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We operate natural gas liquefaction and export facilities located in Cameron Parish, Louisiana at Sabine Pass and near Corpus Christi, Texas (respectively, the “Sabine Pass LNG Terminal” and “Corpus Christi LNG Terminal”), with total expected production capacity of over 60 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which over 6 mtpa was under construction and the remainder was in operation as of June 30, 2026, comprised of the following:

•over 30 mtpa of total production capacity in operation from natural gas liquefaction facilities at the Sabine Pass LNG Terminal owned by CQP (the “SPL Project”). The Sabine Pass LNG Terminal also has five LNG storage tanks, vaporizers and three marine berths. CQP also owns and operates 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”). As of June 30, 2026, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP.

•over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including over 6 mtpa under construction and the remainder in operation as of June 30, 2026, from our natural gas liquefaction facilities at the Corpus Christi LNG Terminal, of which we have 100% ownership interest. The Corpus Christi LNG Terminal also has three LNG storage tanks and two marine berths. We also own an approximately 21-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several large interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”). The projects under construction at the Corpus Christi LNG Terminal include:

◦a project consisting of seven midscale Trains that is expected to add total production capacity of over 10 mtpa of LNG once fully completed (the “Corpus Christi Stage 3 Project”), with over 1 mtpa under construction and the remainder in operation from the first six midscale Trains that have reached substantial completion as of June 30, 2026; and

◦a project consisting of two additional midscale Trains that is expected to add total production capacity of approximately 5 mtpa of LNG once fully completed, inclusive of estimated debottlenecking opportunities (the “CCL Midscale Trains 8 & 9 Project” and together with the existing assets at the Corpus Christi LNG Terminal, the Corpus Christi Stage 3 Project and the Corpus Christi Pipeline, the “CCL Project”), which was under construction as of June 30, 2026.

In addition to the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”), we are developing expansion projects to provide additional liquefaction capacity at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal and are commercializing to support the additional liquefaction capacity associated with these potential expansion projects. At the Sabine Pass LNG Terminal, we are developing a two-phased expansion adjacent to the SPL 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”). 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. These projects 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 our board of directors (our “Board”) makes a positive FID.

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere 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.

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Accounting for Derivative Instruments

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.

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

New Consolidated Balance Sheet Location						Amount Reclassified
Other current assets						$	68
Deferred NPNS assets						2,195
Current portion of deferred NPNS liabilities						(174)
Deferred NPNS liabilities						(1,740)
Total deferred NPNS assets and liabilities						$	349

The following table presents management’s current estimated net gains (losses) 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:

Years Ending December 31,			Estimated gain (loss) from amortization of deferred NPNS assets and liabilities
2026 (1)			$	56
2027			100
2028			101
2029			85
2030			56
Thereafter			(747)
Total estimated amortization			$	(349)

(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 $1.8 billion and $(2.2) billion of derivative gains (losses) during the three and six months ended June 30, 2026, respectively, and derivative gains of $1.0 billion and $929 million for the same periods of 2025, respectively, for the designated agreements.

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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.

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

						June 30,						December 31,
						2026						2025
Trade receivables
SPL and CCL						$	554					$	755
Cheniere Marketing						662						472
Other subsidiaries						12						10
Total trade receivables						1,228						1,237
Other receivables
SPL and CCL						37						54
Other subsidiaries						70						89
Total other receivables						107						143
Total trade and other receivables, net of current expected credit losses						$	1,335					$	1,380

Upon collection of our receivables by SPL and CCL, cash will be immediately restricted for the payment of liabilities related to the Liquefaction Projects.

Inventory consisted of the following (in millions):

						June 30,						December 31,
						2026						2025
Materials						$	291					$	275
LNG in-transit						256						102
LNG						120						84
Natural gas						23						33
Other						33						30
Total inventory						$	723					$	524

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

									June 30,						December 31,
									2026						2025
Terminal and related assets
Terminal and interconnecting pipeline facilities									$	40,426					$	38,422
Land									905						745
Construction-in-process									3,529						4,096
Accumulated depreciation									(9,102)						(8,434)
Total terminal and related assets, net of accumulated depreciation									35,758						34,829
Fixed assets and other assets
Fixed assets and other assets									265						260
Accumulated depreciation									(202)						(195)
Total fixed assets and other assets, net of accumulated depreciation									63						65
Assets under finance leases
Marine assets									1,605						1,060
Accumulated depreciation									(272)						(199)
Total assets under finance leases, net of accumulated depreciation									1,333						861
Property, plant and equipment, net of accumulated depreciation									$	37,154					$	35,755

The following table shows depreciation expense and offsets to terminal assets (in millions):

						Three Months Ended June 30,												Six Months Ended June 30,
						2026						2025						2026						2025
Depreciation expense						$	378					$	327					$	749					$	636
Sales proceeds earned from commissioning sales of LNG offset to terminal assets (1)						31						7						78						55

(1)We realize offsets to terminal assets for sales proceeds from commissioning volumes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

We have the following contracts accounted for as derivative instruments:

•commodity contracts consisting of the following (collectively, “Commodity Derivatives”):

◦natural gas and power supply contracts, including certain of our long-term IPM agreements for which we have not designated as NPNS, as described in Note 1—Nature of Operations and Basis of Presentation, for the development, commissioning and operation of the Liquefaction Projects and expansion projects, as well as the associated economic hedges (collectively, the “Liquefaction Supply Derivatives”); and,

◦LNG contracts in which we have contractual net settlement and economic hedges on the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”); and

•Foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with cash flows denominated in currencies other than U.S. dollar (“FX Derivatives”), associated with both LNG Trading Derivatives and operations in countries outside of the U.S.

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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):

			Fair Value Measurements as of
			June 30, 2026																								December 31, 2025
			Quoted Prices in Active Markets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs (Level 3)						Total						Quoted Prices in Active Markets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs (Level 3)						Total
Liquefaction Supply Derivatives asset (liability) (1)			$	—					$	(51)					$	306					$	255					$	—					$	(37)					$	2,902					$	2,865
LNG Trading Derivatives liability			—						(57)						—						(57)						—						(17)						—						(17)
FX Derivatives asset (liability)			—						15						—						15						—						(2)						—						(2)

(1)As described in Note 1—Nature of Operations and Basis of Presentation, in June 2026, we designated the NPNS scope exception for certain 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 an asset of $2.5 billion as of December 31, 2025.

We value the Liquefaction Supply Derivatives and LNG Trading Derivatives using a market or option-based approach incorporating present value techniques, as needed, which incorporates observable commodity price curves, when available, and other relevant data. We value our FX Derivatives with a market approach using observable FX rates 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. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility 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. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.

In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility includes the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control. As applicable to our natural gas supply contracts, 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, 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.

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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 and international LNG prices. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of June 30, 2026:

Net Fair Value Asset (in millions)

Valuation Approach

Significant Unobservable Input

Range of Significant Unobservable Inputs / Weighted Average (1)

Liquefaction Supply Derivatives

$306

Market approach incorporating present value techniques

Henry Hub basis spread

$(2.663) - $0.195 / $(0.120)

Option pricing model

International LNG pricing spread, relative to Henry Hub (2)

85% - 362% / 188%

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

(2)Spread contemplates U.S. dollar-denominated pricing.

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

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

						Three Months Ended June 30,												Six Months Ended June 30,
						2026						2025						2026						2025
Balance, beginning of period						$	(1,663)					$	(1,415)					$	2,902					$	(801)
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)						1,849						1,204						(2,533)						389
Included in cost of sales, new deals (3)						18						7						14						4
Purchases and settlements:
Purchases (4)						—						—						—						—
Settlements (5)						451						194						272						400
Transfers out of level 3 (6)						—						—						—						(2)
Agreements designated as NPNS and no longer measured at fair value on a recurring basis (7)						(349)						—						(349)						—
Balance, end of period						$	306					$	(10)					$	306					$	(10)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period						$	471					$	1,211					$	(261)					$	393

(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.

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Commodity Derivatives

We hold Liquefaction Supply Derivatives, which are indexed to Henry Hub, global LNG or other natural gas price indices. As of June 30, 2026, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence or accelerate upon the satisfaction of certain events.

Cheniere Marketing has historically entered into, and may from time to time enter into, LNG transactions that provide for contractual net settlement. Such transactions are accounted for as LNG Trading Derivatives along with financial commodity contracts in the form of swaps or futures. The terms of LNG Trading Derivatives range up to approximately one year.

The following table shows the notional amounts of our Commodity Derivatives:

June 30, 2026

December 31, 2025

Liquefaction Supply Derivatives (1)

LNG Trading Derivatives

Liquefaction Supply Derivatives (1) (2)

LNG Trading Derivatives

Notional amount, net (in TBtu)

7,749

14

12,218

39

(1)Inclusive of amounts under contracts that commence or accelerate upon the satisfaction of certain events and exclusive of unexercised extension options as of both June 30, 2026 and December 31, 2025.

(2)Includes 4,266 TBtu of Liquefaction Supply Derivatives 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.

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

									Gain (Loss) Recognized in Consolidated Statements of Operations
			Consolidated Statements of Operations Location (1)						Three Months Ended June 30,												Six Months Ended June 30,
									2026						2025						2026						2025
LNG Trading Derivatives			LNG revenues						$	41					$	150					$	(764)					$	277
LNG Trading Derivatives			Cost of sales						(7)						(42)						(30)						3
Liquefaction Supply Derivatives (2)			LNG revenues						1						1						1						2
Liquefaction Supply Derivatives (2) (3)			Cost of sales						2,306						1,438						(2,346)						737

(1)Fair value fluctuations associated with activities of our Commodity Derivatives are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

(2)Does not include the realized value associated with the Liquefaction Supply Derivatives that settle through physical delivery.

(3)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.

FX Derivatives

Cheniere Marketing holds FX Derivatives to protect against the volatility in future cash flows attributable to changes in international currency exchange rates. The FX Derivatives are executed primarily to economically hedge the foreign currency exposure arising from cash flows expended for both physical and financial LNG transactions that are denominated in a currency other than the U.S. dollar. The terms of FX Derivatives range up to approximately one year.

The total notional amount of our FX Derivatives was $403 million and $783 million as of June 30, 2026 and December 31, 2025, respectively.

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

									Gain (Loss) Recognized in Consolidated Statements of Operations
			Consolidated Statements of Operations Location						Three Months Ended June 30,												Six Months Ended June 30,
									2026						2025						2026						2025
FX Derivatives			LNG revenues						$	(2)					$	(50)					$	21					$	(61)

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

			June 30, 2026
			Liquefaction Supply Derivatives						LNG Trading Derivatives						FX Derivatives						Total
Consolidated Balance Sheets Location
Current derivative assets			$	123					$	17					$	16					$	156
Derivative assets			735						—						—						735
Total derivative assets			858						17						16						891
Current derivative liabilities			(304)						(72)						(1)						(377)
Derivative liabilities			(299)						(2)						—						(301)
Total derivative liabilities			(603)						(74)						(1)						(678)
Derivative asset (liability), net			$	255					$	(57)					$	15					$	213
			December 31, 2025
			Liquefaction Supply Derivatives						LNG Trading Derivatives						FX Derivatives						Total
Consolidated Balance Sheets Location
Current derivative assets			$	7					$	1					$	1					$	9
Derivative assets			4,663						—						—						4,663
Total derivative assets			4,670						1						1						4,672
Current derivative liabilities			(597)						(18)						(3)						(618)
Derivative liabilities			(1,208)						—						—						(1,208)
Total derivative liabilities			(1,805)						(18)						(3)						(1,826)
Derivative asset (liability), net			$	2,865					$	(17)					$	(2)					$	2,846

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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):

						Liquefaction Supply Derivatives						LNG Trading Derivatives						FX Derivatives
As of June 30, 2026
Gross assets						$	1,257					$	38					$	18
Offsetting amounts						(399)						(21)						(2)
Net assets (1)						$	858					$	17					$	16
Gross liabilities						$	(639)					$	(98)					$	(1)
Offsetting amounts						36						24						—
Net liabilities (2)						$	(603)					$	(74)					$	(1)
As of December 31, 2025
Gross assets						$	5,688					$	2					$	2
Offsetting amounts						(1,018)						(1)						(1)
Net assets (1)						$	4,670					$	1					$	1
Gross liabilities						$	(1,855)					$	(54)					$	(5)
Offsetting amounts						50						36						2
Net liabilities (2)						$	(1,805)					$	(18)					$	(3)

(1)Includes current and non-current derivative assets of $156 million and $735 million, respectively, as of June 30, 2026 and $9 million and $4,663 million, respectively, as of December 31, 2025.

(2)Includes current and non-current derivative liabilities of $377 million and $301 million, respectively, as of June 30, 2026 and $618 million and $1,208 million, respectively, as of December 31, 2025.

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

			Consolidated Balance Sheets Location						June 30,						December 31,
									2026						2025
Liquefaction Supply Derivatives			Margin deposits						$	19					$	20
Liquefaction Supply Derivatives			Other current liabilities						—						(3)
LNG Trading Derivatives			Margin deposits						107						56
LNG Trading Derivatives			Other current liabilities						—						(5)

Our consolidated VIEs’ assets and liabilities related to CQP as of June 30, 2026 and substantially all related to CQP as of December 31, 2025. We own a 48.6% limited partner interest in CQP, and we also own all of the 2% general partner interest and 100% of the incentive distribution rights in CQP. The remaining 49.4% non-controlling limited partner interest in CQP is held by affiliates of Blackstone Inc. and Brookfield Asset Management, Inc. as well as the public.

In January 2026, we redeemed the remaining redeemable NCI in our other consolidated VIE that owns the Gregory Power Plant, a natural gas-fired combined cycle facility located in San Patricio County, Texas.

The following table presents the summarized consolidated assets and liabilities (in millions) of our consolidated VIEs, which are included in our Consolidated Balance Sheets. The assets in the table below may only be used to settle obligations of the respective VIEs. In addition, there is no recourse to us for the consolidated VIEs’ liabilities. The assets and liabilities in the

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table below exclude intercompany balances between the respective VIEs and Cheniere that eliminate in our Consolidated Financial Statements.

						June 30,						December 31,
						2026						2025
ASSETS
Current assets
Cash and cash equivalents						$	443					$	182
Restricted cash and cash equivalents						23						22
Trade and other receivables, net of current expected credit losses						349						512
Inventory						165						186
Current derivative assets						3						—
Margin deposits						10						11
Prepaid expenses						62						42
Other current assets, net						3						13
Total current assets						1,058						968
Property, plant and equipment, net of accumulated depreciation						15,034						15,397
Operating lease assets						74						77
Deferred NPNS assets						669						—
Derivative assets						5						541
Other non-current assets, net						374						287
Total assets						$	17,214					$	17,270
LIABILITIES
Current liabilities
Accounts payable						$	82					$	58
Accrued liabilities						693						1,000
Current debt, net of unamortized discount and debt issuance costs						109						306
Deferred revenue						102						119
Current operating lease liabilities						5						5
Current portion of deferred NPNS liabilities						103						—
Current derivative liabilities						93						164
Other current liabilities						9						11
Total current liabilities						1,196						1,663
Long-term debt, net of unamortized discount and debt issuance costs						14,335						14,161
Operating lease liabilities						71						73
Deferred NPNS liabilities						1,081						—
Derivative liabilities						27						900
Other non-current liabilities						149						159
Total liabilities						$	16,859					$	16,956

 

Accrued liabilities consisted of the following (in millions): 

						June 30,						December 31,
						2026						2025
Natural gas purchases						$	905					$	1,209
Terminal and related asset costs						224						306
Interest costs and related debt fees						215						219
Compensation and benefits						163						215
Tax-related liabilities						103						90
Other accrued liabilities						66						42
Total accrued liabilities						$	1,676					$	2,081

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Debt consisted of the following (in millions): 

						June 30,						December 31,
						2026						2025
SPL:
Senior Secured Notes:
5.875% due 2026						$	—					$	200
5.00% due 2027						—						1,500
4.200% due 2028						1,350						1,350
4.500% due 2030						2,000						2,000
due 2037 with weighted average rate of 4.748% and 4.747% at June 30, 2026 and December 31, 2025, respectively (1)						1,677						1,730
Total SPL Senior Secured Notes						5,027						6,780
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)						—						—
Total debt - SPL						5,027						6,780
CQP:
Senior Notes:
4.500% due 2029						1,500						1,500
4.000% due 2031						1,500						1,500
3.25% due 2032						1,200						1,200
5.950% due 2033						1,400						1,400
5.750% due 2034						1,200						1,200
5.550% due 2035						1,000						1,000
5.350% due 2036 (the “2036 CQP Senior Notes”) (2)						1,000						—
6.050% due 2056 (the “2056 CQP Senior Notes”) (2)						750						—
Total CQP Senior Notes						9,550						7,800
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)						—						—
Total debt - CQP						9,550						7,800
CCH:
Senior Secured Notes:
5.125% due 2027						1,201						1,201
3.700% due 2029						1,125						1,125
3.788% weighted average rate due 2039 (1)						2,539						2,539
Total CCH Senior Secured Notes						4,865						4,865
Term loan facility agreement (the “CCH Credit Facility”)						—						550
Working capital facility agreement (the “CCH Working Capital Facility”)						—						—
Revolving credit agreement (the “CCH Revolving Credit Facility”)						65						—
Total debt - CCH						4,930						5,415
Cheniere:
Senior Notes:
4.625% due 2028						1,500						1,500
5.650% due 2034						1,500						1,500
5.200% due 2036 (the “2036 Cheniere Senior Notes”) (3)						1,000						—
6.000% due 2056 (the “2056 Cheniere Senior Notes”) (3)						750						—
Total Cheniere Senior Notes						4,750						3,000
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)						—						—
Total debt - Cheniere						4,750						3,000
Total debt						24,257						22,995
Current debt, net of unamortized discount and debt issuance costs (1)						(1,411)						(306)
Unamortized discount and debt issuance costs						(214)						(182)
Total long-term debt, net of unamortized discount and debt issuance costs						$	22,632					$	22,507

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

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(2)Issued in June 2026, pursuant to the same base indenture as the other CQP Senior Notes, supplemented by the eleventh and twelfth supplemental indentures for the 2036 CQP Senior Notes and 2056 CQP Senior Notes, 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.

(3)Issued in March 2026, pursuant to a base indenture dated as of the issuance date, supplemented by the first and second supplemental indentures for the 2036 Cheniere Senior Notes and 2056 Cheniere Senior Notes, 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 CEI Senior Notes.

Credit Facilities

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

																								SPL Revolving Credit Facility						CQP Revolving Credit Facility						CCH Credit Facility (2)						CCH Revolving Credit Facility (4)						Cheniere Revolving Credit Facility (5)
Total facility size																								$	1,000					$	1,000					$	3,260					$	1,000					$	1,250
Incremental commitments																								—						—						—						—						500
Less:
Outstanding balance																								—						—						—						65						—
Commitments prepaid or terminated																								—						—						1,750						—						—
Letters of credit issued																								129						—						—						110						—
Available commitment																								$	871					$	1,000					$	1,510					$	825					$	1,750
Priority ranking																								Senior secured						Senior unsecured						Senior secured						Senior secured						Senior unsecured
Interest rate on available balance (1)																								SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%						SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%						SOFR plus credit spread adjustment of 0.1%, plus margin of 1.5% or base rate plus 0.5%						SOFR plus margin of 0.75% - 1.5% or base rate plus 0.0% - 0.5%						SOFR plus margin of 1.075% - 2.00% or base rate plus 0.075% - 1.00%
Commitment fees on undrawn balance (1)																								0.075% - 0.30%						0.10% - 0.30%						0.525%						0.06% - 0.20%						0.090% - 0.300%
Letter of credit fees (1)																								1.0% - 1.75%						1.125% - 2.0%						N/A						0.75% - 1.5%						1.075% - 2.00%
Maturity date																								June 23, 2028						June 23, 2028						(3)						June 26, 2031						August 1, 2031

(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. The interest rate and the commitment fees of the Cheniere Revolving Credit Facility are also based on the achievement of certain methane emissions management standards.

(2)During the six months ended June 30, 2026, we prepaid $550 million of outstanding borrowings under the CCH Credit Facility using proceeds from the issuance of the 2036 Cheniere Senior Notes and 2056 Cheniere Senior Notes and canceled $1.2 billion of unused commitments. In June 2026, CCH entered into an amendment to the CCH Credit Facility to, among other things, extend the availability period for disbursements of term loans to the later of the Corpus Christi Stage 3 Project completion date and December 31, 2027.

(3)The CCH Credit Facility matures the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project.

(4)In June 2026, CCH entered into the CCH Revolving Credit Facility, which amended and restated the CCH Working Capital Facility to, among other things, decrease the aggregate commitments by $500 million, extend the maturity date by approximately four years and reduce the rates applicable to our interest and fees.

(5)In June 2026, we entered into a Commitment Increase and Maturity Extension Agreement for the Cheniere Revolving Credit Facility to increase the aggregate commitments by $500 million and extend the maturity date by one year.

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Restrictive Debt Covenants

The agreements governing our and our subsidiaries’ indebtedness contain customary terms and events of default and certain covenants that, among other things, may limit our and our subsidiaries’ ability to make certain investments or pay dividends or distributions. For example, SPL and CCH are restricted from making distributions under agreements governing their respective 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 were, and each of our subsidiaries was, 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):

						Three Months Ended June 30,												Six Months Ended June 30,
						2026						2025						2026						2025
Total interest cost						$	329					$	298					$	639					$	593
Capitalized interest						(42)						(61)						(97)						(127)
Total interest expense, net of capitalized interest						$	287					$	237					$	542					$	466

Fair Value Disclosures

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

						June 30, 2026												December 31, 2025
						Carrying Amount (1)						Estimated Fair Value (2)						Carrying Amount (1)						Estimated Fair Value (2)
Senior notes						$	24,192					$	23,839					$	22,995					$	22,313

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

(2)As of June 30, 2026 and December 31, 2025, $3.0 billion and $3.1 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.

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.

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We are the lessee of LNG vessels leased under time charters (“vessel charters”) as well as tug vessels, office space and facilities, land sites and equipment.

Future annual minimum lease payments for operating and finance leases as of June 30, 2026 are as follows (in millions): 

Years Ending December 31,			Operating Leases						Finance Leases
2026			$	355					$	103
2027			626						205
2028			425						207
2029			315						208
2030			300						208
Thereafter			1,027						958
Total lease payments (1)			3,048						1,889
Less: Interest			(535)						(476)
Present value of lease liabilities			$	2,513					$	1,413

(1)Does not include approximately $6.0 billion of legally binding minimum payments for leases executed as of June 30, 2026 that will commence in future periods, consisting primarily of vessel charters, with fixed minimum lease terms of up to 15 years.

The following table shows the weighted-average remaining lease term and the weighted-average discount rate for our operating leases and finance leases:

			June 30, 2026												December 31, 2025
			Operating Leases						Finance Leases						Operating Leases						Finance Leases
Weighted-average remaining lease term (in years)			7.1						9.6						7.4						8.5
Weighted-average discount rate (1)			5.2%						6.2%						5.2%						6.6%

(1)The weighted average discount rate is impacted by certain finance leases that commenced prior to the adoption of the current leasing standard under GAAP. In accordance with previous accounting guidance, the implied rate is based on the fair value of the underlying assets.

The following table includes other quantitative information for our operating and finance leases (in millions):

			Six Months Ended June 30,
			2026						2025
Right-of-use assets obtained in exchange for operating lease liabilities			$	93					$	402
Right-of-use assets obtained in exchange for finance lease liabilities			545						472

LNG Vessel Subleases

We sublease certain LNG vessels under charter to third parties while retaining our existing obligation to the original lessor. All of our sublease arrangements have been assessed as operating leases. The following table shows the sublease income recognized in other revenues on our Consolidated Statements of Operations (in millions):

						Three Months Ended June 30,												Six Months Ended June 30,
						2026						2025						2026						2025
Fixed income						$	4					$	18					$	24					$	41
Variable income						7						10						39						22
Total sublease income						$	11					$	28					$	63					$	63

As of June 30, 2026, the aggregate future annual minimum sublease payment to be received from LNG vessel subleases was $2 million and is expected to be received during the remainder of the year ending December 31, 2026.

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

						Three Months Ended June 30,												Six Months Ended June 30,
						2026						2025						2026						2025
Revenues from contracts with customers
LNG revenues (excluding net derivative gain (loss) below)						$	5,600					$	4,414					$	12,104					$	9,602
Regasification revenues						34						34						68						68
Other revenues (1)						43						59						91						126
Total revenues from contracts with customers						5,677						4,507						12,263						9,796
Net derivative gain (loss) (see Note 5)						40						101						(742)						218
Sublease income (see Note 9)						11						28						63						63
Other revenues						4						5						16						8
Total revenues						$	5,732					$	4,641					$	11,600					$	10,085

(1)Includes revenues from LNG vessel subcharters that do not qualify as leases for accounting purposes.

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 Assets and Liabilities

The following table shows our contract assets, net of current expected credit losses, which are included in other current assets, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):

						June 30,						December 31,
						2026						2025
Contract assets, net of current expected credit losses						$	449					$	424

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):

						Six Months Ended June 30, 2026
Balance, beginning of period						$	272
Cash received but not yet recognized in revenue						94
Revenue recognized from prior period deferral						(133)
Balance, end of period						$	233

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:

						June 30, 2026												December 31, 2025
						Unsatisfied Transaction Price (in billions)						Weighted Average Recognition Timing (years) (1)						Unsatisfied Transaction Price (in billions)						Weighted Average Recognition Timing (years) (1)
LNG revenues						$	109.9					9						$	107.7					8
Regasification revenues						0.3						2						0.4						2
Total revenues						$	110.2											$	108.1

(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.

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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:

			Three Months Ended June 30,												Six Months Ended June 30,
			2026						2025						2026						2025
LNG revenues			72		%				66		%				74		%				69		%
Regasification revenues			8		%				8		%				8		%				8		%

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):

			Three Months Ended June 30,												Six Months Ended June 30,
			2026						2025						2026						2025
Other revenues
Operating agreement and construction management agreement with equity method investee (1)			$	—					$	—					$	—					$	1
Operating and maintenance expense
Natural gas transportation and storage agreements with equity method investees (1)			11						8						19						16
Natural gas transportation and storage agreements with other related party (2)			—						13						—						28

(1)On February 13, 2025, we sold all of our equity interests in one of our equity method investments to a third party. Additionally, we assigned certain operating and construction management agreements to the purchaser of such interests. Included in the table above are $1 million of other revenues and $1 million of operating and maintenance expense from the investee during the six months ended June 30, 2025.

(2)These arrangements were with a party that was related to the entity that indirectly owns a portion of CQP’s limited partner interests. 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.

We had a related party balance of $4 million and $3 million that was recorded within accrued liabilities on our Consolidated Balance Sheets as of June 30, 2026 and December 31, 2025, respectively.

We recorded an income tax provision of $366 million and $25 million during the three and six months ended June 30, 2026, respectively, and an income tax provision of $426 million and $547 million for the same periods of 2025, which was calculated using the annual effective tax rate method.

Our effective tax rate was 9.1% and 9.8% during the three and six months ended June 30, 2026, respectively, as compared to 18.3% and 17.6% for the same periods of 2025. 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

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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.

We utilize the two-class method for computing earnings per share, which requires an allocation of earnings as if all earnings were distributed during the period to the common stockholders and participating securities. The redeemable NCI that was held by a third party in one of our consolidated VIEs was considered participating because, under certain circumstances, it was redeemable for cash at a return. Therefore, the accretion of the redeemable NCI to its redemption value, net of tax, which was recognized as a deemed dividend within retained earnings, was deducted from net income (loss) in computing net income (loss) per share attributable to common stockholders. As described in Note 6—Non-Controlling Interests and Variable Interest Entities, in January 2026, we redeemed the remaining redeemable NCI in this VIE.

The following table provides a reconciliation of net income attributable to common stockholders and basic and diluted weighted average common shares outstanding (in millions, except per share data):

						Three Months Ended June 30,												Six Months Ended June 30,
						2026						2025						2026						2025
Net income (loss) attributable to Cheniere						$	3,068					$	1,626					$	(434)					$	1,979
Less: accretion of redeemable NCI, net of tax						—						3						2						5
Net income (loss) attributable to common stockholders						$	3,068					$	1,623					$	(436)					$	1,974
Weighted average common shares outstanding:
Basic						209.0						221.8						209.7						222.6
Dilutive unvested stock (1)						0.5						0.5						—						0.6
Diluted						209.5						222.3						209.7						223.2
Net income (loss) per share attributable to common stockholders—basic (2)						$	14.68					$	7.32					$	(2.08)					$	8.87
Net income (loss) per share attributable to common stockholders—diluted (2)						$	14.65					$	7.30					$	(2.08)					$	8.85

(1)Potentially dilutive securities that were not included in the diluted net loss per share computation for the six months ended June 30, 2026 were 0.5 million shares of unvested stock, because their effects would have been anti-dilutive.

(2)Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

On July 28, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on August 18, 2026 to stockholders of record as of the close of business on August 10, 2026.

The following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):

			Three Months Ended June 30,												Six Months Ended June 30,
			2026						2025						2026						2025
Total shares repurchased			2.23						1.41						4.88						3.01
Weighted average price paid per share			$	246.35					$	217.38					$	222.59					$	218.22
Total cost of repurchases (1)			$	550					$	306					$	1,087					$	656

(1)Amount excludes associated commission fees and excise taxes incurred, which are excluded costs under the repurchase program.

In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. As of June 30, 2026, we had approximately

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$9.1 billion remaining under our share repurchase program. Under the share repurchase authorization, repurchases can be made from time to time using a variety of methods, which may include open market purchases, privately negotiated transactions or otherwise, all in accordance with the rules of the Securities and Exchange Commission and other applicable legal requirements. The timing and amount of any shares of Cheniere’s common stock that are repurchased under the share repurchase authorization will be determined by Cheniere’s management based on market conditions and other factors. The share repurchase authorization does not obligate Cheniere to acquire any particular amount of common stock, and may be modified, suspended or discontinued at any time or from time to time at Cheniere’s discretion.

 

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 (loss) attributable to Cheniere, 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 selling, 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 $2.9 billion in gains and $2.5 billion in losses for the three and six months ended June 30, 2026, respectively, and $1.5 billion and $917 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 $20 million and $34 million for the three and six months ended June 30, 2026, respectively, and $29 million and $65 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.

Percentage of Total Revenues from Contracts with External Customers

Percentage of Trade Receivables, Net and Contract Assets, Net from External Customers

Three Months Ended June 30,

Six Months Ended June 30,

June 30,

December 31,

2026

2025

2026

2025

2026

2025

Customer A

*

*

*

*

15%

15%

Customer B

*

*

*

10%

*

*

Customer C

12%

*

*

*

11%

*

* Less than 10%

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

			Six Months Ended June 30,
			2026						2025
Cash paid during the period for interest on debt, net of amounts capitalized			$	475					$	444
Cash paid for income taxes, net of refunds			30						411
Non-cash investing and financing activities (1):
Unpaid purchases of property, plant and equipment (2)			189						176
Unpaid excise tax on stock repurchased during the year			10						5
Unpaid dividends			—						111

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

(2)Net of proceeds not yet collected from commissioning sales of LNG of $6 million and $3 million, respectively.

See Note 9—Leases for supplemental cash flow information related to our leases.

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