Cheniere Energy, Inc.

Results of Operations

Consolidated results of operations

Volumes loaded and recognized from the Liquefaction Projects

Components of LNG revenues and corresponding LNG volumes delivered

(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.

Net income (loss) attributable to Cheniere

Net income (loss) attributable to Cheniere increased by $1.4 billion and declined by $2.4 billion during the three and six months ended June 30, 2026, respectively, as compared to the same periods of 2025.

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

•$1.4 billion of favorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely associated with our long-term IPM agreements prior to the NPNS designation, as further described below, primarily due to narrowing spreads between global and U.S. domestic natural gas benchmarks and the easing of the global natural gas price volatility that began in the first quarter of 2026;

•$380 million increase in revenues, net of cost of sales and excluding changes in fair value of agreements accounted for as derivative instruments, from higher margins as a result of increased production volume, largely due to additional Trains of the Corpus Christi Stage 3 Project in operation during the three months ended June 30, 2026 compared to the same period in 2025, and from the relative portion of our cargoes sold that is subject to global LNG pricing; partially offset by:

•$303 million increase in net income attributable to NCI, as further described below under the caption Net income attributable to NCI.

The decline between the six month periods was primarily due to:

•$3.4 billion of unfavorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely associated with our long-term IPM agreements prior to the NPNS designation, as further described below, primarily attributable to elevated global natural gas price volatility influenced in part by the tightening supply conditions, transit constraints and heightened geopolitical uncertainties from the conflict and instabilities across parts of the Middle East during 2026, as well as widening spreads between global and U.S. domestic natural gas benchmarks; partially offset by:

•$522 million favorable change in income tax provision;

•$529 million increase in revenues, net of cost of sales and excluding changes in fair value of agreements accounted for as derivative instruments and $370 million in certain excise tax credits recognized in the first quarter of 2026, from higher margins from increased production volume due to additional Trains of the Corpus Christi Stage 3 Project in operation during the six months ended June 30, 2026 compared to the same period in 2025, as well as from contributions from optimization activities and the relative portion of our cargoes sold that is subject to global LNG pricing.

Continued tightening of global natural gas and LNG supply conditions, including upstream production constraints, liquefaction capacity limitations and shipping and transit disruptions in the Middle East, together with heightened geopolitical uncertainties in key producing and consuming regions, may result in sustained volatility in global natural gas and LNG prices. Such volatility, along with fluctuations in regional price differentials, could materially impact our results of operations, cash flows and financial condition, particularly from LNG sales under spot or short-term agreements indexed to global prices. Additionally, the potential impacts of sustained volatility in global natural gas and LNG prices may also affect the fair value of our agreements accounted for as derivatives, particularly those indexed to global natural gas benchmarks.

In June 2026, we designated the NPNS scope exception under Accounting Standards Codification Topic 815, Derivatives and Hedging, for certain IPM agreements providing for natural gas deliveries along the U.S. Gulf Coast. This designation comprised approximately 73% of total fixed minimum contractual IPM agreement volumes at the designation date. The remaining 27% of such total volumes was comprised of agreements for which deliveries occur upstream of our liquefaction facilities and were excluded from the NPNS designation. This exception is available for contracts that are expected to be physically settled and used or sold in the normal course of business, which is consistent with our intended purpose to consume the delivered physical natural gas to produce LNG. Our designation considered increased observable U.S. Gulf Coast third-party physical natural gas market activity involving contracts indexed to global LNG or natural gas prices, among other factors, in evaluating whether the pricing mechanism is consistent with the economics of the underlying physical market. As a result of this designation, these agreements are no longer accounted for as derivative instruments that are measured at fair value on a recurring basis. Instead, the agreements are accounted for on a delivery basis upon physical receipt of the natural gas. The estimated fair values of these agreements as of the designation date were established as the new cost basis and are being amortized into cost of sales on a systematic basis over the remaining expected terms of the agreements. Because recognition is based on the timing and volume of contract deliveries, the amounts recognized in any reporting period are expected to vary and are not expected to follow a linear pattern. These non-cash amounts reflect the amortization of deferred gains and losses established at the designation date rather than changes in current-period market prices. If it is determined that the contracts designated as NPNS no longer meet the scope exception, the contracts would be recorded at fair value and any gains and losses would be immediately recognized in earnings.

The following is an expanded discussion of the material drivers of the variance in net income (loss) attributable to Cheniere:

Revenues

The $1.1 billion and $1.5 billion increases in total revenues during the three and six months ended June 30, 2026, respectively, as compared to the same periods of 2025 were primarily attributable to:

•$1.2 billion and $2.5 billion increases, respectively, due to higher volumes of LNG delivered as LNG revenues between both the three and six month periods, and additionally due to an increase in U.S. natural gas prices between the six month periods, to which the majority of our long-term LNG sales contracts are indexed; partially offset by:

•$1.0 billion of unfavorable changes between the six month periods from the agreements accounted for as derivative instruments included in revenues, as further described above under the caption Net income (loss) attributable to Cheniere.

Operating costs and expenses

The $669 million decrease and $4.2 billion increase in total operating costs and expenses during the three and six months ended June 30, 2026, respectively, as compared to the same periods of 2025 were primarily attributable to:

•$944 million of favorable and $3.0 billion of unfavorable changes, respectively, in the fair value of agreements accounted for as derivative instruments included in cost of sales, primarily related to our long-term IPM agreements, of which $736 million of favorable and $3.1 billion of unfavorable changes, respectively, related to the changes in the fair value of NPNS-designated agreements prior to the designation date, as further described above under the caption Net income (loss) attributable to Cheniere;

•$161 million and $1.4 billion increases, respectively, in the cost of natural gas feedstock, largely due to increased volume of LNG delivered between both the three and six month periods and additionally due to an increase in U.S. natural gas prices between the six month periods;

•$51 million and $112 million increases, respectively, in depreciation, amortization and accretion expense, primarily as a result of the substantial completions of the first six Trains of the Corpus Christi Stage 3 Project; and,

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

Income tax provision

The $60 million favorable variance in income tax provision during the three months ended June 30, 2026 as compared to the same period of 2025 was primarily attributable to the decrease in our effective tax rate, as further described below, partially offset by a higher income tax expense due to a $1.7 billion increase in pre-tax income. The $522 million favorable variance in income tax provision during the six months ended June 30, 2026 as compared to the same period of 2025 was primarily attributable to a lower income tax expense due to a $2.9 billion decrease in pre-tax income as well as the decrease in our effective tax rate, as further described below.

Our effective tax rate was 9.1% and 9.8% for the three and six months ended June 30, 2026, respectively, as compared to 18.3% and 17.6% during the same periods of 2025, respectively. Our effective tax rate decreased between the comparable periods primarily due to the proportion of pre-tax income attributable to CQP, which is partially not taxable to us, and increased

Foreign Derived Deduction Eligible Income deduction. The effective tax rate for all periods was lower than the statutory rate of 21.0% primarily due to CQP’s income that is partially not taxable to us.

Net income attributable to NCI

The $303 million and $78 million increases in net income attributable to NCI during the three and six months ended June 30, 2026, respectively, as compared to the same periods of 2025 were primarily attributable to $608 million and $153 million increases in CQP’s consolidated net income primarily from favorable changes in the fair value of agreements accounted for as derivative instruments between the three month periods and increases in revenue, net of cost of natural gas feedstock and excluding changes in fair value of agreements accounted for as derivative instruments.

Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements, unless they satisfy criteria for, and we designate, the normal purchases and normal sales exception which applies the accrual method of accounting.

As noted above under Net income (loss) attributable to Cheniere, due to our designation of the NPNS exception in June 2026 for certain IPM agreements previously accounted for as derivative instruments, future earnings volatility resulting from fair value market adjustments will be mitigated for those contracts that would have otherwise been marked-to-market in the absence of such designation.

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

Commissioning volumes

Prior to substantial completion of a Train, amounts received from the sale of commissioning volumes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train and are necessary activities to bring the asset to the condition for its intended use. During the three and six months ended June 30, 2026, we realized offsets to LNG terminal costs of $31 million and $78 million, respectively, corresponding to 3 and 9 TBtu, respectively, of LNG as compared to $7 million and $55 million, respectively, corresponding to 1 and 6 TBtu, respectively, of LNG in the same periods of 2025 that were related to the sale of commissioning volumes associated with the Corpus Christi Stage 3 Project.

Additional liquefaction capacities

The Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project are currently under construction and are expected to add over 15 mtpa of operational liquefaction capacity, inclusive of estimated debottlenecking opportunities, once all Trains reach substantial completion, of which over 6 mtpa is still under construction as of June 30, 2026. As of June 30, 2026, the first six Trains of the Corpus Christi Stage 3 Project were in operation, while as of June 30, 2025, only the first Train of the Corpus Christi Stage 3 Project was in operation. The operation and maintenance of these Trains and increased LNG volumes produced are expected to result in higher revenues and operating costs and expenses. However, prior to the commencement of long-term SPAs associated with these volumes, the additional volumes will be sold by our integrated marketing function at prevailing market prices. Additionally, potential expansion projects that increase the amount of LNG volumes produced, including those discussed above in Disciplined Accretive Growth, would also be expected to result in higher revenues and operating costs and expenses.

Business Seasonality

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