Cheniere Energy Partners CQP Form 10-Q filing Q2 FY2026

DEFINITIONS

As used in this quarterly report, the terms listed below have the following meanings:

Common Industry and Other Terms

ASU Accounting Standards Update

Bcf/d billion cubic feet per day

Bcfe billion cubic feet equivalent

DOE U.S. Department of Energy

EPC engineering, procurement and construction

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

FID final investment decision

FTA countries countries with which the U.S. has a free trade agreement providing for national treatment for trade in natural gas

GAAP generally accepted accounting principles in the U.S.

Henry Hub the final settlement price (in U.S. dollars per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin

IPM agreements integrated production marketing agreements in which the gas producer sells to us gas on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs

LNG liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state

MMBtu million British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit

mtpa million tonnes per annum

NGA Natural Gas Act of 1938, as amended

non-FTA countries countries with which the U.S. does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted

NPNS normal purchases and normal sales, an elective scope exception available under Accounting Standards Codification Topic 815, Derivatives and Hedging, which excludes qualifying physical commodity contracts from derivative accounting

SEC U.S. Securities and Exchange Commission

SOFR Secured Overnight Financing Rate

SPA LNG sale and purchase agreement

TBtu trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit

Train an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG

TUA terminal use agreement

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of June 30, 2026, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

Unless the context requires otherwise, references to “CQP,” the “Partnership,” “we,” “us” and “our” refer to Cheniere Energy Partners, L.P. and its consolidated subsidiaries.

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

(1) In computing basic and diluted net income per common unit, net income is reduced by the amount of undistributed net income allocated to participating securities other than common units, as required under the two-class method. See Note 11—Net Income per Common Unit.

The accompanying notes are an integral part of these consolidated financial statements.

The accompanying notes are an integral part of these consolidated financial statements.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY (DEFICIT)

(in millions)

(unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

The accompanying notes are an integral part of these consolidated financial statements.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We own a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), which has natural gas liquefaction facilities with 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, vaporizers and three marine berths. We also own and operate 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”).

We are developing a two-phased expansion project adjacent to the Liquefaction Project to provide additional liquefaction capacity, 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 potential expansion project. In May 2026, SPL Stage V entered into a lump sum, turnkey EPC contract with Bechtel Energy, Inc. for the first phase of the SPL Expansion Project and issued a limited notice to proceed to commence early engineering and procurement. The development of this project 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 the Board of Directors of our general partner makes a positive FID.

We do not have employees and thus we and our subsidiaries have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. See Note 10—Related Party Transactions for additional details of the activity under these services agreements during the three months ended June 30, 2026 and 2025.

As of June 30, 2026, Cheniere owned 48.6% of our limited partner interest in the form of 239.9 million of our common units. Cheniere also owns 100% of our general partner interest and our incentive distribution rights (“IDRs”).

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of CQP have been prepared in accordance with GAAP for interim financial information and in accordance with Rule 10-01 of Regulation S-X and reflect all normal recurring adjustments, which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. Accordingly, these Consolidated Financial Statements do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2025.

Results of operations for the three and six months ended June 30, 2026 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2026.

We are not subject to either federal or state income tax, as our partners are taxed individually on their allocable share of our taxable income.

Accounting for Derivative Instruments

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

scope exception, the contracts would be recorded at fair value and any gains and losses would be immediately recognized in earnings.

As a result of the designation, the carrying amounts of the NPNS-designated agreements were reclassified on our Consolidated Balance Sheets from other current assets, derivative assets, current derivative liabilities and derivative liabilities as follows (in millions):

The following table presents management’s current estimated net gains from the amortization of the remaining balance of the deferred NPNS assets and liabilities as of the designation date (in millions), which is based on estimated recognition periods of contractual delivery schedules as of the balance sheet date and may change if contract volumes, delivery timing, or contract modifications differ from current expectations:

(1) For the six months ended June 30, 2026, we recorded a gain from amortization of $5 million.

Prior to the designation date, we recognized $551 million and $(126) million of derivative gains (losses) during the three and six months ended June 30, 2026, respectively, and derivative gains of $39 million and $188 million for the same periods of 2025, respectively, for the designated agreements.

Recent Accounting Standards

ASU 2024-03

In November 2024, the FASB issued ASU No. 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, as clarified by ASU No. 2025-01 in January 2025. This guidance requires disaggregated disclosures about certain income statement expense line items on an annual and interim basis. We continue to evaluate the impact of the provisions of this guidance on our disclosures, but plan to adopt this guidance prospectively and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2027.

NOTE 2—UNITHOLDERS’ EQUITY

The common units represent limited partner interests in us, which entitle the unitholders to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. Although common unitholders are not obligated to fund losses of the Partnership, their capital account, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continues to share in losses.

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds IDRs, which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus as additional target levels are met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash, which, as defined in our partnership agreement, is generally our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions we have paid to date have been made from accumulated operating surplus as defined in the partnership agreement.

As of June 30, 2026, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.5% by CQP Target Holdco L.L.C. (“CQP Target Holdco”) and other affiliates of Blackstone Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 7.9% by the public. All of our 2% general partner interest was held by Cheniere. CQP Target Holdco’s equity interests are 50.0% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone, and 50.0% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of Brookfield. The ownership of CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with the SEC.

NOTE 3—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

Trade and other receivables, net of current expected credit losses, consisted of the following (in millions):

Upon collection of our receivables, cash will be immediately restricted for the payment of liabilities related to the Liquefaction Project.

NOTE 4—INVENTORY

Inventory consisted of the following (in millions):

NOTE 5—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Depreciation expense was $172 million and $170 million during the three months ended June 30, 2026 and 2025, respectively, and $345 million and $340 million during the six months ended June 30, 2026 and 2025, respectively.

NOTE 6—DERIVATIVE INSTRUMENTS

We have commodity contracts accounted for as derivatives which consist of natural gas supply contracts for the operation of the Liquefaction Project and expansion project, excluding those contracts for which we have designated NPNS, as described in Note 1—Nature of Operations and Basis of Presentation, as well as the associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis, distinguished by the fair value hierarchy levels prescribed by GAAP (in millions):

(1) As described in Note 1—Nature of Operations and Basis of Presentation, in June 2026, we designated the NPNS scope exception for our IPM agreements, which resulted in these agreements being no longer accounted for as derivative instruments as of the designation date. The fair value of such agreements was a liability of $394 million as of December 31, 2025.

We value the Liquefaction Supply Derivatives using a market approach incorporating present value techniques, as needed, which incorporates observable commodity price curves, when available, and other relevant data.

We include a significant portion of the Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models, which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. We consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value, for which we make judgments about market risk related to liquidity of commodity indices utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. Our fair value estimates incorporate 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.

The Level 3 fair value measurements of our natural gas positions within the Liquefaction Supply Derivatives could be impacted by a change in certain natural gas prices. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of June 30, 2026:

(1) Unobservable inputs were weighted by the relative fair value of the instruments.

Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of the Liquefaction Supply Derivatives.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):

(1) Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to the contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.

(2) Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period, and on the NPNS-designated agreements prior to the designation date, as further described in Note 1—Nature of Operations and Basis of Presentation.

(3) Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.

(4) Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period, which continue to exist at the end of the period.

(5) Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.

(6) Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

(7) Represents the removal of agreements from Level 3 recurring fair value measurements upon the NPNS-designation in June 2026, as further described in Note 1—Nature of Operations and Basis of Presentation.

Liquefaction Supply Derivatives

We hold Liquefaction Supply Derivatives, which are indexed to Henry Hub or other natural gas price indices. As of June 30, 2026, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 6 years.

The forward notional amount for the Liquefaction Supply Derivatives was approximately 3,483 TBtu and 5,028 TBtu as of June 30, 2026 and December 31, 2025, respectively. As of December 31, 2025, our Liquefaction Supply Derivatives included 1,381 TBtu that were designated as NPNS in June 2026, which resulted in these agreements being no longer accounted for as derivative instruments as of the designation date. See Note 1—Nature of Operations and Basis of Presentation for further discussion.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the effect and location of the Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations (in millions):

(1) Does not include the realized value associated with the Liquefaction Supply Derivatives that settle through physical delivery. Fair value fluctuations associated with our derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

(2) Includes gains and losses from the NPNS-designated agreements prior to the designation date, as further described in Note 1—Nature of Operations and Basis of Presentation.

The following table shows the fair value and location of the Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):

Consolidated Balance Sheets Presentation

The following table reconciles the fair value of our derivative assets and liabilities on a gross basis, by contract, to net amounts as presented on our Consolidated Balance Sheets after offsetting for any balances with the same counterparty under master netting arrangements or other relevant netting criteria under GAAP (in millions):

The table below shows the collateral balances that are recorded within other current assets, net and other current liabilities that are not otherwise offset against derivative assets and liabilities on our Consolidated Balance Sheets (in millions):

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 7—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):

NOTE 8—DEBT

Debt consisted of the following (in millions):

(1) Includes notes that amortize based on a fixed amortization schedule as set forth in their respective indentures.

(2) Issued in June 2026, pursuant to the same base indenture as the other CQP Senior Notes. The 2036 CQP Senior Notes and 2056 CQP Senior Notes are supplemented by the eleventh and twelfth supplemental indentures, respectively. See our annual report on Form 10-K for the fiscal year ended December 31, 2025 for additional information regarding the guarantee, security and redemption option of the CQP Senior Notes.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2026 (in millions):

(1) The margins on the interest rate, the commitment fees and the letter of credit fees are subject to change based on the applicable entity’s credit rating.

Restrictive Debt Covenants

The agreements governing our and SPL’s indebtedness contain customary terms and events of default and certain covenants that, among other things, may limit our and SPL’s ability to make certain investments or pay distributions. For example, SPL is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.

As of June 30, 2026, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

Total interest expense, net of capitalized interest, consisted of the following (in millions):

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our senior notes (in millions):

(1) Carrying amounts exclude unamortized discount and debt issuance costs.

(2) As of June 30, 2026 and December 31, 2025, $1.2 billion and $1.3 billion, respectively, of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of the fair value of our senior notes was classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The estimated fair value of any outstanding borrowings under our credit facilities approximates the principal amount outstanding because the interest rates are indexed to market rates and the debt may be repaid, in full or in part, at any time without penalty.

NOTE 9—REVENUES

The following table represents a disaggregation of revenue earned (in millions):

For the three and six months ended June 30, 2026 and 2025, we did not have any material revenue arrangements that were presented within our Consolidated Statements of Operations on a net basis.

Contract Liabilities

The following table reflects the changes in our contract liabilities, which are included in deferred revenue and other non-current liabilities on our Consolidated Balance Sheets (in millions):

The following table reflects the changes in our contract liabilities to affiliate, which are included in other current liabilities—affiliate and other non-current liabilities—affiliate on our Consolidated Balance Sheets (in millions):

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration, which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied:

(1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

The following potential future sources of revenue are omitted from the table above under exemptions we have elected: (1) all performance obligations that are part of a contract that has an original expected duration of one year or less and (2) substantially all variable consideration under our SPAs and TUAs that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price, and allocable to wholly unsatisfied future performance obligations or otherwise constrained, will vary based on (1) the future prices of the underlying variable index, primarily Henry Hub, throughout the contract terms, to the extent customers elect to take delivery of their LNG, (2) adjustments to the consumer price index and (3) the outcome of certain contingent events, including the achievement of milestones upon which delivery of LNG under certain contracts is conditioned.

The following table summarizes the percentage of variable consideration earned under contracts with customers included in the table above:

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):

(1) These arrangements were with a party who was partially owned by the investment management company that indirectly owns a portion of our limited partner interests, and, due to the sale of such interests by that entity effective May 13, 2025, this party is no longer considered a related party as of that date.

Assets and liabilities arising from the agreements with affiliates and other related parties referenced in the above table are classified as affiliate and related party, respectively, on our Consolidated Balance Sheets.

Disclosures relating to future consideration under revenue contracts with affiliates are included in Note 9—Revenues.

See our annual report on Form 10-K for the fiscal year ended December 31, 2025 for additional information regarding the agreements referenced in the above table, as well as a description of other agreements we have with our affiliates, including the Terminal Marine Services Agreement. Under this agreement, Tug Services distributed $3 million during both the three months ended June 30, 2026 and 2025 and $5 million and $4 million during the six months ended June 30, 2026 and 2025, respectively, to Cheniere Terminals, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Equity (Deficit).

NOTE 11—NET INCOME PER COMMON UNIT

Net income per common unit for a given period is based on the distributions we incur to the common unitholders with respect to earnings or losses of the reporting period plus an allocation of undistributed net income or loss based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions declared by us during the period are presented on the Consolidated Statements of Partners’ Equity (Deficit). On July 28, 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 with respect to the three months ended June 30, 2026. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.045 per unit.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The two-class method dictates that net income for a period be reduced by the amount of available cash that will be distributed with respect to that period and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to participating securities based on the distribution waterfall for available cash specified in the partnership agreement. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units and other participating securities on a pro rata basis based on provisions of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit in the current period even though cash distributions are not necessarily derived from current period earnings.

The following table provides a reconciliation of net income and the allocation of net income to the common units, the general partner units and IDRs for purposes of computing basic and diluted net income per unit (in millions, except per unit data). The amounts in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

(1) Represents distributions declared with respect to earnings of the respective period presented.

(2) Under our partnership agreement, the IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss).

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 12—SEGMENT INFORMATION AND CUSTOMER CONCENTRATION

We have determined that we operate as a single operating and reportable segment. The measure of profit and loss regularly provided to the chief operating decision maker (“CODM”) that is most consistent with GAAP is net income, as presented in our Consolidated Statements of Operations. This measure contributes to the CODM’s assessment of performance and resource allocation, which includes monitoring of budget versus actual results, establishing compensation and deciding on capital allocation priorities. Significant expenses regularly provided to the CODM, and included in the measure of profit and loss, are cost of sales, operating and maintenance expense and general and administrative expense, as reported in our Consolidated Statements of Operations. Also provided regularly to the CODM are changes in the fair value of our derivative instruments, which are inclusive of significant noncash items, which were $526 million in gains and $114 million in losses for the three and six months ended June 30, 2026, respectively, and $159 million and $119 million in gains for the same periods of 2025, respectively. Interest income, which is included in interest and dividend income on our Consolidated Statements of Operations, was $6 million and $9 million for the three and six months ended June 30, 2026, respectively, and $2 million and $6 million for the same periods of 2025, respectively.

The measure of segment assets is reported on our Consolidated Balance Sheets as total assets. Substantially all of our tangible long-lived assets, which consist of property, plant and equipment, are located in the U.S. Total expenditures for additions to long-lived assets are reported on our Consolidated Statements of Cash Flows.

The following table shows the concentration of our customer credit risk with 10% or more of total revenues from contracts with external customers and/or trade receivables, net of current expected credit losses and contract assets, net of current expected credit losses. Customers under common control are considered to be a single customer.

• Less than 10%

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of substantive cash flow information (in millions):

(1) Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

• 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

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.

The following table summarizes pre-FID development efforts and certain key milestones associated with the SPL Expansion Project:

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.

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.

Results of Operations

Volumes recognized as revenues

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

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-

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.

The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.

(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

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.

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.

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):

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):

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):

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:

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.

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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketing and Trading Commodity Price Risk

We have commodity contracts accounted for as derivative instruments which consist of natural gas supply contracts for the operation of the Liquefaction Project, excluding those contracts for which we have designated NPNS, as described in Note 1—Nature of Operations and Basis of Presentation, as well as the associated economic hedges (collectively, the “Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):

See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments.

ITEM 4. CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our general partner’s management, including our general partner’s Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are, and may in the future be, involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. There have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2025.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2025.

ITEM 5. OTHER INFORMATION

Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits the directors and executive officers of our general partner to enter into trading plans designed to comply with Rule 10b5-1. During the three-month period ended June 30, 2026, none of the executive officers or directors of our general partner adopted or terminated a Rule 10b5-1 trading plan or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

ITEM 6. EXHIBITS

* Filed herewith.

** Furnished herewith.