CQP

Information Regarding Forward-Looking Statements This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements.” 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 regarding our ability to pay distributions to our unitholders; •statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL; •statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction facility, pipeline facility 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 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; 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 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 20 Table of Contents 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 We are a publicly traded Delaware limited partnership formed by Cheniere. 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. We own a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, with a total production capacity of over 30 mtpa of LNG (the “Liquefaction Project”) as of June 30, 2026. 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 a 94-mile natural gas supply pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the “Creole Trail Pipeline”). 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 12 years of weighted average remaining life as of June 30, 2026, we have contracted with third parties approximately 90% of the total anticipated production from the Liquefaction Project through the mid-2030s. Additionally, there are SPAs that Cheniere Marketing currently holds that may be novated to us in the future. LNG produced by the Liquefaction 21 Table of Contents Project that is not contracted under long-term contracts is available for Cheniere Marketing, Cheniere’s integrated marketing function, pursuant to an SPA it has with us. 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. 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, project leverage and distributions. 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. We have increased available liquefaction capacity at our Liquefaction Project 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 a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. We are developing a two-phased expansion adjacent to the Liquefaction 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 we are commercializing to support the additional liquefaction capacity associated with this project. The SPL Expansion Project requires, 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. 22 Table of Contents The following table summarizes pre-FID development efforts and certain key milestones associated with the SPL Expansion Project: SPL Expansion Project Expected total peak production capacity of LNG (1) Up to ~ 20 mtpa Milestone Regulatory (2) FERC authorizations: Positive environmental assessment Pending Order under Section 3 of NGA Pending Certification to commence construction Pending DOE export authorization: FTA countries ü Non-FTA countries Pending Financing Financing (3) Commercialization and Other Contracting Definitive commercial agreements (4) Definitive full-scope EPC contract ü (5) Target Milestone FID (6) 2026/2027 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 project 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 the SPL Expansion Project, if we reach a positive FID. (4)Liquefaction capacity partially contracted by Cheniere Marketing and SPL Stage V through SPA or long-term IPM agreements conditioned on additional liquefaction capacity beyond what is currently in construction or operation. (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 •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. 23 Table of Contents Operational •As of July 31, 2026, over 3,460 cumulative LNG cargoes totaling approximately 240 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project. Financial •In June 2026, we 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. •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. •On July 28, 2026, with respect to the second quarter of 2026, we declared a cash distribution of $0.820 per common unit to unitholders of record as of August 7, 2026, and the related general partner distribution, to be paid on August 14, 2026. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.045 per unit. 24 Table of Contents Results of Operations Three Months Ended June 30, Six Months Ended June 30, (in millions, except per unit data) 2026 2025 Variance 2026 2025 Variance Revenues LNG revenues $ 1,902 $ 1,857 $ 45 $ 4,605 $ 4,124 $ 481 LNG revenues—affiliate 631 549 82 1,477 1,220 257 Regasification revenues 34 34 — 68 68 — Other revenues 16 15 1 33 32 1 Total revenues 2,583 2,455 128 6,183 5,444 739 Operating costs and expenses Cost of sales (excluding operating and maintenance expense and depreciation and amortization expense shown separately below) 765 1,196 (431) 3,481 2,899 582 Cost of sales—affiliate — — — 46 — 46 Operating and maintenance expense 230 289 (59) 456 492 (36) Operating and maintenance expense—affiliate 45 42 3 93 86 7 Operating and maintenance expense—related party — 13 (13) — 28 (28) General and administrative expense 3 2 1 6 6 — General and administrative expense—affiliate 23 24 (1) 47 47 — Depreciation and amortization expense 174 171 3 348 342 6 Other operating costs and expenses 2 2 — 4 2 2 Other operating costs and expenses—affiliate 1 1 — 1 1 — Total operating costs and expenses 1,243 1,740 (497) 4,482 3,903 579 Income from operations 1,340 715 625 1,701 1,541 160 Other income (expense) Interest expense, net of capitalized interest (183) (188) 5 (364) (378) 14 Other income, net 2 4 (2) 7 9 (2) Other income—affiliate 2 22 (20) 3 22 (19) Total other expense (179) (162) (17) (354) (347) (7) Net income $ 1,161 $ 553 $ 608 $ 1,347 $ 1,194 $ 153 Basic and diluted net income per common unit $ 2.14 $ 0.91 $ 1.23 $ 2.33 $ 1.99 $ 0.34 Volumes recognized as revenues Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Variance 2026 2025 Variance Volumes recognized as revenues (in TBtu) 396 351 45 809 756 53 Net income Net income increased by $608 million and $153 million 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 $367 million of favorable changes in the fair value of agreements accounted for as derivative instruments, largely related to our long-term IPM agreements prior to the NPNS designation, as further described below, due to narrowing spreads between global and U.S. domestic natural gas benchmarks. The increase was also attributable to a $192 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 primarily from increased production volume 25 Table of Contents as a result of planned large-scale maintenance activities that occurred during the three months ended June 30, 2025, but did not recur during the three months ended June 30, 2026. The increase between the six month periods was primarily due to a $343 million increase in revenues, net of cost of sales and excluding changes in fair value of agreements accounted for as derivative instruments, from higher production volume and to a lesser degree, increased Henry Hub pricing. Partially offsetting the increase between the six month periods was $233 million of unfavorable changes in the fair value of agreements accounted for as derivative instruments, largely related to our IPM agreements prior to the NPNS designation, as further described below, primarily due to the 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. In June 2026, we designated the NPNS scope exception under Accounting Standards Codification Topic 815, Derivatives and Hedging, for our IPM agreements. 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 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: Revenues Total revenues increased by $128 million and $739 million 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 attributable to: •$305 million increase due to higher production volume, as further described above under the caption Net income; partially offset by: •$167 million decrease due to lower pricing per MMBtu primarily as a result of decreased Henry Hub pricing. The increase between the six month periods was primarily attributable to: •$403 million increase from higher pricing per MMBtu as a result of increased Henry Hub pricing; and •$368 million increase due to higher production volume, as further described above under the caption Net income. Operating costs and expenses The $497 million decrease and $579 million 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: •$479 million increase in the cost of natural gas feedstock between the six month periods largely due to the increase in U.S. natural gas prices; and •$367 million of favorable and $233 million of unfavorable changes between the three and six month periods, 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 $512 million of favorable and $313 million of unfavorable changes, respectively, related to the changes in fair value of NPNS-designated agreements prior to the designation date, as further described above under the caption Net income. The changes in the fair value of our long- 26 Table of Contents term IPM agreements between the three and six month periods were partially offset by $145 million unfavorable and $80 million favorable changes, respectively, in the fair value of other agreements accounted for as derivative instruments included in cost of sales, largely due to changes in market-based locational forward price differentials for North American natural gas deliveries; partially offset by: •$155 million decrease in costs associated with the sale of certain unutilized natural gas procured for the liquefaction process between the six month periods; and •$69 million and $57 million decreases, respectively, in operating and maintenance expense (including affiliate and related party) largely as a result of planned large-scale maintenance activities that occurred during the three months ended June 30, 2025, but did not recur during the three months ended June 30, 2026. 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, due to our designation of the NPNS exception in June 2026 for our 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 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. We may recognize changes in fair value through earnings that could impact our results of operations if and when such uncertainties are resolved. 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 Project. Our Liquefaction Project is 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 site 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 offerings by us or our subsidiaries and equity offerings by us. 27 Table of Contents 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 $ 443 Restricted cash and cash equivalents designated for the Liquefaction Project 23 Available commitments under our credit facilities (1): SPL Revolving Credit Facility 871 CQP Revolving Credit Facility 1,000 Total available commitments under our credit facilities 1,871 Total available liquidity $ 2,337 (1)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. Although our sources and uses of cash are presented below from a consolidated standpoint, we and our subsidiary SPL operate with independent capital structures. Certain restrictions or requirements under debt instruments executed by SPL limit its ability to distribute cash, including the following: •SPL is 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 Project and other restricted payments. In addition, SPL’s operating costs are managed by subsidiaries of Cheniere under affiliate agreements, which may require SPL to advance cash to the respective affiliates; and •SPL is restricted by affirmative and negative covenants included in certain of its debt agreements in its ability to make certain payments, including distributions, unless specific requirements are satisfied. See Note 8—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 to enable each independent capital structure to meet its currently anticipated cash requirements. The sources of liquidity at SPL primarily fund the cash requirements of SPL, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by SPLNG, is available to enable CQP to meet its cash requirements. Supplemental Guarantor Information Certain debt obligations of CQP (the “Guaranteed Obligations”), consisting of the $1.5 billion of 4.500% Senior Notes due 2029, $1.5 billion of 4.000% Senior Notes due 2031, $1.2 billion of 3.25% Senior Notes due 2032, $1.4 billion of 5.950% Senior Notes due 2033, $1.2 billion of 5.750% Senior Notes due 2034, $1.0 billion of 5.550% Senior Notes due 2035, $1.0 billion of 5.350% Senior Notes due 2036 and $750 million of 6.050% Senior Notes due 2056 (collectively, the “CQP Senior Notes”) are jointly and severally guaranteed by certain subsidiaries of CQP (each a “Guarantor” and collectively, the “CQP Guarantors”), as prescribed within the respective debt agreements governing such Guaranteed Obligation. The CQP Guarantors’ guarantees of such Guaranteed Obligations are full and unconditional, subject to certain release provisions including, as applicable, (1) the sale, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of a Guarantor, (2) the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from another guarantee that resulted in the creation of its guarantee of the Guaranteed Obligation and (4) the legal defeasance or satisfaction and discharge of obligations under the indenture governing the CQP Senior Notes. In the event of a default in payment of the principal or interest by us, whether at maturity of the respective debt obligation or by 28 Table of Contents declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the CQP Guarantors to enforce the guarantee. The Guaranteed Obligations contain affirmative and negative covenants that are customary for the respective debt instrument, including, with limited exceptions, restrictions on CQP’s and the CQP Guarantors’ ability to incur additional indebtedness and/or liens, enter into hedging arrangements and/or engage in transactions with affiliates. The Guaranteed Obligations also include events of default that are customary for the respective debt instrument, which are subject to customary grace periods and materiality standards. The rights of holders of the Guaranteed Obligations against the CQP Guarantors may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the CQP Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished. The following tables include summarized financial information of CQP (the “Parent Issuer”) and the CQP Guarantors (together with the Parent Issuer, the “Obligor Group”) on a combined basis. Investments in and equity in the earnings of SPL and, subject to certain conditions governing its guarantee, certain other subsidiaries of CQP (collectively with SPL, the “Non-Guarantors”), which are not currently members of the Obligor Group, have been excluded. Intercompany balances and transactions between entities in the Obligor Group have been eliminated. Although the creditors of the Obligor Group have no claim against the Non-Guarantors, the Obligor Group may gain access to the assets of the Non-Guarantors upon bankruptcy, liquidation or reorganization of the Non-Guarantors due to its investment in these entities. However, such claims to the assets of the Non-Guarantors would be subordinated to any claims by the Non-Guarantors’ creditors, including trade creditors. Summarized Balance Sheets (in millions) June 30, December 31, 2026 2025 ASSETS Current assets Current assets, net $ 495 $ 226 Current assets—affiliate 167 146 Current assets with Non-Guarantors 40 56 Total current assets 702 428 Non-current assets, net 2,803 2,851 Total assets $ 3,505 $ 3,279 LIABILITIES Current liabilities Current liabilities $ 162 $ 154 Current liabilities—affiliate 36 50 Current liabilities due to Non-Guarantors 151 151 Total current liabilities 349 355 Long-term debt, net of unamortized discount and debt issuance costs 9,447 7,724 Other non-current liabilities 123 130 Non-current liabilities—affiliate 15 18 Non-current liabilities—Non-Guarantors 3 — Total liabilities $ 9,937 $ 8,227 29 Table of Contents Summarized Statement of Operations (in millions) Six Months Ended June 30, 2026 Revenues $ 101 Revenues from Non-Guarantors 286 Total revenues 387 Operating costs and expenses 128 Operating costs and expenses—affiliate 115 Recovery of operating costs and expenses from Non-Guarantors (2) Total operating costs and expenses 241 Income from operations 146 Net loss $ (53) 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 $ 1,609 $ 1,223 Net cash used in investing activities (299) (131) Net cash used in financing activities (1,045) (1,327) Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents $ 265 $ (235) Operating Cash Flows The $386 million increase between the periods was primarily related to higher net cash inflows from the sale of LNG cargoes, largely due to higher revenue from increased production volumes and increased Henry Hub pricing. Investing Cash Flows Cash outflows for property, plant and equipment 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) $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 (2) optimization and other site improvement projects during both periods. We expect to continue to incur costs 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 $ 1,903 $ 265 Redemptions and repayments of debt and borrowings (1,913) (565) Distributions (1,007) (1,025) Other, net (28) (2) Net cash used in financing activities $ (1,045) $ (1,327) 30 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 CQP: 2036 CQP Senior Notes $ 995 $ — 2056 CQP Senior Notes 748 — SPL: SPL Revolving Credit Facility 160 265 Total proceeds from issuances of debt and borrowings $ 1,903 $ 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 SPL: 5.625% Senior Secured Notes due 2025 $ — $ (300) 5.875% Senior Secured Notes due 2026 (200) — 5.00% Senior Secured Notes due 2027 (1,500) — 4.747% weighted average rate Senior Notes due 2037 (53) — SPL Revolving Credit Facility (160) (265) Total redemptions and repayments of debt and borrowings $ (1,913) $ (565) Cash Distributions to Unitholders Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from accumulated operating surplus. The following provides a summary of distributions paid by us during the six months ended June 30, 2026 and 2025: Total Distribution (in millions) Date Paid Period Covered by Distribution Distribution Per Common Unit Common Units General Partner Units Incentive Distribution Rights May 15, 2026 January 1 - March 31, 2026 $ 0.790 $ 382 $ 10 $ 90 February 13, 2026 October 1 - December 31, 2025 0.830 402 10 108 May 15, 2025 January 1 - March 31, 2025 0.820 397 10 104 February 14, 2025 October 1 - December 31, 2024 0.820 397 10 104 In addition, Tug Services distributed $5 million and $3 million during the six months ended June 30, 2026 and 2025, respectively, to Cheniere Terminals in accordance with its terminal marine service agreement, which is recognized as part of the distributions to the holder of our general partner interest. Refer to Note 10—Related Party Transactions of our Notes to Consolidated Financial Statements for further discussion of this agreement. On July 28, 2026, with respect to the second quarter of 2026, we declared a cash distribution of $0.820 per common unit to unitholders of record as of August 7, 2026, and the related general partner distribution, to be paid on August 14, 2026. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.045 per unit. 31 Table of Contents 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.