LNG 10-K & 10-Q changes, risk factors and insider trading

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 operationoperations 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.

As of December 31, 2024,2025, we had, on a consolidated basis, $2.6$1.1 billion of cash and cash equivalents (of which $270$182 million was held by CQPour consolidated variable interest entities (“VIEs”)), $552$485 million of restricted cash and cash equivalents (of which $109$22 million was held by CQPour VIEs), a total of $7.7$7.2 billion of available commitments under our credit facilities and $23.1$23.0 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,Project as well asand the CCL Midscale Trains 8 & 9 ProjectProject, andas well as the SPL Expansion Project and the CCL Expansion Project if a positive FIDFIDs isare 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 lenders or seek alternative 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 future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2024,2025, we had SPAs with initial terms of 10 or more years with aapproximately total of 2930 different third party customers.customers, with customers under common control being considered a single customer.

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.

In addition, prior to completion of the Corpus Christi Stage 3 Project, CCH is also required to confirm before making a distribution that it has sufficient funds, including senior debt commitments, equity funding and projected contracted cash flows from the fixed price component of its third party SPAs, to meet remaining expenditures required for the Corpus Christi Stage 3 Project in order to achieve completion by a certain specified date.

In addition to restrictions on the ability of us, CQP, SPL and CCH to make distributions or incur additional indebtedness, as further described in the immediately preceding risk factor, the agreements governing our indebtedness also contain various other covenants that may prevent us from engaging in beneficial transactions, including limitations on our ability to:

Additionally as of December 31, 2024,2025, $3.9$1.2 billion of repurchase authority remained under our share repurchase program authorized by our Board had authorized,Board, which wassubsequently increased into Juneapproximately 2024 by $4.0$10 billion from 2026 through 2027.2030 after a $9 billion increase was authorized in February 2026. 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.

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, or interruptions to our power supply, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of our Liquefaction Projects or our other facilities. Our LNG terminal infrastructure and LNG facilities located in or near Corpus Christi, Texas and Sabine Pass, Louisiana are designed in accordance with the requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards, and all applicable industry codes and standards.

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 for transporters to continue shipping natural gas to us 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 immediately preceding 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.factor. 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.

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 immediately preceding risk factorfactor. DisruptionsAdditionally, tocomposition changes in the third party supplyquality of naturalfeed gas toreceived ourfrom pipelinesthird parties may impact operational efficiency and facilitiesperformance, which could have a material adversean effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.results. 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.

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, includingProject, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project.

Timely and cost-effective completion of the Corpus Christi Stage 3 Project and any potential expansion projects, includingProject, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our EPC partners, including Bechtel, and our other contractors under their agreements. 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:

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, includingProject, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. 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, includingProject, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project, or result in a contractor’s unwillingness to perform further work. 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,LNG to customers, such as shortages of LNG vessels worldwide or operational impacts on LNG shipping, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We sell a significant amount of our LNG under DATDAP 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.

•changes in governmental regulations or maritime self-regulatory organizationsorganizations’ regulations;

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.

•increasingly competitive liquefaction capacity in North AmericaAmerican LNG landscape;

•reduced demand and lower prices for natural gas worldwide;

•increased natural gas production worldwide, either domestically or deliverable by pipelines, which could suppress demand for LNG;

•decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas throughin hydraulicNorth fracturingAmerica;

•changes in regulatory, tax or other governmental policies regarding exported North American LNG, natural gas or alternative energy sources, which may reduce the demand for exported North American LNG and/or natural gas;

•adverse relative demand for North American LNG compared to other markets,sources, which may decrease LNG exports from North America; and

Operations of the Liquefaction Projects are dependent upon the ability of our SPA customers to deliver LNG supplies from theNorth United States,America, 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 theNorth United StatesAmerica 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 theNorth United States,America, which could increase the available supply of natural gas outside theNorth United StatesAmerica 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,U.S., may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States.U.S. 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.U.S.

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 theNorth United States,America, including the Liquefaction Projects, may also be impacted by an increase in natural gas prices in theNorth United States.America.

As described in General in Items 1. and 2. Business and Properties, as of December 31, 2025, we have contracted through our SPAs and IPM agreements approximately 95%90% of the total anticipated production from the Liquefaction Projects through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes from SPAs that are contractuallyconditional subject toon additional liquefaction capacity beyond what is currently in construction or operation.operation, subject to unilateral waiver by us. 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 StatesU.S. could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

•decreases in demand for LNG or increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;

A cyber attackcyberattack 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 attacksCyberattacks 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,cyberattacks, 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 attackcyberattack 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 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,U.S., 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.

The design, construction and operation of interstate natural gas pipelines, LNG terminals,Trains, including those at the Liquefaction Projects, CCLthe MidscaleSPL Trains 8 & 9Expansion Project, the SPLCCL 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 43 of the NGA authorizing SPL, CCL and the Corpus Christi Stage 3 Project to export domestically produced LNG.LNG, as further detailed in DOE Export Licenses in Our Business. We currently have the SPL Expansion Project and the CCL Midscale Trains 8 & 9 Project pending non-FTA export approval with the DOE. However, non-FTA export approval for the SPL Expansion Project is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal applications.application. 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.

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. UnderThe theFERC’s EPAct, the FERC has civil penalty authorityjurisdiction under the NGA andallows the NGPAimposition toof imposecivil and criminal penalties for currentany violations of the NGA and any rules, regulations or orders of the FERC thereunder, up to $1.5$1.6 million per day for each violation.

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 StatesU.S. 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 would have applied to our facilities beginning in calendar year 2024. OnThe NovemberOBBBA, 12,signed 2024,by President Trump on July 4, 2025, delays the EPAimposition finalizedof a rule to impose and collectthe methane emissions chargescharge authorizeduntil undercalendar theyear IRA.2034. 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.

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. Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. 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 2024,2025, we continued to grow our portfolio of SPA and IPM agreements, and we believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, willas well as the current geopolitical environment that has intensified the demand for supply security, should enable us to enter into long-term agreements and provide a foundation for additional growth in our business in the future. 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.

•As of February 14,20, 2025,2026, approximatelyover 3,9304,610 cumulative LNG cargoes totaling approximatelyover 270315 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

•In March, August, October and December 2024,2025, wesubstantial achievedcompletions firstof LNGTrains production1, from2 Train3 1and 4, respectively, of the Corpus Christi Stage 3 Project andwere inachieved. In February 2025, the first cargo of2026, LNG was produced for the first time from Train 5 of the Corpus Christi Stage 3 Project.

◦Excluding•In amountsFebruary refinanced,2026, SPL redeemed $800the remaining $200 million of outstanding aggregate principal amount of its senior5.875% securedSenior notes.Secured Notes due 2026 (the “2026 SPL Senior Notes”).

◦We continued to invest in accretive organic growth, including our investmentinvestments in the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

RevenuesTotal revenues

The $4.7$4.3 billion decreaseincrease in total revenues betweenduring the year ended December 31, 20242025 as compared to the same period of 20232024 was primarily attributable to:

•$676$2.9 millionbillion decreaseincrease in revenues attributabledue to declininghigher pricing per MMBtu primarily from increased Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed, between the years.indexed;

As of MarchJune 31,30, 2026, we were the largest producer of LNG in the U.S. and the second largest LNG operator globally, based on the total production capacity of our natural gas liquefaction facilities. Our total production capacity is expected to be over 60 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which approximatelyover 86 mtpa was under construction and the remainder was in operation as of MarchJune 31,30, 2026, comprised of the following:

•over 30 mtpa of total production capacity in operation from natural gas liquefaction facilities located in Cameron Parish, Louisiana at Sabine Pass (the “SPL Project”). We own and operate the SPL Project and export facility (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, through our ownership interest in and management agreements with CQP, which is a publicly traded limited partnership. As of MarchJune 31,30, 2026, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP. The Sabine Pass LNG Terminal also has five LNG storage tanks with aggregate capacity of approximately 17 Bcfe and vaporizers with regasification capacity of approximately 4 Bcf/d, as well as three marine berths, two of which can accommodate vessels with nominal capacity of up to 266,000 cubic meters and the third berth, which can accommodate vessels with nominal capacity of up to 200,000 cubic meters. We also own and operate through CQP a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the “Creole Trail Pipeline”).

•over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including approximatelyover 86 mtpa under construction and the remainder in operation as of MarchJune 31,30, 2026, from our natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”), of which we have 100% ownership interest. The Corpus Christi LNG Terminal also has three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. We also own and operate through CCP an approximately 21-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several large interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”). The projects under construction at the Corpus Christi LNG Terminal include:

◦a project consisting of seven midscale Trains that is expected to add total production capacity of over 10 mtpa of LNG once fully completed (the “Corpus Christi Stage 3 Project”), with approximatelyover 31 mtpa under construction and the remainder in operation from the first fivesix midscale Trains that have reached substantial completion as of MarchJune 31,30, 2026; and ◦a project consisting of two additional midscale Trains that is expected to add total production capacity of approximately 5 mtpa of LNG once fully completed, inclusive of estimated debottlenecking opportunities (the “CCL Midscale Trains 8 & 9 Project” and together with the existing assets at the Corpus Christi LNG Terminal, the Corpus Christi Stage 3 Project and the Corpus Christi Pipeline, the “CCL Project”), which was under construction as of MarchJune 31,30, 2026.

Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows, and include SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and long-term IPM agreements, in which a gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is primarily indexed to Henry Hub and 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. Through our SPAs and long-term IPM agreements currently in effect, with approximately 15 years of weighted average remaining life as of MarchJune 31,30, 2026, we have contracted approximately90% 90%or more of the total anticipated production from the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes from SPAs that are conditional on additional liquefaction capacity beyond what is currently in construction or operation, subject to unilateral waiver by us. 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.

•As of MayJuly 1,31, 2026, over 4,7604,940 cumulative LNG cargoes totaling over 325340 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

•In March and June 2026, substantial completioncompletions of TrainTrains 5 and 6, respectively, of the Corpus Christi Stage 3 Project waswere achieved.

•In MarchJune 2026, CheniereCQP issued and sold $1.0 billion aggregate principal amount of 5.200%5.350% Senior Notes due 2036 (the “2036 CQP Senior Notes”) and $750 million aggregate principal amount of 6.000%6.050% Senior Notes due 2056,2056 (the “2056 CQP Senior Notes”), and a portion of the net proceeds waswere used to prepayfully $550redeem million$1.5 billion aggregate principal amount of CCH’sSPL’s outstanding5.00% borrowingsSenior underSecured Notes due 2027 (the “2027 SPL Senior Notes”), as well as for general corporate purposes, including funding a portion of the CCHLNTP Creditrelated Facility.to Concurrently,the wefirst canceled $600 millionphase of unused commitments under the CCHSPL CreditExpansion Facility.Project.

•During the three and six months ended MarchJune 31,30, 2026, we accomplished the following pursuant to our capital allocation priorities:

◦We repurchased approximately 2.72.2 million and 4.9 million shares of our common stockstock, respectively, as part of our share repurchase program for approximately $537$550 million.million and $1.1 billion, respectively.

◦SPL redeemed or repaid $253 million aggregate principal amount of its senior notes acrossduring itsthe complex.six months ended June 30, 2026, exclusive of amounts refinanced, as noted above.

◦We paid a dividenddividends of $0.555 and $1.11 per share of common stockstock, during the three months ended March 31, 2026.respectively.

◦We continued to invest in accretive organic growth, including our investments in the Corpus Christi Stage 3 Project andProject, the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

(2)Includes volumes sold under short-term agreements and a portion of volumes sold from natural gas procured under long-term IPM agreements.

Net income (loss) attributable to Cheniere declined by $3.9 billion during the three months ended March 31, 2026 as compared to the same period of 2025, primarily due to $4.8•$1.4 billion of unfavorablefavorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely associated with our long-term IPM agreements.agreements Theseprior increasedto lossesthe wereNPNS designation, as further described below, primarily attributabledue to wideningnarrowing spreads between global and U.S. domestic natural gas benchmarks and elevatedthe easing of the global natural gas price volatility influencedthat began in part by the tighteningfirst supply conditions, transit constraints and heightened geopolitical uncertainties from the conflict and instabilities across partsquarter of the Middle East during 2026. Partially offsetting these losses was $462 million of favorable change in income tax provision (benefit), the recognition of $370 million in tax credits and a $225 million decrease in net income attributable to NCI.2026;

Our•$380 operatingmillion results,increase in revenues, net of cost of sales and excluding thesechanges itemsin discussedfair above,value wereof favorableagreements duringaccounted the three months ended March 31, 2026for as comparedderivative to the same period of 2025 due to higher total margins primarilyinstruments, from higher volumesmargins delivered,as whicha result of increased byproduction 66 TBtu,volume, largely due to the first fouradditional Trains of the Corpus Christi Stage 3 Project in operation throughoutduring the three months ended MarchJune 31,30, 2026 as compared to the first Train of the Corpus Christi Stage 3 Project in operation for only half a month during the same period in 20252025, and from contributions from optimization activities, and to a lesser degree from the relative portion of our cargoes sold that is subject to global LNG pricing.pricing; partially offset by:

The $424$1.1 millionbillion increaseand $1.5 billion increases in total revenues during the three and six months ended MarchJune 31,30, 20262026, respectively, as compared to the same periodperiods of 2025 waswere primarily attributable to:

•1.3$1.2 billion increaseand primarily$2.5 billion increases, respectively, due to higher pricingvolumes perof MMBtuLNG fromdelivered increasedas HenryLNG Hubrevenues pricing,between both the three and six month periods, and additionally due to an increase in U.S. natural gas prices between the six month periods, to which the majority of our long-term LNG sales contracts are indexed, as well as higher volumes of LNG delivered as LNG revenues between the periodsindexed; partially offset by:

•$952$1.0 millionbillion of unfavorable changes inbetween the fairsix valuemonth ofperiods from the agreements accounted for as derivative instruments included in revenues, as further described above under the caption Net income (loss) attributable to Cheniere.

The $4.9$669 million decrease and $4.2 billion increase in total operating costs and expenses during the three and six months ended MarchJune 31,30, 20262026, respectively, as compared to the same periodperiods of 2025 waswere primarily attributable to:

•$1.2$161 million and $1.4 billion increaseincreases, respectively, in the cost of natural gas feedstock, largely due to increased volume of LNG delivered between both the three and six month periods and additionally due to an increase in U.S. natural gas prices andbetween increasedthe volumesix ofmonth LNG deliveredperiods; partially offset by:

•$370 million reduction to cost of sales from the recognition of certain excise tax credits during the threesix months ended MarchJune 31,30, 2026, as further discussed in the Liquidity and Capital Resources section of our annual report on Form 10-K for the fiscal year ended December 31, 2025.

Income tax provision (benefit)

The $462$60 million of favorable variance in income tax provision (benefit) during the three months ended MarchJune 31,30, 2026 as compared to the same period of 2025 was primarily attributable to the decrease in our effective tax rate, as further described below, partially offset by a higher income tax expense due to a $1.7 billion increase in pre-tax income. The $522 million favorable variance in income tax provision during the six months ended June 30, 2026 as compared to the same period of 2025 was primarily attributable to a lower income tax expense due to a $4.5$2.9 billion decrease in pre-tax income (loss) as well as the changedecrease in our effective tax rate, as further described below.

Our effective tax rate was 9.1% and 15.3%9.8% for the three and six months ended June 30, 2026, respectively, as compared to 18.3% and 17.6% during the threesame monthsperiods ended March 31, 2026 andof 2025, respectively,respectively. Our effective tax rate decreased between the comparable periods primarily due to a decline in our pre-tax income (loss) and the proportion of such pre-tax income attributable to CQP, which is partially not taxable to us.us, and increased Foreign Derived Deduction Eligible Income deduction. The effective tax rate for each of the comparable three monthall periods werewas lower than the statutory rate of 21.0% primarily due to CQP’s income that is partially not taxable to us.

The $225$303 million decreaseand $78 million increases in net income attributable to NCI during the three and six months ended MarchJune 31,30, 20262026, respectively, as compared to the same periodperiods of 2025 waswere primarily attributable to a $455$608 million decreaseand $153 million increases in CQP’s consolidated net income primarily from unfavorablefavorable changes in the fair value of agreements accounted for as derivative instruments between the three month periods and increases in revenue, net of cost of natural gas feedstock and excluding changes in fair value of agreements accounted for as derivative instruments.

DerivativeConversely, instruments,commodity contracts accounted for as derivative instruments and for which we usehave not designated the NPNS exception remain subject to manage certain risks, are reported at fair value accounting in ourwhich Consolidated Financial Statements, unless they satisfy criteria for,gains and welosses elect,arising thefrom normalchanges purchasesin andfair normalvalue salesaffect exception which applies the accrual method of accounting.earnings. For commoditysuch derivative instruments, including those related to our long-term IPM agreements,contracts, 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 5—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.events. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

Prior to substantial completion of a Train, amounts received from the sale of commissioning volumes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train and are necessary activities to bring the asset to the condition for its intended use. During the three and six months ended MarchJune 31,30, 2026 and 2025,2026, we realized offsets to LNG terminal costs of $47$31 million and $78 million, respectively, corresponding to 63 TBtuand 9 TBtu, respectively, of LNG as compared to $7 million and $48$55 millionmillion, respectively, corresponding to 51 TBtuand 6 TBtu, respectively, of LNG,LNG respectively,in the same periods of 2025 that waswere related to the sale of commissioning volumes associated with the Corpus Christi Stage 3 Project.

The Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project are currently under construction and are expected to add over 15 mtpa of operational liquefaction capacity, inclusive of estimated debottlenecking opportunities, once all Trains reach substantial completion, of which approximatelyover 86 mtpa is still under construction as of MarchJune 31,30, 2026. As of MarchJune 31,30, 2026, the first fivesix Trains of the Corpus Christi Stage 3 Project were in operation, while as of MarchJune 31,30, 2025, only the first Train of the Corpus Christi Stage 3 Project was in operation. The operation and maintenance of these Trains and increased LNG volumes produced are expected to result in higher revenues and operating costs and expenses. However, prior to the commencement of long-term SPAs associated with these volumes, the additional volumes will be sold by our integrated marketing function at prevailing market prices. Additionally, potential expansion projects that increase the amount of LNG volumes produced, including those discussed above in Disciplined Accretive Growth, would also be expected to result in higher revenues and operating costs and expenses.

(2)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of MarchJune 31,30, 2026. See Note 8—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

Our liquidity position subsequent to MarchJune 31,30, 2026 will be driven by future sources of liquidity and future cash requirements. For a discussion of our future sources and uses of liquidity, see the liquidity and capital resources disclosures in Item 7. 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, 2025.

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project as of MarchJune 31,30, 2026:

(1)As of MarchJune 31,30, 2026, substantial completions of the first fivesix of seven midscale Trains of the Corpus Christi Stage 3 Project have been achieved.

The $148$599 million decreaseincrease between the periods was primarily related to increased cash receipts from the sale of LNG cargoes due to higher revenue from higher production volume, optimization activities and global LNG pricing, as explained above in Results of Operations, and to a morelesser significantextent, decreasean increase from changes in net working capital in the current period as compared to prior period due to differences in timing of payments to suppliers and cash collections from the sale of LNG cargoescargoes. andPartially payments to suppliers. Also contributing tooffsetting the decrease in operatingincreased cash flowsreceipts waswere increased cash usedoutflows for settlement of derivative instruments during the threesix months ended MarchJune 31,30, 2026 compared to cash provided by settlement of derivative instruments during the same period in 2025. Partially offsetting these decreases was increased cash receipts from the sale of LNG cargoes due to higher revenue from increased Henry Hub pricing and higher production volume, as explained above in Results of Operations.

Our investing net cash outflows during the six months ended June 30, 2026 and 2025 primarily related to costs paid for the following projects, all exclusive of associated capitalized interest: (1) construction$829 costsmillion and $741 million, respectively, for the Corpus Christi Stage 3 Project, which were $414 million and $321 million during the three months ended March 31, 2026 and 2025, respectivelyProject; (2) $247$554 million ofand costs$547 paidmillion, respectively, for the CCL Midscale Trains 8 & 9 Project, primarily related to procurement and engineering, (3) $99 million for the SPL Expansion Project during the threesix months ended MarchJune 31,30, 2026, primarily related to procurement and engineering;work performed by Bechtel under the LNTP and (34) optimization and other site improvement projects during both periods. We expect to continue to incur capital expenditures for the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project as construction progresses on these projects.projects, as well costs incurred for the early engineering and procurement for the SPL Expansion Project under the LNTP issued in May 2026.

The following table shows the proceeds from issuances of debt and borrowings, including intra-quarterintra-period activity (in millions):

Debt Redemptions and Repayments of Debt and Borrowings

The following table shows the redemptions and repayments of debt,debt and borrowings, including intra-quarterintra-period activity (in millions):

During the threesix months ended MarchJune 31,30, 2026 and 2025, we paid $537$1.1 millionbillion and $350$656 million to repurchase approximately 2.74.9 million and 1.63.0 million shares of our common stock, respectively, under our share repurchase program. Additionally, the Internal Revenue Service imposes an excise tax of 1% on the fair market value of our stock repurchases less our stock issuances, and we paid $13$33 million of such excise taxes during the threesix months ended MarchJune 31,30, 2025 related to our repurchases during the fiscal year 2023.2023 Inand April2024 2026, weand paid $26 million of such excise taxes during the six months ended June 30, 2026 related to our repurchases during the fiscal year 2025. In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. As of MarchJune 31,30, 2026, we had approximately $9.7$9.1 billion remaining under our share repurchase program.

During the threesix months ended MarchJune 31,30, 2026 and 2025, we paid dividends of $0.555$1.110 and $0.500$1.000 per share of common stock for a total of $117$233 million and $112$223 million, respectively.