Cheniere Energy, Inc.

Results of Operations

Consolidated results of operations

Volumes loaded and recognized from the Liquefaction Projects(1)

(1)For certain delivered LNG sales, volumes recognized as revenue may differ from loaded volumes due to normal transit-related consumption and losses, including boil-off gas and vessel heel.

Components of LNG revenues and corresponding LNG volumes recognized

(1)Long-term agreements include agreements with an initial tenor of 12 months or more.

(2)Includes volumes sold under short-term agreements and a portion of volumes sold from natural gas procured under long-term IPM agreements.

(3)For certain delivered LNG sales, volumes recognized as revenue may differ from loaded volumes due to normal transit-related consumption and losses, including boil-off gas and vessel heel.

Net income attributable to Cheniere

Net income attributable to Cheniere increased by $121 million and decreased by $2.3 billion during the three and nine months ended September 30, 2026, respectively, as compared to the same periods of 2025.

The increase between the three month periods was primarily due to:

•$417 million increase in revenues, net of cost of sales and excluding changes in fair value of agreements accounted for as derivative instruments, from increased production volumes, largely due to additional Trains of the Corpus Christi Stage 3 Project in operation during 2026 as well as from the higher proportion of our cargoes sold at prices indexed to global LNG or natural gas benchmarks; and

•$135 million favorable change in income tax provision as further described below under the caption Income tax provision; partially offset by:

•$197 million total increase in operating and maintenance expense, depreciation expense and interest expense, net of capitalized interest, primarily as a result of additional Trains of the Corpus Christi Stage 3 Project in operation; and

•$142 million of unfavorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), primarily due to $654 million of favorable fair value changes recognized on our long-term IPM agreements in 2025 that did not recur in 2026 due to our NPNS designation in June 2026 because these agreements were no longer subject to recurring fair value measurement, as further described below, partially offset by $470 million of favorable fair value changes recognized between the periods on our derivatives related to financial positions to economically hedge the purchase and sale of physical LNG.

The decrease between the nine month periods was primarily due to:

•$3.6 billion of unfavorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely associated with our long-term IPM agreements prior to the NPNS designation in June 2026, as further described below. The changes in the fair value of our long-term IPM agreements reflected $2.3 billion of losses recognized in the nine months ended September 30, 2026 due, in part, to geopolitical uncertainties and instabilities discussed below in Significant factors affecting our results of operations, compared with $1.5 billion of gains recognized in the same period of 2025; and

•$411 million total increase in operating and maintenance expense, depreciation expense and interest expense, net of capitalized interest, primarily as a result of additional Trains of the Corpus Christi Stage 3 Project in operation; partially offset by:

•$1.3 billion increase in revenues, net of cost of sales and excluding changes in fair value of agreements accounted for as derivative instruments, from increased production volume due to additional Trains of the Corpus Christi Stage 3 Project in operation during 2026 as well as from contributions from optimization activities and the higher proportion of our cargoes sold at prices indexed to global LNG or natural gas benchmarks, and $370 million in certain excise tax credits recognized in the first quarter of 2026; and

•$657 million favorable change in income tax provision as further described below under the caption Income tax provision.

In June 2026, we designated the NPNS scope exception under Accounting Standards Codification Topic 815, Derivatives and Hedging, for certain IPM agreements providing for natural gas deliveries along the U.S. Gulf Coast. This designation comprised approximately 73% of total fixed minimum contractual IPM agreement volumes at the designation date. The remaining 27% of such total volumes was comprised of agreements for which deliveries occur upstream of our liquefaction facilities and were excluded from the NPNS designation. The NPNS 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. Following the NPNS designation, physical natural gas purchases under these agreements are no longer remeasured at fair value through earnings. Amounts are recognized under the applicable inventory and cost-of-sales guidance as the natural gas is received, consumed in the production process and the related LNG is sold. 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 attributable to Cheniere:

Revenues

The $1.7 billion and $3.2 billion increases in total revenues during the three and nine months ended September 30, 2026, respectively, as compared to the same periods of 2025 were primarily attributable to $1.4 billion and $3.3 billion increases in LNG revenues, respectively, due to higher volumes of LNG and higher pricing per MMBtu, primarily as a result of increased global LNG prices between both the three and nine month periods, and additionally due to an increase in U.S. natural gas prices between the nine month periods.

Operating costs and expenses

The $1.6 billion and $5.8 billion increases in total operating costs and expenses during the three and nine months ended September 30, 2026, respectively, as compared to the same periods of 2025 were primarily attributable to:

•$551 million and $3.5 billion, respectively, of unfavorable changes in the fair value of agreements accounted for as derivative instruments recognized in cost of sales, of which $598 million and $3.7 billion, respectively, related to the long-term IPM agreements designated as NPNS in June 2026, as further described above under the caption Net income attributable to Cheniere. The unfavorable variance between the three month periods was primarily attributable to favorable fair value changes recognized on these agreements in 2025 that did not recur following the NPNS designation, because these agreements were no longer subject to recurring fair value measurement. The unfavorable variance between the nine month periods also reflected losses recognized on these agreements prior to the NPNS designation in June 2026, compared with gains recognized in the same period of 2025, due in part to changes in global LNG pricing dynamics associated with geopolitical uncertainties and instabilities discussed below;

•$749 million and $2.1 billion increases, respectively, in the cost of natural gas feedstock, due to increased volume of LNG delivered between both the three and nine month periods, and additionally due to an increase in U.S. natural gas prices between the nine month periods;

•$93 million and $119 million increases, respectively, in operating and maintenance expense and $55 million and $167 million increases, respectively, in depreciation, amortization and accretion expense primarily as a result of additional Trains of the Corpus Christi Stage 3 Project in operation; partially offset by:

•$370 million reduction to cost of sales from the recognition of certain excise tax credits during the nine months ended September 30, 2026, as further discussed in the Liquidity and Capital Resources section of ourannual report on Form 10-K for the fiscal year ended December 31, 2025.

Income tax provision

The $135 million favorable variance in income tax provision during the three months ended September 30, 2026 as compared to the same period of 2025 was primarily attributable to the decrease in our effective tax rate, as further described below. The $657 million favorable variance in income tax provision during the nine months ended September 30, 2026 as compared to the same period of 2025 was primarily attributable to a lower income tax expense due to a $2.8 billion decrease in pre-tax income as well as the decrease in our effective tax rate, as further described below.

Our effective tax rate was 10.2% and 10.1% for the three and nine months ended September 30, 2026, respectively, as compared to 18.9% and 18.0% during the same periods of 2025, respectively. Our effective tax rate decreased between the comparable periods primarily due to a change in the proportion of our pre-tax income attributable to CQP, which is partially not taxable to us, and increased Foreign Derived Deduction Eligible Income(“FDDEI”)deduction. For all periods presented, the effective tax rate was lower than the 21.0% statutory rate primarily due to CQP’s income that is partially not taxable to us, with the FDDEI deduction further reducing the effective tax rate for the three and nine months ended September 30, 2026.

Net income attributable to NCI

Net income attributable to NCI during the three and nine months ended September 30, 2026 increased $69 million and $147 million, respectively, as compared to the same periods of 2025 due to $133 million and $286 million increases in CQP’s consolidated net income, respectively, primarily from higher margins from favorable pricing effects associated with LNG volumes delivered during the comparable periods, partially offset by unfavorable changes in the fair value of agreements accounted for as derivative instruments between the nine month periods.

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 qualify for, and we designate, an applicable scope exception under Accounting Standards Codification Topic 815, including the NPNS scope exception.

As discussed above under Net income attributable to Cheniere, we designated the NPNS scope exception in June 2026 for certain IPM agreements previously accounted for as derivative instruments. Those agreements are no longer subject to recurring fair value adjustments and the market-driven earnings variability will be mitigated for those contracts that would have otherwise been marked-to-market in the absence of such designation.

Conversely, commodity contracts accounted for as derivative instruments and for which we have not designated the NPNS exception remain subject to fair value accounting in which gains and losses arising from changes in fair value affect earnings. For such contracts, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 5—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of satisfaction of certain events. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

Commissioning volumes

Prior to substantial completion of a Train, amounts received from the sale of commissioning volumes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train and are necessary activities to bring the asset to the condition for its intended use. During the three and nine months ended September 30, 2026, we realized offsets to LNG terminal costs of $28 million and $106 million, respectively, corresponding to 3 and 12 TBtu, respectively, of LNG as compared to $47 million and $102 million, respectively, corresponding to 6 and 12 TBtu, respectively, of LNG in the same periods of 2025 that were related to the sale of commissioning volumes associated with the Corpus Christi Stage 3 Project.

Additional liquefaction capacities

The CCL Midscale Trains 8 & 9 Project is currently under construction and is expected to add approximately 5 mtpa of operational liquefaction capacity, inclusive of estimated debottlenecking opportunities, once all Trains reach substantial completion. As of September 30, 2026, all seven Trains of the Corpus Christi Stage 3 Project were in operation, while as of September 30, 2025, only the first two Trains of the Corpus Christi Stage 3 Project were in operation. The operation and maintenance of these Trains and increased LNG volumes produced are expected to result in higher revenues and operating costs and expenses. However, prior to the commencement of long-term SPAs associated with these volumes, the additional volumes will be sold by our integrated marketing function at prevailing market prices. Additionally, potential expansion projects that increase the amount of LNG volumes produced, including those discussed above in Disciplined Accretive Growth, would also be expected to result in higher revenues and operating costs and expenses.

Geopolitical uncertainties and instabilities

Global natural gas and LNG markets continue to experience supply constraints, liquefaction capacity limitations, shipping and transit disruptions affecting key global LNG trade routes and heightened geopolitical uncertainty in key producing and consuming regions. These conditions may contribute to continued volatility in global natural gas and LNG prices and fluctuations in regional price differentials. While our long-term contractual arrangements provide a significant degree of stability to our cash flows, a portion of our results remains exposed to changes in global natural gas and LNG prices and regional price differentials, including through LNG volumes sold under short-term agreements, optimization activities and certain derivative instruments. Accordingly, the extent to which favorable global LNG pricing and regional price differentials contributed to our results during 2026 may not recur in future periods, and changes in these market conditions could have either a favorable or unfavorable effect on our future results of operations and cash flows.

Business seasonality

Our quarterly results are affected by production levels, timing of our maintenance activities and the resulting availability of volumes. Therefore, operating profit may not be generated evenly throughout the year. Weather variations, including temperature, have an impact on LNG output at our Liquefaction Projects. Our Liquefaction Projects are capable of relatively higher production volumes during the cooler months as compared to the summer months. We typically perform our scheduled major maintenance activities at our sites during shoulder months in the second and third quarters in order to mitigate the impact to our annual operating results.