Cheniere Energy, Inc.: Form 10-K for the period ended Dec 31, 2024

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. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

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

• Risks Relating to Our Financial Matters;
• Risks Relating to Our Operations and Industry; and
• Risks Relating to Regulations.

Risks Relating to Our Financial Matters

An inability to source capital to supplement our available cash resources and existing credit facilities could cause us to have inadequate liquidity and could materially and adversely affect us.

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). SPL, CQP, CCH and Cheniere operate with independent capital structures as further detailed in Note 10—Debt of our Notes to Consolidated Financial Statements. 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. Our ability to fund our capital expenditures and refinance our indebtedness may depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, lending institutions’ evolving policies on financing businesses linked to fossil fuels and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also may rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

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 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.

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.

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.

Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. 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.

The agreements governing our and our subsidiaries’ indebtedness contain customary terms and events of default and certain covenants that, among other things, may limit our and our subsidiaries’ ability to make certain investments or pay dividends or distributions. For example, CCH and SPL are restricted from making distributions under agreements governing their indebtedness generally unless, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical and projected debt service coverage ratio of 1.25:1.00 is satisfied.

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.

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.

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. 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. 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. 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.

These transactions and other derivative transactions have and may continue to result in substantial volatility in results of operations reported under GAAP, particularly in periods of significant commodity, currency or financial market variability. 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 liquidity may be adversely impacted by the cash margin requirements of the respective commodity exchanges or over-the-counter arrangements, or the failure of a counterparty to perform in accordance with a contract. 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.

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.

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.

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.

Dividends are authorized and determined by our Board in its sole discretion and depend upon a number of factors, including:

• Cash available for distribution;
• Our results of operations and anticipated future results of operations;
• Our financial condition, especially in relation to the anticipated future capital needs of any expansion of our liquefaction facilities;
• The level of distributions paid by comparable companies;
• Our operating expenses; and
• Other factors our Board deems relevant.

We expect to continue to pay quarterly dividends to our stockholders; however, our Board may reduce our dividend or cease declaring dividends at any time, including if it determines that our current or forecasted future cash flows provided by our operating activities, after deducting capital expenditures, investments and other commitments, are not sufficient to pay our desired levels of dividends to our stockholders or to pay dividends to our stockholders at all.

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. 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.

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.

Risks Relating to Our Operations and Industry

Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Projects, damage to our Liquefaction Projects and increased insurance costs, all of which could adversely affect us.

Weather events such as major hurricanes and winter storms have caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our facilities. Our risk of loss related to weather events or other disasters is limited by contractual provisions in our SPAs, which can provide under certain circumstances relief from operational events, and partially mitigated by insurance we maintain. Aggregate direct and indirect losses associated with the aforementioned weather events, net of insurance reimbursements, have not historically been material to our Consolidated Financial Statements, and we believe our insurance coverages maintained, existence of certain protective clauses within our SPAs and other risk management strategies mitigate our exposure to material losses. 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. 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.

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.

We depend upon third party pipelines and other facilities that provide gas delivery options to our liquefaction facilities and pipelines. 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. 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. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Projects to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of 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. Our risk is in part mitigated by the diversification of our natural gas supply and transportation across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. 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.

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.

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. The commercial development of an LNG facility takes a number of years and requires a substantial capital investment that is dependent on sufficient funding and commercial interest, among other factors.

We will require significant additional funding to be able to commence construction of the 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. 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.

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.

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. 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. Although our major EPC contracts are fixed price, as construction progresses, we may decide or be forced to submit change orders to our contractor, including change orders to comply with existing or future environmental or other regulations. 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. As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Significant increases in the cost of a 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. While historically we have not experienced cost overruns or construction delays that have had a significant adverse impact on our operations, factors giving rise to such events in the future may be outside of our control and could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are subject to significant construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The construction and operation of our LNG terminals and our pipelines are, and will be, subject to the inherent risks associated with these types of operations as discussed throughout our risk factors, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. Although losses incurred as a result of self-insured risk have not been material historically, the occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are dependent on our EPC partners and other contractors for the successful completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project.

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. The ability of our EPC partners and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:

• design and engineer each Train to operate in accordance with specifications;
• engage and retain third party subcontractors and procure equipment and supplies;
• respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
• attract, develop and retain skilled personnel, including engineers;
• post required construction bonds and comply with the terms thereof;
• manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
• maintain their own financial condition, including adequate working capital.

Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Corpus Christi Stage 3 Project and any potential expansion projects, including the 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. The obligations of EPC partners and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.

Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, or result in a contractor’s unwillingness to perform further work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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. 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.

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.

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. However, other events outside of our control where we may not be protected may have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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. While historical downturns have not had a material adverse impact to our operations or results, any prolonged weakening of such markets could result in depressed or negative margins. See the risk factor Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects for additional discussion.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:

• competitive liquefaction capacity in North America;
• insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
• insufficient LNG tanker capacity;
• weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;
• reduced demand and lower prices for natural gas;
• increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
• decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
• cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;
• changes in supplies of, and prices for, alternative energy sources which may reduce the demand for natural gas;
• changes in regulatory, tax or other governmental policies regarding 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.

Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect our LNG business and the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Failure of exported LNG to be a long term competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Operations of the Liquefaction 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. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from the United States and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.

Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, 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. 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. However, as a result of transitions globally from fossil-based systems of energy production and consumption to renewable energy sources, LNG may face increased competition from alternative, cleaner sources of energy as such alternative sources emerge. Additionally, LNG from the Liquefaction Projects also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction 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. 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. However, as a result of the factors described above and other factors, the LNG we produce may not remain a long term competitive source of energy internationally, particularly when our existing long term contracts begin to expire. Any significant impediment to the ability to continue to secure long term commercial contracts or deliver LNG from the United States could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We face competition based upon the international market price for LNG.

Our Liquefaction Projects are subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our Liquefaction Projects are diverse and include, among others:

• increases in worldwide LNG production capacity and availability of LNG for market supply;
• increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
• increases in the cost to supply natural gas feedstock to our Liquefaction Projects;
• decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
• decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
• increases in capacity and utilization of nuclear power and related facilities; and
• displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

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.

The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our trading, marketing, pipeline, liquefaction and shipping operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Projects. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should multiple of the third party pipelines which supply our Liquefaction Projects suffer similar concurrent attacks, our Liquefaction Projects may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A cyber attack involving our business or operational control systems or related infrastructure, or that of third 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.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our senior management or other key personnel could affect our business results.

We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. 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. 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. 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 do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term, other than our employment agreement with our President and Chief Executive Officer. The loss of the services of any of these individuals could have a material adverse effect on our business.

Outbreaks of infectious diseases, such as COVID-19, at one or more of our facilities could adversely affect our operations or business.

Our facilities at the Sabine Pass LNG Terminal and Corpus Christi LNG Terminal are critical infrastructure and continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including subsequent variants, had no adverse impact on our on-going operations, the risk of future variants and other infectious diseases is unknown and the outbreak of a more potent variant or another infectious disease in the future at one or more of our facilities could adversely affect our operations or business.

Risks Relating to Regulations

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipelines and the export of LNG could impede operations and construction and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG.

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. 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 March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project, for which a positive Environmental Assessment from the FERC was received in June 2024. 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. 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. 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. Failure to comply with or our inability to obtain and maintain existing or newly imposed approvals, permits and filings that may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to our operations could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our 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.

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. Under the NGA, the rates charged by our interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any potential shipper with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our interstate pipelines could be subject to substantial penalties and fines.

In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.5 million per day for each violation.

Although the FERC has not imposed fines or penalties on us to date, we are exposed to substantial penalties and fines if we fail to comply with such regulations.

Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.

Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our LNG 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. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, difficulty obtaining and maintaining permits from regulatory agencies or increased capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.

The EPA has finalized or proposed multiple GHG regulations that impact our assets and supply chain. On December 2, 2023, the EPA issued final rules to reduce methane and VOC emissions from new, existing and modified emission sources in the oil and gas sector. These regulations require monitoring of methane and VOC emissions at our compressor stations. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that 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. In addition, other international, federal and state initiatives may be considered in the future to address GHG emissions through treaty commitments, direct regulation, market-based regulations such as a GHG emissions tax or cap-and-trade programs or clean energy or performance-based standards. 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.

Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.

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. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY beginning in 2022.

Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national or international climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.

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. Revised, reinterpreted or additional laws and regulations that result in increased compliance, operating or construction costs or restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.

The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:

• perform ongoing assessments of pipeline safety and compliance;
• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
• improve data collection, integration and analysis;
• repair and remediate the pipeline as necessary; and
• implement preventative and mitigating actions.

We are required to utilize pipeline integrity management programs that are intended to maintain pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines, 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.

We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact. Any changes to local, domestic or international tax laws and regulations, or their interpretation and application, including those related to tariffs and duties, could affect our obligations, profitability and cash flows in the future. In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control. We continuously monitor and assess proposed tax legislation that could negatively impact our business.

We became subject to the 15% CAMT in 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service (the “IRS”) released proposed regulations relating to the application and implementation of the CAMT. The proposed regulations address a wide range of topics relating to the operation of CAMT; however, significant uncertainty continues to exist regarding many of the operative implementing provisions and regulatory guidance related to the CAMT issued in the future could affect both the timing and amount of our CAMT liability.

Cyberattacks represent a potentially significant risk to the Company and our industry. We have implemented policies and procedures that are intended to manage and reduce this risk.

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”). 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. We include business continuity planning as a component of our strategy to help ensure critical systems are available to support our company in the instance of a disruptive event. We also participate in various industry organizations to stay abreast of recent trends and developments.

On an ongoing basis, we assess our people, processes and technology and, when necessary, adjust the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. We conduct regular assessments and audits, cross-functional risk mitigation exercises and risk strategy sessions to identify cybersecurity risks, applicable regulatory requirements and industry standards. These engagements are also designed to exercise, assess the maturity of and enhance 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. 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.

With respect to third party service providers, our information security program includes conducting risk-based due diligence of certain service providers’ information security programs prior to onboarding. We seek to contractually require third party service providers with access to our information technology systems, sensitive business data or personal information to maintain reasonable security controls and restrict their ability to use our data, including personal information, for purposes other than to provide services to us, except as required by applicable law. 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.

Governance

Our cybersecurity leadership team consists of our Director and Chief Information Security Officer, Vice President and Chief Information Officer and Senior Vice President of Shared Services. These individuals collectively provide the strategic oversight of our cybersecurity governance, cyber risk management and security operations and are responsible for maintaining our technology defense posture and program. As part of their governance and risk management responsibilities, these individuals oversee the efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents, including the systems deployed in our technology infrastructure to monitor for threats, perform security control testing and assessments, and incorporate threat intelligence into our day-to-day cybersecurity operations and strategic initiatives. 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. Cybersecurity risks are integrated into our enterprise risk assessment process, which is reviewed by our Board at least annually. Our 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. The Audit Committee discusses with management our cybersecurity risk exposures and the steps management has taken to mitigate such exposures, including our risk assessment and risk management policies. On a quarterly basis, our cybersecurity leadership team updates the Audit Committee on the overall status of our cybersecurity program, key operational metrics, current assessments, cybersecurity issues or events and pertinent events related to cybersecurity.

For additional information about cybersecurity risks, see the risk A cyber attack involving our business, operational control systems or related infrastructure, or that of third 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 are, and may in the future be, involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.

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. 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. In March 2022, the EPA lifted the stay, and in June 2022 our subsidiaries petitioned the EPA and LDEQ for approval of additional operating parameters to demonstrate compliance with the emission limitation. The petition remains pending. 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. We do not expect that any ultimate penalty will have a material adverse impact on our financial results.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Discussion of 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.

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. 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.

Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. 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. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. 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. The continued strength and stability of our long-term cash flows served as the foundation of our updated comprehensive, long-term capital allocation plan announced in June 2024, which includes an increased share repurchase authorization and increased dividends, in addition to a continued decrease in consolidated long-term leverage and investment in accretive organic growth.

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. (“Galp”), a subsidiary of Galp Energia, SGPS, S.A., under which Galp has agreed to purchase approximately 0.5 mtpa of LNG from Cheniere

Marketing on a free-on-board basis for a term of 20 years. 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. 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. In October 2024, the authorization from the DOE to export LNG to FTA countries was received for the SPL Expansion Project.

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.

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”). 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. 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. 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”). 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.

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. 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. 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. 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.

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. Similarly, the average settlement price for the Japan Korea Marker (“JKM”) was $11.83/MMBtu in 2024, 26.6% lower than the 2023 average of $16.13/MMBtu. The Henry Hub benchmark also dropped from an average settlement price of $2.74/MMBtu in 2023 to $2.27/MMBtu in 2024, down 17.1% year-over-year.

However, a drop in temperatures in Europe toward the end of 2024 and into the beginning of 2025 has resulted in faster drawdowns from underground storage and a rebound in spot prices relative to the third quarter. This, 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.

Results of Operations

Consolidated results of operations

(in millions, except per share data)

Volumes loaded and recognized from the Liquefaction Projects

37

Components of LNG revenues and corresponding LNG volumes delivered

(1) Long-term agreements include agreements with an initial tenor of 12 months or more.

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. The majority of the decrease was attributable to our IPM agreements, where the associated gains that are primarily included in cost of sales decreased from $7.0 billion during the year ended December 31, 2023 to $1.5 billion during the year ended December 31, 2024, mainly due to the impact on fair value of the decline and sustained moderation of global LNG and gas price volatility and more subdued changes in the current period relative to the same period of 2023 as global prices and spreads narrowed as a result of market rebalancing. The remaining change in fair value of derivatives was primarily due to an unfavorable shift in long-term U.S. natural gas basis spreads. In addition, there was a $2.8 billion decrease in LNG revenues, net of cost of sales and excluding the effect of derivatives, for the year ended December 31, 2024 as compared to the same period of 2023, the majority of which was attributable to a reduction of volumes sold under short-term agreements as a higher proportion of our LNG was sold under long-term contracts, as further described in Revenues below.

These unfavorable variances were partially offset by:

• $1.7 billion favorable variance in income tax provision between the year ended December 31, 2024 as compared to the same period of 2023, primarily due to lower taxable earnings as described above; and
• $938 million reduction in net income attributable to non-controlling interests during the year ended December 31, 2024 as compared to the same period of 2023, substantially all of which is due to a decrease in CQP’s consolidated net income between the comparable periods from declining gains related to changes in fair value of derivatives between the years.

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
• $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.

Operating costs and expenses

The $4.7 billion unfavorable variance between the year ended December 31, 2024 compared to the same period of 2023 was primarily attributable to:

• $6.5 billion of decreases in gains from changes in fair value of derivatives included in cost of sales, with the primary drivers of the variance described above under the caption Net income attributable to Cheniere;

This unfavorable variance was partially offset by:

• $1.7 billion decrease between the periods in cost of sales excluding the effect of derivative changes described above, primarily as a result of a $1.6 billion decrease in cost of 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 in the current year compared to the prior year.

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.

Income tax provision

The $1.7 billion favorable variance between the years ended December 31, 2024 and 2023 was primarily attributable to a $9.3 billion decrease in pre-tax income and, to a lesser extent, a lower effective tax rate between the periods.

Our effective tax rate was 15.3% and 17.3% for years ended December 31, 2024 and 2023, respectively. 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.

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.

Significant factor affecting our results of operations

Below is a significant factor that affects our results of operations.

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. For commodity derivative instruments, including those related to our IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. 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. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt and equity offerings by us or our subsidiaries. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.

(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. 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. See Note 10—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

Our liquidity position subsequent to December 31, 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.

Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures. Certain restrictions or requirements under debt and equity instruments executed by our subsidiaries limit the entity’s use of cash, including the following:

• SPL and CCH are required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Projects and other restricted payments. In addition, SPL and CCH’s operating costs are managed by our subsidiaries under affiliate agreements, which may require SPL and CCH to advance cash to the respective affiliates, however the cash remains restricted for operation and construction of the Liquefaction Projects;
• CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner. 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.

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. The sources of liquidity at SPL, CQP and CCH primarily fund the cash requirements of the respective entity, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by Cheniere Marketing, is available to enable Cheniere to meet its cash requirements.

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. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.

Future Sources of Liquidity under Executed Contracts

We expect future material sources of liquidity to be derived from our long-term customer arrangements and structured cash flows under our SPAs and IPM agreements. As described in Items 1. and 2. Business and Properties, these contracts with creditworthy counterparties form the foundation of our business and provide us with significant, stable, long-term cash flows. Under our long-term SPAs and IPM agreements, we have contracted substantially all of our total anticipated production through the mid-2030s from our liquefaction capacity that is currently under construction or in operation.

LNG Revenues from Executed SPAs

We are contractually entitled to significant future consideration contracted under our long-term SPAs that has not yet been recognized as revenue. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be significant to our future liquidity. 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 terms dependent on project milestone dates based on the estimated dates as of December 31, 2024. The following table summarizes our estimate of revenues to be received from executed long-term SPAs as of December 31, 2024 (in billions):

(1) LNG revenues exclude estimated revenues from contracts with unsatisfied contractual conditions precedent. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones, such as reaching FID on a certain liquefaction Train.

(2) LNG revenues exclude revenues from contracts with original expected durations of one year or less. 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.

(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.

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. The variable fees under our SPAs were generally sized with the intention to cover the supply and transportation of natural gas and the liquefaction fuel consumed to produce the LNG to be sold under each such SPA, thus limiting our exposure to future U.S. natural gas price increases. Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension.

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. This LNG includes LNG produced from (1) the Liquefaction Projects prior to the date of first commercial delivery under long-term SPAs, (2) LNG production efficiencies and (3) natural gas procured under IPM agreements, as described below. These volumes may be supplemented by volumes procured from other locations worldwide to support operational requirements or take advantage of market opportunities.

Liquidity from Executed IPM Agreements

The table in the LNG Revenues from Executed SPAs section above excludes fees expected to be generated through sales of LNG produced from natural gas procured under our IPM agreements, under which we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. While IPM agreements are not revenue contracts for accounting purposes, the payment structure under the IPM agreements generates a take-or-pay style fixed liquefaction fee. Although the IPM agreements secure natural gas purchases over long-term periods, the LNG produced from that natural gas is generally sold under short-term SPAs. 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.

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. 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. 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. In October 2024, the authorization from the DOE to export LNG to FTA countries was received. In June 2024, we received a positive Environmental Assessment from the FERC relating to the CCL Midscale Trains 8 & 9 Project, and we expect to receive all remaining necessary regulatory approvals for the project in 2025. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts

We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures related to our core operations under executed contracts as of December 31, 2024 (in billions):

(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.

(2) Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. We include contracts for which we have an early termination option if the option is not currently expected to be exercised. We include contracts with unsatisfied contractual conditions if the conditions are currently expected to be met.

(3) Natural gas supply agreements exclude IPM agreements, which are structured to generate a fixed margin when viewed in conjunction with the sale of LNG produced from the natural gas procured under the IPM agreements, as described under Liquidity from Executed IPM Agreements.

(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.

(5) Natural gas transportation and storage services agreements include $1.2 billion in obligations to 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, 2024 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.

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. 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 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.

To ensure that we are able to transport natural gas feedstock to the Liquefaction Projects, we have transportation precedent and other agreements to secure firm pipeline transportation capacity from interstate and intrastate pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Projects.

Capital Expenditures

We enter into lump sum turnkey contracts with third party contractors for the EPC of our Liquefaction Projects. 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. In addition to amounts presented in the table above, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity.

Corpus Christi Stage 3 Project

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2024:

Leases

Our obligations under our lease arrangements primarily consist of LNG vessel time charters with terms of up to 15 years to ensure delivery of cargoes sold on a DAT basis. We have also entered into leases for the use of tug vessels, office space and facilities, land sites and equipment.

Additional Future Cash Requirements for Operations and Capital Expenditures

Corporate Activities

We are required to maintain corporate and general and administrative functions to serve our business activities. During the year ended December 31, 2024, selling, general and administrative expense was $0.4 billion, a portion of which was related to leases for office space which is included in the table of cash requirements for operations and capital expenditures under executed contracts above.

Taxes

CAMT accelerates our cash tax payments for federal income taxes due to near-term deferral of the realization of our existing NOL carryforwards and may cause volatility in future cash tax payments due to variability in adjusted financial statement income. Additionally, our cash tax payments may be substantially lower in the periods that the Corpus Christi Stage 3 Project is placed into service due to anticipated tax depreciation allowances from the project. Thus, the ongoing interplay between the CAMT, the utilization of our existing NOLs and bonus depreciation eligibility of our Corpus Christi Stage 3 Project is expected to cause volatility in our cash tax payments. 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.

As part of our ongoing effort to mitigate our emissions from our shipping transport operations, we primarily utilize the LNG that we produce at our terminals as transport fuel in our shipping vessel operations, serving as a substitute for diesel and heavy fuel oils, which have higher emission factors. 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. Although we believe we qualify and are entitled to claim such credits, we have not recognized any financial benefit of our credit claims in our results of operations to date. Our claims are currently under review by the IRS, and there is ongoing uncertainty regarding the final determination of our eligibility.

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.

Future Cash Requirements for Financing under Executed Contracts

We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2024 (in billions):

(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. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.

Debt

As of December 31, 2024, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $23.1 billion and credit facilities with no outstanding loan balances. As of December 31, 2024, each of our issuers was in compliance with all covenants related to their respective debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10—Debt of our Notes to Consolidated Financial Statements.

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. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.075% to 0.525%, subject to change based on the applicable entity’s credit rating. Issued letters of credit under our credit facilities are subject to letter of credit fees ranging from 1.0% to 2.20%, subject to change based on the applicable entity’s credit rating. We had $334 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2024.

Additional Future Cash Requirements for Financing

CQP Distributions

CQP is required by its partnership agreement to, within 45 days after the end of each quarter, distribute to unitholders all available cash at the end of a quarter less the amount of any reserves established by its general partner. 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. 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. As of December 31, 2024, we had up to $3.9 billion available under the share repurchase program. 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. 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 Item 5. Market for Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchase of Equity Securities.

Another aspect of our capital allocation plan is to lower our long-term leverage target through debt paydown to approximately 4x, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of our indebtedness, including senior notes of SPL, CQP, CCH and Cheniere. 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 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. 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.

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.

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. Additional discussion of these items follows the table.

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. 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. 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. 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. 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.

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.

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. 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. 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.

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. We expect to incur a proportional level of capital expenditures in the upcoming year as construction work progresses on the Corpus Christi Stage 3 Project.

Financing Cash Flows

The following table summarizes our financing activities (in millions):

Debt Issuances

The following table shows our debt issuances (in millions):

Debt Redemptions, Repayments and Repurchases

The following table shows the redemptions, repayments and repurchases of debt, including intra-year repayments (in millions):

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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. As of December 31, 2024, we had approximately $3.9 billion remaining under our share repurchase program.

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.

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.

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.

Fair Value of 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. We record changes in the fair value of our derivative positions through earnings, based on the value for which the derivative instrument could be exchanged between willing parties. Valuation of our liquefaction supply derivative contracts is often developed through the use of internal models which includes significant unobservable inputs representing Level 3 fair value measurements as further described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.

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. 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. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended

December 31, 2024 and 2023 (in millions), which entirely consisted of liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the end of each respective period.

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.

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 ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as it relates to commodity prices impacting the valuation of our liquefaction supply derivatives, given the level of volatility to which such prices are subjected. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices.

Recent Accounting Standards

For a summary of recently issued accounting standards, see Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.

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”). 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):

See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on their evaluation as of the end of the fiscal year ended December 31, 2024, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Our Management’s Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements and is incorporated herein by reference.