# Cheniere Energy, Inc. (LNG) Informational only - not investment advice. CIK: 0000003570 SIC: 4924 Natural Gas Distribution SIC breadcrumb: [Transportation, Communications, Electric, Gas, And Sanitary Services](/division/E/) > [Electric, Gas, And Sanitary Services](/major-group/49/) > [SIC 4924 Natural Gas Distribution](/industry/4924/) Latest 10-K filed: 2026-02-26 SEC page: https://www.sec.gov/edgar/browse/?CIK=3570 Filing source: https://www.sec.gov/Archives/edgar/data/3570/000000357026000005/lng-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 19976000000 | USD | 2025 | 2026-02-26 | | Net income | 5330000000 | USD | 2025 | 2026-02-26 | | Assets | 47882000000 | USD | 2025 | 2026-02-26 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-26. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000003570.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts. | Metric | 2012 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | | 1,283,000,000 | 5,601,000,000 | 7,987,000,000 | 9,730,000,000 | 9,358,000,000 | 15,864,000,000 | 33,428,000,000 | 20,394,000,000 | 15,703,000,000 | 19,976,000,000 | | Net income | | -610,000,000 | -393,000,000 | 471,000,000 | 648,000,000 | -85,000,000 | -2,343,000,000 | 1,428,000,000 | 9,881,000,000 | 3,252,000,000 | 5,330,000,000 | | Operating income | | -30,000,000 | 1,388,000,000 | 2,024,000,000 | 2,361,000,000 | 2,631,000,000 | -701,000,000 | 4,559,000,000 | 15,489,000,000 | 6,128,000,000 | 9,112,000,000 | | Diluted EPS | | -2.67 | -1.68 | 1.90 | 2.51 | -0.34 | -9.25 | 5.64 | 40.72 | 14.20 | 24.13 | | Operating cash flow | | -404,000,000 | 1,231,000,000 | 1,990,000,000 | 1,833,000,000 | 1,265,000,000 | 2,469,000,000 | 10,523,000,000 | 8,418,000,000 | 5,394,000,000 | 5,539,000,000 | | Capital expenditures | | 4,356,000,000 | 3,357,000,000 | 3,643,000,000 | 3,056,000,000 | 1,839,000,000 | 966,000,000 | 1,830,000,000 | 2,121,000,000 | 2,238,000,000 | 3,078,000,000 | | Dividends paid | | | | | 0.00 | 0.00 | 85,000,000 | 349,000,000 | 393,000,000 | 412,000,000 | 451,000,000 | | Share buybacks | 20,414,000 | | 0.00 | 0.00 | 249,000,000 | 155,000,000 | 9,000,000 | 1,373,000,000 | 1,473,000,000 | 2,262,000,000 | 2,724,000,000 | | Assets | | 23,703,000,000 | 27,906,000,000 | 31,987,000,000 | 35,492,000,000 | 35,697,000,000 | 39,258,000,000 | 41,266,000,000 | 43,076,000,000 | 43,858,000,000 | 47,882,000,000 | | Liabilities | | | | | | | | | 34,056,000,000 | 33,798,000,000 | 34,804,000,000 | | Stockholders' equity | | -1,396,000,000 | -1,764,000,000 | -526,000,000 | -14,000,000 | -191,000,000 | -2,571,000,000 | -2,969,000,000 | 5,060,000,000 | 5,699,000,000 | 7,915,000,000 | | Cash and cash equivalents | | 876,000,000 | 722,000,000 | 981,000,000 | 2,474,000,000 | 1,628,000,000 | 1,404,000,000 | 1,353,000,000 | 4,066,000,000 | 2,638,000,000 | 1,099,000,000 | | Free cash flow | | -4,760,000,000 | -2,126,000,000 | -1,653,000,000 | -1,223,000,000 | -574,000,000 | 1,503,000,000 | 8,693,000,000 | 6,297,000,000 | 3,156,000,000 | 2,461,000,000 | ### Ratios ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported. | Metric | 2012 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Net margin | | -47.54% | -7.02% | 5.90% | 6.66% | -0.91% | -14.77% | 4.27% | 48.45% | 20.71% | 26.68% | | Operating margin | | -2.34% | 24.78% | 25.34% | 24.27% | 28.11% | -4.42% | 13.64% | 75.95% | 39.02% | 45.61% | | Return on equity | | | | | | | | | 195.28% | 57.06% | 67.34% | | Return on assets | | -2.57% | -1.41% | 1.47% | 1.83% | -0.24% | -5.97% | 3.46% | 22.94% | 7.41% | 11.13% | | Liabilities / equity | | | | | | | | | 6.73 | 5.93 | 4.40 | | Current ratio | | 2.08 | 2.69 | 2.43 | 2.25 | 1.44 | 1.08 | 0.83 | 1.63 | 1.08 | 0.94 | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-07. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000003570.json. Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived. | Quarter | End date | Revenue | Net income | Diluted EPS | Method | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q2 | 2022-06-30 | | | 2.90 | reported discrete quarter | | 2022-Q3 | 2022-09-30 | | | -9.54 | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | | 22.10 | reported discrete quarter | | 2023-Q2 | 2023-03-31 | | 5,434,000,000 | | reported discrete quarter | | 2023-Q2 | 2023-06-30 | 4,102,000,000 | | 5.61 | reported discrete quarter | | 2023-Q3 | 2023-06-30 | | 1,369,000,000 | | reported discrete quarter | | 2023-Q3 | 2023-09-30 | 4,159,000,000 | | 7.03 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 4,823,000,000 | 1,377,000,000 | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 4,253,000,000 | 502,000,000 | 2.13 | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 3,251,000,000 | 880,000,000 | 3.84 | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 3,763,000,000 | 893,000,000 | 3.93 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 4,436,000,000 | 977,000,000 | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 5,444,000,000 | 353,000,000 | 1.57 | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 4,641,000,000 | 1,626,000,000 | 7.30 | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 4,441,000,000 | 1,049,000,000 | 4.75 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 5,450,000,000 | 2,302,000,000 | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 5,868,000,000 | -3,502,000,000 | -16.65 | reported discrete quarter | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance - [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States - [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States - [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States - [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States - [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States - [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized - [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized - [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks - [GDP](/indicator/GDP/): Gross Domestic Product - [GPDI](/indicator/GPDI/): Gross Private Domestic Investment - [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment - [PCEC](/indicator/PCEC/): Personal Consumption Expenditures - [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services - [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt - [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product - [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit - [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts - [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures - [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing - [USCONS](/indicator/USCONS/): All Employees, Construction - [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade - [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities - [USGOVT](/indicator/USGOVT/): All Employees, Government - [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private - [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods - [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft - [BUSINV](/indicator/BUSINV/): Total Business Inventories - [EXPGS](/indicator/EXPGS/): Exports of Goods and Services - [IMPGS](/indicator/IMPGS/): Imports of Goods and Services - [IR](/indicator/IR/): Import Price Index (End Use): All Commodities - [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/3570/000000357026000014/lng-20260331.htm Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high Filing date: 2026-05-07 Report date: 2026-03-31 ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Information Regarding Forward-Looking Statements This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:  •statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates, or at all; •statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products; •statements regarding any financing transactions or arrangements, or our ability to enter into such transactions; •statements relating to Cheniere’s capital deployment, including intent, ability, extent and timing of capital expenditures, debt repayment, dividends, share repurchases and execution on the capital allocation plan; •statements regarding our future sources of liquidity and cash requirements; •statements relating to the construction of our Trains and pipelines, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto; •statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts; •statements regarding counterparties to our commercial contracts, construction contracts and other contracts; •statements regarding our planned development and construction of additional Trains or pipelines, including the financing of such Trains or pipelines; •statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities; •statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change; •statements relating to our goals, commitments and strategies in relation to environmental matters; •statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions; •statements regarding our anticipated LNG and natural gas marketing activities; and •any other statements that relate to non-historical or future information. All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that 24 Table of Contents      the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, 2025. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise. 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. Our discussion and analysis includes the following subjects:  •Overview •Overview of Significant Events •Results of Operations •Liquidity and Capital Resources •Summary of Critical Accounting Estimates •Recent Accounting Standards Overview Cheniere, a Delaware corporation, is a Houston-based 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 aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers. LNG is natural gas (primarily methane) in liquid form and is a cleaner dispatchable fuel for power generation. The LNG we produce is shipped all over the world, converted back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses. As of March 31, 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 approximately 8 mtpa was under construction and the remainder was in operation as of March 31, 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 March 31, 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”). 25 Table of Contents      •over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including approximately 8 mtpa under construction and the remainder in operation as of March 31, 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 approximately 3 mtpa under construction and the remainder in operation from the first five midscale Trains that have reached substantial completion as of March 31, 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 March 31, 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 March 31, 2026, we have contracted approximately 90% 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 [Excerpt truncated for page length; source filing is linked above.] ## Latest 10-K MD&A Extracted from Item 7 to the first post-MD&A boundary after HTML sanitization. Published MD&A gate trimmed front/tail over-capture. Confidence: high Results of Operations Consolidated results of operations Year Ended December 31, (in millions, except per share data) 2025 2024 Variance Revenues LNG revenues $ 19,435  $ 14,899  $ 4,536  Regasification revenues 136  135  1  Other revenues 405  669  (264) Total revenues 19,976  15,703  4,273  Operating costs and expenses Cost of sales (excluding operating and maintenance expense and depreciation, amortization and accretion expense shown separately below) 7,150  6,021  1,129  Operating and maintenance expense 1,966  1,857  109  Selling, general and administrative expense 383  441  (58) Depreciation, amortization and accretion expense 1,329  1,220  109  Other operating costs and expenses 36  36  —  Total operating costs and expenses 10,864  9,575  1,289  Income from operations 9,112  6,128  2,984  Other income (expense) Interest expense, net of capitalized interest (948) (1,010) 62  Gain (loss) on modification or extinguishment of debt (8) (9) 1  Interest and dividend income 106  189  (83) Other income, net 20  5  15  Total other expense (830) (825) (5) Income before income taxes and NCI 8,282  5,303  2,979  Less: income tax provision 1,488  811  677  Net income 6,794  4,492  2,302  Less: net income attributable to NCI 1,464  1,240  224  Net income attributable to Cheniere $ 5,330  $ 3,252  $ 2,078  Net income per share attributable to common stockholders—basic $ 24.19  $ 14.24  $ 9.95  Net income per share attributable to common stockholders—diluted $ 24.13  $ 14.20  $ 9.93  39 Table of Contents Volumes loaded and recognized from the Liquefaction Projects Year Ended December 31, 2025 2024 (in TBtu) Operational Commissioning Total Operational Commissioning Total Volumes loaded during the current period 2,400  24  2,424  2,327  —  2,327  Volumes loaded during the prior period but recognized during the current period 39  —  39  37  —  37  Less: volumes loaded during the current period and in transit at the end of the period (23) (1) (24) (39) —  (39) Total volumes recognized in the current period 2,416  23  2,439  2,325  —  2,325  Components of LNG revenues and corresponding LNG volumes delivered Year Ended December 31, 2025 2024 Variance LNG revenues (in millions): LNG from the Liquefaction Projects sold under third party long-term agreements (1) $ 14,804  $ 12,144  $ 2,660  LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2) 3,794  2,345  1,449  LNG procured from third parties (2) 226  280  (54) Net derivative gain (loss) 344  (73) 417  Other revenues 267  203  64  Total LNG revenues $ 19,435  $ 14,899  $ 4,536  Volumes delivered as LNG revenues (in TBtu): LNG from the Liquefaction Projects sold under third party long-term agreements (1) 2,095  2,118  (23) LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2) 321  207  114  LNG procured from third parties (2) 22  24  (2) Total volumes delivered as LNG revenues 2,438  2,349  89  (1)Long-term agreements include agreements with an initial tenor of 12 months or more. (2)Includes volumes sold under short-term agreements and volumes sold from natural gas procured under IPM agreements. 2025 vs. 2024 Net income attributable to Cheniere increased by $2.1 billion during the year ended December 31, 2025 as compared to the same period of 2024 primarily due to $2.3 billion of favorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely associated with our derivatives related to IPM agreements, and an $876 million increase in revenues, net of cost of natural gas feedstock, from increased volume of LNG loaded and recognized between the years. Partially offsetting these favorable changes was an increased tax provision of $677 million. The following is an expanded discussion of the significant drivers of the variance in net income attributable to Cheniere by line item: 40 Table of Contents Total revenues The $4.3 billion increase in total revenues during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to: •$2.9 billion increase due to higher pricing per MMBtu primarily from increased Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed; •$1.2 billion increase due to higher volumes of LNG delivered between the periods, primarily as a result of increased production volume due to the substantial completions of the first four Trains of the Corpus Christi Stage 3 Project in 2025; •$417 million increase in gains from agreements accounted for as derivative instruments included in revenues, largely due to the impact of declines in global gas prices and volatility within our derivatives related to financial positions to economically hedge the purchase and sale of physical LNG, of which the gain between the years was attributable to a $223 million gain from favorable changes in fair value of agreements accounted for as derivatives and a $194 million gain from the settlement of previously entered derivative instruments; partially offset by •$243 million decrease in sublease and subcharter income from our LNG vessels due to fewer days the LNG vessels were subcontracted out and at lower rates in the current year as compared to the same period of 2024. Total operating costs and expenses The $1.3 billion increase in total operating costs and expenses during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to: •$3.1 billion increase in the cost of natural gas feedstock, largely due to the increase in U.S. natural gas prices and to a lesser degree, increased volume of LNG delivered; •$109 million increase in depreciation, amortization and accretion expense, primarily as a result of the substantial completions of the first four Trains of the Corpus Christi Stage 3 Project; •$109 million increase in operating and maintenance expense primarily due to the completion of planned large-scale maintenance activities on two Trains at the SPL Project and additional expenses from the substantial completions of the first four Trains of the Corpus Christi Stage 3 Project in 2025; partially offset by: •$2.1 billion of gains from changes in fair value of agreements accounted for as derivative instruments included in cost of sales, largely due to favorable changes on our IPM agreements from the narrowing of global and U.S. domestic natural gas spreads, the effect of which is minimized by the relative change in volatilities of applicable global and U.S. domestic natural gas prices, partially offset by changes in market-based locational forward price differentials for North American natural gas deliveries. As further discussed in Liquidity and Capital Resources, we will recognize a $370 million reduction to cost of sales due to the realization of certain excise tax credits during the three months ending March 31, 2026. Total other expense The $5 million increase in total other expense during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to: •$83 million decrease in interest and dividend income as a result of decreased interest rates and lower average cash and cash equivalents balances between the periods; partially offset by •$62 million decrease in interest expense, net of capitalized interest, due to a $33 million increase in capitalized interest costs given the higher carrying value of assets under construction and additionally due to $29 million lower gross interest costs due to debt reduction activities associated with our long-term capital allocation plan; and •$15 million increase in other income, net, primarily from a $26 million gain recognized on the sale of our equity interests in an equity method investment during the three months ended March 31, 2025. 41 Table of Contents Income tax provision The $677 million unfavorable variance during the year ended December 31, 2025 as compared to the same period of 2024 was substantially all attributable to a higher income tax expense due to a $3.0 billion increase in pre-tax income. The effect of the change in our effective tax rate between the comparable periods was not material to our income tax provision. On July 4, 2025, the OBBBA was signed into law with significant changes to the Internal Revenue Code that impact us, including, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025 and modifying the export-promoting Foreign Derived Intangible Income (“FDII”) deduction rules, renamed to the Foreign Derived Deduction Eligible Income (“FDDEI”) under the OBBBA beginning in 2026. The legislation did not have a material impact on our income tax expense for the year ended December 31, 2025, and it did not materially change our effective income tax rate for 2025; however, commencing with its effectiveness in 2026, we expect that the FDDEI regime will favorably impact our effective tax rate relative to prior policy, as a larger portion of our export-related income is projected to be eligible for a preferential tax rate despite an increase in the tax rate on qualifying sales. The FDDEI regime provides for an effective tax rate of 14%, a rate lower than the statutory corporate tax rate of 21%, on eligible sales of property or services to a foreign person for foreign use. Relative to the prior FDII tax rules, the FDDEI regime increases the effective tax rate on eligible sales but broadens qualifying income by eliminating certain asset-based eligibility constraints and removing the requirement to reduce eligible income by specified allocable expenses. See Liquidity and Capital Resources for discussion of the impacts of the OBBBA on our liquidity. Net income attributable to NCI The $224 million increase during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to a $477 million increase in CQP’s consolidated net income primarily from favorable changes in fair value of agreements accounted for as derivative instruments. Significant factors affecting our results of operations Below are significant factors that affect our results of operations. Gains and losses on derivative instruments Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements, unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception which applies the accrual method of accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to 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. Commissioning volumes 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 42 Table of Contents the construction of that Train and are necessary activities to bring the asset to the condition for its intended use. During the year ended December 31, 2025, we realized offsets to LNG terminal costs of $187 million corresponding to 23 TBtu of LNG that was related to the sale of commissioning volumes associated with the Corpus Christi Stage 3 Project. We did not record any offsets to LNG terminal costs during the year ended December 31, 2024. Additional liquefaction capacities 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 over 9 mtpa is still under construction as of December 31, 2025. As of December 31, 2025, the first four Trains of the Corpus Christi Stage 3 Project were in operation, with substantial completions for each Train achieved in March, August, October and December 2025, respectively. 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 in Items 1. and 2. Business and Properties, would also be expected to result in higher revenues and operating costs and expenses. Additionally, see Items 1. and 2. Business and Properties for discussion of our business seasonality. 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. December 31, 2025 Cash and cash equivalents (1) $ 1,099  Restricted cash and cash equivalents (1) 485  Available commitments under our credit facilities (2): SPL Revolving Credit Facility 824  CQP Revolving Credit Facility 1,000  CCH Credit Facility 2,710  CCH Working Capital Facility 1,390  Cheniere Revolving Credit Facility 1,250  Total available commitments under our credit facilities 7,174  Total available liquidity $ 8,758  (1)Amounts presented include balances held by our VIEs, as discussed in Note 8—Non-Controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements. As of December 31, 2025, assets of our VIEs, which are included in our Consolidated Balance Sheets, included $182 million of cash and cash equivalents and $22 million of restricted cash and cash equivalents. (2)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2025. 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, 2025 will be driven by future sources of liquidity and future cash requirements, as further discussed under the caption Future Sources and Uses of Liquidity. 43 Table of Contents Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures. 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. 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. See Note 10—Debt of our Notes to Consolidated Financial Statements for additional information on these covenants. Despite the restrictions noted above, we believe that sufficient flexibility exists within the Cheniere complex to enable each independent capital structure to meet its currently anticipated cash requirements. 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, 2025. 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, as of December 31, 2025, we have contracted approximately 90% of the total anticipated production from the Liquefaction Projects through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes from SPAs that are conditional on additional liquefaction capacity beyond what is currently in construction or operation, subject to unilateral waiver by us. 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 44 Table of Contents terms dependent on project milestone dates based on the estimated dates as of December 31, 2025. The following table summarizes our estimate of revenues to be received from executed long-term SPAs as of December 31, 2025 (in billions): Estimated Revenues Under Executed SPAs by Period (1) (2) 2026 2027 - 2030 Thereafter Total LNG revenues (fixed fees) $ 6.6  $ 29.4  $ 71.7  $ 107.7  LNG revenues (variable fees) (3) 9.8  43.9  129.2  182.9  Total $ 16.4  $ 73.3  $ 200.9  $ 290.6  (1)LNG revenues exclude estimated revenues from contracts with unsatisfied contractual conditions precedent. We 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. (3)LNG revenues (variable fees) reflect the assumption of delivery of all contractual volumes, irrespective of any contractual right of non-delivery. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2025. As described in General, under our SPAs, customers purchase LNG on either an FOB basis or a DAP basis generally for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The 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. The LNG produced and available for Cheniere Marketing to sell includes volumes related to commissioning, which 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. The volumes sold by Cheniere Marketing may be supplemented by volumes procured from third parties at other locations worldwide to support operational requirements or take advantage of market opportunities. 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 20 years, we expect to generate liquidity from the approximately 5,066 TBtu of LNG to be produced from natural gas not yet received under IPM agreements as of December 31, 2025. Additional Future Sources of Liquidity Available Commitments under Credit Facilities As of December 31, 2025, we had $7.2 billion in available commitments under our credit facilities, as detailed earlier in the table summarizing our available liquidity, subject to compliance with the applicable covenants, to potentially meet liquidity needs. Our credit facilities mature between 2027 and 2030, based on estimated project milestone dates as of December 31, 2025. 45 Table of Contents Disciplined Accretive Growth Our significant land positions at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. In June 2025, certain subsidiaries of CQP updated the SPL Expansion Project’s FERC application, originally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities. Following our pre-filing in July 2025, in February 2026, we filed an application with the FERC under the NGA for authorization to site, construct and operate the CCL Expansion Project in a phased approach, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities. 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, 2025 (in billions): Estimated Payments Due Under Executed Contracts by Period (1) 2026 2027 - 2030 Thereafter Total Purchase obligations (2): Natural gas supply agreements excluding IPM agreements (3) (4) $ 7.3  $ 13.3  $ 5.0  $ 25.6  Natural gas transportation and storage service agreements (5) 0.6  2.2  4.4  7.2  Capital expenditures 1.5  0.9  —  2.4  Other Purchase Obligations —  0.1  0.5  0.6  Leases (6) 0.9  3.2  4.7  8.8  Total $ 10.3  $ 19.7  $ 14.6  $ 44.6  (1)Agreements in force as of December 31, 2025 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2025. (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, 2025. Natural gas supply agreements are presented net of $0.2 billion in contracted sales of natural gas as of December 31, 2025. (5)Natural gas transportation and storage services agreements include $1.3 billion in obligations to related parties. See Note 13 — Related Party Transactions for further information about our related parties. (6)Leases include payments under (1) operating leases, (2) finance leases, (3) short-term leases and (4) vessel time charters that were executed as of December 31, 2025 but will commence in the future. Payments during future renewal option periods that are exercisable at our sole discretion are included only to the extent that the option is believed to be reasonably certain to be exercised. Leases are presented net of future income associated with vessel time charters that were subchartered to third parties, which was immaterial as of December 31, 2025. 46 Table of Contents Natural Gas Supply, Transportation and Storage Service Agreements Excluding IPM agreements and unexercised extension options, we have secured approximately 6,847 TBtu of natural gas feedstock for our Liquefaction Projects through long-term natural gas supply agreements with remaining fixed terms of up to 14 years. As of December 31, 2025, we have secured approximately 70% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2026, excluding the 8% of which has been secured under IPM agreements. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2026. As further described in LNG Revenues from Executed SPAs, the pricing structure of our SPAs often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, thus limiting our net exposure to future increases in natural gas prices. 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 contracts for both the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order. As of December 31, 2025, substantial completions of the first four of seven midscale Trains of the Corpus Christi Stage 3 Project were achieved. Additionally, in June 2025, our Board made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under an EPC contract for a contract price of approximately $2.9 billion, subject to adjustment only by change order. Refer to Corpus Christi LNG Terminal in Items 1. and 2. Business and Properties — Our Business for a summary of the construction status and estimated completion of both the Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project as of December 31, 2025. 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. Leases Our obligations under our lease arrangements primarily consist of LNG vessel time charters with fixed minimum terms of up to 15 years to ensure delivery of cargoes sold on a DAP 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 Taxes Our cash tax payments may fluctuate over time and may be influenced by (1) accelerated tax depreciation deductions on qualifying assets, including the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project and (2) timing of utilization of our existing net operating loss (“NOL”) carryforwards. See the risk Additions or changes in tax laws and regulations or variables impacting our tax obligations could potentially affect our financial results or liquidity under Risks Relating to Regulations in Item 1A. Risk Factors. 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 transport fuel in our operations enabled us to claim federal alternative fuel excise tax credits totaling $370 million for the period spanning from 2018 to 2024, preceding the expiration of the incentive program on December 31, 2024. We accounted for the claims as a gain contingency under ASC 450-30, Contingencies - Gain Contingencies, which does not allow recognition until cash or claims to cash are realized or realizable. We did not recognize the claims as of December 31, 2025 because there were inherent uncertainties associated with the realizability of these claims. Subsequent to December 31, 2025, the Internal Revenue Service (the “IRS”) issued a closing 47 Table of Contents letter to us indicating completion of their review, confirming our eligibility and issuing final cash payment. As such, we will recognize a $370 million reduction to cost of sales during the three months ending March 31, 2026. Disciplined Accretive Growth The FID of any expansion projects, including the SPL Expansion Project and CCL Expansion Project, will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion. In January 2026, we acquired the remaining redeemable noncontrolling interest in our consolidated subsidiary that owns the Gregory Power Plant, a natural gas-fired combined cycle facility located immediately proximal to the Corpus Christi LNG Terminal. Such acquisition enhances operational control and further mitigates risk exposure associated with increased power demand from the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, but is expected to require further capital injection for operating liquidity and capital improvements. 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, 2025 (in billions): Estimated Payments Due Under Executed Contracts by Period (1) (2) 2026 2027 - 2030 Thereafter Total Debt $ 0.3  $ 11.8  $ 10.9  $ 23.0  Interest payments 1.1  3.2  1.7  6.0  Total $ 1.4  $ 15.0  $ 12.6  $ 29.0  (1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2025. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity. (2)Table excludes payments under finance leases, which are included in Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts table above. Debt As of December 31, 2025, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $22.4 billion and credit facilities with $550 million outstanding loan balances. As of December 31, 2025, each of our issuers was in compliance with all covenants related to their respective debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10—Debt of our Notes to Consolidated Financial Statements. Interest As of December 31, 2025, our senior notes had a weighted average contractual interest rate of 4.65%. Interest on borrowings under our credit facilities is indexed to SOFR, and we are subject to interest rates on outstanding balances, commitment fees on undrawn balances and letter of credit fees on issued letters of credit. We had $286 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2025. Further details of our credit facilities can be found in Note 10—Debt of our Notes to Consolidated Financial Statements. 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 48 Table of Contents partner interest in CQP in the form of 239.9 million common units, 100% of the general partner interest and 100% of the incentive distribution rights, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. During the year ended December 31, 2025, $803 million in distributions were paid to our non-controlling interests. Capital Allocation Plan In June 2024, our Board approved an updated comprehensive long-term capital allocation plan, which included an increase to our share repurchase authorization by $4.0 billion through 2027. As of December 31, 2025, we had up to $1.2 billion available under the share repurchase program. In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by management based on market conditions and other factors, with the majority of the repurchases executed within trading parameters pre-established for each applicable trading period in compliance with SEC Rule 10b5-1 and some repurchases executed on the open market. During the year ended December 31, 2025, we repurchased approximately 12.1 million shares of our common stock for $2.7 billion at a weighted average price per share of $221.55. A discussion of our share repurchase program can be found in 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, 2025, we used $0.7 billion of available cash to reduce our outstanding indebtedness, all of which was pursuant to our capital allocation plan. In June 2025, we announced updates to our company outlook, which included a plan to increase our annualized dividend by over 10% to $2.22 per common share, which commenced with the dividend pertaining to the third quarter of 2025. On January 27, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on February 27, 2026 to stockholders of record as of the close of business on February 6, 2026. Financially Disciplined Growth To the extent that liquefaction capacity at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal is expanded beyond the Liquefaction Projects, such as the SPL Expansion Project and the CCL 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.  Year Ended December 31, 2025 2024 Net cash provided by operating activities $ 5,539  $ 5,394  Net cash used in investing activities (3,012) (2,279) Net cash used in financing activities (4,130) (4,451) Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents (3) 1  Net decrease in cash, cash equivalents and restricted cash and cash equivalents $ (1,606) $ (1,335) 49 Table of Contents Operating Cash Flows The $145 million increase between the periods was primarily related to higher net cash inflows from LNG sales, as explained above in Results of Operations, and increased cash inflows from settlement of derivative instruments. Partially offsetting the increase was lower cash flows attributed to working capital from differences in timing of cash collections from the sale of LNG cargoes and payments to suppliers. As described in Results of Operations, the OBBBA was signed into law during the third quarter of 2025 and includes, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025, which deferred our cash tax obligations, ultimately reducing our income tax payable to a nominal amount in 2025, and modifying the export-promoting FDII deduction rules, renamed to the FDDEI under the OBBBA, which is expected to reduce our income taxes payable relative to prior policy in future periods. Additionally, on September 30, 2025, the IRS issued Notice 2025-49, which revised rules for calculating CAMT adjusted financial statement income, deferring our cash tax obligations and entitling us to a refund of $380 million of previously paid CAMT, which we received in December 2025. Investing Cash Flows Our investing net cash outflows primarily related to: (1) construction costs for the Corpus Christi Stage 3 Project, which were $1.3 billion and $1.5 billion during the years ended December 31, 2025 and 2024, respectively; (2) $1.0 billion of costs paid for the CCL Midscale Trains 8 & 9 Project during the year ended December 31, 2025, primarily related to procurement and engineering; and (3) optimization and other site improvement projects during both periods. The $0.2 billion decrease in construction costs for the Corpus Christi Stage 3 Project between the periods was primarily related to a decline in expenditures in the current year related to the EPC contract as the project approaches completion. 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. Financing Cash Flows The following table summarizes our financing activities (in millions): Year Ended December 31, 2025 2024 Proceeds from issuances of debt and borrowings $ 1,987  $ 2,725  Redemptions and repayments of debt (2,092) (3,521) Distributions to NCI (803) (846) Contributions from redeemable NCI 122  6  Payments related to tax withholdings for share-based compensation (51) (46) Repurchase of common stock, inclusive of excise taxes paid (2,724) (2,262) Dividends to stockholders (451) (412) Other, net (118) (95) Net cash used in financing activities $ (4,130) $ (4,451) 50 Table of Contents Proceeds from Issuances of Debt and Borrowings The following table shows the proceeds from issuances of debt and borrowings, including intra-year activity (in millions): Year Ended December 31, 2025 2024 Cheniere: 5.650% Senior Notes due 2034 $ —  $ 1,497  Cheniere Revolving Credit Facility 175  —  CQP: 5.750% Senior Notes due 2034 —  1,198  2035 CQP Senior Notes 997  —  SPL: SPL Revolving Credit Facility 265  30  CCH: CCH Credit Facility 550  —  Total proceeds from issuances of debt and borrowings $ 1,987  $ 2,725  Debt Redemptions and Repayments The following table shows the redemptions and repayments of debt, including intra-year activity (in millions): Year Ended December 31, 2025 2024 Cheniere: Cheniere Revolving Credit Facility $ (175) $ —  SPL: 5.750% Senior Secured Notes due 2024 —  (300) 2025 SPL Senior Notes (300) (1,700) 2026 SPL Senior Notes (1,300) —  4.746% weighted average rate Senior Notes due 2037 (52) —  SPL Revolving Credit Facility (265) (30) CCH: 5.875% Senior Notes due 2025 —  (1,491) Total redemptions and repayments of debt $ (2,092) $ (3,521) Repurchase of Common Stock During the years ended December 31, 2025 and 2024, we paid $2.7 billion and $2.3 billion to repurchase approximately 12.1 million and 13.8 million shares of our common stock, respectively, under our share repurchase program. Additionally, during the year ended December 31, 2025, we paid $33 million of excise taxes related to our repurchase of common stock during the fiscal years 2023 and 2024, since the IRS imposes an excise tax of 1% on the fair market value of our stock repurchases less our stock issuances. In April 2026, we expect to pay $26 million of excise taxes related to our repurchases during the fiscal year 2025. As of December 31, 2025, we had approximately $1.2 billion remaining under our share repurchase program. In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. 51 Table of Contents Cash Dividends to Stockholders During the year ended December 31, 2025, we paid aggregate dividends of $2.055 per share of common stock for a total of $451 million and during the year ended December 31, 2024, we paid aggregate dividends of $1.805 per share of common stock for a total of $412 million. On January 27, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on February 27, 2026 to stockholders of record as of the close of business on February 6, 2026. 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 Our derivative instruments are recorded at fair value unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. 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. 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. 52 Table of Contents Additionally, the valuation of certain liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of liquefaction supply derivatives valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2025 and 2024 (in millions). The changes in fair value shown are limited to instruments still held at the end of each respective period. Year Ended December 31, 2025 2024 Favorable changes in fair value of liquefaction supply derivatives still held at the end of the period $ 2,887  $ 738  The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our IPM agreements in effect during the years ended December 31, 2025 and 2024. The estimated fair value of level 3 liquefaction supply derivatives recognized in our Consolidated Balance Sheets as of December 31, 2025 and 2024 amounted to an asset of $2.9 billion and a liability of $801 million, respectively. 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.