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What changed in Cheniere Energy, Inc.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of Cheniere Energy, Inc.'s 2024 and 2025 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 2025 report.

+246 added−415 removedSource: 10-K (2026-02-26) vs 10-K (2025-02-20)

Top changes in Cheniere Energy, Inc.'s 2025 10-K

246 paragraphs added · 415 removed · 170 edited across 7 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

85 edited+16 added−198 removed69 unchanged
Biggest changeNatural 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; 24 T able of Contents • 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 exported LNG, natural gas or alternative energy sources, which may reduce the demand for exported LNG and/or natural gas; • political conditions in customer regions; • sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events; • adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and • cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Biggest changeNatural 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: • increasingly competitive North American LNG landscape; • 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 worldwide; • increased demand for natural gas in North America; 26 Table of Contents • increased natural gas production worldwide, either domestically or deliverable by pipelines, which could suppress demand for LNG; • decreased oil and natural gas exploration activities which may decrease the production of natural gas in North America; • 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 exported North American LNG, natural gas or alternative energy sources, which may reduce the demand for exported North American 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 North American LNG compared to other sources, which may decrease LNG exports from North America; and • cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
While 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.
While substantially all of our long-term third party customer arrangements are executed with a creditworthy 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.
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.
Our investment decision on the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and any potential future expansion of LNG facilities, including the SPL Expansion Project and the CCL Expansion Project, relies on cost estimates developed initially through front end engineering and design studies.
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.
Timely and cost-effective completion of the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL 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.
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.
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, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL 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 the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, 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, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project, or result in a contractor’s unwillingness to perform further work.
Factors which may negatively affect potential demand for LNG from our Liquefaction Projects are diverse and include, among others: • increases in worldwide LNG production capacity and availability of LNG for market supply; • increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply; • increases in the cost to supply natural gas feedstock to our Liquefaction Projects; • decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel; • decreases in the price of non-U.S.
Factors which may negatively affect potential demand for LNG from our Liquefaction Projects are diverse and include, among others: • increases in worldwide LNG production capacity and availability of LNG for market supply; • decreases in demand for LNG or increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply; • increases in the cost to supply natural gas feedstock to our Liquefaction Projects; • increases in the cost to supply power to our Liquefaction Projects; • decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel; • decreases in the price of non-U.S.
Additionally, while our vessel charters allow us to secure fixed rates under long term contracts (in certain cases subject to inflation) and we generally structure our SPAs to recover any increase in such costs, our profitability, particularly relating to our short term or spot LNG sales outside of our SPAs, is largely dependent on the strength of international LNG markets.
Additionally, while our vessel charters allow us to secure fixed rates under long term contracts (in certain cases subject to inflation) and we generally structure our SPAs to recover increase in such costs, our profitability, particularly relating to our short term or spot LNG sales outside of our SPAs, is largely dependent on the strength of international LNG markets.
Business and Properties, it is expected that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to alternative fossil fuel energy sources such as oil and coal.
Business and Properties, it is expected that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to fossil fuel energy sources such as oil and coal.
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.
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 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.
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.
Cost overruns and delays in the construction of our expansion projects, including the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project and the CCL 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 cyber attack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Projects, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.
A cyberattack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Projects, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.
If any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be adversely impacted.
If any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or for transporters to continue shipping natural gas to us from producing regions or to end markets could be adversely impacted.
A cyber attack involving our business or operational control systems or related infrastructure, or that of third parties pipelines with whom we do business, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.
A cyberattack involving our business or operational control systems or related infrastructure, or that of third parties pipelines with whom we do business, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.
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.
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 or otherwise volatile effect on our earnings reported under GAAP. For example, as described in Results of Operations in Item 7.
Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction facilities in the United States. As described in Market Factors and Competition in Items 1. and 2.
Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction facilities in the U.S. As described in Market Factors and Competition in Items 1. and 2.
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.
In addition, prior to completion of the Corpus Christi Stage 3 Project, CCH is also required to confirm before making a distribution 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.
There may be impediments to the transport of LNG, such as shortages of LNG vessels worldwide or operational impacts on LNG shipping, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. We sell a significant amount of our LNG under DAT terms requiring delivery to international destinations.
There may be impediments to the transport of LNG to customers, such as shortages of LNG vessels worldwide or operational impacts on LNG shipping, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. We sell a significant amount of our LNG under DAP terms requiring delivery to international destinations.
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.
A shortage in the labor pool of skilled workers, remoteness of our site locations, general inflationary pressures, changes in 28 Table of Contents 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.
Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Projects.
Cyberattacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyberattacks, including third party pipelines which supply natural gas to our Liquefaction Projects.
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.
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, 29 Table of Contents political opposition or local community resistance to our operations could impede the operation and construction of our infrastructure.
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 and the ability of Bechtel Energy Inc. ( “Bechtel” ) and our other contractors to execute successfully under their agreements.
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 and the ability of Bechtel and our other contractors to execute successfully under their agreements.
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 21 T able of Contents 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.
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.
Any change orders could result in longer construction periods, higher construction costs, including increased commodity prices (particularly nickel and steel) and escalating labor costs, or both. Additionally, our SPAs generally provide that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations.
Any change orders could result in longer construction periods, higher construction costs, including increased commodity prices (particularly nickel and steel) and escalating labor costs, or both. Additionally, certain of our SPAs provide that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations.
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.
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 25 Table of Contents owner, including disruptions due to off-hire and downtime periods or shipping delays.
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, 2024, 2023 and 2022.
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, 2025, 2024 and 2023.
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.
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 operations 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.
It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. 28 T able of Contents In 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. In 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.
In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our LNG terminals, marine berths and pipelines, including FERC, PHMSA, EPA and the United States Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs.
In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our LNG terminals, marine berths and pipelines, including FERC, PHMSA, EPA and the U.S. Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs.
However, as a result of the factors described above and other factors, the LNG we produce may not remain a long term competitive source of energy internationally, particularly when our existing long term contracts begin to expire.
However, as a result of the factors described above and other factors, the LNG we produce may not remain a long 27 Table of Contents term competitive source of energy internationally, particularly when our existing long term contracts begin to expire.
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.
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 the CCL Midscale Trains 8 & 9 Project, as well as the SPL Expansion Project and the CCL Expansion Project if positive FIDs are made on these expansion projects.
Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Projects in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Projects, may also be impacted by an increase in natural gas prices in the United States. As described in General in Items 1. and 2.
Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Projects in certain markets. The cost of LNG supplies from North America, including the Liquefaction Projects, may also be impacted by an increase in natural gas prices in North America. As described in General in Items 1. and 2.
For 19 T able of Contents certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
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. 22 T able of Contents 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. We do not, nor do we intend to, maintain insurance against all of these risks and losses.
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.
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.
In addition to restrictions on the ability of us, CQP, SPL and CCH to make distributions or incur additional indebtedness, the agreements governing our indebtedness also contain various other covenants that may prevent us from engaging in beneficial transactions, including limitations on our ability to: • make certain investments; • purchase, redeem or retire equity interests; • issue preferred stock; • sell or transfer assets; • incur liens; • enter into transactions with affiliates; • consolidate, merge, sell or lease all or substantially all of our assets; and • enter into sale and leaseback transactions.
In addition to restrictions on the ability of us, CQP, SPL and CCH to make distributions or incur additional indebtedness, as further described in the immediately preceding risk factor , the agreements governing our indebtedness also contain various other covenants that may prevent us from engaging in beneficial transactions, including limitations on our ability to: • make certain investments; • purchase, redeem or retire equity interests; • issue preferred stock; • sell or transfer assets; • incur liens; • enter into transactions with affiliates; • consolidate, merge, sell or lease all or substantially all of our assets; and • enter into sale and leaseback transactions.
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. 26 T able of Contents We depend on our executive officers for various activities.
In addition, we are also subject to increased competition for skilled workers from new entrants to the LNG market. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. We depend on our executive officers for various activities.
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.
We will require significant additional funding to be able to commence construction of the SPL Expansion Project, the CCL 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.
Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside North America, which could increase the available supply of natural gas outside North America and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. 27 T able of Contents 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. 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.
However, future adverse weather events and collateral effects, or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or interruption of operations at our terminals or related infrastructure, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of our Liquefaction Projects or our other facilities.
However, future adverse weather events and collateral effects, or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or 22 Table of Contents interruption of operations at our terminals or related infrastructure, or interruptions to our power supply, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of our Liquefaction Projects or our other facilities.
We continuously pursue liquefaction expansion opportunities and other projects along the LNG value chain. As described further in Items 1. and 2. Business and Properties , we are currently developing the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project.
We continuously pursue liquefaction expansion opportunities and other projects along the LNG value chain. As described further in Items 1. and 2. Business and Properties , we are currently developing the SPL Expansion Project and the CCL Expansion Project.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the U.S., may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the U.S.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, our net income for the years ended December 31, 2024 and 2023 included $1.3 billion and $8.0 billion of gains, respectively, resulting from changes in the fair values of our derivatives (before tax and the impact of non-controlling interests), substantially all of which 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 years ended December 31, 2025 and 2024 included $3.6 billion and $1.3 billion of gains, respectively, resulting from changes in the fair values of our derivatives (before 21 Table of Contents tax and the impact of non-controlling interests), substantially all of which were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreements.
Operations of the Liquefaction Projects are dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally.
Operations of the Liquefaction Projects are dependent upon the ability of our SPA customers to deliver LNG supplies from North America, which is primarily dependent upon LNG being a competitive source of energy internationally.
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. If we are unable to obtain sufficient funding, we may be unable to fully execute our business strategy.
Our ability to complete development and/or construction of additional Trains, including the SPL Expansion Project and the CCL Expansion Project, will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our growth strategy.
In the United States, we are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions.
In the U.S., we are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions.
The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Liquefaction Projects, 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.
The design, construction and operation of interstate natural gas pipelines, Trains, including those at the Liquefaction Projects, the SPL Expansion Project, the CCL 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.
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 T able 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 U.S. could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. We face competition based upon the international market price for LNG.
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. 23 T able of Contents 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 security situation in the Gulf of Aden and congestion at the Panama Canal; and • weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.
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’ regulations; • 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 security situation in the Gulf of Aden and congestion at the Panama Canal; and • weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.
Business and Properties, 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.
Business and Properties, as of December 31, 2025, we have contracted through our SPAs and IPM agreements approximately 90% 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 from SPAs that are conditional on additional liquefaction capacity beyond what is currently in construction or operation, subject to unilateral waiver by us.
Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2024, we had SPAs with initial terms of 10 or more years with a total of 29 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, 2025, we had SPAs with initial terms of 10 or more years with approximately 30 different third party customers, with customers under common control being considered a single customer.
In February 2024, certain of our subsidiaries submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project.
In February 2024, certain of our subsidiaries submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project and in June 2025, certain of our subsidiaries submitted an updated application to the FERC reflecting a two-phased approach to the SPL Expansion Project.
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.
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.
Our LNG terminal infrastructure and LNG facilities located in or near Corpus Christi, Texas and Sabine Pass, Louisiana are designed in accordance with requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards , and all applicable industry codes and standards.
Our LNG terminal infrastructure and LNG facilities are designed in accordance with the requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards , and all applicable industry codes and standards.
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.
The inability to achieve acceptable funding may cause a delay in the development or construction of the SPL Expansion Project, the CCL Expansion Project or any additional expansion projects, which could have a material adverse effect on our growth strategy, financial condition, operating results, cash flow and liquidity.
As of December 31, 2024, we had, on a consolidated basis, $2.6 billion of cash and cash equivalents (of which $270 million was held by CQP), $552 million of restricted cash and cash equivalents (of which $109 million was held by CQP), a total of $7.7 billion of available commitments under our credit facilities and $23.1 billion of total debt outstanding (before unamortized discount and debt issuance costs).
As of December 31, 2025, we had, on a consolidated basis, $1.1 billion of cash and cash equivalents (of which $182 million was held by our consolidated variable interest entities ( “VIEs” )), $485 million of restricted cash and cash equivalents (of which $22 million was held by our VIEs), a total of $7.2 billion of available commitments under our credit facilities and $23.0 billion of total debt outstanding (before unamortized discount and debt issuance costs).
Significant increases in the cost of a liquefaction project or significant construction delays could impact the commercial viability of the project as well as require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays), thereby negatively impacting our business and limiting our growth prospects.
As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. 24 Table of Contents Significant increases in the cost of a liquefaction project or significant construction delays could impact the commercial viability of the project as well as require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays), thereby negatively impacting our business and limiting our growth prospects.
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.
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. 20 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.
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.
We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception which applies the accrual method of accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations. 30 Table of Contents Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected. We and our subsidiaries may be restricted under the terms of our and their indebtedness from paying dividends or distributions under certain circumstances, which could materially and adversely affect our liquidity.
We and our subsidiaries may be restricted under the terms of our and their indebtedness from paying dividends or distributions under certain circumstances, which could materially and adversely affect our liquidity.
We use derivative instruments to manage certain risks, including commodity-related price risk. The extent of our derivative position at any given time depends on our assessment of risks and related exposures for these commodities.
The extent of our derivative position at any given time depends on our assessment of risks and related exposures for these commodities.
Our share repurchase program does not obligate us to acquire a specific number of shares during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board may consider when declaring dividends, among others. 20 T able of Contents 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.
Our share repurchase program does not obligate us to acquire a specific number of shares during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board may consider when declaring dividends, among others.
The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.5 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
The FERC’s jurisdiction under the NGA allows the imposition of civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC thereunder, up to $1.6 million per day for each violation.
As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
LNG, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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.
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. 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.
As of December 31, 2024 and 2023, we had collateral posted with counterparties by us of $128 million and $18 million, respectively, which are included in margin deposits in our Consolidated Balance Sheets.
In addition, our liquidity may be adversely impacted by the cash margin requirements of the respective commodity exchanges or over-the-counter arrangements. As of December 31, 2025 and 2024, we had collateral posted with counterparties by us of $76 million and $128 million, respectively, which are included in margin deposits in our Consolidated Balance Sheets.
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.
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. 23 Table of Contents We are dependent on our EPC partners and other contractors for the successful completion of the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project.
However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including composition changes in the quality of feed gas received from third parties, non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply of natural gas to our pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the immediately preceding risk factor .
If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms. 18 T able of Contents 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.
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.
Any inability to pay or increase dividends or distributions by us or our subsidiaries as a result of the foregoing restrictions could have a material adverse effect on our liquidity. Our use of derivative instruments, including our IPM agreements, to manage risks could adversely affect our earnings reported under GAAP and our liquidity.
Any inability to pay or increase dividends or distributions by us or our subsidiaries as a result of the foregoing restrictions could have a material adverse effect on our liquidity. 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.
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.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with.
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. We currently have the SPL Expansion Project and the CCL Midscale Trains 8 & 9 Project pending non-FTA export approval with the DOE.
To date, the DOE has also issued orders under Section 3 of the NGA authorizing SPL, CCL and the Corpus Christi Stage 3 Project to export domestically produced LNG, as further detailed in DOE Export Licenses in Ou r Business .
Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the risk factor 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.
Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the immediately preceding risk factor .
Additionally as of December 31, 2024, $3.9 billion of repurchase authority remained under our share repurchase program our Board had authorized, which was increased in June 2024 by $4.0 billion through 2027.
Additionally as of December 31, 2025, $1.2 billion of repurchase authority remained under our share repurchase program authorized by our Board, which subsequently increased to approximately $10 billion from 2026 through 2030 after a $9 billion increase was authorized in February 2026.
Any restrictions on the ability to engage in beneficial transactions could materially and adversely affect us. Our ability to declare and pay dividends and repurchase shares is subject to certain considerations.
Our ability to declare and pay dividends and repurchase shares is subject to certain considerations.
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.
To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of all of our Trains in operation or under construction, as well as orders under Section 7 of the NGA authorizing the construction and operation of all of our pipelines in operation or under construction.
However, approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal applications. 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.
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.
Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that applied to our facilities beginning in calendar year 2024. On November 12, 2024, the EPA finalized a rule to impose and collect methane emissions charges authorized under the IRA.
Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that would have applied to our facilities beginning in calendar year 2024. The OBBBA, signed by President Trump on July 4, 2025, delays the imposition of the methane emissions charge until calendar year 2034.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

8 edited+0 added−0 removed10 unchanged
Biggest changeOur Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management’s plan for mitigating these risks, while the Audit Committee has been delegated the authority to oversee and periodically review the security of our information technology systems and controls, including 30 T able of Contents programs and defenses against cybersecurity threats.
Biggest changeOur Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management’s plan for mitigating these risks, while the Audit Committee has been delegated the authority to oversee and periodically review the security of our information technology systems and controls, including programs and defenses against cybersecurity threats.
For additional information about cybersecurity risks, see the risk A cyber attack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Projects, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation under Risks Relating to Our Operations and Industry in Item 1A.Risk Factors.
For additional information about cybersecurity risks, see the risk A cyberattack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Projects, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation under Risks Relating to Our Operations and Industry in Item 1A.Risk Factors.
We also seek to negotiate contractual requirements which compel our service providers to notify us of information security incidents occurring on their systems which may affect our systems or data, including personal information. During the year ended December 31, 2024, cybersecurity incidents and threats did not materially affect our business, results of operations or financial condition.
We also seek to negotiate contractual requirements which compel our service providers to notify us of information security incidents occurring on their systems which may affect our systems or data, including personal information. During the year ended December 31, 2025, cybersecurity incidents and threats did not materially affect our business, results of operations or financial condition.
We maintain a training program to help our personnel identify and assist in mitigating cybersecurity and data security risks. Our employees and Board members participate in annual training, user awareness campaigns and additional issue-specific training as needed. We also provide annual training for certain contractors who have access to our information technology networks.
We maintain a training program to help our personnel identify and assist in mitigating cybersecurity and data security risks. Our employees and Board members participate in periodic training, user awareness campaigns and additional issue-specific training as needed. We also provide periodic training for certain contractors who have access to our information technology networks.
These engagements are also designed to exercise, assess the maturity of and enhance our Cyber Incident Response Plan. To support these efforts, we have contracted with third parties to perform facility and system penetration tests, compromise assessments of information technology systems and security maturity assessments of our corporate and operational networks.
These engagements are also designed to exercise, assess the maturity of and enhance our Cybersecurity Incident Response Plan. To support these efforts, we have contracted with third parties to perform facility and system penetration tests, compromise assessments of information technology systems and security maturity assessments of our corporate and operational networks.
Our strategy also includes segmentation of corporate and operations networks, defense in depth and the least privileged access principle. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, we routinely evaluate opportunities to refine our cybersecurity program in order to mitigate operational network risks.
Our strategy also includes segmentation of corporate and operations networks, defense in depth and the principle of least privilege. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, we routinely evaluate opportunities to refine our cybersecurity program in order to mitigate operational network risks.
They have decades of experience managing strategic technology operations, including the identification of cybersecurity risk and the defense of information technology assets from global threats. Risks that could affect us are an integral part of our Board and Audit Committee deliberations throughout the year.
They have decades of 32 Table of Contents experience managing strategic technology operations, including the identification of cybersecurity risk and the defense of information technology assets from global threats. Risks that could affect us are an integral part of our Board and Audit Committee deliberations throughout the year.
Risk Management and Strategy As part of our broader approach to risk management, our cybersecurity program is designed to follow an “identify, protect, detect, respond and recover” approach to cybersecurity that is based off of the National Institute of Standards and Technology Cybersecurity Framework ( “CSF” ).
Risk Management and Strategy As part of our broader approach to risk management, our cybersecurity program is designed to follow a “govern, identify, protect, detect, respond and recover” approach to cybersecurity that is based on the National Institute of Standards and Technology Cybersecurity Framework ( “CSF” ).

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

3 edited+1 added−2 removed1 unchanged
Biggest changeIn 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.
Biggest changeIn August 2004, the EPA stayed the application of the emission standard to combustion turbines such as those at the Sabine Pass LNG Terminal. In March 2022, the EPA lifted the stay, and in June 2022, we petitioned the EPA and LDEQ for approval of additional operating parameters to demonstrate compliance with the emission limitation.
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.
LDEQ Matter We 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. AE-CN-22-00833 (the “ 2023 Compliance Order ”) issued by the LDEQ on April 12, 2023.
We do not expect that any ultimate penalty will have a material adverse impact on our financial results.
As of December 2025, we had filed test results with the LDEQ indicating that for the 2025 testing period all 44 turbines met the relevant compliance standard. We do not expect that any ultimate penalty will have a material adverse impact on our financial results.
Removed
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.
Added
The EPA approved the petition on July 31, 2025 and in October 2025 the LDEQ confirmed that all remaining milestones under the 2023 Compliance Order have been met. We continue to work with the LDEQ to resolve the 2023 Compliance Order.
Removed
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 2024, our subsidiaries have filed test results with the LDEQ indicating that for the 2024 testing period all 44 turbines meet the relevant compliance standard.

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

5 edited+3 added−1 removed4 unchanged
Biggest changePurchase of Equity Securities by the Issuer and Affiliated Purchasers The following table summarizes stock repurchases for the three months ended December 31, 2024: 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, 2024 1,306,270 $184.72 1,306,270 $3,930 November 1 - 30, 2024 139,533 $190.79 139,533 $3,903 December 1 - 31, 2024 65,940 $203.79 65,940 $3,890 Total 1,511,743 1,511,743 (1) See Note 18—Share Repurchase Programs of our Notes to Consolidated Financial Statements for details on the amount authorized by our Board under our share repurchase programs.
Biggest changePurchase of Equity Securities by the Issuer and Affiliated Purchasers The following table summarizes stock repurchases for the three months ended December 31, 2025: Period Total Number of Shares Purchased Average Price Paid Per Share (1) 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) (2) October 1 - 31, 2025 2,561,225 $224.25 2,561,225 $1,642 November 1 - 30, 2025 1,063,305 $209.91 1,063,305 $1,418 December 1 - 31, 2025 1,143,924 $190.84 1,143,924 $1,200 Total 4,768,454 4,768,454 (1) Average price excludes associated commission fees and excise taxes incurred, which are excluded costs under the repurchase program.
We intend to continue to declare and pay quarterly dividends, with the goal of increasing the dividend over time. 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.
We intend to continue to declare and pay quarterly dividends, with the goal of increasing the dividend over time. 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 our Board.
(LYB) 32 T able of Contents The following graph compares the five-year total return on our common stock, the S&P 500 Index and our Peer Group. 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, 2019 and that any dividends were fully reinvested.
(LYB) 34 Table of Contents The following graph compares the five-year total return on our common stock, the S&P 500 Index and our Peer Group. 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, 2020 and that any dividends were fully reinvested.
As of February 14, 2025, we had approximately 223.7 million shares of common stock outstanding held by 71 record owners. Because our shares are held by brokers and other institutions on behalf of our stockholders, we are unable to estimate the total number of actual stockholders represented by these record owners.
As of February 20, 2026, we had approximately 210.2 million shares of common stock outstanding held by 69 record owners. Because our shares are held by brokers and other institutions on behalf of our stockholders, we are unable to estimate the total number of actual stockholders represented by these record owners.
ITEM 4. MINE SAFETY DISCLOSURE Not applicable. 31 T able of Contents PART II ITEM 5.
ITEM 4. MINE SAFETY DISCLOSURE Not applicable. 33 Table of Contents PART II ITEM 5.
Removed
December 31, Company / Index 2019 2020 2021 2022 2023 2024 Cheniere Energy, Inc. $ 100.00 $ 98.30 $ 166.59 $ 248.77 $ 284.11 $ 363.85 S&P 500 Index 100.00 118.39 152.34 124.72 157.47 196.84 Peer Group 100.00 73.79 106.70 158.40 173.86 201.79
Added
(2) In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. See Note 18—Share Repurchase Programs of our Notes to Consolidated Financial Statements for details on the amount authorized by our Board under our share repurchase programs.
Added
December 31, Company / Index 2020 2021 2022 2023 2024 2025 Cheniere Energy, Inc. $ 100.00 $ 169.48 $ 253.08 $ 291.07 $ 370.15 $ 337.99 S&P 500 Index 100.00 128.68 105.35 133.02 166.27 195.96 Peer Group (1) 100.00 144.60 214.66 235.62 273.47 284.95 (1) Includes Hess Corporation (HES) through end of trading on July 17, 2025.
Added
On July 18, 2025, HES was acquired by Chevron Corporation and its common stock was suspended from trading on the New York Stock Exchange prior to opening of trading. ITEM 6. [Reserved] 35 Table of Contents

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

17 edited+7 added−8 removed14 unchanged
Biggest changeWe expect to incur a proportional level of capital expenditures in the upcoming year as construction work progresses on the Corpus Christi Stage 3 Project. 47 Table of Contents Financing Cash Flows The following table summarizes our financing activities (in millions): Year Ended December 31, 2024 2023 Proceeds from issuances of debt $ 2,725 $ 1,397 Redemptions, repayments and repurchases of debt (3,521) (2,598) Distributions to non-controlling interests (846) (1,016) Payments related to tax withholdings for share-based compensation (46) (63) Repurchase of common stock (2,262) (1,473) Dividends to stockholders (412) (393) Other, net (89) (34) Net cash used in financing activities $ (4,451) $ (4,180) Debt Issuances The following table shows our debt issuances (in millions): Year Ended December 31, 2024 2023 Proceeds from issuances of debt Cheniere: 2034 Cheniere Senior Notes $ 1,497 $ — CQP: 2034 CQP Senior Notes 1,198 — 5.950% Senior Notes due 2033 — 1,397 SPL: SPL Revolving Credit Facility 30 — Total proceeds from issuances of debt $ 2,725 $ 1,397 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, 2024 2023 Redemptions, repayments and repurchases of debt SPL: 5.750% Senior Secured Notes due 2024 $ (300) $ (1,700) 5.625% Senior Secured Notes due 2025 (1,700) — SPL Revolving Capital Facility (30) — CCH: 7.000% Senior Notes due 2024 — (498) 5.875% Senior Notes due 2025 (1,491) — 5.125% Senior Notes due 2027 — (69) 3.700% Senior Notes due 2029 — (237) 2.742% Senior Notes due 2039 — (94) Total redemptions, repayments and repurchases of debt $ (3,521) $ (2,598) 48 Table of Contents Repurchase of Common Stock During the years ended December 31, 2024 and 2023, we paid $2.3 billion and $1.5 billion to repurchase approximately 13.8 million and 9.5 million shares of our common stock, respectively, under our share repurchase program.
Biggest changeFinancing Cash Flows The following table summarizes our financing activities (in millions): Year Ended December 31, 2025 2024 Proceeds from issuances of debt and borrowings $ 1,987 $ 2,725 Redemptions and repayments of debt (2,092) (3,521) Distributions to NCI (803) (846) Contributions from redeemable NCI 122 6 Payments related to tax withholdings for share-based compensation (51) (46) Repurchase of common stock, inclusive of excise taxes paid (2,724) (2,262) Dividends to stockholders (451) (412) Other, net (118) (95) Net cash used in financing activities $ (4,130) $ (4,451) 50 Table of Contents Proceeds from Issuances of Debt and Borrowings The following table shows the proceeds from issuances of debt and borrowings, including intra-year activity (in millions): Year Ended December 31, 2025 2024 Cheniere: 5.650% Senior Notes due 2034 $ — $ 1,497 Cheniere Revolving Credit Facility 175 — CQP: 5.750% Senior Notes due 2034 — 1,198 2035 CQP Senior Notes 997 — SPL: SPL Revolving Credit Facility 265 30 CCH: CCH Credit Facility 550 — Total proceeds from issuances of debt and borrowings $ 1,987 $ 2,725 Debt Redemptions and Repayments The following table shows the redemptions and repayments of debt, including intra-year activity (in millions): Year Ended December 31, 2025 2024 Cheniere: Cheniere Revolving Credit Facility $ (175) $ — SPL: 5.750% Senior Secured Notes due 2024 — (300) 2025 SPL Senior Notes (300) (1,700) 2026 SPL Senior Notes (1,300) — 4.746% weighted average rate Senior Notes due 2037 (52) — SPL Revolving Credit Facility (265) (30) CCH: 5.875% Senior Notes due 2025 — (1,491) Total redemptions and repayments of debt $ (2,092) $ (3,521) Repurchase of Common Stock During the years ended December 31, 2025 and 2024, we paid $2.7 billion and $2.3 billion to repurchase approximately 12.1 million and 13.8 million shares of our common stock, respectively, under our share repurchase program.
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 liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity.
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. 52 Table of Contents Additionally, the valuation of certain liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity.
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.
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.
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, 2024, we used $800 million of available cash to reduce our outstanding indebtedness, all of which was 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, 2025, we used $0.7 billion of available cash to reduce our outstanding indebtedness, all of which was pursuant to our capital allocation plan.
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 49 Table of Contents December 31, 2024 and 2023 (in millions), which entirely consisted of 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 liquefaction supply derivatives valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2025 and 2024 (in millions).
Year Ended December 31, 2024 2023 Favorable changes in fair value relating to instruments still held at the end of the period $ 738 $ 5,700 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 in effect during the years ended December 31, 2024 and 2023.
Year Ended December 31, 2025 2024 Favorable changes in fair value of liquefaction supply derivatives still held at the end of the period $ 2,887 $ 738 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 in effect during the years ended December 31, 2025 and 2024.
The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2024 and 2023 amounted to a liability of $801 million and $2.2 billion, respectively.
The estimated fair value of level 3 liquefaction supply derivatives recognized in our Consolidated Balance Sheets as of December 31, 2025 and 2024 amounted to an asset of $2.9 billion and a liability of $801 million, respectively.
On January 28, 2025, we declared a quarterly dividend of $0.50 per share of common stock that is payable on February 21, 2025 to stockholders of record as of the close of business on February 7, 2025.
On January 27, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on February 27, 2026 to stockholders of record as of the close of business on February 6, 2026.
On January 28, 2025, we declared a quarterly dividend of $0.50 per share of common stock that is payable on February 21, 2025 to stockholders of record as of the close of business on February 7, 2025.
On January 27, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on February 27, 2026 to stockholders of record as of the close of business on February 6, 2026.
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. 46 Table of Contents Sources and Uses of Cash The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash and cash equivalents (in millions).
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 SPL Expansion Project and the CCL Expansion Project, we expect that additional financing would be used to fund construction of the expansion.
Fair Value of Level 3 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.
Fair Value of Level 3 Liquefaction Supply Derivatives Our derivative instruments are recorded at fair value unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.
Sources and Uses of Cash The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash and cash equivalents (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report.
Investing Cash Flows Our investing net cash outflows in both periods primarily were for the construction costs for the Corpus Christi Stage 3 Project, which were $1.5 billion during both the years ended December 31, 2024 and 2023, as well as for optimization and other site improvement projects.
Investing Cash Flows Our investing net cash outflows primarily related to: (1) construction costs for the Corpus Christi Stage 3 Project, which were $1.3 billion and $1.5 billion during the years ended December 31, 2025 and 2024, respectively; (2) $1.0 billion of costs paid for the CCL Midscale Trains 8 & 9 Project during the year ended December 31, 2025, primarily related to procurement and engineering; and (3) optimization and other site improvement projects during both periods.
Cash Dividends to Stockholders We paid aggregate dividends of $1.805 per share of common stock for a total of $412 million during the year ended December 31, 2024 and $1.62 per share of common stock for a total of $393 million during the year ended December 31, 2023.
In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. 51 Table of Contents Cash Dividends to Stockholders During the year ended December 31, 2025, we paid aggregate dividends of $2.055 per share of common stock for a total of $451 million and during the year ended December 31, 2024, we paid aggregate dividends of $1.805 per share of common stock for a total of $412 million.
The updated capital allocation plan also included a plan to increase our quarterly dividend by approximately 15% to $2.00 per common share on an annualized basis, which commenced with the dividend pertaining to the third quarter of 2024.
In June 2025, we announced updates to our company outlook, which included a plan to increase our annualized dividend by over 10% to $2.22 per common share, which commenced with the dividend pertaining to the third quarter of 2025.
Year Ended December 31, 2024 2023 Net cash provided by operating activities $ 5,394 $ 8,418 Net cash used in investing activities (2,279) (2,202) Net cash used in financing activities (4,451) (4,180) Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents 1 2 Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents $ (1,335) $ 2,038 Operating Cash Flows The $3.0 billion decrease between the periods was primarily related to lower cash receipts from the sale of LNG cargoes due to a reduction in both pricing per MMBtu and volumes sold under short-term agreements, although this exposed us less to declining international LNG and gas prices in the current year as a higher proportion of our LNG was sold under long-term agreements.
Year Ended December 31, 2025 2024 Net cash provided by operating activities $ 5,539 $ 5,394 Net cash used in investing activities (3,012) (2,279) Net cash used in financing activities (4,130) (4,451) Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents (3) 1 Net decrease in cash, cash equivalents and restricted cash and cash equivalents $ (1,606) $ (1,335) 49 Table of Contents Operating Cash Flows The $145 million increase between the periods was primarily related to higher net cash inflows from LNG sales, as explained above in Results of Operations , and increased cash inflows from settlement of derivative instruments.
As of December 31, 2024, we had approximately $3.9 billion remaining under our share repurchase program.
In April 2026, we expect to pay $26 million of excise taxes related to our repurchases during the fiscal year 2025. As of December 31, 2025, we had approximately $1.2 billion remaining under our share repurchase program.
Removed
The decrease was partially offset by lower cash outflows for natural gas feedstock, largely due to the decline and sustained moderation of global LNG and gas prices as well as lower U.S. natural gas prices during the year ended December 31, 2024 as compared to December 31, 2023. We became subject to the 15% CAMT in 2024.
Added
Additional discussion of these items follows the table.
Removed
For the period ended December 31, 2024, our CAMT liability exceeded our regular tax liability by $383 million which created a CAMT credit carryforward with indefinite life.
Added
Partially offsetting the increase was lower cash flows attributed to working capital from differences in timing of cash collections from the sale of LNG cargoes and payments to suppliers .
Removed
Our CAMT liability exceeded our regular tax liability in 2024 primarily because we used approximately $2.8 billion of our NOL carryover from 2019 to offset our regular taxable income; however, such NOL carryover does not factor into our CAMT computation resulting in a higher CAMT tax base.
Added
As described in Results of Operations , the OBBBA was signed into law during the third quarter of 2025 and includes, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025, which deferred our cash tax obligations, ultimately reducing our income tax payable to a nominal amount in 2025, and modifying the export-promoting FDII deduction rules, renamed to the FDDEI under the OBBBA, which is expected to reduce our income taxes payable relative to prior policy in future periods.
Removed
We may continue to owe CAMT in future periods until the time our existing NOL carryovers are fully exhausted. Additionally, any final regulatory guidance related to the CAMT issued in the future could significantly affect the timing and amount of our CAMT obligations.
Added
Additionally, on September 30, 2025, the IRS issued Notice 2025-49, which revised rules for calculating CAMT adjusted financial statement income, deferring our cash tax obligations and entitling us to a refund of $380 million of previously paid CAMT, which we received in December 2025.
Removed
During 2024, the IRS issued Notice 2024-66 which extended the due date of our CAMT estimated payments to April 15, 2025. As a result, the majority of our current tax expense incurred for the year ended December 31, 2024 will be paid in 2025.
Added
The $0.2 billion decrease in construction costs for the Corpus Christi Stage 3 Project between the periods was primarily related to a decline in expenditures in the current year related to the EPC contract as the project approaches completion.
Removed
Additionally, our cash taxes in the near term could potentially be impacted by possible new federal tax legislation being enacted. Several key provisions of the Tax Cuts and Jobs Act (the “TCJA” ) are set to expire or change after 2025, raising the prospects for a new tax bill being enacted in 2025.
Added
We expect to continue to incur capital expenditures for the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project as construction progresses on these projects.
Removed
While the current corporate tax rate of 21% established by the TCJA is permanent and not set to expire, President Trump has proposed reducing the rate to 15% for U.S. manufacturers. Any significant changes to the corporate tax rate, Foreign-Derived Intangible Income provisions, immediate expensing rules or other key tax policies in 2025 could affect our financial position and liquidity.
Added
Additionally, during the year ended December 31, 2025, we paid $33 million of excise taxes related to our repurchase of common stock during the fiscal years 2023 and 2024, since the IRS imposes an excise tax of 1% on the fair market value of our stock repurchases less our stock issuances.
Removed
While we are unable to predict the timing and scope of any potential tax legislation, we continue to monitor and assess any proposed tax law changes to determine the impact on our business, cash flows and financial results.

Item 7. Management's Discussion & Analysis

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

50 edited+49 added−36 removed31 unchanged
Biggest changeThis, along with the expiry of the gas transit agreement between Russia and Ukraine on December 31, 2024, is likely to increase the call on LNG imports in the coming months in order to replenish European gas storage facilities to 90% capacity by November 1, as required by the EU each year. 36 Table of Contents Results of Operations Consolidated results of operations Year Ended December 31, (in millions, except per share data) 2024 2023 Variance Revenues LNG revenues $ 14,899 $ 19,569 $ (4,670) Regasification revenues 135 135 — Other revenues 669 690 (21) Total revenues 15,703 20,394 (4,691) Operating costs and expenses Cost of sales (excluding items shown separately below) 6,021 1,356 4,665 Operating and maintenance expense 1,857 1,835 22 Selling, general and administrative expense 441 474 (33) Depreciation, amortization and accretion expense 1,220 1,196 24 Other operating costs and expenses 36 44 (8) Total operating costs and expenses 9,575 4,905 4,670 Income from operations 6,128 15,489 (9,361) Other income (expense) Interest expense, net of capitalized interest (1,010) (1,141) 131 Gain (loss) on modification or extinguishment of debt (9) 15 (24) Interest and dividend income 189 211 (22) Other income (expense), net 5 4 1 Total other expense (825) (911) 86 Income before income taxes and non-controlling interests 5,303 14,578 (9,275) Less: income tax provision 811 2,519 (1,708) Net income 4,492 12,059 (7,567) Less: net income attributable to non-controlling interests 1,240 2,178 (938) Net income attributable to Cheniere $ 3,252 $ 9,881 $ (6,629) Net income per share attributable to Cheniere—basic $ 14.24 $ 40.99 $ (26.75) Net income per share attributable to Cheniere—diluted $ 14.20 $ 40.72 $ (26.52) Volumes loaded and recognized from the Liquefaction Projects Year Ended December 31, (in TBtu) 2024 2023 Variance Volumes loaded during the current period 2,327 2,299 28 Volumes loaded during the prior period but recognized during the current period 37 56 (19) Less: volumes loaded during the current period and in transit at the end of the period (39) (37) (2) Total volumes recognized in the current period 2,325 2,318 7 37 Table of Contents Components of LNG revenues and corresponding LNG volumes delivered Year Ended December 31, 2024 2023 Variance LNG revenues (in millions) : LNG from the Liquefaction Projects sold under third party long-term agreements (1) $ 12,144 $ 12,820 $ (676) LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements 2,345 6,028 (3,683) LNG procured from third parties 280 359 (79) Net derivative gain (loss) (73) 110 (183) Other revenues 203 252 (49) Total LNG revenues $ 14,899 $ 19,569 $ (4,670) Volumes delivered as LNG revenues (in TBtu) : LNG from the Liquefaction Projects sold under third party long-term agreements (1) 2,118 2,034 84 LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements 207 284 (77) LNG procured from third parties 24 35 (11) Total volumes delivered as LNG revenues 2,349 2,353 (4) (1) Long-term agreements include agreements with an initial tenor of 12 months or more.
Biggest changeResults of Operations Consolidated results of operations Year Ended December 31, (in millions, except per share data) 2025 2024 Variance Revenues LNG revenues $ 19,435 $ 14,899 $ 4,536 Regasification revenues 136 135 1 Other revenues 405 669 (264) Total revenues 19,976 15,703 4,273 Operating costs and expenses Cost of sales (excluding operating and maintenance expense and depreciation, amortization and accretion expense shown separately below) 7,150 6,021 1,129 Operating and maintenance expense 1,966 1,857 109 Selling, general and administrative expense 383 441 (58) Depreciation, amortization and accretion expense 1,329 1,220 109 Other operating costs and expenses 36 36 — Total operating costs and expenses 10,864 9,575 1,289 Income from operations 9,112 6,128 2,984 Other income (expense) Interest expense, net of capitalized interest (948) (1,010) 62 Gain (loss) on modification or extinguishment of debt (8) (9) 1 Interest and dividend income 106 189 (83) Other income, net 20 5 15 Total other expense (830) (825) (5) Income before income taxes and NCI 8,282 5,303 2,979 Less: income tax provision 1,488 811 677 Net income 6,794 4,492 2,302 Less: net income attributable to NCI 1,464 1,240 224 Net income attributable to Cheniere $ 5,330 $ 3,252 $ 2,078 Net income per share attributable to common stockholders—basic $ 24.19 $ 14.24 $ 9.95 Net income per share attributable to common stockholders—diluted $ 24.13 $ 14.20 $ 9.93 39 Table of Contents Volumes loaded and recognized from the Liquefaction Projects Year Ended December 31, 2025 2024 (in TBtu) Operational Commissioning Total Operational Commissioning Total Volumes loaded during the current period 2,400 24 2,424 2,327 — 2,327 Volumes loaded during the prior period but recognized during the current period 39 — 39 37 — 37 Less: volumes loaded during the current period and in transit at the end of the period (23) (1) (24) (39) — (39) Total volumes recognized in the current period 2,416 23 2,439 2,325 — 2,325 Components of LNG revenues and corresponding LNG volumes delivered Year Ended December 31, 2025 2024 Variance LNG revenues (in millions) : LNG from the Liquefaction Projects sold under third party long-term agreements (1) $ 14,804 $ 12,144 $ 2,660 LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2) 3,794 2,345 1,449 LNG procured from third parties (2) 226 280 (54) Net derivative gain (loss) 344 (73) 417 Other revenues 267 203 64 Total LNG revenues $ 19,435 $ 14,899 $ 4,536 Volumes delivered as LNG revenues (in TBtu) : LNG from the Liquefaction Projects sold under third party long-term agreements (1) 2,095 2,118 (23) LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2) 321 207 114 LNG procured from third parties (2) 22 24 (2) Total volumes delivered as LNG revenues 2,438 2,349 89 (1) Long-term agreements include agreements with an initial tenor of 12 months or more.
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.
We own a 48.6% limited 48 Table of Contents 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.
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.
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.
The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by management based on market conditions and other factors, with repurchases executed within trading parameters pre-established for each applicable trading period in compliance with SEC Rule 10b5-1.
The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by management based on market conditions and other factors, with the majority of the repurchases executed within trading parameters pre-established for each applicable trading period in compliance with SEC Rule 10b5-1 and some repurchases executed on the open market.
(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, 2024.
(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, 2025.
During the year ended December 31, 2024, $846 million in distributions were paid to our non-controlling interests. Capital Allocation Plan In June 2024, our Board approved an updated comprehensive long-term capital allocation plan, which included an increase to our share repurchase authorization by $4.0 billion through 2027.
During the year ended December 31, 2025, $803 million in distributions were paid to our non-controlling interests. Capital Allocation Plan In June 2024, our Board approved an updated comprehensive long-term capital allocation plan, which included an increase to our share repurchase authorization by $4.0 billion through 2027.
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, 2024.
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, 2025.
Our discussion and analysis includes the following subjects: • Overview • Overview of Significant Events • Market Environment • Results of Operations • Liquidity and Capital Resources • Summary of Critical Accounting Estimates • Recent Accounting Standards Overview We are an energy infrastructure company primarily engaged in LNG-related businesses.
Our discussion and analysis includes the following subjects: • Overview • Overview of Significant Events • Marke t Environment • Results of Operations • Liquidity and Capital Resources • Summary of Critical Accounting Estimates • Recent Accounting Standards Overview We are an energy infrastructure company primarily engaged in LNG-related businesses.
Our liquidity position subsequent to December 31, 2024 will be driven by future sources of liquidity and future cash requirements, as further discussed under the caption Future Sources and Uses of Liquidity . 40 Table of Contents 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, 2025 will be driven by future sources of liquidity and future cash requirements, as further discussed under the caption Future Sources and Uses of Liquidity. 43 Table of Contents Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures.
Disciplined Accretive Growth The FID of any expansion projects will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
Disciplined Accretive Growth The FID of any expansion projects, including the SPL Expansion Project and CCL Expansion Project, will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We have estimated revenues under agreements with 41 Table of Contents terms dependent on project milestone dates based on the estimated dates as of December 31, 2024.
In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We have estimated revenues under agreements with 44 Table of Contents terms dependent on project milestone dates based on the estimated dates as of December 31, 2025.
See the risk Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity under Risks Relating to Regulations in Item 1A. Risk Factors .
See the risk Additions or changes in tax laws and regulations or variables impacting our tax obligations could potentially affect our financial results or liquidity under Risks Relating to Regulations in Item 1A. Risk Factors .
The future capital expenditures included in the table above primarily consist of fixed costs under the lump sum 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 occur, 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 lump sum Bechtel EPC contracts for both the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order.
As further described in the LNG Revenues from Executed SPAs section, the pricing structure of our SPAs 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.
As further described in LNG Revenues from Executed SPAs , the pricing structure of our SPAs often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, thus limiting our net exposure to future increases in natural gas prices.
As of December 31, 2024, we have secured approximately 74% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2025, excluding the 6% of which has been secured under IPM agreements. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2025.
As of December 31, 2025, we have secured approximately 70% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2026, excluding the 8% of which has been secured under IPM agreements. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2026.
The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2024 (in billions): Estimated Payments Due Under Executed Contracts by Period (1) 2025 2026 - 2029 Thereafter Total Debt $ 0.4 $ 10.5 $ 12.2 $ 23.1 Interest payments 1.1 3.5 2.0 6.6 Total $ 1.5 $ 14.0 $ 14.2 $ 29.7 (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, 2024.
The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2025 (in billions): Estimated Payments Due Under Executed Contracts by Period (1) (2) 2026 2027 - 2030 Thereafter Total Debt $ 0.3 $ 11.8 $ 10.9 $ 23.0 Interest payments 1.1 3.2 1.7 6.0 Total $ 1.4 $ 15.0 $ 12.6 $ 29.0 (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, 2025.
Discussion of items for the year ended December 31, 2022 and variance drivers between the year ended December 31, 2023 as compared to December 31, 2022 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, 2023 .
Discussion of items for the year ended December 31, 2023 and variance drivers between the year ended December 31, 2024 as compared to December 31, 2023 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 3 1, 2 02 4 .
As of December 31, 2024, assets of our VIEs, which are included in our Consolidated Balance Sheets, included $270 million of cash and cash equivalents and $125 million of restricted 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, 2024.
As of December 31, 2025, assets of our VIEs, which are included in our Consolidated Balance Sheets, included $182 million of cash and cash equivalents and $22 million of restricted 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, 2025.
Our credit facilities mature between 2026 and 2029, based on estimated project milestone dates as of December 31, 2024. Disciplined Accretive Growth Our significant land positions at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources.
Our credit facilities mature between 2027 and 2030, based on estimated project milestone dates as of December 31, 2025. 45 Table of Contents Disciplined Accretive Growth Our significant land positions at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources.
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, 2024 (in billions): Estimated Payments Due Under Executed Contracts by Period (1) 2025 2026 - 2029 Thereafter Total Purchase obligations (2): Natural gas supply agreements excluding IPM agreements (3) (4) $ 6.6 $ 16.4 $ 6.6 $ 29.6 Natural gas transportation and storage service agreements (5) 0.5 2.0 4.4 6.9 Capital expenditures 1.6 0.6 — 2.2 Other Purchase Obligations — 0.2 0.5 0.7 Leases (6) 0.7 2.9 3.4 7.0 Total $ 9.4 $ 22.1 $ 14.9 $ 46.4 (1) Agreements in force as of December 31, 2024 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2024.
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, 2025 (in billions): Estimated Payments Due Under Executed Contracts by Period (1) 2026 2027 - 2030 Thereafter Total Purchase obligations (2): Natural gas supply agreements excluding IPM agreements (3) (4) $ 7.3 $ 13.3 $ 5.0 $ 25.6 Natural gas transportation and storage service agreements (5) 0.6 2.2 4.4 7.2 Capital expenditures 1.5 0.9 — 2.4 Other Purchase Obligations — 0.1 0.5 0.6 Leases (6) 0.9 3.2 4.7 8.8 Total $ 10.3 $ 19.7 $ 14.6 $ 44.6 (1) Agreements in force as of December 31, 2025 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2025.
LNG produced by the Liquefaction Projects that is not contracted under long-term contracts is available for Cheniere Marketing, our integrated marketing function, to sell in the global market under spot sales or other short-term agreements.
LNG produced by the Liquefaction Projects that is not contracted under long-term contracts is available for Cheniere Marketing, our integrated marketing function, to sell in the global market under spot sales or other short-term agreements. The LNG produced and available for Cheniere Marketing to sell includes volumes related to commissioning, which are not recognized as revenues.
December 31, 2024 Cash and cash equivalents (1) $ 2,638 Restricted cash and cash equivalents (1) 552 Available commitments under our credit facilities (2): SPL Revolving Credit Facility 776 CQP Revolving Credit Facility 1,000 CCH Credit Facility 3,260 CCH Working Capital Facility 1,390 Cheniere Revolving Credit Facility 1,250 Total available commitments under our credit facilities 7,676 Total available liquidity $ 10,866 (1) Amounts presented include balances held by our consolidated variable interest entities ( “VIEs” ), as discussed in Note 8—Non-controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements.
December 31, 2025 Cash and cash equivalents (1) $ 1,099 Restricted cash and cash equivalents (1) 485 Available commitments under our credit facilities (2): SPL Revolving Credit Facility 824 CQP Revolving Credit Facility 1,000 CCH Credit Facility 2,710 CCH Working Capital Facility 1,390 Cheniere Revolving Credit Facility 1,250 Total available commitments under our credit facilities 7,174 Total available liquidity $ 8,758 (1) Amounts presented include balances held by our VIEs, as discussed in Note 8—Non-Controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements.
During 2024, 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 business in the future.
For further discussion of our business, see Items 1. and 2. Business and Properties . During 2025, 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.
During the year ended December 31, 2024, we repurchased approximately 13.8 million shares of our common stock for $2.3 billion at a weighted average price per share of $163.72. A discussion of our share repurchase program can be found in
During the year ended December 31, 2025, we repurchased approximately 12.1 million shares of our common stock for $2.7 billion at a weighted average price per share of $221.55. A discussion of our share repurchase program can be found in
Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10—Debt of our Notes to Consolidated Financial Statements. 45 Table of Contents Interest As of December 31, 2024, our senior notes had a weighted average contractual interest rate of 4.69%. Borrowings under our credit facilities are indexed to SOFR.
Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10—Debt of our Notes to Consolidated Financial Statements. Interest As of December 31, 2025, our senior notes had a weighted average contractual interest rate of 4.65%.
Through our SPAs and IPM agreements currently in effect, with approximately 15 years of weighted average remaining life as of December 31, 2024, we have contracted 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.
Under our long-term SPAs and IPM agreements, as of December 31, 2025, we have contracted approximately 90% 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 from SPAs that are conditional on additional liquefaction capacity beyond what is currently in construction or operation, subject to unilateral waiver by us.
Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows.
Business and Properties , these contracts with creditworthy counterparties form the foundation of our business and provide us with significant, stable, long-term cash flows.
(4) Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2024. Natural gas supply agreements are presented net of $0.3 billion in contracted sales of natural gas as of December 31, 2024.
(4) Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2025. Natural gas supply agreements are presented net of $0.2 billion in contracted sales of natural gas as of December 31, 2025. (5) Natural gas transportation and storage services agreements include $1.3 billion in obligations to related parties.
Under our SPAs, 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 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.
As described in General , under our SPAs, customers purchase LNG on either an FOB basis or a DAP basis generally for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub.
The following table summarizes our estimate of revenues to be received from executed long-term SPAs as of December 31, 2024 (in billions): Estimated Revenues Under Executed SPAs by Period (1) (2) 2025 2026 - 2029 Thereafter Total LNG revenues (fixed fees) $ 6.3 $ 27.9 $ 70.5 $ 104.7 LNG revenues (variable fees) (3) 9.2 42.0 124.2 175.4 Total $ 15.5 $ 69.9 $ 194.7 $ 280.1 (1) LNG revenues exclude estimated revenues from contracts with unsatisfied contractual conditions precedent.
The following table summarizes our estimate of revenues to be received from executed long-term SPAs as of December 31, 2025 (in billions): Estimated Revenues Under Executed SPAs by Period (1) (2) 2026 2027 - 2030 Thereafter Total LNG revenues (fixed fees) $ 6.6 $ 29.4 $ 71.7 $ 107.7 LNG revenues (variable fees) (3) 9.8 43.9 129.2 182.9 Total $ 16.4 $ 73.3 $ 200.9 $ 290.6 (1) LNG revenues exclude estimated revenues from contracts with unsatisfied contractual conditions precedent.
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 .
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. Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows.
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.
See Note 10—Debt of our Notes to Consolidated Financial Statements for additional information on these covenants. 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.
(5) Natural gas transportation and storage services agreements include $1.2 billion in obligations to related parties. 43 Table of Contents (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, 2024 but will commence in the future.
See Note 1 3 — Related Party Transactions for further information about our related parties. (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, 2025 but will commence in the future.
Payments during future renewal option periods 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. Leases are presented net of $1.2 billion in future income associated with vessel time charters that were subchartered to third parties.
Payments during future renewal option periods 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 may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved. Liquidity and Capital Resources The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term.
We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.
Operational • As of February 14, 2025, approximately 3,930 cumulative LNG cargoes totaling approximately 270 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects. • In December 2024, we achieved first LNG production from Train 1 of the Corpus Christi Stage 3 Project and in February 2025, the first cargo of LNG was produced from the Corpus Christi Stage 3 Project.
Operational • As of February 20, 2026, over 4,610 cumulative LNG cargoes totaling over 315 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects. • In March, August, October and December 2025, substantial completions of Trains 1, 2 3 and 4, respectively, of the Corpus Christi Stage 3 Project were achieved.
Natural Gas Supply, Transportation and Storage Service Agreements Excluding IPM agreements and unexercised extension options, we have secured approximately 7,980 TBtu of natural gas feedstock for our Liquefaction Projects through long-term natural gas supply agreements with remaining fixed terms of up to 15 years.
Leases are presented net of future income associated with vessel time charters that were subchartered to third parties, which was immaterial as of December 31, 2025. 46 Table of Contents Natural Gas Supply, Transportation and Storage Service Agreements Excluding IPM agreements and unexercised extension options, we have secured approximately 6,847 TBtu of natural gas feedstock for our Liquefaction Projects through long-term natural gas supply agreements with remaining fixed terms of up to 14 years.
Our use of LNG as a cleaner burning fuel in our operations has enabled us to claim domestic alternative fuel excise tax credits which we are actively pursuing for the period spanning from 2018 to 2024.
Our use of LNG as transport fuel in our operations enabled us to claim federal alternative fuel excise tax credits totaling $370 million for the period spanning from 2018 to 2024, preceding the expiration of the incentive program on December 31, 2024.
Net income attributable to non-controlling interests The $938 million decrease between the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to a $1.7 billion decrease in CQP’s consolidated net income, primarily due to $1.5 billion of decreases in gains from the fair value of its IPM agreements accounted for as derivatives.
Net income attributable to NCI The $224 million increase during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to a $477 million increase in CQP’s consolidated net income primarily from favorable changes in fair value of agreements accounted for as derivative instruments.
In April 2024, the net proceeds, together with cash on hand, were used to retire the approximately $1.5 billion outstanding aggregate principal amount of CCH’s 5.875% Senior Secured Notes due 2025 (the “2025 CCH Senior Notes” ). • During the year ended December 31, 2024, we accomplished the following pursuant to our capital allocation priorities: ◦ We repurchased approximately 13.8 million shares of our common stock as part of our share repurchase program for approximately $2.3 billion. ◦ Excluding amounts refinanced, SPL redeemed $800 million of outstanding aggregate principal amount of its senior secured notes. ◦ We paid dividends of $1.805 per share of common stock during the year ended December 31, 2024. ◦ 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. 35 Table of Contents Market Environment The LNG market in 2024 remained relatively tight as a result of low supply capacity growth, strong demand outside Europe and continued geopolitical tensions.
S&P also revised its outlook on SPL to positive from stable in December 2025. • During the year ended December 31, 2025, we accomplished the following pursuant to our capital allocation priorities: ◦ We repurchased approximately 12.1 million shares of our common stock as part of our share repurchase program for approximately $2.7 billion. ◦ We redeemed and repaid $652 million aggregate principal amount of notes across our complex, comprised of the following: ▪ In December 2025, SPL redeemed $300 million aggregate principal amount of its 2026 SPL Senior Notes. ▪ In September 2025, SPL repaid $52 million aggregate principal amount outstanding of its series of senior secured notes due 2037 with a weighted average interest rate of 4.746%, based on their respective fixed amortization schedules. ▪ In March 2025, SPL repaid the remaining $300 million aggregate principal amount outstanding of its 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes” ) at maturity. ◦ We paid dividends of $2.055 per share of common stock during the year ended December 31, 2025. ◦ We continued to invest in accretive organic growth, including our investments in the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.
Other income (expense) The $86 million favorable variance between the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to: • $131 million decrease in interest expense, net of capitalized interest, between the comparable years primarily due to a $92 million increase in interest costs qualifying for capitalization, given the higher carrying value of assets under construction, and additionally due to lower overall interest cost due to debt reduction activities associated with our long-term capital allocation plan; These favorable variances were partially offset by: • $24 million increase in losses on modification or extinguishment of debt between the comparable years from debt reduction activities, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources; and • $22 million decrease in interest and dividend income between the comparable years, primarily as a result of lower average cash and cash equivalents balances between the respective periods.
Total other expense The $5 million increase in total other expense during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to: • $83 million decrease in interest and dividend income as a result of decreased interest rates and lower average cash and cash equivalents balances between the periods; partially offset by • $62 million decrease in interest expense, net of capitalized interest, due to a $33 million increase in capitalized interest costs given the higher carrying value of assets under construction and additionally due to $29 million lower gross interest costs due to debt reduction activities associated with our long-term capital allocation plan; and • $15 million increase in other income, net, primarily from a $26 million gain recognized on the sale of our equity interests in an equity method investment during the three months ended March 31, 2025. 41 Table of Contents Income tax provision The $677 million unfavorable variance during the year ended December 31, 2025 as compared to the same period of 2024 was substantially all attributable to a higher income tax expense due to a $3.0 billion increase in pre-tax income.
As of December 31, 2024, each of our issuers was in compliance with all covenants related to their respective debt agreements.
Debt As of December 31, 2025, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $22.4 billion and credit facilities with $550 million outstanding loan balances. As of December 31, 2025, each of our issuers was in compliance with all covenants related to their respective debt agreements.
Over a remaining fixed term of 18 years, we expect to generate liquidity from the approximately 3,825 TBtu of LNG to be produced from natural gas not yet received under IPM agreements as of December 31, 2024, excluding approximately 665 TBtu related to an IPM agreement that is subject to unsatisfied contractual conditions precedent. 42 Table of Contents Additional Future Sources of Liquidity Available Commitments under Credit Facilities As of December 31, 2024, we had $7.7 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.
Additional Future Sources of Liquidity Available Commitments under Credit Facilities As of December 31, 2025, we had $7.2 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.
As of December 31, 2024, we had up to $3.9 billion available under the share repurchase program.
As of December 31, 2025, we had up to $1.2 billion available under the share repurchase program. In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization.
Significant factor affecting our results of operations Below is a significant factor that affects our results of operations. 39 Table of Contents Gains and losses on derivative instruments Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements.
Gains and losses on derivative instruments Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements, unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception which applies the accrual method of accounting, as described in Note 2 — Summar y of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
We had $334 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2024.
Interest on borrowings under our credit facilities is indexed to SOFR, and we are subject to interest rates on outstanding balances, commitment fees on undrawn balances and letter of credit fees on issued letters of credit. We had $286 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2025.
The following is an additional discussion of the significant drivers of the variance in net income attributable to Cheniere by line item: Revenues The $4.7 billion decrease in revenues between the year ended December 31, 2024 compared to the same period of 2023 was primarily attributable to: • $3.8 billion decrease in revenues generated by our marketing function under short-term agreements between the comparative years due to declining global LNG and gas prices and a reduction of volumes sold under short-term agreements as a result of additional long-term agreements commencing in 2024 as compared to 2023; and 38 Table of Contents • $676 million decrease in revenues attributable to declining Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed, between the years.
The following is an expanded discussion of the significant drivers of the variance in net income attributable to Cheniere by line item: 40 Table of Contents Total revenues The $4.3 billion increase in total revenues during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to: • $2.9 billion increase due to higher pricing per MMBtu primarily from increased Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed; • $1.2 billion increase due to higher volumes of LNG delivered between the periods, primarily as a result of increased production volume due to the substantial completions of the first four Trains of the Corpus Christi Stage 3 Project in 2025; • $417 million increase in gains from agreements accounted for as derivative instruments included in revenues, largely due to the impact of declines in global gas prices and volatility within our derivatives related to financial positions to economically hedge the purchase and sale of physical LNG, of which the gain between the years was attributable to a $223 million gain from favorable changes in fair value of agreements accounted for as derivatives and a $194 million gain from the settlement of previously entered derivative instruments; partially offset by • $243 million decrease in sublease and subcharter income from our LNG vessels due to fewer days the LNG vessels were subcontracted out and at lower rates in the current year as compared to the same period of 2024.
LNG revenues also exclude volumes produced from the commissioning of certain Corpus Christi Stage 3 Project Trains, as volumes related to commissioning are not recognized as revenues. We recognize proceeds from commissioning activities prior to the start of commercial operations as offsets to LNG terminal costs as a component of the testing phase of a Train’s construction.
We recognize proceeds from commissioning activities prior to the start of commercial operations as offsets to LNG terminal costs, as a component of the testing phase of a Train’s construction. The volumes sold by Cheniere Marketing may be supplemented by volumes procured from third parties at other locations worldwide to support operational requirements or take advantage of market opportunities.
Our effective tax rate decreased between the comparable periods and was lower than the statutory rate of 21.0% because a larger percentage of pre-tax income was attributable to CQP’s income that is not taxable to us.
The effect of the change in our effective tax rate between the comparable periods was not material to our income tax provision.
Net income attributable to Cheniere Net income attributable to Cheniere declined $6.6 billion for the year ended December 31, 2024 as compared to the same period of 2023 and was primarily attributable to $6.7 billion of decreases in gains (before tax and the impact of non-controlling interests) from changes in fair value of derivatives.
(2) Includes volumes sold under short-term agreements and volumes sold from natural gas procured under IPM agreements. 2025 vs. 2024 Net income attributable to Cheniere increased by $2.1 billion during the year ended December 31, 2025 as compared to the same period of 2024 primarily due to $2.3 billion of favorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely associated with our derivatives related to IPM agreements, and an $876 million increase in revenues, net of cost of natural gas feedstock, from increased volume of LNG loaded and recognized between the years.
Removed
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.
Added
Business and Properties, as well as the current geopolitical environment that has intensified the demand for supply security, should enable us to enter into long-term agreements and provide a foundation for additional growth in our business in the future.
Removed
Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices.
Added
Overview of Significant Events Our significant events since January 1, 2025 and through the filing date of this Form 10-K include the following: Strategic Growth • Following our pre-filing in July 2025, in February 2026, we filed an application with the FERC under the NGA for authorization to site, construct and operate in a phased approach the CCL Expansion Project, a potential further expansion of the Corpus Christi LNG Terminal, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities. 36 Table of Contents • In December 2025, we filed an application with the FERC to increase the LNG production capacity of the previously-authorized Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project by approximately 5 mtpa, which remains pending at the FERC. • In March 2025, we received authorization from the FERC under the NGA to site, construct and operate the CCL Midscale Trains 8 & 9 Project, and in June 2025, our Board made a positive FID with respect to the investment in the development, construction and operation of the CCL Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under a fixed price separated turnkey EPC contract. • In June 2025, certain subsidiaries of CQP updated the SPL Expansion Project’s FERC application, originally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities.
Removed
Overview of Significant Events Our significant events since January 1, 2024 and through the filing date of this Form 10-K include the following: Strategic • In July 2024, Cheniere Marketing entered into a long-term SPA with Galp Trading S.A.
Added
Commercialization • In August 2025, Cheniere announced the execution of a long-term LNG SPA between Cheniere Marketing and JERA Co., Inc. ( “JERA” ), under which JERA has agreed to purchase approximately 1 mtpa of LNG from Cheniere Marketing on an FOB basis from 2029 through 2050.
Removed
(“ Galp ”), a subsidiary of Galp Energia, SGPS, S.A., under which Galp has agreed to purchase approximately 0.5 mtpa of LNG from Cheniere 34 Table of Contents Marketing on a free-on-board basis for a term of 20 years.
Added
The purchase price for LNG under the SPA is indexed to the Henry Hub price, plus a fixed liquefaction fee. • In May 2025, Cheniere Marketing entered into an IPM agreement with Canadian Natural Resources Limited to purchase 140,000 MMBtu per day of natural gas at a price based on the Japan Korea Marker, less fixed LNG shipping costs and a fixed liquefaction fee, for a term of approximately 15 years commencing in 2030.
Removed
Deliveries are expected to commence in the early 2030s and are subject to, among other things, a positive FID with respect to the second train of the SPL Expansion Project ( “SPL Train 8” ) and includes a limited number of early cargoes to be purchased by Galp prior to the start of SPL Train 8. • In June 2024, we received a positive Environmental Assessment from the FERC relating to the CCL Midscale Trains 8 & 9 Project.
Added
In February 2026, LNG was produced for the first time from Train 5 of the Corpus Christi Stage 3 Project. • During the second quarter of 2025, we completed planned large-scale maintenance activities on two Trains at the SPL Project.
Removed
We expect to receive all remaining necessary regulatory approvals for the project in 2025. • In February 2024, certain subsidiaries of CQP submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking.
Added
Financial • In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. • In February 2026, SPL redeemed the remaining $200 million aggregate principal amount of its 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes” ). • In August 2025, we amended and restated our $1.25 billion Cheniere Revolving Credit Facility to, among other things, (1) extend the maturity date thereunder, (2) reduce the interest rate and commitment fees payable thereunder and (3) make certain other changes to the terms and conditions of the existing Cheniere Revolving Credit Facility. • In July 2025, CQP issued and sold $1.0 billion aggregate principal amount of 5.550% Senior Notes due 2035 (the “2035 CQP Senior Notes” ), and the net proceeds, together with cash on hand, were used to redeem $1.0 billion of the aggregate principal amount of SPL’s 2026 SPL Senior Notes. • In June 2025, we announced updates to our company outlook, which included a plan to increase our annualized dividend by over 10% to $2.22 per common share, which commenced with the dividend pertaining to the third quarter of 2025. 37 Table of Contents • We received the following upgrades from credit rating agencies, including S&P Global Ratings ( “S&P” ) and Fitch Ratings ( “Fitch” ): Entity Date Previous Rating Upgraded Rating Rating Agency Outlook Cheniere November 2025 BBB BBB+ S&P Stable CQP November 2025 BBB BBB+ S&P Stable CCH October 2025 BBB BBB+ S&P Positive Cheniere February 2025 BBB- BBB Fitch Stable CQP February 2025 BBB- BBB Fitch Stable • In addition to the above issuer credit rating upgrades, the unsecured CQP Notes were upgraded from BBB- to BBB by S&P in June 2025, concurrent with the assignment of the 2035 CQP Senior Notes credit rating.
Removed
In October 2024, the authorization from the DOE to export LNG to FTA countries was received for the SPL Expansion Project.
Added
Market Environment Our results of operations are affected by the market environment in which we operate, including known trends and uncertainties, macroeconomic factors and other external environmental factors.
Removed
Financial • In June 2024, we announced updates to our ‘20/20 Vision’ comprehensive long-term capital allocation plan, which included an increase to our share repurchase authorization by $4.0 billion through 2027 and a plan to increase our quarterly dividend by approximately 15% to $2.00 per common share on an annualized basis, which commenced with the dividend pertaining to the third quarter of 2024. • In May 2024, CQP issued $1.2 billion aggregate principal amount of 5.750% Senior Notes due 2034 (the “2034 CQP Senior Notes” ).
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With just under 20 mtpa of year on year ( “YoY” ) increase in LNG supplies globally in 2025, the LNG market is transitioning from a multi-year state of tight market conditions into a period of rapid growth.
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In June 2024, the net proceeds, together with cash on hand, were used to redeem $1.2 billion of the outstanding aggregate principal amount of SPL’s 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes” ). • In May 2024, in connection with the 2034 CQP Senior Notes issuance, Moody’s Ratings ( “Moody ’ s” ) upgraded CQP’s issuer credit rating to Baa2 from Ba1 and revised CQP’s outlook to stable from positive.
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The continued ramp up in new LNG supplies from the U.S. and Canada mark the start of a more ample supply landscape which is expected to loosen global balances over the next few years and result in a more moderate and stable price environment for LNG.
Removed
Moody’s also upgraded SPL’s issuer credit rating to Baa1 from Baa2 and revised SPL’s outlook to stable from positive. In July 2024, Fitch Ratings upgraded CCH’s issuer credit rating to BBB+ from BBB with a stable outlook.
Added
Sustained downward pressure on global prices could potentially unlock latent demand that has otherwise been priced out since the disruption of Russian natural gas supply to Europe.
Removed
In October 2024, S&P Global Ratings changed the outlook of CCH’s senior secured debt rating to positive from stable. • In March 2024, we issued $1.5 billion aggregate principal amount of 5.650% Senior Notes due 2034 (the “2034 Cheniere Senior Notes” ).
Added
The increase in supply corresponded to a 5% YoY uptick in trade, which was primarily supported by Europe and the Middle East and North Africa ( “MENA” ) region amid weaker demand in Asia. Europe’s demand for LNG increased approximately 27% YoY in 2025 reaching a record level of approximately 125 mtpa.
Removed
Global LNG imports registered a very modest growth in 2024, increasing by less than 4 mtpa year on year due to constrained supply from delays to projects under construction, Russian sanctions and a fallow period for new projects coming on-line. Consequently, a recovery in Asia’s LNG consumption had to be satisfied at the expense of other regions.
Added
The main driver for this growth continues to be the replacement of Russian natural gas and the replenishment of underground storage inventories. We expect this driver to continue to play an important role in keeping LNG demand in Europe resilient, especially in light of the European Parliament’s vote to ban all residual Russian natural gas, including Russian LNG by 2027.
Removed
Asian demand increased significantly from 2023, adding over 20 mtpa of import year-over-year. The largest single country contribution to this growth came from China, which increased 6.8 mtpa year-over-year after a slowdown during the previous two years. Growth outside of Asia tightened the balances further this year by increasing the call on supply away from Europe.
Added
The MENA region also contributed to demand growth in 2025 with imports increasing 7 mtpa or 62% versus 2024.
Removed
Egypt and Brazil propelled imports from the Middle East, North Africa and Latin America regions by 6.2 mtpa to a total of 25.5 mtpa in 2024. In contrast, Europe’s imports declined 19% year-over-year, down approximately 22.7 mtpa, due to weak gas-fired power generation demand and sluggish growth in the industrial sector.
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Egypt was the main driver of this increase as it resorted to additional LNG imports to satisfy its growing domestic energy needs and supplement its own natural gas production. 38 Table of Contents Asia’s LNG consumption however was down about 4% in 2025, dropping by 12 mtpa to 270 mtpa.
Removed
These market conditions contributed to a strong spot price environment albeit annual spot prices in 2024 were overall lower than in the previous year. The TTF monthly settlement prices averaged $10.91/MMBtu in 2024, 20.5% lower than the 2023 average of $13.73/MMBtu.
Added
While many of the major markets in Asia saw YoY declines, China’s was the largest, representing nearly the entire YoY change in the region. China’s LNG imports declined 16% or 12 mtpa YoY, due to broader, likely transient macro-economic challenges.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeQUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Marketing and Trading Commodity Price Risk We have commodity derivatives consisting of natural gas and power supply contracts for the commissioning and operation of the Liquefaction Projects and the SPL Expansion Project, and associated economic hedges (collectively, the “Liquefaction Supply Derivatives” ) and physical and financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives” ).
Biggest changeQUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Marketing and Trading Commodity Price Risk We have commodity derivatives consisting of natural gas and power supply contracts for the commissioning and operation of the Liquefaction Projects and the SPL Expansion Project, and associated economic hedges (collectively, the “Liquefaction Supply Derivatives” ) and LNG derivatives in which we have contractual net settlement and economic hedges on the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives” ).
In 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, 2024 December 31, 2023 Fair Value Change in Fair Value Fair Value Change in Fair Value Liquefaction Supply Derivatives $ (742) $ 2,516 $ (2,117) $ 1,526 LNG Trading Derivatives 17 49 10 12 See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments. 50 Table of Contents
In 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, 2025 December 31, 2024 Fair Value Change in Fair Value Fair Value Change in Fair Value Liquefaction Supply Derivatives $ 2,865 $ 2,722 $ (742) $ 2,516 LNG Trading Derivatives (17) 1 17 49 See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments. 53 Table of Contents

Other LNG 10-K year-over-year comparisons