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 27 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 June 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 over 6 mtpa was under construction and the remainder was in operation as of June 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 June 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”). 28 Table of Contents •over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including over 6 mtpa under construction and the remainder in operation as of June 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 over 1 mtpa under construction and the remainder in operation from the first six midscale Trains that have reached substantial completion as of June 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 June 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 June 30, 2026, we have contracted 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. Disciplined Accretive Growth We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. Our capital allocation plan is designed, in part, to invest in financially disciplined growth accretive to our common stock. Capital investment parameters are the foundation of our disciplined, accretive growth, and include consideration to: •Achieve value accretive returns through long-term commercial contracts: We aim to contract approximately 90% of our current and planned liquefaction capacity under long-term SPAs and long-term IPM agreements with creditworthy counterparties under the pricing structures described above, with financial parameters that consider, among other things, targeted unlevered returns that exceed our cost of equity and return on stock at prevailing stock prices and project leverage. Our success in securing long-term commercial contracts at desired returns is influenced by global LNG and natural gas market conditions and other uncertainties described in the risk factors of our annual report on Form 10-K for the fiscal year ended December 31, 2025. •Achieve credit accretive returns: We aim to conservatively fund our projects through financing structures that sustain our long-term, run-rate leverage and credit metrics. Our ability to secure the required financing is influenced by market interest rates and other factors described in the risk factors of our annual report on Form 10-K for the fiscal year ended December 31, 2025. 29 Table of Contents We have increased available liquefaction capacity at our Liquefaction Projects as a result of debottlenecking and other optimization projects. We believe these factors provide a foundation for additional growth in our portfolio of customer contracts in the future. We hold significant land positions at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, which provide opportunity for further liquefaction capacity expansion. We are developing a two-phased expansion adjacent to the SPL Project, inclusive of three liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”) and a further expansion of the CCL 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 “CCL Expansion Project”). These projects and any future expansions at our sites require, among other things, regulatory approvals and acceptable commercial and financing arrangements before we make a positive FID. Risks associated with cost overruns and delays in the completion of our expansion projects are described in the risk factors of our annual report on Form 10-K for the fiscal year ended December 31, 2025. The following table summarizes pre-FID development efforts and certain key milestones associated with the SPL Expansion Project and the CCL Expansion Project: SPL Expansion Project CCL Expansion Project Expected total peak production capacity of LNG (1) Up to ~ 20 mtpa Up to 24 mtpa Milestone Regulatory (2) FERC authorizations: Positive environmental assessment Pending Pending Order under Section 3 of NGA Pending Pending Certification to commence construction Pending DOE export authorization: FTA countries ü Pending Non-FTA countries Pending Pending Financing Financing (3) (3) Commercialization and Other Contracting Definitive commercial agreements (4) (4) Definitive full-scope EPC contract ü (5) Target Milestone FID (6) 2026/2027 2027/2028 ü indicates receipt of authorization, subject to ongoing conditionality (1)Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory review and approval and may change based on design considerations, engagement with contractors and other factors. Subject to adjustment for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities. (2)Our activities, including our expansion activities, are highly regulated and require regulatory approvals at various stages, including approvals of the FERC and DOE under Sections 3 and 7 of the NGA, as well as several other material governmental and regulatory approvals and permits. The progression of our expansion projects is dependent on receiving all regulatory approvals required within the respective stages. See our annual report on Form 10-K for the fiscal year ended December 31, 2025 for further discussion of the regulations under federal, state and local statutes, rules, regulations and laws to which we are subject and associated risk factors relating to regulations. (3)We anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of this expansion project if we reach a positive FID. (4)Liquefaction capacity partially contracted by Cheniere Marketing, through SPAs that are conditioned on additional liquefaction capacity beyond what is currently in construction or operation and may be available to be novated to SPL or CCL, and by SPL Stage V, through an IPM agreement. 30 Table of Contents (5)In May 2026, SPL Stage V entered into a lump sum, turnkey EPC contract with Bechtel Energy, Inc. (“Bechtel”) for the first phase of the SPL Expansion Project and issued a limited notice to proceed (“LNTP”) to commence early engineering and procurement. (6)Expected to be subject to phased FID. Any positive FID is subject to achievement of or consideration to relevant milestones and capital investment parameters described herein. Overview of Significant Events Our significant events since January 1, 2026 and through the filing date of this Form 10-Q include the following: Strategic Growth •In June 2026, we received authorization from the FERC to increase the LNG production capacity of the previously-authorized Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project by approximately 5 mtpa in aggregate. •In May 2026, SPL Stage V entered into a lump sum, turnkey EPC contract with Bechtel for the first phase of the SPL Expansion Project and issued an LNTP to commence early engineering and procurement. •Following our pre-filing in July 2025, in February 2026, we filed an application with the FERC under the NGA for authorization to site, construct and operate in a phased approach the CCL Expansion Project, a potential further expansion of the Corpus Christi LNG Terminal, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities. Commercialization •In February 2026, we announced the execution of our second long-term LNG SPA between Cheniere Marketing and CPC Corporation, Taiwan (“CPC”), under which CPC has agreed to purchase up to approximately 1.2 mtpa of LNG from Cheniere Marketing on a DAP basis from 2026 through 2050. Operational •As of July 31, 2026, over 4,940 cumulative LNG cargoes totaling over 340 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects. •In March and June 2026, substantial completions of Trains 5 and 6, respectively, of the Corpus Christi Stage 3 Project were achieved. Financial •In June 2026, we entered into the following debt transactions concurrently: ◦We entered into a Commitment Increase and Maturity Extension Agreement for the Cheniere Third Amended and Restated Revolving Credit Agreement (the “Cheniere Revolving Credit Facility”) to increase the aggregate commitments by $500 million to $1.75 billion and extend the maturity date by one year; ◦CCH entered into the $1.0 billion CCH Revolving Credit Agreement (the “CCH Revolving Credit Facility”), which amended and restated the previous working capital facility agreement (the “CCH Working Capital Facility”) to, among other things, decrease the aggregate commitments by $500 million, extend the maturity date by approximately four years and reduce the rates applicable to our interest and fees; and ◦CCH entered into an amendment to the Second Amended and Restated Term Loan Facility Agreement (the “CCH Credit Facility”) to, among other things, extend the availability period for disbursements of term loans to the later of the Corpus Christi Stage 3 Project completion date and December 31, 2027. 31 Table of Contents •In June 2026, CQP issued and sold $1.0 billion aggregate principal amount of 5.350% Senior Notes due 2036 (the “2036 CQP Senior Notes”) and $750 million aggregate principal amount of 6.050% Senior Notes due 2056 (the “2056 CQP Senior Notes”), and a portion of the net proceeds were used to fully redeem $1.5 billion aggregate principal amount of SPL’s 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), as well as for general corporate purposes, including funding a portion of the LNTP related to the first phase of the SPL Expansion Project. •In March 2026, Cheniere issued and sold $1.0 billion aggregate principal amount of 5.200% Senior Notes due 2036 and $750 million aggregate principal amount of 6.000% Senior Notes due 2056, and a portion of the net proceeds was used to prepay $550 million of CCH’s outstanding borrowings under the CCH Credit Facility. Concurrently, we canceled $600 million of unused commitments under the CCH Credit Facility, and in May 2026, we canceled an additional $600 million of unused commitments. •In February 2026, Moody’s Ratings (“Moody’s”) upgraded its rating of Cheniere’s senior unsecured notes from Baa3 to Baa2 with a stable outlook. Moody’s also upgraded their rating of CCH’s senior secured notes from Baa2 to Baa1 with a stable outlook. •In February 2026, our board of directors (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. •During the three and six months ended June 30, 2026, we accomplished the following pursuant to our capital allocation priorities: ◦We repurchased approximately 2.2 million and 4.9 million shares of our common stock, respectively, as part of our share repurchase program for approximately $550 million and $1.1 billion, respectively. ◦SPL repaid $253 million aggregate principal amount of its senior notes during the six months ended June 30, 2026, exclusive of amounts refinanced, as noted above. ◦We paid dividends of $0.555 and $1.11 per share of common stock, respectively. ◦We continued to invest in accretive organic growth, including our investments in the Corpus Christi Stage 3 Project, 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. 32 Table of Contents Results of Operations Consolidated results of operations Three Months Ended June 30, Six Months Ended June 30, (in millions, except per share data) 2026 2025 Variance 2026 2025 Variance Revenues LNG revenues $ 5,640 $ 4,515 $ 1,125 $ 11,362 $ 9,820 $ 1,542 Regasification revenues 34 34 — 68 68 — Other revenues 58 92 (34) 170 197 (27) Total revenues 5,732 4,641 1,091 11,600 10,085 1,515 Operating costs and expenses Cost of sales (excluding operating and maintenance expense and depreciation, amortization and accretion expense shown separately below) 439 1,117 (678) 8,757 4,688 4,069 Operating and maintenance expense 533 559 (26) 1,058 1,032 26 Selling, general and administrative expense 88 99 (11) 224 215 9 Depreciation, amortization and accretion expense 380 329 51 753 641 112 Other operating costs and expenses 2 7 (5) 6 18 (12) Total operating costs and expenses 1,442 2,111 (669) 10,798 6,594 4,204 Income from operations 4,290 2,530 1,760 802 3,491 (2,689) Other income (expense) Interest expense, net of capitalized interest (287) (237) (50) (542) (466) (76) Interest and dividend income 19 31 (12) 35 68 (33) Other income (expense), net (14) (1) (13) (40) 19 (59) Total other expense (282) (207) (75) (547) (379) (168) Income before income taxes and NCI 4,008 2,323 1,685 255 3,112 (2,857) Less: income tax provision 366 426 (60) 25 547 (522) Net income 3,642 1,897 1,745 230 2,565 (2,335) Less: net income attributable to NCI 574 271 303 664 586 78 Net income (loss) attributable to Cheniere $ 3,068 $ 1,626 $ 1,442 $ (434) $ 1,979 $ (2,413) Net income (loss) per share attributable to common stockholders—basic $ 14.68 $ 7.32 $ 7.36 $ (2.08) $ 8.87 $ (10.95) Net income (loss) per share attributable to common stockholders—diluted $ 14.65 $ 7.30 $ 7.35 $ (2.08) $ 8.85 $ (10.93) 33 Table of Contents Volumes loaded and recognized from the Liquefaction Projects Three Months Ended June 30, 2026 Six Months Ended June 30, 2026 (in TBtu) Operational Commissioning Total Operational Commissioning Total Volumes loaded during the current period 669 3 672 1,351 9 1,360 Volumes loaded during the prior period but recognized during the current period 59 1 60 23 1 24 Less: volumes loaded during the current period and in transit at the end of the period (71) (1) (72) (71) (1) (72) Total volumes recognized in the current period 657 3 660 1,303 9 1,312 Three Months Ended June 30, 2025 Six Months Ended June 30, 2025 (in TBtu) Operational Commissioning Total Operational Commissioning Total Volumes loaded during the current period 550 — 550 1,152 6 1,158 Volumes loaded during the prior period but recognized during the current period 32 1 33 39 — 39 Less: volumes loaded during the current period and in transit at the end of the period (32) — (32) (32) — (32) Total volumes recognized in the current period 550 1 551 1,159 6 1,165 Components of LNG revenues and corresponding LNG volumes delivered Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Variance 2026 2025 Variance LNG revenues (in millions): LNG from the Liquefaction Projects sold under third party long-term agreements (1) $ 3,548 $ 3,575 $ (27) $ 8,346 $ 7,343 $ 1,003 LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2) 1,997 687 1,310 3,206 1,963 1,243 LNG procured from third parties (2) — 86 (86) 416 150 266 Net derivative gain (loss) 40 101 (61) (742) 218 (960) Other revenues 55 66 (11) 136 146 (10) Total LNG revenues $ 5,640 $ 4,515 $ 1,125 $ 11,362 $ 9,820 $ 1,542 Volumes delivered as LNG revenues (in TBtu): LNG from the Liquefaction Projects sold under third party long-term agreements (1) 534 496 38 1,070 1,012 58 LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2) 123 54 69 233 147 86 LNG procured from third parties (2) — 8 (8) 36 15 21 Total volumes delivered as LNG revenues 657 558 99 1,339 1,174 165 (1)Long-term agreements include agreements with an initial tenor of 12 months or more. (2)Includes volumes sold under short-term agreements and a portion of volumes sold from natural gas procured under long-term IPM agreements. 34 Table of Contents Net income (loss) attributable to Cheniere Net income (loss) attributable to Cheniere increased by $1.4 billion and declined by $2.4 billion during the three and six months ended June 30, 2026, respectively, as compared to the same periods of 2025. The increase between the three month periods was primarily due to: •$1.4 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 long-term IPM agreements prior to the NPNS designation, as further described below, primarily due to narrowing spreads between global and U.S. domestic natural gas benchmarks and the easing of the global natural gas price volatility that began in the first quarter of 2026; •$380 million increase in revenues, net of cost of sales and excluding changes in fair value of agreements accounted for as derivative instruments, from higher margins as a result of increased production volume, largely due to additional Trains of the Corpus Christi Stage 3 Project in operation during the three months ended June 30, 2026 compared to the same period in 2025, and from the relative portion of our cargoes sold that is subject to global LNG pricing; partially offset by: •$303 million increase in net income attributable to NCI, as further described below under the caption Net income attributable to NCI. The decline between the six month periods was primarily due to: •$3.4 billion of unfavorable 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 prior to the NPNS designation, as further described below, primarily attributable to elevated global natural gas price volatility influenced in part by the tightening supply conditions, transit constraints and heightened geopolitical uncertainties from the conflict and instabilities across parts of the Middle East during 2026, as well as widening spreads between global and U.S. domestic natural gas benchmarks; partially offset by: •$522 million favorable change in income tax provision; •$529 million increase in revenues, net of cost of sales and excluding changes in fair value of agreements accounted for as derivative instruments and $370 million in certain excise tax credits recognized in the first quarter of 2026, from higher margins from increased production volume due to additional Trains of the Corpus Christi Stage 3 Project in operation during the six months ended June 30, 2026 compared to the same period in 2025, as well as from contributions from optimization activities and the relative portion of our cargoes sold that is subject to global LNG pricing. Continued tightening of global natural gas and LNG supply conditions, including upstream production constraints, liquefaction capacity limitations and shipping and transit disruptions in the Middle East, together with heightened geopolitical uncertainties in key producing and consuming regions, may result in sustained volatility in global natural gas and LNG prices. Such volatility, along with fluctuations in regional price differentials, could materially impact our results of operations, cash flows and financial condition, particularly from LNG sales under spot or short-term agreements indexed to global prices. Additionally, the potential impacts of sustained volatility in global natural gas and LNG prices may also affect the fair value of our agreements accounted for as derivatives, particularly those indexed to global natural gas benchmarks. In June 2026, we designated the NPNS scope exception under Accounting Standards Codification Topic 815, Derivatives and Hedging, for certain IPM agreements providing for natural gas deliveries along the U.S. Gulf Coast. This designation comprised approximately 73% of total fixed minimum contractual IPM agreement volumes at the designation date. The remaining 27% of such total volumes was comprised of agreements for which deliveries occur upstream of our liquefaction facilities and were excluded from the NPNS designation. This exception is available for contracts that are expected to be physically settled and used or sold in the normal course of business, which is consistent with our intended purpose to consume the delivered physical natural gas to produce LNG. Our designation considered increased observable U.S. Gulf Coast third-party physical natural gas market activity involving contracts indexed to global LNG or natural gas prices, among other factors, in evaluating whether the pricing mechanism is consistent with the economics of the underlying physical market. As a result of this designation, these agreements are no longer accounted for as derivative instruments that are measured at fair value on a recurring basis. Instead, the agreements are accounted for on a delivery basis upon physical receipt of the natural gas. The 35 Table of Contents estimated fair values of these agreements as of the designation date were established as the new cost basis and are being amortized into cost of sales on a systematic basis over the remaining expected terms of the agreements. Because recognition is based on the timing and volume of contract deliveries, the amounts recognized in any reporting period are expected to vary and are not expected to follow a linear pattern. These non-cash amounts reflect the amortization of deferred gains and losses established at the designation date rather than changes in current-period market prices. If it is determined that the contracts designated as NPNS no longer meet the scope exception, the contracts would be recorded at fair value and any gains and losses would be immediately recognized in earnings. The following is an expanded discussion of the material drivers of the variance in net income (loss) attributable to Cheniere: Revenues The $1.1 billion and $1.5 billion increases in total revenues during the three and six months ended June 30, 2026, respectively, as compared to the same periods of 2025 were primarily attributable to: •$1.2 billion and $2.5 billion increases, respectively, due to higher volumes of LNG delivered as LNG revenues 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; partially offset by: •$1.0 billion of unfavorable changes between the six month periods from the agreements accounted for as derivative instruments included in revenues, as further described above under the caption Net income (loss) attributable to Cheniere. Operating costs and expenses The $669 million decrease and $4.2 billion increase in total operating costs and expenses during the three and six months ended June 30, 2026, respectively, as compared to the same periods of 2025 were primarily attributable to: •$944 million of favorable and $3.0 billion of unfavorable changes, respectively, in the fair value of agreements accounted for as derivative instruments included in cost of sales, primarily related to our long-term IPM agreements, of which $736 million of favorable and $3.1 billion of unfavorable changes, respectively, related to the changes in the fair value of NPNS-designated agreements prior to the designation date, as further described above under the caption Net income (loss) attributable to Cheniere; •$161 million and $1.4 billion increases, 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 between the six month periods; •$51 million and $112 million increases, respectively, in depreciation, amortization and accretion expense, primarily as a result of the substantial completions of the first six Trains of the Corpus Christi Stage 3 Project; and, •$370 million reduction to cost of sales from the recognition of certain excise tax credits during the six months ended June 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 The $60 million favorable variance in income tax provision during the three months ended June 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 $2.9 billion decrease in pre-tax income as well as the decrease in our effective tax rate, as further described below. Our effective tax rate was 9.1% and 9.8% for the three and six months ended June 30, 2026, respectively, as compared to 18.3% and 17.6% during the same periods of 2025, respectively. Our effective tax rate decreased between the comparable periods primarily due to the proportion of pre-tax income attributable to CQP, which is partially not taxable to us, and increased 36 Table of Contents Foreign Derived Deduction Eligible Income deduction. The effective tax rate for all periods was lower than the statutory rate of 21.0% primarily due to CQP’s income that is partially not taxable to us. Net income attributable to NCI The $303 million and $78 million increases in net income attributable to NCI during the three and six months ended June 30, 2026, respectively, as compared to the same periods of 2025 were primarily attributable to $608 million and $153 million increases in CQP’s consolidated net income primarily from favorable 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. 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 designate, the normal purchases and normal sales exception which applies the accrual method of accounting. As noted above under Net income (loss) attributable to Cheniere, due to our designation of the NPNS exception in June 2026 for certain IPM agreements previously accounted for as derivative instruments, future earnings volatility resulting from fair value market adjustments will be mitigated for those contracts that would have otherwise been marked-to-market in the absence of such designation. Conversely, commodity contracts accounted for as derivative instruments and for which we have not designated the NPNS exception remain subject to fair value accounting in which gains and losses arising from changes in fair value affect earnings. For such 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, as well as the timing of satisfaction of certain 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. 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 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 June 30, 2026, we realized offsets to LNG terminal costs of $31 million and $78 million, respectively, corresponding to 3 and 9 TBtu, respectively, of LNG as compared to $7 million and $55 million, respectively, corresponding to 1 and 6 TBtu, respectively, of LNG in the same periods of 2025 that were related to the sale of commissioning volumes associated with the Corpus Christi Stage 3 Project. 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 6 mtpa is still under construction as of June 30, 2026. As of June 30, 2026, 37 Table of Contents the first six Trains of the Corpus Christi Stage 3 Project were in operation, while as of June 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. Business Seasonality Our quarterly results are affected by production levels, timing of our maintenance activities and the resulting availability of volumes. Therefore, operating profit may not be generated evenly throughout the year. Weather variations, including temperature, have an impact on LNG output at our Liquefaction Projects. Our Liquefaction Projects are capable of relatively higher production volumes during the cooler months as compared to the summer months. We typically perform our scheduled major maintenance activities at our sites during shoulder months in the second and third quarters in order to mitigate the impact to our annual operating results. 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. June 30, 2026 Cash and cash equivalents (1) $ 1,099 Current restricted cash and cash equivalents (1) 420 Available commitments under our credit facilities (2): SPL Revolving Credit Facility 871 CQP Revolving Credit Facility 1,000 CCH Credit Facility 1,510 CCH Revolving Credit Facility 825 Cheniere Revolving Credit Facility 1,750 Total available commitments under our credit facilities 5,956 Total available liquidity $ 7,475 (1)Amounts presented include $443 million of cash and cash equivalents and $23 million of restricted cash and cash equivalents held by our consolidated VIE, all of which were related to CQP, as discussed in Note 6—Non-Controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements. (2)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of June 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 June 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. 38 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. 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. Corpus Christi LNG Terminal Expansion 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 June 30, 2026: Corpus Christi Stage 3 Project CCL Midscale Trains 8 & 9 Project Overall project completion percentage 98.4% 48.3% Completion percentage of: Engineering 99.8% 91.5% Procurement 100.0% 69.9% Subcontract work 98.0% 53.4% Construction 96.0% 6.7% Date of expected substantial completion 2H 2026 (1) 2H 2028 (1)As of June 30, 2026, substantial completions of the first six of seven midscale Trains of the Corpus Christi Stage 3 Project have been achieved. 39 Table of Contents Sources and Uses of Cash The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash and cash equivalents (in millions). 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. Six Months Ended June 30, 2026 2025 Net cash provided by operating activities $ 2,658 $ 2,059 Net cash used in investing activities (1,927) (1,575) Net cash used in financing activities (793) (1,653) Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents (3) (4) Net decrease in cash, cash equivalents and restricted cash and cash equivalents $ (65) $ (1,173) Operating Cash Flows The $599 million increase 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 lesser extent, an 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 cargoes. Partially offsetting the increased cash receipts were increased cash outflows for settlement of derivative instruments during the six months ended June 30, 2026 compared to cash provided by settlement of derivative instruments during the same period in 2025. Investing Cash Flows 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) $829 million and $741 million, respectively, for the Corpus Christi Stage 3 Project; (2) $554 million and $547 million, 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 six months ended June 30, 2026, primarily related to procurement and work performed by Bechtel under the LNTP and (4) 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, as well costs incurred for the early engineering and procurement for the SPL Expansion Project under the LNTP issued in May 2026. Financing Cash Flows The following table summarizes our financing activities (in millions): Six Months Ended June 30, 2026 2025 Proceeds from issuances of debt and borrowings $ 4,511 $ 265 Redemptions and repayments of debt and borrowings (3,263) (565) Distributions to NCI (394) (400) Contributions from redeemable NCI — 49 Redemption of redeemable NCI (136) — Payments related to tax withholdings for share-based compensation (37) (46) Repurchase of common stock, inclusive of excise taxes paid (1,113) (690) Dividends to stockholders (233) (223) Other, net (128) (43) Net cash used in financing activities $ (793) $ (1,653) 40 Table of Contents Proceeds from Issuances of Debt and Borrowings The following table shows the proceeds from issuances of debt and borrowings, including intra-period activity (in millions): Six Months Ended June 30, 2026 2025 Cheniere: 5.200% Senior Notes due 2036 $ 997 $ — 6.000% Senior Notes due 2056 746 — Cheniere Revolving Credit Facility 700 — CQP: 2036 CQP Senior Notes 995 — 2056 CQP Senior Notes 748 — SPL: SPL Revolving Credit Facility 160 265 CCH: CCH Working Capital Facility 100 — CCH Revolving Credit Facility 65 — Total proceeds from issuances of debt and borrowings $ 4,511 $ 265 Redemptions and Repayments of Debt and Borrowings The following table shows the redemptions and repayments of debt and borrowings, including intra-period activity (in millions): Six Months Ended June 30, 2026 2025 Cheniere: Cheniere Revolving Credit Facility $ (700) $ — SPL: 5.625% Senior Secured Notes due 2025 — (300) 5.875% Senior Secured Notes due 2026 (200) — 2027 SPL Senior Notes (1,500) — 4.747% weighted average rate Senior Notes due 2037 (53) — SPL Revolving Credit Facility (160) (265) CCH: CCH Working Capital Facility (100) — CCH Credit Facility (550) — Total redemptions and repayments of debt and borrowings $ (3,263) $ (565) Repurchase of Common Stock During the six months ended June 30, 2026 and 2025, we paid $1.1 billion and $656 million to repurchase approximately 4.9 million and 3.0 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 $33 million of such excise taxes during the six months ended June 30, 2025 related to our repurchases during the fiscal year 2023 and 2024 and 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 June 30, 2026, we had approximately $9.1 billion remaining under our share repurchase program. 41 Table of Contents Cash Dividends to Stockholders During the six months ended June 30, 2026 and 2025, we paid dividends of $1.110 and $1.000 per share of common stock for a total of $233 million and $223 million, respectively. On July 28, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on August 18, 2026 to stockholders of record as of the close of business on August 10, 2026. Summary of Critical Accounting Estimates The preparation of 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. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2025. Recent Accounting Standards For a summary of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation of our Notes to Consolidated Financial Statements. 42 Table of Contents