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

TheEach of the risk factors inoutlined below are discussed more fully following this report are grouped into the following categoriessummary:

•Risks Relating to Our Financial Matters;

•Risks Relating to Our Operations and Industry;

•Risks Relating to Regulations;

•Risks Relating to Our Relationship with Our General Partner;

•Risks Relating to an Investment in Us and Our Common Units; and

•Risks Relating to Tax Matters.Matters

As of December 31, 2024,2025, we had, on a consolidated basis, $270$182 million of cash and cash equivalents, $109$19 million of restricted cash and cash equivalents, a total of $1.8 billion of available commitments under our credit facilities and $15.2$14.6 billion of total debt outstanding (before unamortized discount and debt issuance costs). SPL and CQP operate with independent capital structures as further detailed in Note 10—Debt of our Notes to Consolidated Financial Statements. We incur, and will incur, significant interest expense relating to financing the assets at the Sabine Pass LNG Terminal, and we anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of the SPL Expansion Project if a positive FID is made. Our ability to fund our capital expenditures and refinance our indebtedness may depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, lending institutions’ evolving policies on financing businesses linked to fossil fuels and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also may rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement lenders or seek alternative financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2024,2025, we had SPAs with aapproximately total of 11ten different third party customers.customers, with customers under common control being considered a single customer, whereby five customers individually with revenues greater than 10% of total revenues from contracts with external customers accounted for an aggregate of 76% of total revenues from contracts with external customers for the year ended December 31, 2025.

While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.

We are a limited partnership formed by Cheniere to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We own the natural gas liquefaction and export facility in Cameron Parish, Louisiana at Sabine Pass,Pass. Louisiana.Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. For further discussion of our business, see Items 1. and 2. Business and Properties. We believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, as well as the current geopolitical environment that has intensified the demand for supply security, should enable us to enter into long-term agreements and provide a foundation for additional growth in our business in the future.

•As of February 14,20, 2025,2026, approximatelyover 2,8403,270 cumulative LNG cargoes totaling over 195225 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

•In MayDecember 2024,2025, weSPL issuedredeemed $1.2$300 billionmillion aggregate principal amount of 5.750%its 5.875% Senior Secured Notes due 20342026 (the “20342026 CQPSPL Senior Notes”). Inand Junesubsequently 2024,in February 2026, SPL redeemed the netremaining proceeds,$200 together with cash on hand, were used to redeem $1.2 billion of the outstandingmillion aggregate principal amount of SPL’sits 5.625% Senior Secured Notes due 2025 (the “20252026 SPL Senior Notes”).Notes.

•ExcludingIn amountsMarch refinanced,2025, SPL redeemedrepaid $800the remaining $300 million of outstanding aggregate principal amount outstanding of its senior5.625% securedSenior notesSecured duringNotes thedue year2025 endedat December 31, 2024.maturity.

RevenuesTotal revenues

Significant factorfactors affecting our results of operations

Below is aare significant factorfactors that affectsaffect our results of operations.

Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements, unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception which applies the accrual method of accounting, as described in Note 3—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. For commodity derivative instruments, including those related to our IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

•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 10—Debt of our Notes to Consolidated Financial Statements for additional information on these covenants.

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 20332033, and$1.2 thebillion 2034of CQP5.750% Senior Notes due 2034 and $1.0 billion of 5.550% Senior Notes due 2035 (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 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, Sabinecertain Passother LPsubsidiaries 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.

(2)LNG revenues (including $0.7$0.5 billion and $1.4$1.0 billion of fixed fees and variable fees, respectively, from affiliates) exclude the SPASPAs with Cheniere Marketing associated with our IPM agreement in effect,agreements, for which pricing is linked to international natural gas prices.

Under our long-termSPAs SPAs,and IPM agreements currently in effect, we have contracted approximately 80%85% of the total anticipated production thoughthrough the mid-2030s from our liquefaction capacity that is currently in construction or operation. UnderAdditionally, there are SPAs that Cheniere Marketing currently holds that may be novated to us in the future. As described in General, under our SPAs, customers purchase LNG on an FOB basis (delivered to the customer at the Sabine Pass LNG Terminal) generally for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The variable fees under our SPAs were generally sized with the intention to cover the supply and transportation of natural gas and the liquefaction fuel consumed to produce the LNG to be sold under each such SPA, thus limiting our exposure to future U.S. natural gas price increases. Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension.

The table above excludes an SPA with Cheniere Marketing under which we sell LNG produced from natural gas procured under our IPM agreement in effect at pricing linked to the same global gas market prices.prices as one of our IPM agreements. The IPM agreement in effect,agreements, under which we pay for natural gas feedstock based on global gas prices less liquefaction fees and certain costs incurred by us, generatesgenerate a take-or-pay style fixed liquefaction fee when viewed in conjunction with the associated SPA. Over a remaining fixed termAs of 13December years,31, 2025, we expect to generate liquidity from the approximately 575531 TBtu of LNG yet to be delivered under thisan SPA aswith Cheniere Marketing, which has a remaining fixed term of December12 31,years, 2024.and Wewe dohad not haveyet executed an SPA as of December 31, 2024 for the approximately 665669 TBtu associated with anour other IPM agreement that is subject to unsatisfied contractual conditions precedent.agreement.

Our significant land position at the Sabine Pass LNG Terminal provides potential development and investment opportunities for further liquefaction capacity expansion at a strategically advantaged location with proximity to pipeline infrastructure and resources. In FebruaryJune 2024,2025, certain of our subsidiaries submitted an application to the FERC under the NGA for authorization to site, construct and operateupdated the SPL Expansion Project,Project’s asFERC wellapplication, asoriginally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an applicationexpected total peak production capacity of up to theapproximately DOE20 requesting authorization to export LNG to FTA countries and non-FTA countries, bothmtpa of whichLNG, applicationsinclusive excludeof debottlenecking.estimated Indebottlenecking October 2024, the authorization from the DOE to export LNG to FTA countries was received.opportunities. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.FID is made.

(3)Natural gas supply agreements exclude the IPM agreement,agreements, which, as described in Future Sources of Liquidity under Executed Contracts, isare structured to generate a fixed margin when viewed in conjunction with the associated SPASPAs with Cheniere Marketing.

Excluding our IPM agreement,agreements, we have secured approximately 3,9003,406 TBtu of natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements with remaining fixed terms of up to 76 years. As of December 31, 2024,2025, we have secured approximately 73% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2025,2026, excluding the 3% of which has been secured under our IPM agreement in effect.agreements. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2025.2026. As further described in the Future Sources of Liquidity under Executed Contracts section,Contracts, the pricing structure of our SPAs often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices.

We rely on our general partner to manage all aspects of the development, construction, operation and maintenance of the Sabine Pass LNG Terminal and to conduct our business. Because our general partner has no employees, it relies on subsidiaries of Cheniere to provideprovide, through services agreements our subsidiaries have with them, the personnel necessary to allow it to meet its management obligations to us and our subsidiaries. As ofdescribed Decemberin 31,Note 2024,13—Related CheniereParty andTransactions, itsour subsidiariespayment hadstructures 1,714 full-time employees, including 501 employees who directly supportedunder the Sabineservices Passagreements LNGprimarily Terminalconsist operations.of cost reimbursement, plus a compensating fee based on a fixed amount (indexed for inflation) per Train in service. Prior to the substantial completion of a Train, a compensating fee is charged based on a percentage of the capital expenditures of the Train under construction.

The FID of any expansion projectsprojects, including the SPL Expansion Project, will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.

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 MarchJune 31,30, 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 MarchJune 31,30, 2026, we have contracted with third parties approximately 85%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 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.

•As of MayJuly 1,31, 2026, approximatelyover 3,3603,460 cumulative LNG cargoes totaling overapproximately 230240 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

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

•On AprilJuly 28, 2026, with respect to the firstsecond quarter of 2026, we declared a cash distribution of $0.790$0.820 per common unit to unitholders of record as of MayAugust 8,7, 2026, and the related general partner distribution, to be paid on MayAugust 15,14, 2026. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.015$0.045 per unit.

Volumes loaded and recognized fromas the Liquefaction Projectrevenues

NetThe incomeincrease decreased by $455 million duringbetween the threesix monthsmonth endedperiods March 31, 2026 as compared to the same period of 2025was primarily due to $599a $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 associated with our derivatives related to long-termour IPM agreements.agreements Theseprior lossesto werethe NPNS designation, as further described below, primarily attributabledue to widening spreads between global and U.S. domestic natural gas benchmarks andthe 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. Partially offsetting these losses were a $120 million decrease in cost of sales, net of revenues, from the sale of certain unutilized natural gas procured for the liquefaction process and a $100 million increase in revenues, net of cost of natural gas feedstock, from increased Henry Hub pricing.

The $611•$403 million increase in total revenues during the three months ended March 31, 2026 as compared to the same period of 2025 was primarily attributable to a $576 million increase due tofrom higher pricing per MMBtu as a result of increased Henry Hub pricing.pricing; and

The $1.1$497 billionmillion decrease and $579 million increase in total operating costs and expenses during the three and six months ended MarchJune 31,30, 20262026, respectively, as compared to the same periodperiods of 2025 waswere primarily attributable to:

•$508$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; partially offset by:and

•$144$155 million decrease in costs associated with the sale of certain unutilized natural gas procured for the liquefaction process.process between the six month periods; and

DerivativeConversely, instruments,commodity contracts accounted for as derivative instruments and for which we usehave not designated the NPNS exception remain subject to manage certain risks, are reported at fair value accounting in ourwhich Consolidated Financial Statements, unless they satisfy criteria for,gains and welosses elect,arising thefrom normalchanges purchasesin andfair normalvalue salesaffect exception which applies the accrual method of accounting.earnings. For commoditysuch derivative instruments, including those related to our long-term IPM agreements,contracts, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport.points. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

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

Our liquidity position subsequent to MarchJune 31,30, 2026 will be driven by future sources of liquidity and future cash requirements. For a discussion of our future sources and uses of liquidity, see the liquidity and capital resources disclosures in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the fiscal year ended December 31, 2025.

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 and2034, $1.0 billion of 5.550% Senior Notes due 20352035, $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 $245$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.

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

The following provides a summary of distributions paid by us during the threesix months ended MarchJune 31,30, 2026 and 2025:

In addition, Tug Services distributed $2$5 million and $1$3 million during the threesix months ended MarchJune 31,30, 2026 and 2025, respectively, to Cheniere Terminals in accordance with theirits 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 AprilJuly 28, 2026, with respect to the firstsecond quarter of 2026, we declared a cash distribution of $0.790$0.820 per common unit to unitholders of record as of MayAugust 8,7, 2026, and the related general partner distribution, to be paid on MayAugust 15,14, 2026. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.015$0.045 per unit.