclusive of contracts executed to support additional liquefaction capacity at the Corpus Christi LNG Terminal beyond the Corpus Christi Stage 3 Project.
As described in Market Factors and Competition , we have contracted through our SPAs and IPM agreements approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.
Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. 26 Table of Contents We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel.
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. 25 We depend on our executive officers for various activities.
RISK FACTORS The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below.
ITEM 1A. RISK FACTORS The following are some of the important factors that should be considered when investing in us, as such risk factors could adversely affect our business, financial condition, results of operation or cash flows or have other adverse impacts, and could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements.
Any changes to local, domestic or international tax laws and regulations, or their interpretation and application, including those with retroactive effect, could affect our tax obligations, profitability and cash flows in the future. In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control.
In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control. We continuously monitor and assess proposed tax legislation that could negatively impact our business.
Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipelines on land owned by third parties. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.
We would anticipate seeking non-FTA export authorization from the DOE on the SPL Expansion Project in the future, having entered the pre-filing review process with the FERC in May 2023. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipelines on land owned by third parties.
In September 2022, certain of our subsidiaries entered the pre-filing review process with the FERC under the National Environmental Policy Act for CCL Midscale Trains 8 and 9. To date, the DOE has also issued orders under Section 4 of the NGA authorizing SPL, CCL and the Corpus Christi Stage 3 Project to export domestically produced LNG.
To date, the DOE has also issued orders under Section 4 of the NGA authorizing SPL, CCL and the Corpus Christi Stage 3 Project 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.
Removed
Item 1A. Risk Factors in this Annual Report on Form 10-K. All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements.
Added
Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated.
Removed
In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology.
Added
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 but not limited to changes in scope, the ability of Bechtel Energy Inc.
Removed
The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors.
Added
We do not maintain key person life insurance policies on any of our personnel.
Removed
Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate.
Added
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.
Removed
We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur.
Added
The CCL 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.
Removed
Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC.

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Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

1 edited+12 added−9 removed1 unchanged
Biggest changeCertain of our subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.
Biggest changeWe do not expect that any ultimate penalty will have a material adverse impact on our financial results. ITEM 4. MINE SAFETY DISCLOSURE Not applicable. 30 PART II ITEM 5.
Removed
LDEQ Matter Certain of our subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG Terminal and the commissioning of the SPL Project, and relating to certain requirements under its Title V Permit.
Added
LDEQ Matter Certain of our subsidiaries are in discussions with the LDEQ to resolve alleged non-compliance with national emission standards for formaldehyde from combustion turbines at the Sabine Pass LNG Terminal. The allegations are identified in a Consolidated Compliance Order and Notice of Potential Penalty, Tracking No.
Removed
The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of our subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period.
Added
AE-CN-22-00833 (the “2023 Compliance Order” ) issued by the LDEQ on April 12, 2023. In August 2004, the EPA stayed the application of the emission standard to combustion turbines such as those at the Sabine Pass LNG Terminal.
Removed
PHMSA Matter In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG Terminal (the “2018 SPL tank incident”).
Added
In March 2022, the EPA lifted the stay, and in June 2022 our subsidiaries petitioned the EPA and LDEQ for approval of additional operating parameters to demonstrate compliance with the emission limitation. The petition remains pending.
Removed
These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO.
Added
Our subsidiaries continue to work with the LDEQ to resolve the matters identified in the 2023 Compliance Order, including the petition pending with the EPA. As of December 2023, our subsidiaries have filed test results with the LDEQ indicating that for the initial compliance period all 44 turbines meet the relevant compliance standard.
Removed
On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to service.
Added
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Market Information, Holders and Dividend Policy Our common stock has traded on the New York Stock Exchange under the symbol “LNG” since February 5, 2024, and previously traded on the NYSE American or its predecessors under the symbol “LNG” from March 24, 2003 through February 3, 2024.
Removed
In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to SPL alleging violations of federal pipeline safety regulations relating to the 2018 SPL tank incident and proposing civil penalties totaling $2,214,900. On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200.
Added
As of February 16, 2024, we had approximately 234.7 million shares of common stock outstanding held by 75 record owners. We intend to continue to declare and pay quarterly dividends, with the goal of increasing the dividend over time.
Removed
On October 12, 2021, SPL responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty.
Added
The declaration of dividends is subject to the discretion of our Board, and will depend on our financial condition and other factors deemed relevant by the Board. See the risk Our ability to declare and pay dividends and repurchase shares is subject to certain considerations under Risks Relating to Our Financial Matters in Item 1A. Risk Factors.
Removed
PHMSA notified SPL in a letter dated November 9, 2021 that the case was considered “closed.” SPL continues to coordinate with PHMSA and FERC to address the matters relating to the 2018 SPL tank incident, including repair approach and related analysis. One tank has been placed back into operational service.
Added
Purchase of Equity Securities by the Issuer and Affiliated Purchasers The following table summarizes stock repurchases for the three months ended December 31, 2023: Period Total Number of Shares Purchased Average Price Paid Per Share Total Number of Shares Purchased as a Part of Publicly Announced Plans Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans (in millions) (1) October 1 - 31, 2023 732,055 $167.95 732,055 $2,357 November 1 - 30, 2023 634,274 $174.28 634,274 $2,247 December 1 - 31, 2023 607,966 $173.21 607,966 $2,141 Total 1,974,295 $171.60 1,974,295 (1) See Note 19—Share Repurchase Programs of our Notes to Consolidated Financial Statements for details on the amount authorized by our Board under our share repurchase programs. 31 Total Stockholder Return The following is a customized peer group consisting of 17 companies (the “Peer Group” ) that were selected because they are publicly traded companies that have comparable Global Industry Classification Standards.
Removed
We do not expect that the Consent Order and related analysis, repair and remediation or resolution of the NOPV will have a material adverse impact on our financial results or operations.
Added
We also took into consideration those companies that have similar market capitalization, enterprise values and operating characteristics and capital intensity. Peer Group Air Products and Chemicals, Inc. (APD) Marathon Petroleum Corporation (MPC) Baker Hughes Company (BKR) Occidental Petroleum Corporation (OXY) ConocoPhillips (COP) ONEOK, Inc. (OKE) Enterprise Products Partners L.P. (EPD) Phillips 66 (PSX) EOG Resources, Inc. (EOG) Suncor Energy Inc.
Added
(SU) Halliburton Company (HAL) Targa Resources Corp. (TRGP) Hess Corporation (HES) Valero Energy Corporation (VLO) Kinder Morgan, Inc. (KMI) The Williams Companies, Inc. (WMB) LyondellBasell Industries N.V. (LYB) The following graph compares the five-year total return on our common stock, the S&P 500 Index and our Peer Group.
Added
The graph was constructed on the assumption that $100 was invested in our common stock, the S&P 500 Index and our Peer Group on December 31, 2018 and that any dividends were fully reinvested.
Added
December 31, Company / Index 2018 2019 2020 2021 2022 2023 Cheniere Energy, Inc. $ 100.00 $ 103.18 101.42 $ 171.88 $ 256.67 $ 295.20 S&P 500 Index 100.00 131.48 155.65 200.29 163.98 207.04 Peer Group 100.00 122.09 90.09 130.28 193.39 212.27 32 ITEM 6. [Reserved]

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

22 edited+11 added−6 removed8 unchanged
Biggest changeThe proceeds from the borrowings during year ended December 31, 2021, together with cash on hand, were used to redeem or repurchase $6.8 billion of outstanding indebtedness, entirely associated with redemptions of our outstanding notes or paydown of our credit facilities. 49 Table of Contents Debt Issuances and Related Financing Costs The following table shows the proceeds from issuances of debt, including intra-year borrowings (in millions): Year Ended December 31, 2022 2021 Proceeds from issuances of debt SPL: 5.900% Senior Secured Amortizing Notes due 2037 $ 430 $ — 2037 SPL Private Placement Senior Secured Notes 70 482 SPL Working Capital Facility 60 — CQP: 4.000% Senior Notes due 2031 — 1,500 3.25% Senior Notes due 2032 — 1,200 CCH: 2.742% Senior Notes due 2029 — 750 CCH Credit Facility 440 — CCH Working Capital Facility — 400 Cheniere: Cheniere Revolving Credit Facility 575 1,359 Cheniere’s term loan facility (the “Cheniere Term Loan Facility”) — 220 Total proceeds from issuances of debt $ 1,575 $ 5,911 During the years ended December 31, 2022 and 2021, we paid debt issuance costs and other financing costs of $51 million and $53 million, respectively, included in other, net in the Financing Cash Flows table above, related to the debt issuances above and amendment of credit facilities during the respective periods. 50 Table of Contents Debt Redemptions, Repayments and Repurchases and Related Modification or Extinguishment Costs The following table shows the redemptions, repayments and repurchases of debt, including intra-year repayments (in millions): Year Ended December 31, 2022 2021 Redemption, repayments and repurchases of debt SPL: 2022 SPL Senior Notes $ — $ (1,000) 2023 SPL Senior Notes (1,500) — SPL Working Capital Facility (60) — CQP: 5.250% Senior Notes due 2025 — (1,500) 5.625% Senior Notes due 2026 — (1,100) CCH: CCH Credit Facility (2,169) (898) CCH Working Capital Facility (250) (290) 2024 CCH Senior Notes (752) — 5.625% Senior Notes due 2025 (9) 5.125% Senior Notes due 2027 (230) — 3.700% Senior Notes due 2029 (138) — 3.751% weighted average Senior Notes rate due 2039 (88) — Cheniere: 4.875% Cheniere Convertible Senior Notes due 2021 — (295) 4.25% Convertible Senior Notes due 2045 (500) — Cheniere Revolving Credit Facility (575) (1,359) 4.625% Senior Secured Notes due 2028 (500) — Cheniere Term Loan Facility — (368) Total redemptions, repayments and repurchases of debt $ (6,771) $ (6,810) During the years ended December 31, 2022 and 2021, we paid debt modification or extinguishment costs of $3 million and $82 million, respectively, included in other, net in the Financing Cash Flows table above, related to these redemptions and repayments.
Biggest changeThe proceeds from the borrowings during the year ended December 31, 2022, together with cash on hand, were used to redeem or repurchase $6.8 billion of outstanding indebtedness, entirely associated with redemptions of our outstanding notes or repayment of amounts outstanding under our credit facilities. 47 Table of Contents Debt Redemptions, Repayments and Repurchases The following table shows the redemptions, repayments and repurchases of debt, including intra-year repayments (in millions): Year Ended December 31, 2023 2022 Redemptions, repayments and repurchases of debt SPL: 2024 SPL Senior Notes $ (1,700) $ — 2023 SPL Senior Notes — (1,500) SPL Working Capital Facility — (60) CCH: CCH Credit Facility — (2,169) CCH Working Capital Facility — (250) 7.000% Senior Notes due 2024 (498) (752) 5.625% Senior Notes due 2025 — (9) 5.125% Senior Notes due 2027 (69) (230) 3.700% Senior Notes due 2029 (237) (138) 2.742% Senior Notes due 2039 (94) — 3.788% weighted average Senior Notes rate due 2039 — (88) Cheniere: 2045 Cheniere Convertible Senior Notes — (500) Cheniere Revolving Credit Facility — (575) 4.625% Senior Notes due 2028 — (500) Total redemptions, repayments and repurchases of debt $ (2,598) $ (6,771) Non-Controlling Interest Distributions We own a 48.6% limited partner interest in CQP with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public.
A further aspect of our revised capital allocation plan is to lower our long-term leverage target through debt paydown to approximately 4x, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of our indebtedness, including senior notes of SPL, CQP, CCH and Cheniere.
A further aspect of our capital allocation plan is to lower our long-term leverage target through debt paydown to approximately 4x, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of our indebtedness, including senior notes of SPL, CQP, CCH and Cheniere.
Quantitative and Qualitative Disclosures About Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices. 52 Table of Contents Recent Accounting Standards For a summary of recently issued accounting standards, see Note 2 — Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
Quantitative and Qualitative Disclosures About Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices. 49 Table of Contents Recent Accounting Standards For a summary of recently issued accounting standards, see Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
Financially Disciplined Growth To the extent that liquefaction capacity at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal is expanded beyond the Liquefaction Projects and the Corpus Christi Stage 3 Project, such as CCL Midscale Trains 8 and 9, we expect that additional financing would be used to fund construction of the expansion.
Financially Disciplined Growth To the extent that liquefaction capacity at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal is expanded beyond the Liquefaction Projects, such as the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, we expect that additional financing would be used to fund construction of the expansion.
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.
Changes in facts and circumstances or additional information may result in revised 48 Table of Contents estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.
The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2022 and 2021 amounted to a liability of $9.9 billion and $4.0 billion, respectively, consisting entirely of physical liquefaction supply derivatives.
The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2023 and 2022 amounted to a liability of $2.2 billion and $9.9 billion, respectively, consisting entirely of physical liquefaction supply derivatives.
The timing and amount of any paydown of our indebtedness will be determined by management based on market conditions and other factors. During the year ended December 31, 2022, we used $5.6 billion of available cash to reduce our outstanding indebtedness, of which $5.4 billion was the redemption or prepayment of indebtedness pursuant to our capital allocation plan.
The timing and amount of any paydown of our indebtedness will be determined by management based on market conditions and other factors. During the year ended December 31, 2023, we used $1.2 billion of available cash to reduce our outstanding indebtedness, all of which was pursuant to our capital allocation plan.
Fair Value of Level 3 Physical Liquefaction Supply Derivatives All derivative instruments are recorded at fair value, other than certain derivatives for which we have elected to apply accrual accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
Fair Value of Level 3 Physical Liquefaction Supply Derivatives All of our derivative instruments are recorded at fair value, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
Provided below are the changes in fair value from valuation of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2022 and 2021 (in millions), which entirely consisted of physical liquefaction supply derivatives.
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 for the years ended December 31, 2023 and 2022 (in millions), which entirely consisted of physical liquefaction supply derivatives.
Year Ended December 31, 2022 2021 Unfavorable changes in fair value relating to instruments still held at the end of the period $ (6,493) $ (4,305) The unfavorable changes in fair value on instruments held at the end of both years is primarily attributed to significant appreciation in estimated forward international LNG commodity curves on our IPM agreements during the years ended December 31, 2022 and 2021.
Year Ended December 31, 2023 2022 Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period $ 5,700 $ (6,493) The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our IPM agreements during the years ended December 31, 2023 and 2022.
On January 27, 2023, we declared a quarterly dividend of $0.395 per share of common stock that is payable on February 27, 2023 to stockholders of record as of February 7, 2023.
On January 26, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on February 23, 2024 to stockholders of record as of the close of business on February 6, 2024.
The $932 million increase in 2022 compared to 2021 was primarily due to spend during the year ended December 31, 2022 related to construction work performed by Bechtel for the Corpus Christi Stage 3 Project, partially offset by a decrease in spend due to the completion of Train 6 of the SPL Project in February 2022, which was under construction throughout 2021.
The $358 million increase in 2023 compared to 2022 was primarily due to $1.5 billion of cash outflows during the year ended December 31, 2023 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, partially offset by a decrease in spend due to the completion of Train 6 of the SPL Project in February 2022.
Financing Cash Flows The following table summarizes our financing activities (in millions): Year Ended December 31, 2022 2021 Proceeds from issuances of debt $ 1,575 $ 5,911 Redemptions and repayments of debt (6,771) (6,810) Distributions to non-controlling interest (947) (649) Repurchase of common stock (1,373) (9) Dividends to stockholders (349) (85) Other, net (149) (175) Net cash used in financing activities $ (8,014) $ (1,817) During the years ended December 31, 2022 and 2021, we had total debt issuances of $1.6 billion and $5.9 billion, respectively.
Financing Cash Flows The following table summarizes our financing activities (in millions): Year Ended December 31, 2023 2022 Proceeds from issuances of debt $ 1,397 $ 1,575 Redemptions, repayments and repurchases of debt (2,598) (6,771) Distributions to non-controlling interest (1,016) (947) Repurchase of common stock (1,473) (1,373) Dividends to stockholders (393) (349) Other, net (97) (149) Net cash used in financing activities $ (4,180) $ (8,014) Debt Issuances During the year ended December 31, 2023, CQP issued an aggregate principal amount of $1.4 billion of 2033 CQP Senior Notes, the proceeds of which were used, together with cash on hand, to redeem $1.4 billion of the 2024 SPL Senior Notes.
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.
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.
The revised capital allocation plan also includes a targeted annual dividend growth rate of approximately 10% through Corpus Christi Stage 3 Project construction. On September 12, 2022, we declared a quarterly dividend of $0.395 per common share, which represented a 20% increase from the previous quarterly dividend.
The capital allocation plan also includes a targeted annual dividend growth rate of approximately 10% through Corpus Christi Stage 3 Project construction. On January 26, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on February 23, 2024 to stockholders of record as of the close of business on February 6, 2024.
We expect our capital expenditures to increase in future periods as construction work progresses on the Corpus Christi Stage 3 Project following our issuance of full notice to proceed to Bechtel in June 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.
We have elected to account for the effects of CAMT on deferred tax assets, carryforwards, and tax credits in the period they arise. Investing Cash Flows Our investing cash net outflows in both years primarily were for the construction costs for the Liquefaction Projects.
Investing Cash Flows Our investing net cash outflows in both years primarily were for the construction costs for the Liquefaction Projects.
CQP paid distributions of $947 million and $649 million during the years ended December 31, 2022 and 2021, respectively, to non-controlling interests.
Distributions of $1.0 billion and $947 million were paid during the years ended December 31, 2023 and 2022, respectively, to non-controlling interests. Repurchase of Common Stock During the years ended December 31, 2023 and 2022, we paid $1.5 billion and $1.4 billion to repurchase 9.5 million and 9.4 million shares of our common stock, respectively, under our share repurchase program.
Repurchase of Common Stock The following table presents information with respect to repurchases of common stock (in millions, except per share data): Year Ended December 31, 2022 2021 Aggregate common stock repurchased 9.35 0.10 Weighted average price paid per share $ 146.88 $ 87.32 Total amount paid $ 1,373 $ 9 As of December 31, 2022, we had approximately $3.6 billion remaining under our share repurchase program. 51 Table of Contents Cash Dividends to Stockholders During the year ended December 31, 2022, we paid aggregate dividends of $1.385 per share of common stock, for a total of $349 million paid to common stockholders.
As of December 31, 2023, we had approximately $2.1 billion remaining under our share repurchase program. Cash Dividends to Stockholders During the year ended December 31, 2023, we paid aggregate dividends of $1.62 per share of common stock, for a total of $393 million.
Year Ended December 31, 2022 2021 Net cash provided by operating activities $ 10,523 $ 2,469 Net cash used in investing activities (1,844) (912) Net cash used in financing activities (8,014) (1,817) Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents 5 — Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents $ 670 $ (260) Operating Cash Flows Our operating cash net inflows during the years ended December 31, 2022 and 2021 were $10.5 billion and $2.5 billion, respectively.
Year Ended December 31, 2023 2022 Net cash provided by operating activities $ 8,418 $ 10,523 Net cash used in investing activities (2,202) (1,844) Net cash used in financing activities (4,180) (8,014) Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents 2 5 Net increase in cash, cash equivalents and restricted cash and cash equivalents $ 2,038 $ 670 46 Table of Contents Operating Cash Flows The $2.1 billion decrease between the periods was primarily related to lower cash receipts from the sale of LNG cargoes due to lower pricing per MMBtu as a result of decreased pricing and a reduction of volumes sold under short-term agreements, as well as a decrease in regasification revenues.
In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability.
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.
We paid dividends of $0.33 per share of common stock, for a total of $85 million during the year ended December 31, 2021. On January 27, 2023, we declared a quarterly dividend of $0.395 per share of common stock that is payable on February 27, 2023 to stockholders of record as of February 7, 2023.
We paid aggregate dividends of $1.385 per share of common stock, for a total of $349 million during the year ended December 31, 2022.
Removed
The $8.1 billion increase was primarily related to increased cash receipts from the sale of LNG cargoes due to higher revenue per MMBtu and, to a lesser extent, higher volume of LNG delivered.
Added
A discussion of our revenues, including LNG and regasification revenues, can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements. The decrease was partially offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.
Removed
Additionally, a portion of the increase was related to the receipt of the lump sum Termination Fee from Chevron related to the Termination Agreement, as further described in Overview of S ignificant Events , of which $796 million of cash inflows were allocable to the termination of the TUA, while an offsetting $31 million was recognized as a loss on extinguishment of debt allocable to a premium paid to Chevron to terminate a revenue sharing arrangement with them that was accounted for as debt, as discussed below under Financing Cash Flows .
Added
As described in Future Sources and Uses of Liquidity , our future operating cash flows will be impacted by CAMT, which may result in greater volatility in our cash tax payments, including potentially higher cash payments in the near-term relative to the year ended December 31, 2023. See Future Sources and Uses of Liquidity for additional discussion.
Removed
Partially offsetting these operating cash inflows were higher operating cash outflows primarily due to higher natural gas feedstock costs and lower contribution from certain portfolio optimization activities. 48 Table of Contents On August 16, 2022, President Biden signed H.R. 5376 (P.L. 117-169), commonly referred to as the Inflation Reduction Act, into law, which includes the implementation of a new 15% corporate alternative minimum tax (the “CAMT”) effective in 2023 on the adjusted financial statement income of certain large corporations, among other provisions.
Added
During the year ended December 31, 2023, we also made investments in infrastructure expected to support the development, construction and operations of the Corpus Christi Stage 3 Project, including an investment in pipeline capacity for natural gas feedstock.
Removed
The proceeds from the borrowings during the year ended December 31, 2022, together with cash on hand, were used to pay down $6.8 billion of outstanding indebtedness, which included $965 million of debt repurchases on the open market, and the remaining associated with redemptions of our outstanding notes or paydown of our credit facilities.
Added
Also during the year ended December 31, 2023, we acquired an existing power generation facility located near Corpus Christi, Texas to mitigate power price risk associated with our anticipated increased power load at the Corpus Christi LNG Terminal.
Removed
In addition, during the year ended December 31, 2022, we paid $31 million associated with a premium paid to terminate a revenue sharing arrangement under the Termination Agreement with Chevron. Non-Controlling Interest Distributions We own a 48.6% limited partner interest in CQP with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public.
Added
Additionally, during the year ended December 31, 2023, SPL purchased $200 million of the 2024 SPL Senior Notes in the open market and redeemed an additional $100 million of the 2024 SPL Senior Notes. As of December 31, 2023, the only bonds maturing in 2024 are the remaining $300 million outstanding of the 2024 SPL Senior Notes.
Removed
This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and adjustments for transportation prices, and associated events deriving fair value including, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.
Added
During the year ended December 31, 2022, SPL issued $430 million of 5.900% Senior Secured Amortizing Notes due 2037 and $70 million of 2037 SPL Private Placement Senior Secured Notes, and we had total borrowings of $1.1 billion under our credit facilities.
Added
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.
Added
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.
Added
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.
Added
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.
Added
As applicable to our natural gas supply contracts, 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.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

79 edited+42 added−55 removed19 unchanged
Biggest changeIn February 2023, S&P also upgraded its issuer credit ratings of SPL from BBB to BBB+ with stable outlook. • In September 2022, our Board approved a revised comprehensive, long-term capital allocation plan which included: ◦ increasing the share repurchase authorization by $4.0 billion for an additional 3 years, beginning on October 1, 2022; ◦ lowering our consolidated long-term leverage target to approximately 4x; ◦ increasing our dividend by 20% commencing with a declared distribution of $0.395 per common share in September 2022 (paid in November 2022), and targeting an approximate 10% annual dividend growth rate through Corpus Christi Stage 3 Project construction; and ◦ continuing to invest in accretive organic growth. 35 Table of Contents • We accomplished the following pursuant to our capital allocation priorities: ◦ During the year ended December 31, 2022, we prepaid $5.4 billion of consolidated long-term indebtedness pursuant to our capital allocation plan. ◦ During the year ended December 31, 2022, we repurchased approximately 9.3 million shares of our common stock as part of our share repurchase program for approximately $1.4 billion.
Biggest changeThe CQP Revolving Credit Facility and SPL Revolving Credit Facility each refinanced and replaced the respective existing credit facilities to, among other things, (1) extend the maturity date thereunder, (2) reduce the rate of interest and commitment fees applicable thereunder and (3) make certain other changes to the terms and conditions of the prior credit facilities. 34 Table of Contents • 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 Entity Previous Rating Upgraded Rating Rating Agency October 2023 CCH BBB- BBB S&P August 2023 Cheniere Ba1 Baa3 Moody’s August 2023 CCH Baa3 Baa2 Moody’s August 2023 SPL BBB BBB+ Fitch July 2023 CCH BBB- BBB Fitch February 2023 SPL BBB BBB+ S&P January 2023 Cheniere — BBB- Fitch • During the year ended December 31, 2023, we accomplished the following pursuant to our capital allocation priorities: ◦ We prepaid $1.2 billion of consolidated long-term indebtedness, which excludes prepayments associated with debt refinancing and includes $600 million of debt repurchases in the open market. ◦ We repurchased approximately 9.5 million shares of our common stock as part of our share repurchase program for $1.5 billion. ◦ We paid dividends of $1.620 per share of common stock during the year ended December 31, 2023. ◦ We continued to invest in accretive organic growth, including our investment in the Corpus Christi Stage 3 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.
While 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 LNG market price paid for the natural gas feedstock purchase.
While 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.
Because 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, 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, notwithstanding the operational intent to mitigate risk exposure over time.
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.
As further described in the LNG Revenues section above, the pricing structure 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.
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.
The pricing structure 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.
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.
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 bares 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.
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.
Beginning with the distribution paid in the second quarter of 2022, quarterly distributions by CQP are comprised of a base amount plus a variable amount equal to the remaining available cash per unit, which takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of CQP’s business. 41 Table of Contents • Our 48.6% limited partner interest, 100% general partner interest and incentive distribution rights in CQP limit our right to receive cash held by CQP to the amounts specified by the provisions of CQP’s partnership agreement; and • SPL, CQP and CCH are restricted by affirmative and negative covenants included in certain of their debt agreements in their ability to make certain payments, including distributions, unless specific requirements are satisfied.
Beginning with the distribution paid in the second quarter of 2022, quarterly distributions by CQP are currently comprised of a base amount plus a variable amount equal to the remaining available cash per unit, which takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of CQP’s business; • Our 48.6% limited partner interest, 100% general partner interest and incentive distribution rights in CQP limit our right to receive cash held by CQP to the amounts specified by the provisions of CQP’s partnership agreement; and • SPL and CCH are restricted by affirmative and negative covenants included in certain of their debt agreements in their ability to make certain payments, including distributions, unless specific requirements are satisfied.
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, 2022. 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.
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.
During 2022, we continued to grow our portfolio of SPA and IPM agreements, and 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 portfolio of customer contracts in the future.
During 2023, we continued to grow our portfolio of SPA and IPM agreements, and 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 portfolio of customer contracts in the future.
We market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL through our integrated marketing function, Cheniere Marketing. Cheniere Marketing has a portfolio of long-, medium- and short-term SPAs to deliver commercial LNG cargoes to locations worldwide.
In addition, we market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL through our integrated marketing function, Cheniere Marketing. Cheniere Marketing has a portfolio of long-, medium- and short-term SPAs to deliver commercial LNG cargoes to locations worldwide.
As of December 31, 2022, each of our issuers was in compliance with all covenants related to their respective 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.
As of December 31, 2023, each of our issuers was in compliance with all covenants related to their respective 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.
In addition, SPL and CCH’s operating expenses are managed by our subsidiaries under affiliate agreements, which may require SPL and CCH to advance cash to the respective affiliates, however the cash remains restricted to Cheniere for operation and construction of the Liquefaction Projects; • CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner.
In addition, SPL and CCH’s operating costs are managed by our subsidiaries under affiliate agreements, which may require SPL and CCH to advance cash to the respective affiliates, however the cash remains restricted for operation and construction of the Liquefaction Projects; • CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner.
Fixed fees are fees that are due to us regardless of whether a customer exercises 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.
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.
To ensure that we are able to transport natural gas feedstock to the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity from pipeline companies.
To ensure that we are able to transport natural gas feedstock to the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity from interstate and intrastate pipeline companies.
Notwithstanding the restrictions noted above, we believe that sufficient flexibility exists within the Cheniere complex to enable each independent capital structure to meet its currently anticipated cash requirements.
Despite the restrictions noted above, we believe that sufficient flexibility exists within the Cheniere complex to enable each independent capital structure to meet its currently anticipated cash requirements.
In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt and equity offerings by us or our subsidiaries. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
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 and equity offerings by us or our subsidiaries. The table below provides a summary of our available liquidity (in millions).
Discussion of 2020 items and variance drivers between the year ended December 31, 2021 as compared to December 31, 2020 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, 2021 .
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 fi scal year ended December 31, 2022 .
As of December 31, 2022, we have secured approximately 86% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2023. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2023.
As of December 31, 2023, we have secured approximately 82% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2024. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2024.
Certain of our leases also contain variable payments, such as inflation, which are not included above unless the contract terms require the payment of a fixed amount that is unavoidable. Payments during renewal options that are exercisable at our sole discretion are included only to the extent that the option is believed to be reasonably certain to be exercised.
Certain of our leases also contain variable payments, such as inflation, which are not included above unless the contract terms require in-substance fixed payments that are, in effect, unavoidable. Payments during renewal options that are exercisable at our sole discretion are included only to the extent that the option is believed to be reasonably certain to be exercised.
We have also entered into leases for the use of tug vessels, office space and facilities and land sites. A discussion of our lease obligations can be found in Note 1 2 —Leases of our Notes to Consolidated Financial Statements.
We have also entered into leases for the use of tug vessels, office space, marine equipment and facilities and land sites. A discussion of our lease obligations can be found in Note 12—Leases of our Notes to Consolidated Financial Statements.
Pursuant to the revised capital allocation plan, on September 12, 2022 our Board authorized an 47 Table of Contents increase in the existing share repurchase program by $4.0 billion for an additional three years, beginning on October 1, 2022. As of December 31, 2022, we had up to $3.6 billion available under the share repurchase program.
Pursuant to the revised capital allocation plan, on September 12, 2022 our Board authorized an increase in the existing share repurchase program by $4.0 billion for an additional three years, beginning on October 1, 2022. As of December 31, 2023, we had up to $2.1 billion available under the share repurchase program.
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 and transportation and liquefaction fuel to produce LNG, thus limiting our exposure to fluctuations in U.S. natural gas prices.
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.
Gains and losses on derivative instruments Derivative instruments, which in addition to managing exposure to commodity-related marketing and price risks are utilized to manage exposure to changing interest rates and foreign exchange volatility, are reported at fair value on our Consolidated Financial Statements.
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, which in addition to managing exposure to commodity-related marketing and price risks, are utilized to manage exposure to changing interest rates and foreign exchange volatility, are reported at fair value on our Consolidated Financial Statements.
During the year ended December 31, 2022, we repurchased a total of 9.3 million shares of our common stock for $1.4 billion at a weighted average price per share of $146.88. A discussion of our share repurchase program can be found in
During the year ended December 31, 2023, we repurchased a total of 9.5 million shares of our common stock for $1.5 billion at a weighted average price per share of $155.50. A discussion of our share repurchase program can be found in
Our credit facilities mature between 2024 and 2029. Uncontracted Liquefaction Supply We expect a portion of total production capacity from the Liquefaction Projects that has not yet been contracted under executed agreements as of December 31, 2022 to be available for Cheniere Marketing to market to additional LNG customers.
Uncontracted Liquefaction Supply We expect a portion of total production capacity from the Liquefaction Projects that has not yet been contracted under executed agreements as of December 31, 2023 to be available for Cheniere Marketing to market to additional LNG customers.
Natural Gas Supply, Transportation and Storage Service Agreements We have secured natural gas feedstock for the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal through long-term natural gas supply and 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.
Natural Gas Supply, Transportation and Storage Service Agreements We have secured natural gas feedstock for the CCL Project and the SPL 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.
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.
Future Cash Requirements for Financing under Executed Contracts We are committed to make future cash payments for financing pursuant to certain of our contracts.
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.
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.
The following table summarizes our estimate of material cash requirements for operations and capital expenditures under executed contracts as of December 31, 2022 (in billions): Estimated Payments Due Under Executed Contracts by Period (1) 2023 2024 - 2027 Thereafter Total Purchase obligations (2): Natural gas supply agreements (3) $ 10.5 $ 26.2 $ 29.2 $ 65.9 Natural gas transportation and storage service agreements (4) 0.5 2.1 5.4 8.0 Capital expenditures 1.0 3.1 — 4.1 Other purchase obligations (5) 0.2 0.6 0.6 1.4 Leases (6) 0.8 3.0 3.3 7.1 Total $ 13.0 $ 35.0 $ 38.5 $ 86.5 (1) Agreements in force as of December 31, 2022 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2022.
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) $ 5.8 $ 20.2 $ 25.4 $ 51.4 Natural gas transportation and storage service agreements (4) 0.5 2.0 4.9 7.4 Capital expenditures 1.2 1.7 — 2.9 Leases (5) 0.9 3.0 3.7 7.6 Total $ 8.4 $ 26.9 $ 34.0 $ 69.3 (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.
During the year ended December 31, 2022, selling, general and administrative expense was $0.4 billion, a portion of which was related to leases for office space, which is included in the table of cash requirements for operations and capital expenditures under executed contracts above. Our full-time employee headcount was 1,551 as of December 31, 2022.
During the year ended December 31, 2023, selling, general and administrative expense was $0.5 billion, a portion of which was related to leases for office space, which is included in the table of cash requirements for operations and capital expenditures under executed contracts above.
Notwithstanding any arrangements between TotalEnergies and SPL, payments required to be made by TotalEnergies to SPLNG will continue to be made by TotalEnergies to SPLNG in accordance with its TUA.
Notwithstanding any arrangements between TotalEnergies and SPL, payments required to be made by TotalEnergies to SPLNG will continue to be made by TotalEnergies to SPLNG in accordance with its TUA and we continue to recognize the payments received from TotalEnergies as revenue.
Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.10% to 0.638%, subject to change based on the applicable entity’s credit rating. Issued letters of credit under our credit facilities are subject to letter of credit fees ranging from 1.25% to 1.625%.
Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.075% to 0.525%, subject to change based on the applicable entity’s credit rating. Issued letters of credit under our credit facilities are subject to letter of credit fees ranging from 1.000% to 2.200%, subject to change based on the applicable entity’s credit rating.
Income tax provision (benefit) . $1.2 billion increase between comparable periods primarily attributable to an increase in pretax income. The effective tax rate was 14.8% and 31.3% for the years ended December 31, 2022 and 2021, respectively.
Income tax provision The $2.1 billion unfavorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to an increase in pre-tax income. Our effective tax rate was 17.3% and 14.8% for the years ended December 31, 2023 and 2022, respectively.
Future Sources and Uses of Liquidity Future Sources of Liquidity under Executed Contracts Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration under our SPAs and TUAs which has not yet been recognized as revenue.
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.
Under the SPAs, the customers purchase LNG on either a FOB or delivered at terminal (“DAT”) basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub.
Under the SPAs, the customers purchase LNG on either an FOB basis (delivered to the customer at the Sabine Pass LNG Terminal or the Corpus Christi LNG Terminal, as applicable) 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 41 Table of Contents 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.
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.
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows.
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.
LNG capacity in 2023, and we anticipate that a portion of these contracts will support our future growth. 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.
For commodity derivative instruments related to our IPM agreements, including those entered into during the year ended December 31, 2022 as described further in Overview of Significant Events , 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.
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.
We expect that any potential future expansion at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal would increase cash requirements to support expanded operations, although expansion could be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion. 46 Table of Contents Future Cash Requirements for Financing under Executed Contracts We are committed to make future cash payments for financing pursuant to certain of our contracts.
We expect that any potential future expansion at the Corpus Christi LNG Terminal and the Sabine Pass 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.
We own a 48.6% limited partner interest in CQP in the form of 239.9 million common units, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. During the year ended December 31, 2022, CQP paid $947 million in distributions to its non-controlling interest.
We own a 48.6% limited partner interest in CQP in the form of 239.9 million common units, 100% of the general partner interest and 100% of the incentive distribution rights, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public.
Additional Future Cash Requirements for Financing CQP Distribution CQP is required by its partnership agreement to, within 45 days after the end of each quarter, distribute to unitholders all available cash at the end of a quarter less the amount of any reserves established by its general partner.
We had $435 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2023. 45 Table of Contents Additional Future Cash Requirements for Financing CQP Distributions CQP is required by its partnership agreement to, within 45 days after the end of each quarter, distribute to unitholders all available cash at the end of a quarter less the amount of any reserves established by its general partner.
See Financially Disciplined Growth section for further discussion. 45 Table of Contents Corpus Christi Stage 3 Project The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of January 31, 2023: Overall project completion percentage 24.5% Completion percentage of: Engineering 41.3% Procurement 36.9% Subcontract work 29.5% Construction 2.2% Date of expected substantial completion 2H 2025 - 1H 2027 Leases Our obligations under our lease arrangements primarily consist of LNG vessel time charters with terms of up to 15 years to ensure delivery of cargoes sold on a DAT basis.
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 Leases Our obligations under our lease arrangements primarily consist of LNG vessel time charters with terms of up to 15 years to ensure delivery of cargoes sold on a DAT basis.
These volumes are expected to be primarily sourced by LNG produced by the Liquefaction Projects but supplemented by volumes procured from other locations worldwide, as needed.
These volumes are expected to be primarily sourced by LNG produced by the Liquefaction Projects but supplemented by volumes procured from other locations worldwide, as needed. Substantially all of our contracted capacity is from contracts with terms exceeding 10 years.
We include contracts with unsatisfied conditions precedent if the conditions are currently expected to be met. 44 Table of Contents (3) Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2022.
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.
We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We operate two natural gas liquefaction and export facilities at Sabine Pass, Louisiana and near Corpus Christi, Texas (respectively, the “Sabine Pass LNG Terminal” and “Corpus Christi LNG Terminal”) with a total of nine operational natural gas liquefaction Trains.
We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We operate two natural gas liquefaction and export facilities at Sabine Pass, Louisiana and near Corpus Christi, Texas. For further discussion of our business, see Items 1. and 2. Business and Properties .
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 we make a positive FID.
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 we make a positive FID. 42 Table of Contents 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.
Additionally, 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.
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 following table summarizes our estimate of future material sources of liquidity to be received from executed contracts as of December 31, 2022 (in billions): Estimated Revenues Under Executed Contracts by Period (1) 2023 2024 - 2027 Thereafter Total LNG revenues (fixed fees) (2) $ 6.1 $ 26.1 $ 79.8 $ 112.0 LNG revenues (variable fees) (2) (3) 10.5 46.2 144.5 201.2 Regasification revenues 0.1 0.5 0.2 0.8 Financial derivatives (4) (0.1) — — (0.1) Other revenues (5) 0.2 0.2 0.1 0.5 Total $ 16.8 $ 73.0 $ 224.6 $ 314.4 (1) Agreements in force as of December 31, 2022 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2022.
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) $ 6.3 $ 27.1 $ 77.6 $ 111.0 LNG revenues (variable fees) (3) 7.0 40.8 140.5 188.3 Total $ 13.3 $ 67.9 $ 218.1 $ 299.3 (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 variable fees under our SPAs were generally sized with the intention to cover the costs of gas purchases and variable transportation and liquefaction fuel to produce the LNG to be sold under each such SPA.
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. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A-, A3 and A- by S&P, Moody’s and Fitch, respectively.
The sources of liquidity at SPL, CQP and CCH primarily fund the cash requirements of the respective entity, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by Cheniere Marketing, is available to enable Cheniere to meet its cash requirements.
The sources of liquidity at SPL, CQP and CCH primarily fund the cash requirements of the respective entity, and any remaining liquidity not subject to restriction, as supplemented by unrestricted liquidity provided by Cheniere Marketing, is available to enable Cheniere to meet its cash requirements. 40 Table of Contents 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.
The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022.
The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material.
(3) LNG revenues (variable fees) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2022.
(3) LNG revenues (variable fees) reflect the assumption of delivery of all contractual volumes, irrespective of any contractual right of non-delivery. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2023.
The majority of the contracted capacity is comprised of fixed-price, long-term SPAs that SPL and CCL have executed with third parties to sell LNG from the SPL Project and the CCL Project, including the Corpus Christi Stage 3 Project. Substantially all of our contracted capacity is from contracts with terms exceeding 10 years.
Through our SPAs and IPM agreements, we have contracted substantially all of the total anticipated production from the Liquefaction Projects through the mid-2030s. The majority of the contracted capacity is comprised of fixed-price, long-term SPAs that SPL and CCL have executed with third parties to sell LNG from the Liquefaction Projects.
(6) Leases include payments under (1) operating leases, (2) finance leases, (3) short-term leases and (4) vessel time charters that were executed as of December 31, 2022 but will commence in the future.
(4) Includes $1.3 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements, of which $1.0 billion had unsatisfied contractual conditions. (5) Leases include payments under (1) operating leases, (2) finance leases, (3) short-term leases and (4) vessel time charters that were executed as of December 31, 2023 but will commence in the future.
December 31, 2022 Cash and cash equivalents (1) $ 1,353 Restricted cash and cash equivalents designated for the following purposes: SPL Project 92 CCL Project 738 Cash held by our subsidiaries that is restricted to Cheniere 304 Total restricted cash and cash equivalents 1,134 Available commitments under our credit facilities (2): SPL’s working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”) 872 CQP’s credit facilities 750 CCH Credit Facility 3,260 CCH Working Capital Facility 1,322 Cheniere’s revolving credit facility (the “Cheniere Revolving Credit Facility”) 1,250 Total available commitments under our credit facilities 7,454 Total available liquidity $ 9,941 (1) Amounts presented include balances held by our consolidated variable interest entity, CQP, as discussed in Note 9 —Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements.
Future material sources of liquidity are discussed below. 39 Table of Contents December 31, 2023 Cash and cash equivalents (1) $ 4,066 Restricted cash and cash equivalents (1) 459 Available commitments under our credit facilities (2): SPL Revolving Credit Facility 720 CQP Revolving Credit Facility 1,000 CCH Credit Facility 3,260 CCH Working Capital Facility 1,345 Cheniere’s revolving credit agreement (the “Cheniere Revolving Credit Facility” ) 1,250 Total available commitments under our credit facilities 7,575 Total available liquidity $ 12,100 (1) Amounts presented include balances held by our consolidated variable interest entity, CQP, and its subsidiaries, as discussed in Note 9 —Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements.
Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures.
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 . Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures.
Corp, a subsidiary of ARC Resources, Ltd., to purchase 140,000 MMBtu per day of natural gas at a price based on Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years commencing with commercial operations of Train 7 of the Corpus Christi Stage 3 Project.
Corp., a subsidiary of ARC Resources Ltd., to purchase 140,000 MMBtu per day of natural gas at a price based on the Dutch Title Transfer Facility ( “TTF” ), less a fixed regasification fee, fixed LNG shipping costs and a fixed liquefaction fee, for a term of approximately 15 years commencing with commercial operations of the first train of the SPL Expansion Project.
Consequently, we believe we are well positioned to help meet the increased demand of our international LNG customers to overcome their supply shortages. 36 Table of Contents Results of Operations Consolidated results of operations Year Ended December 31, (in millions, except per share data) 2022 2021 Variance Revenues LNG revenues $ 31,804 $ 15,395 $ 16,409 Regasification revenues 1,068 269 799 Other revenues 556 200 356 Total revenues 33,428 15,864 17,564 Operating costs and expenses Cost of sales (excluding items shown separately below) 25,632 13,773 11,859 Operating and maintenance expense 1,681 1,444 237 Selling, general and administrative expense 416 325 91 Depreciation and amortization expense 1,119 1,011 108 Development expense 16 7 9 Other 5 5 — Total operating costs and expenses 28,869 16,565 12,304 Income (loss) from operations 4,559 (701) 5,260 Other income (expense) Interest expense, net of capitalized interest (1,406) (1,438) 32 Loss on modification or extinguishment of debt (66) (116) 50 Interest rate derivative gain (loss), net 2 (1) 3 Other income (expense), net 5 (22) 27 Total other expense (1,465) (1,577) 112 Income (loss) before income taxes and non-controlling interest 3,094 (2,278) 5,372 Less: income tax provision (benefit) 459 (713) 1,172 Net income (loss) 2,635 (1,565) 4,200 Less: net income attributable to non-controlling interest 1,207 778 429 Net income (loss) attributable to common stockholders $ 1,428 $ (2,343) $ 3,771 Net income (loss) per share attributable to common stockholders—basic $ 5.69 $ (9.25) $ 14.94 Net income (loss) per share attributable to common stockholders—diluted $ 5.64 $ (9.25) $ 14.89 Volumes loaded and recognized from the Liquefaction Projects Year Ended December 31, 2022 (in TBtu) Operational Commissioning Total Volumes loaded during the current period 2,295 13 2,308 Volumes loaded during the prior period but recognized during the current period 49 1 50 Less: volumes loaded during the current period and in transit at the end of the period (56) — (56) Total volumes recognized in the current period 2,288 14 2,302 37 Table of Contents Components of LNG revenues and corresponding LNG volumes delivered Year Ended December 31, 2022 2021 Variance LNG revenues (in millions) : LNG from the Liquefaction Projects sold under third party long-term agreements (1) $ 20,702 $ 11,990 $ 8,712 LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements 10,169 4,361 5,808 LNG procured from third parties 760 499 261 Net derivative losses (328) (1,776) 1,448 Other revenues 501 321 180 Total LNG revenues $ 31,804 $ 15,395 $ 16,409 Volumes delivered as LNG revenues (in TBtu) : LNG from the Liquefaction Projects sold under third party long-term agreements (1) 1,926 1,608 318 LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements 362 344 18 LNG procured from third parties 29 45 (16) Total volumes delivered as LNG revenues 2,317 1,997 320 (1) Long-term agreements include agreements with an initial tenure of 12 months or more.
Results of Operations Consolidated results of operations Year Ended December 31, (in millions, except per share data) 2023 2022 Variance Revenues LNG revenues $ 19,569 $ 31,804 $ (12,235) Regasification revenues 135 1,068 (933) Other revenues 690 556 134 Total revenues 20,394 33,428 (13,034) Operating costs and expenses Cost of sales (excluding items shown separately below) 1,356 25,632 (24,276) Operating and maintenance expense 1,835 1,681 154 Selling, general and administrative expense 474 416 58 Depreciation and amortization expense 1,196 1,119 77 Other 44 21 23 Total operating costs and expenses 4,905 28,869 (23,964) Income from operations 15,489 4,559 10,930 Other income (expense) Interest expense, net of capitalized interest (1,141) (1,406) 265 Gain (loss) on modification or extinguishment of debt 15 (66) 81 Interest and dividend income 211 57 154 Other income (expense), net 4 (50) 54 Total other expense (911) (1,465) 554 Income before income taxes and non-controlling interest 14,578 3,094 11,484 Less: income tax provision 2,519 459 2,060 Net income 12,059 2,635 9,424 Less: net income attributable to non-controlling interest 2,178 1,207 971 Net income attributable to common stockholders $ 9,881 $ 1,428 $ 8,453 Net income per share attributable to common stockholders—basic $ 40.99 $ 5.69 $ 35.30 Net income per share attributable to common stockholders—diluted $ 40.72 $ 5.64 $ 35.08 36 Table of Contents Volumes loaded and recognized from the Liquefaction Projects Year Ended December 31, (in TBtu) 2023 2022 Variance Volumes loaded during the current period 2,299 2,295 4 Volumes loaded during the prior period but recognized during the current period 56 49 7 Less: volumes loaded during the current period and in transit at the end of the period (37) (56) 19 Total volumes recognized in the current period 2,318 2,288 30 Components of LNG revenues and corresponding LNG volumes delivered Year Ended December 31, 2023 2022 Variance LNG revenues (in millions) : LNG from the Liquefaction Projects sold under third party long-term agreements (1) $ 12,820 $ 20,702 $ (7,882) LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements 6,028 10,169 (4,141) LNG procured from third parties 359 760 (401) Net derivative gains (losses) 110 (328) 438 Other revenues 252 501 (249) Total LNG revenues $ 19,569 $ 31,804 $ (12,235) Volumes delivered as LNG revenues (in TBtu) : LNG from the Liquefaction Projects sold under third party long-term agreements (1) 2,034 1,926 108 LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements 284 362 (78) LNG procured from third parties 35 29 6 Total volumes delivered as LNG revenues 2,353 2,317 36 (1) Long-term agreements include agreements with an initial tenor of 12 months or more.
In September 2022, certain of our subsidiaries entered the pre-filing review process with the FERC under the National Environmental Policy Act for CCL Midscale Trains 8 and 9.
In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project. In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project.
During the years ended December 31, 2022 and 2021, we realized offsets to LNG terminal costs of $204 million and $319 million, corresponding to 15 TBtu and 42 TBtu, respectively, that were related to the sale of commissioning cargoes from the Liquefaction Projects.
During the year ended December 31, 2022, we realized offsets to LNG terminal costs of $204 million corresponding to 15 TBtu attributable to the sale of commissioning cargoes from Train 6 of the SPL Project. We did not have any commissioning cargoes during the year ended December 31, 2023.
Excluding contracts with terms less than 10 years and contracts executed to support additional liquefaction capacity at the Corpus Christi LNG Terminal beyond the Corpus Christi Stage 3 Project, our SPAs and IPM agreements had approximately 17 years of weighted average remaining life as of December 31, 2022.
Excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation, our SPAs and IPM agreements had approximately 16 years of weighted average remaining life as of December 31, 2023.
Exports from our Liquefaction Projects reached 44 million tonnes in aggregate, representing over 85% of the gain in the U.S. total for the year.
Exports from our Liquefaction Projects reached 44 million tonnes in aggregate, representing over 50% 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.
Additionally, we are not aware of any specific adverse direct or indirect effects of the war on our supply chain.
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.
Inclusive of amounts under contracts with unsatisfied conditions precedent as of December 31, 2022, we have secured up to 14,094 TBtu of natural gas feedstock through agreements with remaining terms that range up to 15 years.
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 43 Table of Contents to 12,794 TBtu of natural gas feedstock through agreements with remaining fixed terms of up to approximately 15 years.
The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2022 (in billions): Estimated Payments Due Under Executed Contracts by Period (1) 2023 2024 - 2027 Thereafter Total Debt (2) $ 0.5 $ 10.1 $ 14.5 $ 25.1 Interest payments (2) 1.2 3.8 2.0 7.0 Total $ 1.7 $ 13.9 $ 16.5 $ 32.1 (1) The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022.
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 $ 0.3 $ 11.1 $ 12.5 $ 23.9 Interest payments 1.3 3.3 1.8 6.4 Total $ 1.6 $ 14.4 $ 14.3 $ 30.3 (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.
Full discussion of financial derivatives can be found in Note 7 —Derivative Instruments of our Notes to Consolidated Financial Statements. Additional Future Sources of Liquidity Available Commitments under Credit Facilities As of December 31, 2022, we had $7.5 billion in available commitments under our credit facilities, subject to compliance with the applicable covenants, to potentially meet liquidity needs.
Available Commitments under Credit Facilities As of December 31, 2023, we had $7.6 billion in available commitments under our credit facilities, as detailed earlier in the table summarizing our available liquidity, subject to compliance with the applicable covenants, to potentially meet liquidity needs. Our credit facilities mature between 2026 and 2029.
SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with TotalEnergies, whereby SPL gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG that started in 2019.
SPL has a partial TUA assignment agreement with TotalEnergies, whereby SPL gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG.
The continued strength and stability of our long-term cash flows served as the foundation of our revised comprehensive, long-term capital allocation plan announced in 2022, which includes an increased share repurchase authorization, lowered consolidated long-term leverage target, increased dividends and continued investment in accretive organic growth. 33 Table of Contents Overview of Significant Events Our significant events since January 1, 2022 and through the filing date of this Form 10-K include the following: Strategic • In February 2023, certain subsidiaries of Cheniere Partners initiated the pre-filing review process with the FERC under the National Environmental Policy Act for an expansion adjacent to the SPL Project consisting of up to three Trains with an expected total production capacity of approximately 20 mtpa of LNG. • On January 2, 2023, Corey Grindal, formerly Executive Vice President, Worldwide Trading, was promoted to Executive Vice President and Chief Operating Officer of the Company. • On October 3, 2022, our Board appointed Mr.
The continued strength and stability of our long-term cash flows served as the foundation of our revised comprehensive, long-term capital allocation plan announced in 2022, which includes an increased share repurchase authorization, decreased consolidated long-term leverage target, increased dividends and continued investment in accretive organic growth. 33 Table of Contents 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 November 2023, we announced that SPL Stage V entered into an IPM agreement with ARC Resources U.S.
Operating costs and expenses . $12.3 billion increase between comparable periods primarily attributable to: • $9.9 billion increase in cost of sales excluding the effect of derivative losses described below, primarily as a result of $8.9 billion in increased cost of natural gas feedstock largely due to higher U.S. natural gas prices and, to a lesser extent, from increased volume of natural gas liquified and delivered as LNG, as discussed above under the caption Revenues; • $2.0 billion increase in derivative losses from changes in fair value and settlements included in cost of sales, from $4.2 billion in the year ended December 31, 2021 to $6.2 billion in the year ended December 31, 2022, primarily due to non-cash unfavorable changes in fair value of our commodity derivatives that are attributed to positions indexed to international gas prices; and • $237 million increase in operating and maintenance expense primarily due to increased natural gas transportation and storage capacity demand charges following the Train 6 Completion and the Train 3 Completion as well as third party service and maintenance contract costs.
Operating costs and expenses (recoveries) The $24.0 billion favorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to: • $14.0 billion favorable variance from changes in fair value and settlements of derivatives included in cost of sales, from $6.2 billion of loss in the year ended December 31, 2022 to $7.8 billion of gain in the year ended December 31, 2023, primarily related to non-cash favorable changes in fair value of our IPM agreements as described above under the caption Net income attributable to common stockholders ; and • $10.3 billion decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of $9.6 billion in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices .
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, 2022 will be driven by future sources of liquidity and future cash requirements as further discussed below under the caption Future Sources and Uses of Liquidity .
(2) 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.
Interest As of December 31, 2022, our senior notes had a weighted average contractual interest rate of 4.76%. We have various credit facilities indexed to LIBOR, which is expected to be phased out in 2023.
Interest As of December 31, 2023, our senior notes had a weighted average contractual interest rate of 4.73%. All of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities.
See further discussion in Note 11 —Debt of our Notes to Consolidated Financial Statements. Debt As of December 31, 2022, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $25.1 billion and credit facilities with no outstanding balances.
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 $23.9 billion and credit facilities with no outstanding loan balances.
Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A-, A3 and A- by S&P, Moody’s and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 1 3 —Revenues of our Notes to Consolidated Financial Statements.
A discussion of revenues under our SPAs can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements.
Full discussion of the partial TUA assignment and SPLNG’s revenues under the TUA agreements can be found in Note 1 3 —Revenues of our Notes to Consolidated Financial Statements. 43 Table of Contents Financial Derivatives Cheniere Marketing has entered into financial derivatives to minimize future cash flow variability associated with Cheniere Marketing’s LNG agreements.
Costs incurred by SPL to TotalEnergies under this partial TUA assignment agreement are recognized in operating and maintenance expense. Full discussion of the partial TUA assignment and SPLNG’s revenues under the TUA agreements can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements.
(“TotalEnergies”) under which TotalEnergies is required to pay fixed monthly fees, whether or not it uses the approximately 1 Bcf/d of the regasification capacity it has reserved at the Sabine Pass LNG Terminal. TotalEnergies is obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually, prior to inflation adjustments, for 20 years that commenced in 2009.
Additional Future Sources of Liquidity Regasification Revenues SPLNG has a long-term, third party TUA with TotalEnergies, under which TotalEnergies is required to pay fixed fees of approximately $125 million annually, whether or not it uses the regasification capacity it has reserved.
As of December 31, 2022, assets of CQP, which are included in our Consolidated Balance Sheets, included $0.9 billion of cash and cash equivalents. (2) Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2022.
As of December 31, 2023, assets of CQP and its subsidiaries, which are included in our Consolidated Balance Sheets, included $575 million of cash and cash equivalents and $56 million of restricted cash and cash equivalents.
Through our SPAs and IPM agreements, we have contracted approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s, inclusive of contracts executed to support additional liquefaction capacity at the Corpus Christi LNG Terminal beyond the Corpus Christi Stage 3 Project.
Through our SPAs and IPM agreements, we have contracted approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s with approximately 16 years of weighted average remaining life as of December 31, 2023, excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.
As a result, net income attributable to non-controlling interest will be impacted in future periods as volumes are delivered under the aforementioned contracts and by gains and losses from changes in the fair value of the IPM agreement, which is accounted for as a derivative. 40 Table of Contents 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.
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.
Revised Capital Allocation Plan As described in Overview of Significant Events , in September 2022, our Board approved a revised comprehensive long-term capital allocation plan.
During the year ended December 31, 2023, $1.0 billion in distributions were paid to our non-controlling interests. Capital Allocation Plan In September 2022, our Board approved a revised comprehensive long-term capital allocation plan.
Removed
In addition to natural gas liquefaction facilities at the Sabine Pass LNG Terminal (the “SPL Project”), the Sabine Pass LNG Terminal also has operational regasification facilities and pipelines that interconnect our facilities to several interstate and intrastate natural gas pipelines.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

2 edited+0 added−2 removed1 unchanged
Biggest changeIn order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions): December 31, 2022 December 31, 2021 Fair Value Change in Fair Value Fair Value Change in Fair Value Liquefaction Supply Derivatives $ (10,019) $ 2,249 $ (4,038) $ 903 LNG Trading Derivatives (46) 15 (400) 38 See Note 7 —Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments.
Biggest changeIn order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions): December 31, 2023 December 31, 2022 Fair Value Change in Fair Value Fair Value Change in Fair Value Liquefaction Supply Derivatives $ (2,117) $ 1,526 $ (10,019) $ 2,249 LNG Trading Derivatives 10 12 (46) 15 See Note 7 —Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments. 50 Table of Contents
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Marketing and Trading Commodity Price Risk We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project, and associated economic hedges (collectively, “Liquefaction Supply Derivatives”).
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Marketing and Trading Commodity Price Risk We have commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project, and associated economic hedges (collectively, the “Liquefaction Supply Derivatives” ).
Removed
Foreign Currency Exchange Risk We have entered into foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with operations in countries outside of the United States (“FX Derivatives”).
Removed
In order to test the sensitivity of the fair value of the FX Derivatives to changes in FX rates, management modeled a 10% change in FX rate between the U.S. dollar and the applicable foreign currencies as follows (in millions): December 31, 2022 December 31, 2021 Fair Value Change in Fair Value Fair Value Change in Fair Value FX Derivatives $ (28) $ 3 $ 12 $ 2 See Note 7 —Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our foreign currency derivative instruments. 53 Table of Contents

Other LNG 10-K year-over-year comparisons