10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2025

or

☐    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to            

Commission file number 001-16383

CHENIERE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	95-4352386
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

845 Texas Avenue, Suite 1250

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

(713) 375-5000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: 

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $ 0.003 par value	LNG	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 

As of October 24, 2025, the issuer had 215,234,776 shares of Common Stock outstanding.

CHENIERE ENERGY, INC.

TABLE OF CONTENTS

	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Statements of Operations	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Stockholders’ Equity and Redeemable Non-Controlling Interest	5
	Consolidated Statements of Cash Flows	7
	Notes to Consolidated Financial Statements	8
	Note 1—Nature of Operations and Basis of Presentation	8
	Note 2—Trade and Other Receivables, Net of Current Expected Credit Losses	9
	Note 3—Inventory	9
	Note 4—Property, Plant and Equipment, Net of Accumulated Depreciation	10
	Note 5—Derivative Instruments	10
	Note 6—Non-Controlling Interests and Variable Interest Entities	15
	Note 7—Accrued Liabilities	16
	Note 8—Debt	17
	Note 9—Leases	19
	Note 10—Revenues	20
	Note 11—Related Party Transactions	22
	Note 12—Income Taxes	22
	Note 13—Net Income per Share Attributable to Common Stockholders	23
	Note 14—Share Repurchase Programs	24
	Note 15—Segment Information and Customer Concentration	24
	Note 16—Supplemental Cash Flow Information	25
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41
Item 4.	Controls and Procedures	41
Part II. Other Information
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 5.	Other Information	42
Item 6.	Exhibits	43
	Signatures	44

i

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
CAMT	corporate alternative minimum tax
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 United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP	generally accepted accounting principles in the United States
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
NCI	non-controlling interests
non-FTA countries	countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
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

1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of September 30, 2025, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

Unless the context requires otherwise, references to the “Company,” “we,” “us” and “our” refer to Cheniere Energy, Inc. and its consolidated subsidiaries, including our publicly traded subsidiary, CQP.

2

PART I.    FINANCIAL INFORMATION 

ITEM 1.    CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

(unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues
LNG revenues	$	4,302	$	3,554	$	14,122	$	10,633
Regasification revenues	34		34		102		102
Other revenues	105		175		302		532
Total revenues	4,441		3,763		14,526		11,267
Operating costs and expenses
Cost of sales (excluding operating and maintenance expense and depreciation, amortization and accretion expense shown separately below)	1,750		1,255		6,438		4,275
Operating and maintenance expense	447		450		1,479		1,364
Selling, general and administrative expense	81		99		296		299
Depreciation, amortization and accretion expense	338		306		979		912
Other operating costs and expenses	8		6		26		28
Total operating costs and expenses	2,624		2,116		9,218		6,878
Income from operations	1,817		1,647		5,308		4,389
Other income (expense)
Interest expense, net of capitalized interest	(236)		(247)		(702)		(770)
Loss on modification or extinguishment of debt	(7)		—		(7)		(9)
Interest and dividend income	23		41		91		149
Other income (expense), net	2		(3)		21		(1)
Total other expense	(218)		(209)		(597)		(631)
Income before income taxes and NCI	1,599		1,438		4,711		3,758
Less: income tax provision	303		231		850		550
Net income	1,296		1,207		3,861		3,208
Less: net income attributable to NCI	247		314		833		933
Net income attributable to Cheniere	$	1,049	$	893	$	3,028	$	2,275
Net income per share attributable to common stockholders—basic (1)	$	4.76	$	3.95	$	13.63	$	9.91
Net income per share attributable to common stockholders—diluted (1)	$	4.75	$	3.93	$	13.59	$	9.88
Weighted average number of common shares outstanding—basic	219.3		226.3		221.5		229.6
Weighted average number of common shares outstanding—diluted	219.9		227.0		222.1		230.3
___________________

(1)In computing basic and diluted net income per share attributable to common stockholders, net income attributable to Cheniere is adjusted for the remeasurement of the redeemable NCI, net of tax, to its redemption value, as required under the two-class method. See Note 13—Net Income per Share Attributable to Common Stockholders for the full computation.

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

3

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (1)

(in millions, except share data)

(unaudited)

	September 30,		December 31,
	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	1,075	$	2,638
Restricted cash and cash equivalents	323		552
Trade and other receivables, net of current expected credit losses	1,324		727
Inventory	458		501
Current derivative assets	89		155
Margin deposits	103		128
Other current assets, net	129		100
Total current assets	3,501		4,801
Property, plant and equipment, net of accumulated depreciation	35,345		33,552
Operating lease assets	2,627		2,684
Derivative assets	2,565		1,903
Deferred tax assets	17		19
Other non-current assets, net	1,047		899
Total assets	$	45,102	$	43,858
LIABILITIES, REDEEMABLE NCI AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	279	$	171
Accrued liabilities	1,492		2,179
Current debt, net of unamortized discount and debt issuance costs	605		351
Deferred revenue	176		163
Current operating lease liabilities	539		592
Current derivative liabilities	556		902
Other current liabilities	92		83
Total current liabilities	3,739		4,441
Long-term debt, net of unamortized discount and debt issuance costs	21,957		22,554
Operating lease liabilities	2,091		2,090
Derivative liabilities	1,464		1,865
Deferred tax liabilities	3,075		1,856
Other non-current liabilities	1,315		992
Total liabilities	33,641		33,798
Redeemable NCI	118		7
Stockholders’ equity
Preferred stock: $0.0001 par value, 5.0 million shares authorized, none issued	—		—
Common stock: $0.003 par value, 480.0 million shares authorized; 279.3 million shares and 278.7 million shares issued at September 30, 2025 and December 31, 2024, respectively	1		1
Treasury stock: 62.1 million shares and 54.7 million shares at September 30, 2025 and December 31, 2024, respectively, at cost	(7,826)		(6,136)
Additional paid-in-capital	4,507		4,452
Retained earnings	10,067		7,382
Total Cheniere stockholders’ equity	6,749		5,699
NCI	4,594		4,354
Total stockholders’ equity	11,343		10,053
Total liabilities, redeemable NCI and stockholders’ equity	$	45,102	$	43,858

(1)Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), substantially all of which are related to CQP, as further discussed in Note 6—Non-Controlling Interests and Variable Interest Entities. As of September 30, 2025, total assets and liabilities of our VIEs were $16.7 billion and $17.1 billion, respectively, including $121 million of cash and cash equivalents and $61 million of restricted cash and cash equivalents.

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

4

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND REDEEMABLE NON-CONTROLLING INTEREST

(in millions)

(unaudited)

Three and Nine Months Ended September 30, 2025
	Total Stockholders’ Equity
	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		NCI		Total Equity		Redeemable NCI (1)
	Shares	Par Value Amount		Shares	Amount
Balance at December 31, 2024	224.0	$	1	54.7	$	(6,136)	$	4,452	$	7,382	$	4,354	$	10,053	$	7
Net income (loss)	—	—		—	—		—		353		317		670		(2)
Dividends declared ($0.500 per common share) and dividend equivalents accrued	—	—		—	—		—		(113)		—		(113)		—
Shares repurchased, at cost and inclusive of excise taxes	(1.6)	—		1.6	(352)		—		—		—		(352)		—
Accretion of redeemable NCI (2)	—	—		—	—		—		(2)		—		(2)		2
Distributions to NCI	—	—		—	—		—		—		(200)		(200)		—
Contributions from redeemable NCI	—	—		—	—		—		—		—		—		38
Vesting of share-based compensation awards	0.4	—		—	—		—		—		—		—		—
Share-based compensation	—	—		—	—		40		—		—		40		—
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(44)		—		—		(44)		—
Balance at March 31, 2025	222.8	1		56.3	(6,488)		4,448		7,620		4,471		10,052		45
Net income (loss)	—	—		—	—		—		1,626		273		1,899		(2)
Dividends declared ($0.500 per common share declared each on April 29, 2025 and on June 17, 2025) and dividend equivalents accrued	—	—		—	—		—		(222)		—		(222)		—
Shares repurchased, at cost and inclusive of excise taxes	(1.4)	—		1.4	(310)		—		—		—		(310)		—
Accretion of redeemable NCI (2)	—	—		—	—		—		(3)		—		(3)		4
Distributions to NCI	—	—		—	—		—		—		(200)		(200)		—
Contributions from redeemable NCI	—	—		—	—		—		—		—		—		11
Vesting of share-based compensation awards	0.1	—		—	—		—		—		—		—		—
Share-based compensation	—	—		—	—		37		—		—		37		—
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(2)		—		—		(2)		—
Balance at June 30, 2025	221.5	1		57.7	(6,798)		4,483		9,021		4,544		11,251		58
Net income (loss)	—	—		—	—		—		1,049		250		1,299		(3)
Shares repurchased, at cost and inclusive of excise taxes	(4.4)	—		4.4	(1,028)		—		—		—		(1,028)		—
Accretion of redeemable NCI (2)	—	—		—	—		—		(3)		—		(3)		4
Distributions to NCI	—	—		—	—		—		—		(200)		(200)		—
Contributions from redeemable NCI	—	—		—	—		—		—		—		—		59
Vesting of share-based compensation awards	0.1	—		—	—		—		—		—		—		—
Share-based compensation	—	—		—	—		28		—		—		28		—
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(4)		—		—		(4)		—
Balance at September 30, 2025	217.2	$	1	62.1	$	(7,826)	$	4,507	$	10,067	$	4,594	$	11,343	$	118

(1)Redeemable NCI represents the economic interest held by a third party in one of our consolidated VIEs that is redeemable for cash under certain circumstances, including those that are outside of our control. As such, the economic interest is not a component of permanent equity on our Consolidated Balance Sheets.

(2)Amount in retained earnings presented net of tax.

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

5

Three and Nine Months Ended September 30, 2024
	Total Stockholders’ Equity
	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		NCI		Total Equity		Redeemable NCI (1)
	Shares	Par Value Amount		Shares	Amount
Balance at December 31, 2023	237.0	$	1	40.9	$	(3,864)	$	4,377	$	4,546	$	3,960	$	9,020	$	—
Net income	—	—		—	—		—		502		337		839		—
Dividends declared ($0.435 per common share) and dividend equivalents accrued	—	—		—	—		—		(103)		—		(103)		—
Shares repurchased, at cost and inclusive of excise taxes	(7.5)	—		7.5	(1,203)		—		—		—		(1,203)		—
Distributions to NCI	—	—		—	—		—		—		(253)		(253)		—
Contributions from redeemable NCI	—	—		—	—		—		—		—		—		4
Vesting of share-based compensation awards	0.6	—		—	—		—		—		—		—		—
Share-based compensation	—	—		—	—		34		—		—		34		—
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(40)		—		—		(40)		—
Balance at March 31, 2024	230.1	1		48.4	(5,067)		4,371		4,945		4,044		8,294		4
Net income	—	—		—	—		—		880		282		1,162		—
Dividends declared ($0.435 per common share declared each on April 26, 2024 and on June 17, 2024) and dividend equivalents accrued	—	—		—	—		—		(200)		—		(200)		—
Shares repurchased, at cost and inclusive of excise taxes	(3.1)	—		3.1	(501)		—		—		—		(501)		—
Distributions to NCI	—	—		—	—		—		—		(198)		(198)		—
Contributions from redeemable NCI	—	—		—	—		—		—		—		—		2
Share-based compensation	—	—		—	—		36		—		—		36		—
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(1)		—		—		(1)		—
Balance at June 30, 2024	227.0	1		51.5	(5,568)		4,406		5,625		4,128		8,592		6
Net income	—	—		—	—		—		893		314		1,207		—
Shares repurchased, at cost and inclusive of excise taxes	(1.6)	—		1.6	(285)		—		—		—		(285)		—
Distributions to NCI	—	—		—	—		—		—		(197)		(197)		—
Share-based compensation	—	—		—	—		34		—		—		34		—
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(4)		—		—		(4)		—
Balance at September 30, 2024	225.4	$	1	53.1	$	(5,853)	$	4,436	$	6,518	$	4,245	$	9,347	$	6

(1)Redeemable NCI represents the economic interest held by a third party in one of our consolidated VIEs that is redeemable for cash under certain circumstances, including those that are outside of our control. As such, the economic interest is not a component of permanent equity on our Consolidated Balance Sheets.

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

6

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Nine Months Ended September 30,
	2025		2024
Cash flows from operating activities
Net income	$	3,861	$	3,208
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion expense	979		912
Share-based compensation expense	140		140
Amortization of discount and debt issuance costs	29		32
Reduction of right-of-use assets	465		500
Total gains on derivative instruments, net	(1,629)		(861)
Net cash provided by settlement of derivative instruments	286		—
Deferred taxes	1,227		93
Other, net	11		27
Changes in operating assets and liabilities:
Trade and other receivables	(587)		427
Inventory	42		50
Margin deposits	25		(85)
Other non-current assets	(148)		(55)
Accounts payable and accrued liabilities	(672)		(207)
Total deferred revenue	(10)		24
Total operating lease liabilities	(459)		(489)
Other, net	(76)		37
Net cash provided by operating activities	3,484		3,753
Cash flows from investing activities
Property, plant and equipment, net of proceeds on commissioning sales of LNG of $94 million and zero, respectively	(2,334)		(1,669)
Other, net	71		(37)
Net cash used in investing activities	(2,263)		(1,706)
Cash flows from financing activities
Proceeds from issuances of debt and borrowings	1,262		2,725
Redemptions and repayments of debt	(1,617)		(3,171)
Distributions to NCI	(600)		(648)
Contributions from redeemable NCI	108		6
Payments related to tax withholdings for share-based compensation	(50)		(45)
Repurchase of common stock, inclusive of excise taxes paid	(1,687)		(1,981)
Dividends to stockholders	(332)		(300)
Other, net	(94)		(79)
Net cash used in financing activities	(3,010)		(3,493)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	(3)		(3)
Net decrease in cash, cash equivalents and restricted cash and cash equivalents	(1,792)		(1,449)
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	3,190		4,525
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$	1,398	$	3,076

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

7

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 12 mtpa was under construction and the remainder was in operation as of September 30, 2025, 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 September 30, 2025, 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 12 mtpa under construction and the remainder in operation as of September 30, 2025, from 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 approximately 7 mtpa under construction and the remainder in operation from the first two midscale Trains that have reached substantial completion as of September 30, 2025 (subsequently, in October 2025, the third midscale Train reached substantial completion); 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 September 30, 2025. Our board of directors (the “Board”) made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project on June 17, 2025, and issued a full notice to proceed with construction to Bechtel Energy Inc. effective June 18, 2025.

In addition to the above, 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. 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 the 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, 2024.

Results of operations for the three and nine months ended September 30, 2025 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2025.

8

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Recent Accounting Standards

ASU 2023-09

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740). This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. The adoption of this guidance will not have an impact on our results of operations and financial condition but will have an impact on the annual disclosures required in the relevant notes to the consolidated financial statements. This guidance applies prospectively, with retrospective application permitted. We are progressing on the implementation and evaluating the method of adoption. We will adopt this guidance and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2025.

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—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):

	September 30,		December 31,
	2025		2024
Trade receivables
SPL and CCL	$	518	$	548
Cheniere Marketing	274		109
Other subsidiaries	7		4
Total trade receivables	799		661
Other receivables
Tax-related receivables	441		29
Other	84		37
Total other receivables	525		66
Total trade and other receivables, net of current expected credit losses	$	1,324	$	727

NOTE 3—INVENTORY

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2025		2024
Materials	$	256	$	226
LNG	85		93
LNG in-transit	79		137
Natural gas	19		30
Other	19		15
Total inventory	$	458	$	501

9

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 4—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

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

	September 30,		December 31,
	2025		2024
Terminal and related assets
Terminal and interconnecting pipeline facilities	$	36,492	$	34,282
Land	618		465
Construction-in-process	5,396		5,486
Accumulated depreciation	(8,115)		(7,231)
Total terminal and related assets, net of accumulated depreciation	34,391		33,002
Fixed assets and other
Computer and office equipment	39		36
Furniture and fixtures	33		31
Computer software	124		122
Leasehold improvements	47		47
Other	24		24
Accumulated depreciation	(200)		(188)
Total fixed assets and other, net of accumulated depreciation	67		72
Assets under finance leases
Marine assets	1,060		587
Accumulated depreciation	(173)		(109)
Total assets under finance leases, net of accumulated depreciation	887		478
Property, plant and equipment, net of accumulated depreciation	$	35,345	$	33,552

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Depreciation expense	$	337	$	304	$	973	$	907
Offsets to LNG terminal costs (1)	47		—		102		—

(1)We recognized offsets to LNG terminal costs related to the sale of commissioning volumes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the CCL Project and the SPL Project (collectively, the “Liquefaction Projects”) during the testing phase for its construction.

NOTE 5—DERIVATIVE INSTRUMENTS

We have the following derivative instruments:

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

◦natural gas and power supply contracts, including our IPM agreements, 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 derivatives 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 United States.

10

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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
	September 30, 2025								December 31, 2024
	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)	$	—	$	35	$	589	$	624	$	—	$	59	$	(801)	$	(742)
LNG Trading Derivatives asset	—		14		—		14		—		17		—		17
FX Derivatives asset (liability)	—		(4)		—		(4)		—		16		—		16

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 or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

The Level 3 fair value measurements of our natural gas positions within the Liquefaction Supply Derivatives could be materially impacted by a significant 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 September 30, 2025:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$589	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.638) - $0.295 / $(0.087)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	66% - 391% / 177%

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

11

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

(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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Balance, beginning of period	$	(10)	$	(1,729)	$	(801)	$	(2,178)
Realized and change in fair value gains (losses) included in net income (1):
Included in cost of sales, existing deals (2)	413		256		786		470
Included in cost of sales, new deals (3)	(3)		(4)		(13)		11
Purchases and settlements:
Purchases (4)	—		—		—		—
Settlements (5)	190		204		623		426
Transfers out of level 3 (6)	(1)		5		(6)		3
Balance, end of period	$	589	$	(1,268)	$	589	$	(1,268)
Favorable changes in fair value relating to instruments still held at the end of the period	$	410	$	252	$	773	$	481

(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.

(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.

Commodity Derivatives

We hold Liquefaction Supply Derivatives, which are indexed to Henry Hub, global LNG or other natural gas price indices. As of September 30, 2025, 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 or development of infrastructure to support natural gas gathering and transport.

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:

	September 30, 2025		December 31, 2024
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives
Notional amount, net (in TBtu)	12,625	(9)	12,503	(8)

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both September 30, 2025 and December 31, 2024.

12

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 September 30,				Nine Months Ended September 30,
		2025		2024		2025		2024
LNG Trading Derivatives	LNG revenues	$	96	$	(3)	$	373	$	14
LNG Trading Derivatives	Cost of sales	(67)		(7)		(64)		(27)
Liquefaction Supply Derivatives (2)	LNG revenues	—		(2)		2		—
Liquefaction Supply Derivatives (2)	Cost of sales	636		490		1,373		869

(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.

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 $1,150 million and $642 million as of September 30, 2025 and December 31, 2024, respectively.

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 September 30,				Nine Months Ended September 30,
		2025		2024		2025		2024
FX Derivatives	LNG revenues	$	6	$	(10)	$	(55)	$	5

13

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	September 30, 2025
	Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	42	$	47	$	—	$	89
Derivative assets	2,564		—		1		2,565
Total derivative assets	2,606		47		1		2,654
Current derivative liabilities	(518)		(33)		(5)		(556)
Derivative liabilities	(1,464)		—		—		(1,464)
Total derivative liabilities	(1,982)		(33)		(5)		(2,020)
Derivative asset (liability), net	$	624	$	14	$	(4)	$	634
	December 31, 2024
	Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	105	$	32	$	18	$	155
Derivative assets	1,903		—		—		1,903
Total derivative assets	2,008		32		18		2,058
Current derivative liabilities	(885)		(15)		(2)		(902)
Derivative liabilities	(1,865)		—		—		(1,865)
Total derivative liabilities	(2,750)		(15)		(2)		(2,767)
Derivative asset (liability), net	$	(742)	$	17	$	16	$	(709)

14

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 September 30, 2025
Gross assets	$	3,972	$	48	$	2
Offsetting amounts	(1,366)		(1)		(1)
Net assets (1)	$	2,606	$	47	$	1
Gross liabilities	$	(2,044)	$	(51)	$	(7)
Offsetting amounts	62		18		2
Net liabilities (2)	$	(1,982)	$	(33)	$	(5)
As of December 31, 2024
Gross assets	$	3,064	$	42	$	25
Offsetting amounts	(1,056)		(10)		(7)
Net assets (1)	$	2,008	$	32	$	18
Gross liabilities	$	(2,790)	$	(16)	$	(3)
Offsetting amounts	40		1		1
Net liabilities (2)	$	(2,750)	$	(15)	$	(2)

(1)Includes current and non-current derivative assets of $89 million and $2,565 million, respectively, as of September 30, 2025 and $155 million and $1,903 million, respectively, as of December 31, 2024.

(2)Includes current and non-current derivative liabilities of $556 million and $1,464 million, respectively, as of September 30, 2025 and $902 million and $1,865 million, respectively, as of December 31, 2024.

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

	Consolidated Balance Sheets Location	September 30,		December 31,
		2025		2024
Liquefaction Supply Derivatives	Margin deposits	$	23	$	18
Liquefaction Supply Derivatives	Other current liabilities	1		—
LNG Trading Derivatives	Margin deposits	80		110

NOTE 6—NON-CONTROLLING INTERESTS AND VARIABLE INTEREST ENTITIES

Substantially all of our consolidated VIEs’ assets and liabilities relate to CQP. 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.

15

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	September 30,		December 31,
	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	121	$	270
Restricted cash and cash equivalents	61		125
Trade and other receivables, net of current expected credit losses	360		381
Inventory	152		154
Current derivative assets	15		84
Margin deposits	14		13
Other current assets, net	61		54
Total current assets	784		1,081
Property, plant and equipment, net of accumulated depreciation	15,532		15,880
Operating lease assets	79		80
Derivative assets	14		98
Other non-current assets, net	282		206
Total assets	$	16,691	$	17,345
LIABILITIES
Current liabilities
Accounts payable	$	73	$	70
Accrued liabilities	701		881
Current debt, net of unamortized discount and debt issuance costs	605		351
Deferred revenue	148		120
Current operating lease liabilities	5		4
Current derivative liabilities	139		250
Other current liabilities	8		16
Total current liabilities	1,679		1,692
Long-term debt, net of unamortized discount and debt issuance costs	14,156		14,761
Operating lease liabilities	74		76
Derivative liabilities	1,069		1,213
Other non-current liabilities	163		176
Total liabilities	$	17,141	$	17,918

NOTE 7—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2025		2024
Natural gas purchases	$	676	$	886
Terminal and related asset costs	219		272
Interest costs and related debt fees	266		214
Compensation and benefits	176		283
Tax-related liabilities	115		472
Other accrued liabilities	40		52
Total accrued liabilities	$	1,492	$	2,179

16

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—DEBT

Debt consisted of the following (in millions): 

	September 30,		December 31,
	2025		2024
SPL:
Senior Secured Notes:
5.625% due 2025	$	—	$	300
5.875% due 2026	500		1,500
5.00% due 2027	1,500		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 4.747% and 4.746% at September 30, 2025 and December 31, 2024, respectively (1)	1,730		1,782
Total SPL Senior Secured Notes	7,080		8,432
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	7,080		8,432
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 (2)	1,000		—
Total CQP Senior Notes	7,800		6,800
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	7,800		6,800
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”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”)	—		—
Total debt - CCH	4,865		4,865
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
5.650% Senior Notes due 2034	1,500		1,500
Total Cheniere Senior Notes	3,000		3,000
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	3,000		3,000
Total debt	22,745		23,097
Current debt, net of unamortized discount and debt issuance costs (1)	(605)		(351)
Unamortized discount and debt issuance costs	(183)		(192)
Total long-term debt, net of unamortized discount and debt issuance costs	$	21,957	$	22,554

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

(2)Issued in July 2025 pursuant to the same base indenture as the other CQP Senior Notes, as supplemented by the tenth supplemental indenture. See annual report on Form 10-K for the fiscal year ended December 31, 2024 for additional information regarding the guarantee, security and redemption option of CQP Senior Notes.

17

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of September 30, 2025 (in millions):

	SPL Revolving Credit Facility		CQP Revolving Credit Facility		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility (1)
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	185		—		—		110		—
Available commitment	$	815	$	1,000	$	3,260	$	1,390	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Senior unsecured
Interest rate on available balance (2)	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 credit spread adjustment of 0.1%, plus margin of 1.0% - 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 (2)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.090% - 0.290%
Letter of credit fees (2)	1.0% - 1.75%		1.125% - 2.0%		N/A		1.0% - 1.5%		1.075% - 2.00%
Maturity date	June 23, 2028		June 23, 2028		(3)		June 15, 2027		August 1, 2030

(1)In August 2025, we entered into an amendment and restatement of the Cheniere Revolving Credit Facility, resulting in an extended maturity date, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

(2)The margin on the interest rate, the commitment fees and the letter of credit fees is 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.

(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.

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 September 30, 2025, 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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Total interest cost	$	301	$	304	$	894	$	924
Capitalized interest	(65)		(57)		(192)		(154)
Total interest expense, net of capitalized interest	$	236	$	247	$	702	$	770

18

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

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

	September 30, 2025				December 31, 2024
	Carrying Amount (1)		Estimated Fair Value (2)		Carrying Amount (1)		Estimated Fair Value (2)
Senior notes	$	22,745	$	22,513	$	23,097	$	22,220

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

(2)As of September 30, 2025 and December 31, 2024, $3.1 billion and $3.0 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 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—LEASES

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 September 30, 2025 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2025	$	181	$	37
2026	639		141
2027	545		143
2028	376		146
2029	287		146
Thereafter	1,172		646
Total lease payments (1)	3,200		1,259
Less: Interest	(570)		(307)
Present value of lease liabilities	$	2,630	$	952

(1)Does not include approximately $3.0 billion of legally binding minimum payments for leases executed as of September 30, 2025 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:

	September 30, 2025		December 31, 2024
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	7.3	8.8	7.0	8.8
Weighted-average discount rate (1)	5.2%	6.6%	5.0%	7.4%

(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.

19

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Nine Months Ended September 30,
	2025		2024
Right-of-use assets obtained in exchange for operating lease liabilities (1)	$	408	$	718
Right-of-use assets obtained in exchange for finance lease liabilities (2)	472		59

(1)Net of $33 million reclassified from operating leases to finance leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.

(2)Net of $15 million reclassified from finance leases to operating leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.

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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Fixed income	$	25	$	72	$	66	$	238
Variable income	14		11		36		28
Total sublease income	$	39	$	83	$	102	$	266

Future annual minimum sublease payments to be received from LNG vessel subleases as of September 30, 2025 are as follows (in millions):

Years Ending December 31,	Sublease Payments
2025	$	8
2026	1
Total sublease payments	$	9

NOTE 10—REVENUES

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues from contracts with customers
LNG revenues (excluding net derivative gain (loss) below)	$	4,200	$	3,569	$	13,802	$	10,614
Regasification revenues	34		34		102		102
Other revenues (1)	59		80		185		231
Total revenues from contracts with customers	4,293		3,683		14,089		10,947
Net derivative gain (loss) (see Note 5)	102		(15)		320		19
Sublease income (see Note 9)	39		83		102		266
Other revenues	7		12		15		35
Total revenues	$	4,441	$	3,763	$	14,526	$	11,267

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

For the three and nine months ended September 30, 2025 and 2024, we did not have any material revenue arrangements that were presented within our Consolidated Statements of Operations on a net basis.

20

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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):

	September 30,		December 31,
	2025		2024
Contract assets, net of current expected credit losses	$	401	$	331

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):

	Nine Months Ended September 30, 2025
Deferred revenue, beginning of period	$	318
Cash received but not yet recognized in revenue	149
Revenue recognized from prior period deferral	(162)
Deferred revenue, end of period	$	305

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:

	September 30, 2025			December 31, 2024
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	107.6	8	$	104.7	8
Regasification revenues	0.4		2	0.5		3
Total revenues	$	108.0		$	105.2

(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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
LNG revenues	64	%	60	%	67	%	57	%
Regasification revenues	8	%	8	%	8	%	8	%

21

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—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):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Other revenues
Operating agreement and construction management agreement with equity method investee (1)	$	—	$	3	$	1	$	7
Operating and maintenance expense
Natural gas transportation and storage agreements with equity method investees (1)	8		10		24		15
Natural gas transportation and storage agreements with other related party (2)	—		15		28		44

(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 nine months ended September 30, 2025 and $3 million and $7 million of other revenues and $2 million and $7 million of operating and maintenance expense from the investee during the three and nine months ended September 30, 2024, respectively.

(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.

Below is a summary of our related party balances, all in the ordinary course of business, as reported on our Consolidated Balance Sheets (in millions):

	September 30,		December 31,
	2025		2024
Trade and other receivables, net of current expected credit losses	$	—	$	4
Accrued liabilities	3		8

NOTE 12—INCOME TAXES

We recorded an income tax provision of $303 million and $850 million during the three and nine months ended September 30, 2025, respectively, and an income tax provision of $231 million and $550 million for the same periods of 2024, respectively, which was calculated using the annual effective tax rate method.

Our effective tax rate was 18.9% and 18.0% during the three and nine months ended September 30, 2025, respectively, as compared to 16.1% and 14.6% for the same periods of 2024, respectively. Our effective tax rate increased between the comparable periods primarily due to: (1) decreased ratio of pre-tax income attributable to CQP, which is partially not taxable to us, (2) increased tax expense due to a valuation allowance on a capital loss carryover generated on the sale of all of our equity interests in an equity method investment during the three months ended March 31, 2025 and (3) a reduced Foreign Derived Intangible Income (“FDII”) deduction. The effective tax rate for the comparable three and nine month periods was lower than the statutory rate of 21.0% primarily due to CQP’s income that is partially not taxable to us.

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law with significant changes to the Internal Revenue Code that impact us, including, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025 and modifying the export-promoting FDII deduction rules, renamed to the Foreign Derived Deduction Eligible Income (“FDDEI”) under the OBBBA beginning in 2026.

22

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

We initially applied the relevant and effective provisions of the OBBBA in the third quarter of 2025, including provisions related to bonus depreciation. The legislation did not have a material impact on our income tax expense for the three months ended September 30, 2025, and we do not expect it to materially change our effective income tax rate for 2025. However, the 100% bonus depreciation provision under the OBBBA is expected to defer our tax liability, ultimately reducing our 2025 income taxes payable to a nominal amount, primarily due to the accelerated tax deduction on qualifying Corpus Christi Stage 3 Project assets.

On September 30, 2025, the Internal Revenue Service (the “IRS”) issued Notice 2025-49, which includes, among other provisions, revised interim rules for calculating CAMT adjusted financial statement income, including rules allowing us to utilize and benefit from our existing net operating loss carryovers for both CAMT and regular tax in the same period. As a result, our cash tax obligations have been deferred and we are entitled to a refund of $380 million of previously paid CAMT, which has been recognized as a receivable within trade and other receivables, net of current expected credit losses on our Consolidated Balance Sheets as of September 30, 2025.

NOTE 13—NET INCOME PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

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 held by a third party in one of our consolidated VIEs is considered participating because, under certain circumstances, it is redeemable for cash at a return. Therefore, the accretion of the redeemable NCI to its redemption value, net of tax, which is recognized as a deemed dividend within retained earnings, is deducted from net income in computing net income per share attributable to common stockholders.

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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Net income attributable to Cheniere	$	1,049	$	893	$	3,028	$	2,275
Less: accretion of redeemable NCI, net of tax	4		—		10		—
Net income attributable to common stockholders	$	1,045	$	893	$	3,018	$	2,275
Weighted average common shares outstanding:
Basic	219.3		226.3		221.5		229.6
Dilutive unvested stock	0.6		0.7		0.6		0.7
Diluted	219.9		227.0		222.1		230.3
Net income per share attributable to common stockholders—basic (1)	$	4.76	$	3.95	$	13.63	$	9.91
Net income per share attributable to common stockholders—diluted (1)	$	4.75	$	3.93	$	13.59	$	9.88

(1)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 October 28, 2025, we declared a quarterly dividend of $0.555 per share of common stock that is payable on November 18, 2025 to stockholders of record as of the close of business on November 7, 2025.

23

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 14—SHARE REPURCHASE PROGRAMS

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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Total shares repurchased	4.37		1.58		7.37		12.24
Weighted average price paid per share	$	233.14	$	178.84	$	227.05	$	160.96
Total cost of repurchases (1)	$	1,018	$	282	$	1,674	$	1,970

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

As of September 30, 2025, we had approximately $2.2 billion remaining under our share repurchase program. Our share repurchase program authorization is effective through December 31, 2027.

NOTE 15—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 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 $574 million and $506 million in gains for the three months ended September 30, 2025 and 2024, respectively, and $1.5 billion and $826 million in gains for the nine months ended September 30, 2025 and 2024, respectively. Interest income, which is included in interest and dividend income on our Consolidated Statements of Operations, was $23 million and $41 million for the three months ended September 30, 2025 and 2024, respectively, and $88 million and $149 million for the nine months ended September 30, 2025 and 2024, 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 United States. Total expenditures for additions to long-lived assets is reported on our Consolidated Statements of Cash Flows.

The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2025	2024	2025	2024	2025	2024
Customer A	*	*	*	*	14%	20%
Customer B	*	10%	*	*	*	*

* Less than 10%

24

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2025		2024
Cash paid during the period for interest on debt, net of amounts capitalized	$	640	$	823
Cash paid (refunded) for income taxes, net (1)	415		(72)
Non-cash investing activities:
Unpaid purchases of property, plant and equipment (2)(3)	241		175
Conveyance of other non-current assets to equity method investee in exchange for infrastructure support	—		34
Non-cash financing activities (2):
Unpaid excise tax on stock repurchased	15		18
Unpaid repurchase of common stock	20		—

(1)Amount for nine months ended September 30, 2025 includes $380 million of previously paid CAMT, which has been recognized as a tax-related receivable as of September 30, 2025. See Note 12—Income Taxes for additional information.

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

(3)Net of proceeds not yet collected on commissioning sales of LNG of $8 million and zero, respectively.

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

25

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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things: 

•statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates, or at all;

•statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;

•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;

•statements relating to Cheniere’s capital deployment, including intent, ability, extent and timing of capital expenditures, debt repayment, dividends, share repurchases and execution on the capital allocation plan;

•statements regarding our future sources of liquidity and cash requirements;

•statements relating to the construction of our Trains and pipelines, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;

•statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;

•statements regarding counterparties to our commercial contracts, construction contracts and other contracts;

•statements regarding our planned development and construction of additional Trains or pipelines, including the financing of such Trains or pipelines;

•statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;

•statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;

•statements relating to our goals, commitments and strategies in relation to environmental matters;

•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;

•statements regarding our anticipated LNG and natural gas marketing activities; and

•any other statements that relate to non-historical or future information.

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that

26

the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 31, 2025. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future.

Our discussion and analysis includes the following subjects: 

•Overview

•Overview of Significant Events

•Results of Operations

•Liquidity and Capital Resources

•Summary of Critical Accounting Estimates

•Recent Accounting Standards

Overview

Cheniere, a Delaware corporation, is a Houston-based energy infrastructure company primarily engaged in LNG-related businesses. 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 are the largest producer of LNG in the United States and we were the second largest LNG operator globally, based on the total production capacity of our liquefaction facilities as of September 30, 2025. Our total production capacity is expected to be over 60 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which over 12 mtpa was under construction and the remainder was in operation as of September 30, 2025, comprised of the following:

•over 30 mtpa of total production capacity in operation from natural gas liquefaction facilities located in Cameron Parish, Louisiana at Sabine Pass (the “SPL Project”). We own and operate the SPL Project and export facility (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, through our ownership interest in and management agreements with CQP, which is a publicly traded limited partnership. As of September 30, 2025, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP. 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 through CQP 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”).

27

•over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including over 12 mtpa under construction and the remainder in operation as of September 30, 2025, from our natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”), of which we have 100% ownership interest. The Corpus Christi LNG Terminal also has three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. We also own and operate through CCP 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 approximately 7 mtpa under construction and the remainder in operation from the first two midscale Trains that have reached substantial completion as of September 30, 2025, (subsequently, in October 2025, the third midscale Train reached substantial completion); 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 September 30, 2025. Our board of directors (the “Board”) made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project on June 17, 2025, and issued a full notice to proceed with construction to Bechtel Energy Inc. (“Bechtel”) effective June 18, 2025. Non-FTA export authorization on the CCL Midscale Trains 8 & 9 Project is pending with the DOE.

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 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 IPM agreements currently in effect, with approximately 15 years of weighted average remaining life as of September 30, 2025, we have contracted approximately 90% of the total anticipated production from the CCL Project and the SPL Project (collectively, the “Liquefaction Projects”) through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. LNG produced by the Liquefaction Projects that is not contracted under long-term contracts is available for Cheniere Marketing, our integrated marketing function, to sell in the global market under spot sales or other short-term agreements.

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. Our capital allocation plan is designed, in part, to invest in financially disciplined growth accretive to our common stock. 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 IPM agreements with creditworthy counterparties under the pricing structures described above, with financial parameters that consider, among other things, targeted unlevered returns that exceed our cost of equity and return on stock at prevailing stock prices and project leverage.

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, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 31, 2025.

28

•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, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 31, 2025.

We have increased available liquefaction capacity at our Liquefaction Projects 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 significant land positions at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, which provide opportunity for further liquefaction capacity expansion. We are developing an expansion adjacent to the SPL Project with an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities, and supporting infrastructure (the “SPL Expansion Project”), and we are commercializing to support the additional liquefaction capacity associated with this project. This project and any future expansions at our sites require, 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, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 31, 2025.

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

		SPL Expansion Project
	Expected total peak production capacity of LNG (1)	Up to ~ 20 mtpa
	Milestone
Regulatory (2)	FERC authorizations:
	Positive environmental assessment	Pending
	Order under Section 3 of NGA	Pending
	Certification to commence construction (3)
	DOE export authorization:
	FTA countries	ü
	Non-FTA countries	Pending
Financing	Financing (4)
Commercialization and Other Contracting	Definitive commercial agreements (5)	In process
	Definitive full-scope EPC contract
Critical Milestone	Target FID (6)	2026/2027

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 projects 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, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 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.

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(3)Based on letter from the FERC granting our request to commence with site preparation. The FERC orders require us to comply with certain ongoing conditions and obtain certain additional FERC and other regulatory agency approvals as construction progresses.

(4)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.

(5)Liquefaction capacity partially contracted by Cheniere Marketing and SPL Stage V through SPA or IPM agreements conditioned on additional liquefaction capacity beyond what is currently in construction or operation.

(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.

We have excluded from the table above a potential further expansion of the CCL Project with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities, and supporting infrastructure (the “CCL Stage 4 Expansion Project”), for which we commenced the pre-filing process with the FERC in July 2025, as none of the milestones within the table have yet been achieved.

Overview of Significant Events

Our significant events since January 1, 2025 and through the filing date of this Form 10-Q include the following:

Strategic

•In August 2025, Cheniere announced the execution of a long-term LNG SPA between Cheniere Marketing and JERA Co., Inc. (“JERA”), under which JERA has agreed to purchase approximately 1 mtpa of LNG from Cheniere Marketing on an FOB basis from 2029 through 2050. The purchase price for LNG under the SPA is indexed to the Henry Hub price, plus a fixed liquefaction fee.

•In July 2025, we submitted a request to initiate the pre-filing review process with the FERC under the National Environmental Policy Act for the CCL Stage 4 Expansion Project, a potential further expansion of the Corpus Christi LNG Terminal with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities.

•In June 2025, our Board made a positive FID with respect to the investment in the development, construction and operation of the CCL Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under a fixed price separated turnkey EPC contract.

•In June 2025, certain subsidiaries of CQP updated the SPL Expansion Project’s FERC application, originally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities.

•In May 2025, Cheniere Marketing entered into an IPM agreement with Canadian Natural Resources Limited to purchase 140,000 MMBtu per day of natural gas at a price based on the Japan Korea Marker, less fixed LNG shipping costs and a fixed liquefaction fee, for a term of approximately 15 years commencing in approximately 2030. This agreement is subject to us making a positive FID with respect to the SPL Expansion Project or unilaterally waiving such condition.

•In March 2025, we received authorization from the FERC under the NGA to site, construct and operate the CCL Midscale Trains 8 & 9 Project.

Operational

•As of October 24, 2025, over 4,370 cumulative LNG cargoes totaling over 300 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

•In March and August 2025, substantial completions of Trains 1 and 2, respectively, of the Corpus Christi Stage 3 Project were achieved. Subsequently in October 2025, Train 3 of the Corpus Christi Stage 3 Project achieved substantial completion.

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Financial

•In August 2025, we amended and restated our $1.25 billion Cheniere Revolving Credit Facility to, among other things, (1) extend the maturity date thereunder, (2) reduce the interest rate and commitment fees payable thereunder and (3) make certain other changes to the terms and conditions of the existing Cheniere Revolving Credit Facility.

•In July 2025, CQP issued and sold $1.0 billion aggregate principal amount of 5.550% Senior Notes due 2035 (the “2035 CQP Senior Notes”), and the net proceeds, together with cash on hand, were used to redeem $1.0 billion of the aggregate principal amount of SPL’s 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”).

•In June 2025, we announced updates to our company outlook, which included a plan to increase our annualized dividend by over 10% to $2.22 per common share commencing with the third quarter of 2025, subject to declaration by the Board.

•In February 2025, Fitch Ratings upgraded the issuer credit rating of both Cheniere and CQP to BBB from BBB- with a stable outlook. In June 2025, S&P Global Ratings concurrently assigned a BBB rating to the 2035 CQP Senior Notes and upgraded the remaining unsecured CQP notes to BBB from BBB-.

•During the three and nine months ended September 30, 2025, we accomplished the following pursuant to our capital allocation priorities:

◦We repurchased approximately 4.4 million and 7.4 million shares of our common stock, respectively, as part of our share repurchase program for approximately $1.0 billion and $1.7 billion, respectively.

◦In September 2025, SPL repaid $52 million aggregate principal amount outstanding of its series of senior secured notes due 2037 with a weighted average interest rate of 4.746%, based on their respective fixed amortization schedules.

◦In March 2025, SPL repaid the remaining $300 million aggregate principal amount outstanding of its 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes”) at maturity.

◦We paid dividends of $0.500 and $1.500 per share of common stock, respectively.

◦We continued to invest in accretive organic growth, including our investments in the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

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Results of Operations

Consolidated results of operations

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per share data)	2025		2024		Variance		2025		2024		Variance
Revenues
LNG revenues	$	4,302	$	3,554	$	748	$	14,122	$	10,633	$	3,489
Regasification revenues	34		34		—		102		102		—
Other revenues	105		175		(70)		302		532		(230)
Total revenues	4,441		3,763		678		14,526		11,267		3,259
Operating costs and expenses
Cost of sales (excluding operating and maintenance expense and depreciation, amortization and accretion expense shown separately below)	1,750		1,255		495		6,438		4,275		2,163
Operating and maintenance expense	447		450		(3)		1,479		1,364		115
Selling, general and administrative expense	81		99		(18)		296		299		(3)
Depreciation, amortization and accretion expense	338		306		32		979		912		67
Other operating costs and expenses	8		6		2		26		28		(2)
Total operating costs and expenses	2,624		2,116		508		9,218		6,878		2,340
Income from operations	1,817		1,647		170		5,308		4,389		919
Other income (expense)
Interest expense, net of capitalized interest	(236)		(247)		11		(702)		(770)		68
Loss on modification or extinguishment of debt	(7)		—		(7)		(7)		(9)		2
Interest and dividend income	23		41		(18)		91		149		(58)
Other income (expense), net	2		(3)		5		21		(1)		22
Total other expense	(218)		(209)		(9)		(597)		(631)		34
Income before income taxes and NCI	1,599		1,438		161		4,711		3,758		953
Less: income tax provision	303		231		72		850		550		300
Net income	1,296		1,207		89		3,861		3,208		653
Less: net income attributable to NCI	247		314		(67)		833		933		(100)
Net income attributable to Cheniere	$	1,049	$	893	$	156	$	3,028	$	2,275	$	753
Net income per share attributable to common stockholders—basic	$	4.76	$	3.95	$	0.81	$	13.63	$	9.91	$	3.72
Net income per share attributable to common stockholders—diluted	$	4.75	$	3.93	$	0.82	$	13.59	$	9.88	$	3.71

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Volumes loaded and recognized from the Liquefaction Projects

	Three Months Ended September 30, 2025			Nine Months Ended September 30, 2025
(in TBtu)	Operational	Commissioning	Total	Operational	Commissioning	Total
Volumes loaded during the current period	579	7	586	1,731	13	1,744
Volumes loaded during the prior period but recognized during the current period	32	—	32	39	—	39
Less: volumes loaded during the current period and in transit at the end of the period	(30)	(1)	(31)	(30)	(1)	(31)
Total volumes recognized in the current period	581	6	587	1,740	12	1,752

Components of LNG revenues and corresponding LNG volumes delivered

	Three Months Ended September 30,						Nine Months Ended September 30,
	2025		2024		Variance		2025		2024		Variance
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	$	3,481	$	2,903	$	578	$	10,824	$	8,701	$	2,123
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2)	630		565		65		2,593		1,587		1,006
LNG procured from third parties (2)	38		49		(11)		188		168		20
Net derivative gain (loss)	102		(15)		117		320		19		301
Other revenues	51		52		(1)		197		158		39
Total LNG revenues	$	4,302	$	3,554	$	748	$	14,122	$	10,633	$	3,489
Volumes delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	525		511		14		1,537		1,573		(36)
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2)	56		49		7		203		147		56
LNG procured from third parties (2)	3		3		—		18		14		4
Total volumes delivered as LNG revenues	584		563		21		1,758		1,734		24

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

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

Net income attributable to Cheniere

Net income attributable to Cheniere increased $156 million and $753 million for the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, primarily due to:

•$69 million and $665 million, respectively, of favorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely due to changes in market-based locational forward price differentials for North American natural gas deliveries, which impacted our natural gas supply derivatives, and incrementally for the comparable nine month periods due to the impact of declines in short-term global gas prices and volatility within our derivatives related to financial positions to economically hedge the purchase and sale of physical LNG and our derivatives related to IPM agreements, respectively; and

•$183 million and $661 million of increases, respectively, in LNG revenues, net of cost of sales and excluding changes in fair value of derivatives, primarily as a result of higher pricing per MMBtu between the comparable nine month periods including the effect of settlement of previously entered derivative instruments, as well as increased

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production volume due to the substantial completions of Trains 1 and 2 of the Corpus Christi Stage 3 Project in March 2025 and August 2025, respectively.

Partially offsetting these favorable changes between the comparable three and nine month periods were increased tax provisions of $72 million and $300 million, respectively, as further explained under the caption Income tax provision below, decreased sublease and subcharter income from our LNG vessels of $63 million and $207 million, respectively, due to fewer days the LNG vessels were subcontracted out and at lower rates in the current periods as compared to the same periods of 2024 and increased operating and maintenance expenses of $115 million between the comparable nine month periods primarily due to the completion of planned large-scale maintenance activities on two trains at the SPL Project.

The following is an expanded discussion of the significant drivers of the variance in net income attributable to Cheniere by line item:

Revenues

The $678 million and $3.3 billion increases in revenues between the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, were primarily attributable to:

•$482 million and $2.7 billion increases, respectively, due to higher pricing per MMBtu primarily from increased Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed;

•$117 million and $301 million of gains, respectively, from agreements accounted for as derivative instruments included in revenues of which the gain between the three month periods was primarily attributable to the effect of settlement of previously entered derivative instruments and the gain between the nine month periods was primarily derived from a favorable change in fair value, as further described above under the caption Net income attributable to Cheniere; and

•$149 million and $497 million increases, respectively, due to higher volumes of LNG delivered between the periods, primarily as a result of increased production volume due to the substantial completions of Trains 1 and 2 of the Corpus Christi Stage 3 Project in March 2025 and August 2025, respectively.

These favorable variances were partially offset by $63 million and $207 million decreases in sublease and subcharter income from our LNG vessels between the comparable three and nine month periods, respectively, due to fewer days the LNG vessels were subcontracted out and at lower rates in the current year as compared to the same periods of 2024.

Operating costs and expenses

The $508 million and $2.3 billion unfavorable variances between the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, were primarily attributable to:

•$580 million and $2.6 billion increases, respectively, in cost of sales excluding the effect of derivative changes, substantially all related to the increases in cost of natural gas feedstock, largely due to the increase in U.S. natural gas prices as further described under the caption Revenues;

•$115 million increase in operating and maintenance expense between the comparable nine month periods, primarily due to the completion of planned large-scale maintenance activities on two trains at the SPL Project and additional expenses from the substantial completions of Trains 1 and 2 of the Corpus Christi Stage 3 Project in March 2025 and August 2025, respectively; and

•$32 million and $67 million increases, respectively, in depreciation, amortization and accretion expense, primarily as a result of substantial completions of Trains 1 and 2 of the Corpus Christi Stage 3 Project.

These unfavorable variances were partially offset by $92 million and $419 million of favorable changes in fair value of agreements accounted for as derivative instruments included in cost of sales between the comparable three and nine month periods, respectively, with the primary drivers of the variance described above under the caption Net income attributable to Cheniere.

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Other income (expense)

The $9 million unfavorable variance between the three months ended September 30, 2025 and 2024 and the $34 million favorable variance between the nine months ended September 30, 2025 and 2024 were primarily attributable to:

•$11 million and $68 million decreases in interest expense, net of capitalized interest, between the comparable three and nine month periods, respectively, due to $8 million and $38 million increases, respectively, in capitalized interest costs, given the higher carrying value of assets under construction and additionally due to $3 million and $30 million lower gross interest costs, respectively, due to debt reduction activities associated with our long-term capital allocation plan; and

•$22 million increase in other income, net, between the comparable nine month periods primarily from a $26 million gain recognized on the sale of our equity interests in an equity method investment during the three months ended March 31, 2025.

These favorable variances were partially offset by $18 million and $58 million decreases in interest and dividend income between the comparable three and nine month periods, respectively, as a result of decreased interest rates and lower average cash and cash equivalents balances between the periods.

Income tax provision

The $72 million and $300 million unfavorable variances between the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, were primarily attributable to increases in our effective tax rate, as described below, as well as a higher income tax expense due to $161 million and $953 million increases in pre-tax income, respectively.

Our effective tax rate was 18.9% and 18.0% for the three and nine months ended September 30, 2025, respectively, as compared to 16.1% and 14.6% for the same periods of 2024, respectively. Our effective tax rate increased between the comparable periods primarily due to a decreased proportion of our pre-tax income attributable to CQP, which is partially not taxable to us, and a reduced Foreign Derived Intangible Income (“FDII”) deduction. Additionally contributing to the unfavorable variance in our effective tax rate between the comparable nine month periods was an increased tax expense due to a valuation allowance on a capital loss carryover generated on the sale of all of our equity interests in an equity method investment during the three months ended March 31, 2025, as discussed above under the caption Other income (expense). The effective tax rate for the comparable three and nine month periods was lower than the statutory rate of 21.0% primarily due to CQP’s income that is partially not taxable to us.

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law with significant changes to the Internal Revenue Code that impact us, including, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025 and modifying the export-promoting FDII deduction rules, renamed to the Foreign Derived Deduction Eligible Income (“FDDEI”) under the OBBBA beginning in 2026.

We initially applied the relevant and effective provisions of the OBBBA in the third quarter of 2025, including provisions related to bonus depreciation. The legislation did not have a material impact on our income tax expense for the three months ended September 30, 2025, and we do not expect it to materially change our effective income tax rate for 2025. However, the 100% bonus depreciation provision under the OBBBA is expected to defer our tax liability, ultimately reducing our 2025 income taxes payable to a nominal amount, primarily due to the accelerated tax deduction on qualifying Corpus Christi Stage 3 Project assets.

Commencing with its effectiveness in 2026, we expect that the FDDEI regime will favorably impact our effective tax rate relative to prior policy, as a larger portion of our export-related income is projected to be eligible for a preferential tax rate despite an increase in the tax rate on qualifying sales. The FDDEI regime provides for an effective tax rate of 14%, a rate lower than the statutory corporate tax rate of 21%, on eligible sales of property or services to a foreign person for foreign use. Relative to the prior FDII tax provision, the FDDEI regime increases the effective tax rate on eligible sales but broadens qualifying income by eliminating certain asset-based eligibility constraints and removing the requirement to reduce eligible income by specified allocable expenses.

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On September 30, 2025, the Internal Revenue Service (the “IRS”) issued Notice 2025-49 which includes, among other provisions, revised interim rules for calculating CAMT adjusted financial statement income, including rules allowing us to utilize and benefit from our existing net operating loss carryovers for both CAMT and regular tax in the same period. As a result, our cash tax obligations have been deferred and we are entitled to a refund of $380 million of previously paid CAMT, which has been recognized as a tax-related receivable as of September 30, 2025.

Net income attributable to non-controlling interests

The $67 million and $100 million decreases between the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, were primarily attributable to $129 million and $187 million decreases in CQP’s consolidated net income, respectively, primarily from unfavorable 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. For commodity derivative instruments, including those related to our IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 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, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

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, 2025, we realized offsets to LNG terminal costs of $47 million and $102 million, respectively, corresponding to 6 TBtu and 12 TBtu, respectively, of LNG that were related to the sale of commissioning volumes. We did not record any offsets to LNG terminal costs during the three and nine months ended September 30, 2024.

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.

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

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Trains reach substantial completion, of which over 12 mtpa is still under construction or commissioning as of September 30, 2025. As of September 30, 2025, substantial completions for the first two Trains of the Corpus Christi Stage 3 Project have been achieved, and subsequently in October 2025, substantial completion for the third Train of the Corpus Christi Stage 3 Project was achieved. 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.

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 and equity offerings by us or our subsidiaries.

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

	September 30, 2025
Cash and cash equivalents (1)	$	1,075
Restricted cash and cash equivalents (1)	323
Available commitments under our credit facilities (2):
SPL Revolving Credit Facility	815
CQP Revolving Credit Facility	1,000
CCH Credit Facility	3,260
CCH Working Capital Facility	1,390
Cheniere Revolving Credit Facility	1,250
Total available commitments under our credit facilities	7,715
Total available liquidity	$	9,113

(1)Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), as discussed in Note 6—Non-Controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements. As of September 30, 2025, assets of our VIEs, which are included in our Consolidated Balance Sheets, included $121 million of cash and cash equivalents and $61 million of restricted cash and cash equivalents.

(2)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of September 30, 2025. 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 September 30, 2025 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, 2024.

Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures. Certain restrictions or requirements under debt and equity instruments executed by our subsidiaries limit the entity’s use of cash, including the following:

•SPL and CCH are 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 Projects and other restricted payments. In addition, SPL and CCH’s operating costs are managed by our subsidiaries under affiliate agreements, which may require SPL and CCH to advance cash to the respective affiliates, however the cash remains restricted for operation and construction of the Liquefaction Projects;

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•CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner. Quarterly distributions by CQP are currently comprised of a base amount plus a variable amount equal to the remaining available cash per unit, which takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of CQP’s business;

•Our 48.6% limited partner interest, 100% general partner interest and incentive distribution rights in CQP limit our right to receive cash held by CQP to the amounts specified by the provisions of CQP’s partnership agreement; and

•SPL and CCH are restricted by affirmative and negative covenants included in certain of their debt agreements in their ability to make certain payments, including distributions, unless specific requirements are satisfied.

Despite the restrictions noted above, we believe that sufficient flexibility exists within the Cheniere complex to enable each independent capital structure to meet its currently anticipated cash requirements. The sources of liquidity at SPL, CQP and CCH primarily fund the cash requirements of the respective entity, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by Cheniere Marketing, is available to enable Cheniere to meet its cash requirements.

Corpus Christi LNG Terminal Expansion

As of September 30, 2025, substantial completions of the first two of seven midscale Trains of the Corpus Christi Stage 3 Project were achieved. Additionally, in June 2025, our Board made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under an EPC contract for a contract price of approximately $2.9 billion, subject to adjustment only by change order.

The following table summarizes the project completion and construction status of both the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project as of September 30, 2025:

	Corpus Christi Stage 3 Project	CCL Midscale Trains 8 & 9 Project
Overall project completion percentage	90.5%	21.2%
Completion percentage of:
Engineering	99.4%	57.6%
Procurement	100.0%	33.4%
Subcontract work	93.3%	3.6%
Construction	75.0%	0.0%
Date of expected substantial completion of remaining Trains	2H 2025 - 2H 2026 (1)	2H 2028

(1)In October 2025, substantial completion of Train 3 of the Corpus Christi Stage 3 Project was achieved.

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. 

	Nine Months Ended September 30,
	2025		2024
Net cash provided by operating activities	$	3,484	$	3,753
Net cash used in investing activities	(2,263)		(1,706)
Net cash used in financing activities	(3,010)		(3,493)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	(3)		(3)
Net decrease in cash, cash equivalents and restricted cash and cash equivalents	$	(1,792)	$	(1,449)

38

Operating Cash Flows

The $269 million decrease between the periods was primarily related to lower cash flows attributed to working capital from differences in timing of payments to suppliers and cash collections from the sale of LNG cargoes, partially offset by higher net cash inflows from LNG sales, as explained above in Results of Operations, and increased cash inflows from settlement of derivative instruments.

As described in Results of Operations, the OBBBA was signed into law during the third quarter of 2025 and includes, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025, which is expected to defer our income tax liability, ultimately reducing our income tax payable to a nominal amount in 2025, and modifying the export-promoting FDII deduction rules, renamed to the FDDEI under the OBBBA, which is expected to reduce our income taxes payable relative to prior policy in future periods. Additionally, the IRS issued Notice 2025-49, which revised rules for calculating CAMT adjusted financial statement income, deferring our tax obligations and entitling us to a refund of $380 million of previously paid CAMT.

Investing Cash Flows

Our investing net cash outflows primarily related to: (1) construction costs for the Corpus Christi Stage 3 Project, which were $1.1 billion and $1.3 billion during the nine months ended September 30, 2025 and 2024, respectively; (2) $750 million of costs paid for the CCL Midscale Trains 8 & 9 Project during the nine months ended September 30, 2025, primarily related to procurement and engineering; and (3) optimization and other site improvement projects during both periods. The $0.2 billion decrease in construction costs for the Corpus Christi Stage 3 Project between the periods was primarily related to the timing of cash payments under the related EPC contract. We expect to continue to incur capital expenditures for the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project as construction progresses on these projects.

Financing Cash Flows

The following table summarizes our financing activities (in millions):

	Nine Months Ended September 30,
	2025		2024
Proceeds from issuances of debt and borrowings	$	1,262	$	2,725
Redemptions and repayments of debt	(1,617)		(3,171)
Distributions to NCI	(600)		(648)
Contributions from redeemable NCI	108		6
Payments related to tax withholdings for share-based compensation	(50)		(45)
Repurchase of common stock, inclusive of excise taxes paid	(1,687)		(1,981)
Dividends to stockholders	(332)		(300)
Other, net	(94)		(79)
Net cash used in financing activities	$	(3,010)	$	(3,493)

39

Proceeds from Issuances of Debt and Borrowings

The following table shows the proceeds from issuances of debt and borrowings, including intra-quarter activity (in millions):

	Nine Months Ended September 30,
	2025		2024
Proceeds from issuances of debt and borrowings
Cheniere:
5.650% Senior Notes due 2034	$	—	$	1,497
CQP:
5.750% Senior Notes due 2034	—		1,198
2035 CQP Senior Notes	997		—
SPL:
SPL Revolving Credit Facility	265		30
Total proceeds from issuances of debt and borrowings	$	1,262	$	2,725

Debt Redemptions and Repayments

The following table shows the redemptions and repayments of debt, including intra-quarter activity (in millions):

	Nine Months Ended September 30,
	2025		2024
Redemptions and repayments of debt
SPL:
5.750% Senior Secured Notes due 2024	$	—	$	(300)
5.625% Senior Secured Notes due 2025	(300)		(1,350)
2026 SPL Senior Notes	(1,000)		—
4.746% weighted average rate Senior Notes due 2037	(52)		—
SPL Revolving Credit Facility	(265)		(30)
CCH:
5.875% Senior Notes due 2025	—		(1,491)
Total redemptions and repayments of debt	$	(1,617)	$	(3,171)

Repurchase of Common Stock

During the nine months ended September 30, 2025 and 2024, we paid $1.7 billion and $2.0 billion to repurchase approximately 7.4 million and 12.2 million shares of our common stock, respectively, under our share repurchase program. Additionally, during the nine months ended September 30, 2025, we paid $33 million of excise taxes related to our repurchase of common stock during the fiscal years 2023 and 2024. As of September 30, 2025, we had approximately $2.2 billion remaining under our share repurchase program.

Cash Dividends to Stockholders

During the nine months ended September 30, 2025, we paid aggregate dividends of $1.500 per share of common stock for a total of $332 million and during the nine months ended September 30, 2024, we paid aggregate dividends of $1.305 per share of common stock for a total of $300 million.

On October 28, 2025, we declared a quarterly dividend of $0.555 per share of common stock that is payable on November 18, 2025 to stockholders of record as of the close of business on November 7, 2025.

40

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, 2024.

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 derivatives consisting of natural gas and power supply contracts for the commissioning and operation of the Liquefaction Projects and the SPL Expansion Project, and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”) and physical and financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions):

	September 30, 2025				December 31, 2024
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	624	$	2,262	$	(742)	$	2,516
LNG Trading Derivatives	14		40		17		49

See Note 5—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 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 management, including our Chief Executive Officer and our 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 Chief Executive Officer and our 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. 

41

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. Other than as discussed below, 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, 2024.

Louisiana Department of Environmental Quality (“LDEQ”) Matter

We and another subsidiary of CQP are in discussions with the LDEQ to resolve alleged non-compliance with national emission standards for formaldehyde from combustion turbines at the Sabine Pass LNG Terminal. The allegations are identified in a Consolidated Compliance Order and Notice of Potential Penalty, Tracking No. AE-CN-22-00833 (the “2023 Compliance Order”) issued by the LDEQ on April 12, 2023. In August 2004, the U.S. Environmental Protection Agency (the “EPA”) stayed the application of the emission standard to combustion turbines such as those at the Sabine Pass LNG Terminal. In March 2022, the EPA lifted the stay, and in June 2022, we and the other subsidiary of CQP petitioned the EPA and LDEQ for approval of additional operating parameters to demonstrate compliance with the emission limitation. The EPA approved the petition on July 31, 2025 and in October 2025 the LDEQ confirmed that all remaining milestones under the 2023 Compliance Order have been met. We and the other subsidiary of CQP continue to work with the LDEQ to resolve the 2023 Compliance Order. As of December 2024, we and the other subsidiary of CQP had filed test results with the LDEQ indicating that for the 2024 testing period all 44 turbines met the relevant compliance standard. As of September 2025, for the 2025 testing period, all 44 turbines met the relevant compliance standard. We do not expect that any ultimate penalty will have a material adverse impact on our financial results.

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, 2024, except for the updates presented in our quarterly report on Form 10-Q for the quarterly period ended March 31, 2025.

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes share repurchases for the three months ended September 30, 2025:

Period	Total Number of Shares Purchased	Average Price Paid Per Share	Total Number of Shares Purchased as a Part of Publicly Announced Plans	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans (in millions)
July 1-31, 2025	1,661,471	$232.16	1,661,471	$2,848
August 1-31, 2025	1,258,050	$233.35	1,258,050	$2,555
September 1-30, 2025	1,446,845	$234.08	1,446,845	$2,216
Total	4,366,366		4,366,366

ITEM 5.    OTHER INFORMATION

Rule 10-b5-1 Trading Arrangements

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 our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three-month period ending September 30, 2025, none of our executive officers or directors 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).

42

ITEM 6.    EXHIBITS

Exhibit No.
	Description
10.1*	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00110 Owner Accommodations at Contractor CityWest Offices, dated May 22, 2025, (ii) the Change Order CO-00111 Trim Modifications on PV-17016 and PV-17516 Valves, dated July 21, 2025, (iii) the Change Order CO-00112 Supply of Train 2 Demineralized Water (Owner Request), dated July 25, 2025 and (iv) the Change Order CO-00113 Acceleration Program Extension (August - November 2025), dated August 4, 2025 (Portions of this exhibit have been omitted.)
31.1*	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*	Filed herewith.
**	Furnished herewith.

43

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 

		CHENIERE ENERGY, INC.
Date:	October 29, 2025	By:	/s/ Zach Davis
			Zach Davis
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	October 29, 2025	By:	/s/ David Slack
			David Slack
			Senior Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

44

EX-10.1

Exhibit 10.1

[***] indicates certain identified information has been excluded because it is both (a) not material and (b) would be competitively harmful if publicly disclosed.

CHANGE ORDER

OWNER ACCOMMODATIONS AT CONTRACTOR CITYWEST OFFICES

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00110 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 22-May-2025

The Agreement between the Parties listed above is changed as follows:

1.Pursuant to Article 2.3 (“Owner Accommodations at Contractor Project Offices”) of Attachment A, Schedule A-1 (“Scope of Work”) of the Agreement, Contractor presently has the obligation to accommodate in Contractor’s Houston home office up to a peak of fifty-five (55) Owner personnel for the period commencing at NTP and concluding at Substantial Completion of all Trains.

2.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”), Contractor’s scope for Owner personnel accommodation (Houston home office) is revised as follows:

2.1    With respect to the quantity of spaces to be provided, Owner has requested increases above fifty-five (55) spaces, as follows:

2.1.1    For the period August 2024 to October 2024 (inclusive); Owner requested that Contractor provide a full CityWest Building #4 floor that is the equivalent of one hundred and fifty-two (152) Owner spaces, and, in addition, a further two (2) dedicated large conference rooms the equivalent of fourteen (14) spaces;

2.1.2    For the period November 2024 through to April 2025 (inclusive); Owner requested that Contractor provide half of a CityWest Building #4 floor that is the equivalent of seventy-six (76) Owner spaces, and, in addition, a further two (2) dedicated large conference rooms the equivalent of fourteen (14) spaces;

2.1.3    For the period May 2025 through to December 2025 (inclusive); Owner has requested that Contractor provide half of a CityWest Building #4 floor that is the equivalent of seventy-six (76) Owner spaces, and, in addition, one (1) dedicated large conference room the equivalent of seven (7) spaces.

2.2    Further, Owner requested certain once-off modifications including offices/double-size offices and an additional huddle room.

2.3    This change order only funds such Owner increased accommodation through to 31-Dec-2025; accordingly Owner agrees to provide confirmation, on or before 31-Oct-2025, if Owner elects to continue with increased accommodation beyond 31-Dec-2025.

3.The detailed cost breakdown for this Change Order is detailed in Attachments 1 and 2 of this Change Order.

4.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ……………………………………………………..................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-000109)…….……	$	502,680,390
3. The Contract Price prior to this Change Order was ………………………………………........	$	5,986,680,390
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of .	$ [***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of ....................................................................................................................................	$ [***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ……………………………………………………………………………......	$ [***]
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..………………………………………………………………………	$ [***]
8. The new Contract Price including this Change Order will be …………………………………	$	5,987,680,390

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: No

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A]This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: SS Contractor IS Owner

[B]This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: Contractor _Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order.Except as modifiedbythisandanypreviouslyissuedChangeOrders,allothertermsandconditionsoftheAgreementshallremainin full force and effect.This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By: /s/ Ian Swanbeck

Name: Ian Swanbeck

Title: Vice President, Project Execution

BECHTEL ENERGY INC.

By: /s/ Steve Smith

Name: Steve Smith

Title: Cheniere Program Manager and Senior Vice President

CHANGE ORDER

Trim Modifications On PV-17016 And PV-17516 Valves

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00111 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 21-Jul-2025

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”), at Owner’s request, the scope of the Agreement is revised as follows:

1.1.With respect to Train 1, Contractor will provide Owner with originally designed actuators and topworks from Train 7 for Owner’s subcontractor to retrofit. Owner to install retrofitted actuators and topworks and return presently-installed actuators and topworks to meet Contractor’s schedule.

1.2.With respect to Train 2, Contractor will provide originally designed actuators and topworks from Train 6 to Owner to retrofit. Contractor to uninstall currently installed actuators and topworks and then install retrofitted actuators and topworks, once received from Owner, prior to Contractor's Train 2 strainer outage.

1.3.With respect to Trains 3-7, Contractor will send actuators and topworks offsite for retrofit per Owner’s direction. Contractor to install retrofitted actuators and topworks prior to the respective Substantial Completion of each Train.

2.For clarity, [***]. Presently, Owner has nominated the consideration of additional operations cases per Owner transmittal “CCL-0629-000-00-DMC-TRN-000002” and based on the new cases, Flowserve and Chart have designed a new valve trim per RCA conducted by Owner.

3.Additionally, Owner acknowledges that this Change Order does not serve to revise the feed gas composition, LNG production, or the operation of the heavies removal unit as is stated in the design basis of the Agreement. Owner further acknowledges [***].

4.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

5.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ………………………………………………………….................	$5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-000110)……….……….	$503,680,390
3. The Contract Price prior to this Change Order was ………………………………………...............	$5,987,680,390
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of ...........	$ [***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of .	$ [***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………...............	$ [***]
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$ [***]
8. The new Contract Price including this Change Order will be ……………………………………...	$5,989,169,522

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: No

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A]This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: MDR Contractor IS Owner

[B]This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: Contractor _Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By: /s/ Ian Swanbeck

Name: Ian Swanbeck

Title: Vice President, Project Execution

BECHTEL ENERGY INC.

By: /s/ Maurissa Douglas Rogers

Name: Maurissa Douglas Rogers

Title: Cheniere Program Manager and Senior Vice President

­­CHANGE ORDER

SUPPLY OF TRAIN 2 DEMINERALIZED WATER (OWNER REQUEST)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00112 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 25-Jul-2025

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”), at Owner’s request, Contractor will supply certain quantities of demineralized water on Owner’s behalf with respect to Train 2 only.

2.This Change Order includes the cost of demineralized water supply, and the cost of the delivery truck’s standby time to pump water from the truck to the frac tank.

3.For context, demineralized water was originally an Owner-furnished item to be provided 365 days prior to the RFSU of each Train pursuant to Item 2 of Attachment V of the Agreement.

4.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

5.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...........	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-000111)……….….....	$	505,169,522
3. The Contract Price prior to this Change Order was ……………………………………….........	$	5,989,169,522
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of....	$ [***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of ..................................................................................................................................................	$ [***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ……………………………………………………………………………….......	$ [***]
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………..........	$ [***]
8. The new Contract Price including this Change Order will be …………………………….……	$	5,989,625,745

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: No

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A]This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: MDR Contractor IS Owner

[B]This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: Contractor _Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By: /s/ Ian Swanbeck

Name: Ian Swanbeck

Title: Vice President, Project Execution

BECHTEL ENERGY INC.

By: /s/ Maurissa Douglas Rogers

Name: Maurissa Douglas Rogers

Title: Cheniere Program Manager and Senior Vice President

­­CHANGE ORDER

ACCELERATION PROGRAM EXTENSION (AUGUST - NOVEMBER 2025)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00113 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 04-Aug-2025

The Agreement between the Parties listed above is changed as follows:

1.    Capitalized terms not defined in this Change Order have the meaning set forth in the Agreement;

2.    Whereas Owner has requested Contractor developed a program targeting acceleration of respective present Forecast 1st LNG/RFSU dates as noted in the table below:

Train	Forecast 1st LNG/RFSU range
Train 3- String 2	[***]
Train 3- String 1	[***]
Train 4	[***]
Train 5 - Note 1	[***]
Train 6 - Note 1	[***]
Train 7 - Note 1	[***]

Note 1: Trains 5, 6 and 7 Accelerated RFSU dates assumes continuation of Acceleration Program through [***]

3.    Contractor will issue monthly individual forecast curves to substantial completion for Trains 3-4 reflecting the Acceleration Program Extension.

4.    Accordingly, the Parties agree to implement an acceleration program with respect to Train 3 and Train 4, compensable as a new Provisional Sum (together the “Acceleration Program Extension”, with this Provisional Sum being the “APE Provisional Sum”). Therefore, Attachment GG (Provisional Sums) of the Agreement is revised to include Section 12 as set forth in Attachment 1 of this Change Order.

5.    Notwithstanding that the Parties have agreed to call this a Provisional Sum, in this case Contractor may not invoice any costs or expenses incurred for the Acceleration Program Extension in excess of the APE Provisional Sum amount of [***](U.S. $[***]) in the aggregate. Unless Owner otherwise agrees by Change Order, any amounts invoiced for the Acceleration Program Extension in excess of U.S. $[***] shall be for Contractor’s account. Notwithstanding anything to the contrary herein, Contractor shall not be obligated to continue the Acceleration Program Extension once the APE Provisional Sum has been exceeded.

6.    The APE Provisional Sum shall, notwithstanding anything to the contrary, apply only to the methodologies necessary to accelerate the Work (as further detailed in this Change Order) and any such amounts may not be applied to any activities that Contractor would otherwise be performing, or would otherwise have performed, if the Parties had not executed this Change Order. The APE Provisional Sum mechanism shall be as follows: Contractor shall submit a formal offer of proposed APE Provisional Sum methodologies and corresponding amounts for the subsequent month, and the Parties shall mutually agree on such methodologies and amounts. In the subsequent month, actual methodologies performed by Contractor will be trued up as set forth in Section 12.3 of Attachment 1.

7.    Parties agree that Contractor will not charge Owner any type of markup for the subject Acceleration Program.

8.    Parties agree there shall be one (1) cost reconciliation to adjust the APE Provisional Sum by Change Order at the end of the Acceleration Program Extension (but only if the costs and expenses incurred by Contractor for the Acceleration Program Extension are less than the APE Provisional Sum), provided, however, there shall be a rolling Monthly process (as set forth in Attachment 1) by which to review and true up such payments from previous Months.

9.    Parties acknowledge that Owner may unilaterally cancel the Acceleration Program Extension provided that a minimum notice of one (1) Month is given to Contractor. The Parties agree that continuation of the Acceleration Program Extension is predicated on improvement in schedule across all remaining Trains with RFSU dates reforecast on a monthly basis. Contractor shall provide Owner with the following items on the same day Contractor provides Owner the Monthly Updated Project Schedule as required under Section 5.4D of the Agreement: 1) planned and actual progress by Train for Trains 3-4; 2) the proposed subsequent month APE Provisional Sum; and 3) the revised RFSU date summary table.

10.    Schedule C-1 (Aggregate Labor and Skills Price Payment Milestones) of the Agreement will be updated to add the Payment Milestone(s) listed in Exhibit 1 of this Change Order.

11.    For the avoidance of doubt, there shall be no adjustment to the Guaranteed Dates as a result of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ………………………………………………………….................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00112)……….….…......	$	505,625,745
3. The Contract Price prior to this Change Order was ………………………………………...............	$	5,989,625,745
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of ........	$ [***]
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..	$ [***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………...	$ [***]
7. The Aggregate Provisional Sum Labor and Skills Price will be (increased) by this Change Order in the amount of ..…………………………………………………………………………...............	$ [***]
8. The new Contract Price including this Change Order will be ……………………………………...	$	6,033,899,555

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: N/A

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: MDR Contractor IS Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By: /s/ Ian Swanbeck

Name: Ian Swanbeck

Title: Vice President, Project Execution

BECHTEL ENERGY INC.

By: /s/ Maurissa Douglas Rogers

Name: Maurissa Douglas Rogers

Title: Cheniere Program Manager and Senior Vice President

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Jack A. Fusco, certify that:

1.    I have reviewed this quarterly report on Form 10-Q of Cheniere Energy, Inc.;

2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)     Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)     Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d)     Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)     All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)     Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2025 

/s/ Jack A. Fusco

Jack A. Fusco
Chief Executive Officer of

Cheniere Energy, Inc.

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Zach Davis, certify that:

1.    I have reviewed this quarterly report on Form 10-Q of Cheniere Energy, Inc.;

2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)     Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)     Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)     Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d)     Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)     All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)     Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2025

/s/ Zach Davis

Zach Davis
Chief Financial Officer of

Cheniere Energy, Inc.

EX-32.1

Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: October 29, 2025 

/s/ Jack A. Fusco

Jack A. Fusco
Chief Executive Officer of

Cheniere Energy, Inc.

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Zach Davis, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: October 29, 2025 

/s/ Zach Davis

Zach Davis
Chief Financial Officer of

Cheniere Energy, Inc.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2025	Oct. 24, 2025
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2025
Document Transition Report	false
Entity File Number	001-16383
Entity Registrant Name	CHENIERE ENERGY, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	95-4352386
Entity Address, Address Line One	845 Texas Avenue
Entity Address, Address Line Two	Suite 1250
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	375-5000
Title of 12(b) Security	Common Stock, $ 0.003 par value
Trading Symbol	LNG
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		215,234,776
Entity Central Index Key	0000003570
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	Q3

XML

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended			9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024		Sep. 30, 2025	Sep. 30, 2024
Revenues
Revenues		$ 4,441	$ 3,763		$ 14,526	$ 11,267
Operating costs and expenses
Cost of sales (excluding operating and maintenance expense and depreciation, amortization and accretion expense shown separately below)		1,750	1,255		6,438	4,275
Operating and maintenance expense		447	450		1,479	1,364
Selling, general and administrative expense		81	99		296	299
Depreciation, amortization and accretion expense		338	306		979	912
Other operating costs and expenses		8	6		26	28
Total operating costs and expenses		2,624	2,116		9,218	6,878
Income from operations		1,817	1,647		5,308	4,389
Other income (expense)
Interest expense, net of capitalized interest		(236)	(247)		(702)	(770)
Loss on modification or extinguishment of debt		(7)	0		(7)	(9)
Interest and dividend income		23	41		91	149
Other income (expense), net		2	(3)		21	(1)
Total other expense		(218)	(209)		(597)	(631)
Income before income taxes and NCI		1,599	1,438		4,711	3,758
Less: income tax provision		303	231		850	550
Net income		1,296	1,207		3,861	3,208
Less: net income attributable to NCI		247	314		833	933
Net income attributable to Cheniere		$ 1,049	$ 893		$ 3,028	$ 2,275
Net income per share attributable to common stockholders—basic (1)	[1]	$ 4.76	$ 3.95	[2]	$ 13.63	$ 9.91	[2]
Net income per share attributable to common stockholders—diluted (1)	[1]	$ 4.75	$ 3.93	[2]	$ 13.59	$ 9.88	[2]
Weighted average number of common shares outstanding—basic		219.3	226.3		221.5	229.6
Weighted average number of common shares outstanding—diluted		219.9	227.0		222.1	230.3
LNG [Member]
Revenues
Revenues		$ 4,302	$ 3,554		$ 14,122	$ 10,633
Regasification [Member]
Revenues
Revenues		34	34		102	102
Other [Member]
Revenues
Revenues		$ 105	$ 175		$ 302	$ 532

[1] 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.

[2] In computing basic and diluted net income per share attributable to common stockholders, net income attributable to Cheniere is adjusted for the remeasurement of the redeemable NCI, net of tax, to its redemption value, as required under the two-class method. See Note 13—Net Income per Share Attributable to Common Stockholders for the full computation.

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2025		Dec. 31, 2024
Current assets
Cash and cash equivalents	$ 1,075	[1]	$ 2,638
Restricted cash and cash equivalents	323	[1]	552
Trade and other receivables, net of current expected credit losses	1,324		727
Inventory	458		501
Current derivative assets	89		155
Margin deposits	103		128
Other current assets, net	129		100
Total current assets	3,501		4,801
Property, plant and equipment, net of accumulated depreciation	35,345		33,552
Operating lease assets	2,627		2,684
Derivative assets	2,565		1,903
Deferred tax assets	17		19
Other non-current assets, net	1,047		899
Total assets	45,102	[1]	43,858
Current liabilities
Accounts payable	279		171
Accrued liabilities	1,492		2,179
Current debt, net of unamortized discount and debt issuance costs	605		351
Deferred revenue	176		163
Current operating lease liabilities	539		592
Current derivative liabilities	556		902
Other current liabilities	92		83
Total current liabilities	3,739		4,441
Long-term debt, net of unamortized discount and debt issuance costs	21,957		22,554
Non-current operating lease liabilities	2,091		2,090
Derivative liabilities	1,464		1,865
Deferred tax liabilities	3,075		1,856
Other non-current liabilities	1,315		992
Total liabilities	33,641		33,798
Redeemable NCI	118		7
Stockholders’ equity
Preferred stock: $0.0001 par value, 5.0 million shares authorized, none issued	0		0
Common stock: $0.003 par value, 480.0 million shares authorized; 279.3 million shares and 278.7 million shares issued at September 30, 2025 and December 31, 2024, respectively	1		1
Treasury stock: 62.1 million shares and 54.7 million shares at September 30, 2025 and December 31, 2024, respectively, at cost	(7,826)		(6,136)
Additional paid-in-capital	4,507		4,452
Retained earnings	10,067		7,382
Total Cheniere stockholders’ equity	6,749		5,699
NCI	4,594		4,354
Total stockholders’ equity	11,343		10,053
Total liabilities, redeemable NCI and stockholders’ equity	$ 45,102	[1]	$ 43,858

[1] Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), substantially all of which are related to CQP, as further discussed in Note 6—Non-Controlling Interests and Variable Interest Entities. As of September 30, 2025, total assets and liabilities of our VIEs were $16.7 billion and $17.1 billion, respectively, including $121 million of cash and cash equivalents and $61 million of restricted cash and cash equivalents.

XML

Consolidated Balance Sheets Parentheticals - USD ($) $ in Millions	Sep. 30, 2025		Dec. 31, 2024
Total assets	$ 45,102	[1]	$ 43,858
Total liabilities	33,641		33,798
Cash and cash equivalents	1,075	[1]	2,638
Restricted cash and cash equivalents	$ 323	[1]	$ 552
Preferred Stock, Par Value	$ 0.0001		$ 0.0001
Preferred Stock, Shares Authorized	5,000,000.0		5,000,000.0
Preferred Stock, Shares Issued	0		0
Common Stock, Par Value Per Share	$ 0.003		$ 0.003
Common stock, Shares Authorized	480,000,000.0		480,000,000.0
Common Stock, Shares, Issued	279,300,000		278,700,000
Treasury Stock, Common	62,100,000		54,700,000
Variable Interest Entities [Member]
Total assets	$ 16,691		$ 17,345
Total liabilities	17,141		17,918
Cash and cash equivalents	121		270
Restricted cash and cash equivalents	$ 61		$ 125

[1] Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), substantially all of which are related to CQP, as further discussed in Note 6—Non-Controlling Interests and Variable Interest Entities. As of September 30, 2025, total assets and liabilities of our VIEs were $16.7 billion and $17.1 billion, respectively, including $121 million of cash and cash equivalents and $61 million of restricted cash and cash equivalents.

XML

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions		Total	2025 Q1 Dividends	2025 Q2 Dividends - April	2025 Q2 Dividends - June	2024 Q1 Dividends	2024 Q2 Dividends - April	2024 Q2 Dividends - June	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	NCI	Redeemable NCI
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2023									237,000
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2023										40,900
Stockholders' Equity, Beginning of Period at Dec. 31, 2023		$ 9,020							$ 1	$ (3,864)	$ 4,377	$ 4,546	$ 3,960
Redeemable NCI, Equity, Carrying Amount at Dec. 31, 2023	[1]													$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Non Redeemable NCI		839										502	337
Dividends declared		(103)										(103)
Shares repurchased, at cost and inclusive of excise taxes, shares									(7,500)	7,500
Shares repurchased, at cost and inclusive of excise taxes		(1,203)								$ (1,203)
Distributions to NCI		(253)											(253)
Contributions from redeemable NCI	[1]													4
Vesting of share-based compensation awards, shares									600
Share-based compensation		34									34
Issued shares withheld from employees related to share-based compensation, at cost		(40)									(40)
Common Stock, Shares, Outstanding, End of Period at Mar. 31, 2024									230,100
Treasury Stock, Shares, End of Period at Mar. 31, 2024										48,400
Stockholders' Equity, End of Period at Mar. 31, 2024		8,294							$ 1	$ (5,067)	4,371	4,945	4,044
Redeemable NCI, Equity, Carrying Amount at Mar. 31, 2024	[1]													4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared						$ 0.435
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2023									237,000
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2023										40,900
Stockholders' Equity, Beginning of Period at Dec. 31, 2023		$ 9,020							$ 1	$ (3,864)	4,377	4,546	3,960
Redeemable NCI, Equity, Carrying Amount at Dec. 31, 2023	[1]													0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares repurchased, at cost and inclusive of excise taxes, shares		12,240
Contributions from redeemable NCI		$ 6
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2024									225,400
Treasury Stock, Shares, End of Period at Sep. 30, 2024										53,100
Stockholders' Equity, End of Period at Sep. 30, 2024		9,347							$ 1	$ (5,853)	4,436	6,518	4,245
Redeemable NCI, Equity, Carrying Amount at Sep. 30, 2024	[1]													6
Common Stock, Shares, Outstanding, Beginning of Period at Mar. 31, 2024									230,100
Treasury Stock, Shares, Beginning of Period at Mar. 31, 2024										48,400
Stockholders' Equity, Beginning of Period at Mar. 31, 2024		8,294							$ 1	$ (5,067)	4,371	4,945	4,044
Redeemable NCI, Equity, Carrying Amount at Mar. 31, 2024	[1]													4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Non Redeemable NCI		1,162										880	282
Dividends declared		(200)										(200)
Shares repurchased, at cost and inclusive of excise taxes, shares									(3,100)	3,100
Shares repurchased, at cost and inclusive of excise taxes		(501)								$ (501)
Distributions to NCI		(198)											(198)
Contributions from redeemable NCI	[1]													2
Share-based compensation		36									36
Issued shares withheld from employees related to share-based compensation, at cost		(1)									(1)
Common Stock, Shares, Outstanding, End of Period at Jun. 30, 2024									227,000
Treasury Stock, Shares, End of Period at Jun. 30, 2024										51,500
Stockholders' Equity, End of Period at Jun. 30, 2024		8,592							$ 1	$ (5,568)	4,406	5,625	4,128
Redeemable NCI, Equity, Carrying Amount at Jun. 30, 2024	[1]													6
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared							$ 0.435	$ 0.435
Net Income (Loss), Including Portion Attributable to Non Redeemable NCI		$ 1,207										893	314
Shares repurchased, at cost and inclusive of excise taxes, shares		1,580							(1,600)	1,600
Shares repurchased, at cost and inclusive of excise taxes		$ (285)								$ (285)
Distributions to NCI		(197)											(197)
Share-based compensation		34									34
Issued shares withheld from employees related to share-based compensation, at cost		(4)									(4)
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2024									225,400
Treasury Stock, Shares, End of Period at Sep. 30, 2024										53,100
Stockholders' Equity, End of Period at Sep. 30, 2024		$ 9,347							$ 1	$ (5,853)	4,436	6,518	4,245
Redeemable NCI, Equity, Carrying Amount at Sep. 30, 2024	[1]													6
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2024									224,000
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2024		54,700								54,700
Stockholders' Equity, Beginning of Period at Dec. 31, 2024		$ 10,053							$ 1	$ (6,136)	4,452	7,382	4,354
Redeemable NCI, Equity, Carrying Amount at Dec. 31, 2024		7												7	[1]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Non Redeemable NCI		670										353	317
Net Income (Loss) Attributable to Redeemable NCI	[1]													(2)
Dividends declared		(113)										(113)
Shares repurchased, at cost and inclusive of excise taxes, shares									(1,600)	1,600
Shares repurchased, at cost and inclusive of excise taxes		(352)								$ (352)
Accretion of redeemable non-controlling interest, net of tax	[2]	(2)										(2)		2	[1]
Distributions to NCI		(200)											(200)
Contributions from redeemable NCI	[1]													38
Vesting of share-based compensation awards, shares									400
Share-based compensation		40									40
Issued shares withheld from employees related to share-based compensation, at cost		(44)									(44)
Common Stock, Shares, Outstanding, End of Period at Mar. 31, 2025									222,800
Treasury Stock, Shares, End of Period at Mar. 31, 2025										56,300
Stockholders' Equity, End of Period at Mar. 31, 2025		$ 10,052							$ 1	$ (6,488)	4,448	7,620	4,471
Redeemable NCI, Equity, Carrying Amount at Mar. 31, 2025	[1]													45
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2024									224,000
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2024		54,700								54,700
Stockholders' Equity, Beginning of Period at Dec. 31, 2024		$ 10,053							$ 1	$ (6,136)	4,452	7,382	4,354
Redeemable NCI, Equity, Carrying Amount at Dec. 31, 2024		$ 7												7	[1]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares repurchased, at cost and inclusive of excise taxes, shares		7,370
Contributions from redeemable NCI		$ 108
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2025									217,200
Treasury Stock, Shares, End of Period at Sep. 30, 2025		62,100								62,100
Stockholders' Equity, End of Period at Sep. 30, 2025		$ 11,343							$ 1	$ (7,826)	4,507	10,067	4,594
Redeemable NCI, Equity, Carrying Amount at Sep. 30, 2025		118												118	[1]
Common Stock, Shares, Outstanding, Beginning of Period at Mar. 31, 2025									222,800
Treasury Stock, Shares, Beginning of Period at Mar. 31, 2025										56,300
Stockholders' Equity, Beginning of Period at Mar. 31, 2025		10,052							$ 1	$ (6,488)	4,448	7,620	4,471
Redeemable NCI, Equity, Carrying Amount at Mar. 31, 2025	[1]													45
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Non Redeemable NCI		1,899										1,626	273
Net Income (Loss) Attributable to Redeemable NCI	[1]													(2)
Dividends declared		(222)										(222)
Shares repurchased, at cost and inclusive of excise taxes, shares									(1,400)	1,400
Shares repurchased, at cost and inclusive of excise taxes		(310)								$ (310)
Accretion of redeemable non-controlling interest, net of tax	[2]	(3)										(3)		4	[1]
Distributions to NCI		(200)											(200)
Contributions from redeemable NCI	[1]													11
Vesting of share-based compensation awards, shares									100
Share-based compensation		37									37
Issued shares withheld from employees related to share-based compensation, at cost		(2)									(2)
Common Stock, Shares, Outstanding, End of Period at Jun. 30, 2025									221,500
Treasury Stock, Shares, End of Period at Jun. 30, 2025										57,700
Stockholders' Equity, End of Period at Jun. 30, 2025		11,251							$ 1	$ (6,798)	4,483	9,021	4,544
Redeemable NCI, Equity, Carrying Amount at Jun. 30, 2025	[1]													58
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared			$ 0.500	$ 0.500	$ 0.500
Net Income (Loss), Including Portion Attributable to Non Redeemable NCI		$ 1,299										1,049	250
Net Income (Loss) Attributable to Redeemable NCI	[1]													(3)
Shares repurchased, at cost and inclusive of excise taxes, shares		4,370							(4,400)	4,400
Shares repurchased, at cost and inclusive of excise taxes		$ (1,028)								$ (1,028)
Accretion of redeemable non-controlling interest, net of tax	[2]	(3)										(3)		4	[1]
Distributions to NCI		(200)											(200)
Contributions from redeemable NCI	[1]													59
Vesting of share-based compensation awards, shares									100
Share-based compensation		28									28
Issued shares withheld from employees related to share-based compensation, at cost		$ (4)									(4)
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2025									217,200
Treasury Stock, Shares, End of Period at Sep. 30, 2025		62,100								62,100
Stockholders' Equity, End of Period at Sep. 30, 2025		$ 11,343							$ 1	$ (7,826)	$ 4,507	$ 10,067	$ 4,594
Redeemable NCI, Equity, Carrying Amount at Sep. 30, 2025		$ 118												$ 118	[1]

[1] Redeemable NCI represents the economic interest held by a third party in one of our consolidated VIEs that is redeemable for cash under certain circumstances, including those that are outside of our control. As such, the economic interest is not a component of permanent equity on our Consolidated Balance Sheets.

[2] Amount in retained earnings presented net of tax.

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2025	Sep. 30, 2024
Cash flows from operating activities
Net income	$ 3,861	$ 3,208
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion expense	979	912
Share-based compensation expense	140	140
Amortization of discount and debt issuance costs	29	32
Reduction of right-of-use assets	465	500
Total gains on derivative instruments, net	(1,629)	(861)
Net cash provided by settlement of derivative instruments	286	0
Deferred taxes	1,227	93
Other, net	11	27
Changes in operating assets and liabilities:
Trade and other receivables	(587)	427
Inventory	42	50
Margin deposits	25	(85)
Other non-current assets	(148)	(55)
Accounts payable and accrued liabilities	(672)	(207)
Total deferred revenue	(10)	24
Total operating lease liabilities	(459)	(489)
Other, net	(76)	37
Net cash provided by operating activities	3,484	3,753
Cash flows from investing activities
Property, plant and equipment, net of proceeds on commissioning sales of LNG of $94 million and zero, respectively	(2,334)	(1,669)
Other, net	71	(37)
Net cash used in investing activities	(2,263)	(1,706)
Cash flows from financing activities
Proceeds from issuances of debt and borrowings	1,262	2,725
Redemptions and repayments of debt	(1,617)	(3,171)
Distributions to NCI	(600)	(648)
Contributions from redeemable NCI	108	6
Payments related to tax withholdings for share-based compensation	(50)	(45)
Repurchase of common stock, inclusive of excise taxes paid	(1,687)	(1,981)
Dividends to stockholders	(332)	(300)
Other, net	(94)	(79)
Net cash used in financing activities	(3,010)	(3,493)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	(3)	(3)
Net decrease in cash, cash equivalents and restricted cash and cash equivalents	(1,792)	(1,449)
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	3,190	4,525
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$ 1,398	$ 3,076

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Consolidated Statements of Cash Flows Parenthetical - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2025	Sep. 30, 2024
Cash flows from investing activities
Property, Plant And Equipment, Reduction For Testing Costs Recovered, Collected Portion	$ 94	$ 0

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Nature of Operations and Basis of Presentation

9 Months Ended

Sep. 30, 2025

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 12 mtpa was under construction and the remainder was in operation as of September 30, 2025, 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 September 30, 2025, 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 12 mtpa under construction and the remainder in operation as of September 30, 2025, from 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 approximately 7 mtpa under construction and the remainder in operation from the first two midscale Trains that have reached substantial completion as of September 30, 2025 (subsequently, in October 2025, the third midscale Train reached substantial completion); 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 September 30, 2025. Our board of directors (the “Board”) made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project on June 17, 2025, and issued a full notice to proceed with construction to Bechtel Energy Inc. effective June 18, 2025.

In addition to the above, 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. 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 the 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, 2024.

Results of operations for the three and nine months ended September 30, 2025 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2025.

Recent Accounting Standards

ASU 2023-09

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740). This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. The adoption of this guidance will not have an impact on our results of operations and financial condition but will have an impact on the annual disclosures required in the relevant notes to the consolidated financial statements. This guidance applies prospectively, with retrospective application permitted. We are progressing on the implementation and evaluating the method of adoption. We will adopt this guidance and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2025.

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.

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Trade and Other Receivables, Net of Current Expected Credit Losses

9 Months Ended

Sep. 30, 2025

Receivables [Abstract]

Trade and Other Receivables, Net of Current Expected Credit Losses

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):

	September 30,		December 31,
	2025		2024
Trade receivables
SPL and CCL	$	518	$	548
Cheniere Marketing	274		109
Other subsidiaries	7		4
Total trade receivables	799		661
Other receivables
Tax-related receivables	441		29
Other	84		37
Total other receivables	525		66
Total trade and other receivables, net of current expected credit losses	$	1,324	$	727

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Inventory

9 Months Ended

Sep. 30, 2025

Inventory Disclosure [Abstract]

Inventory

INVENTORY

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2025		2024
Materials	$	256	$	226
LNG	85		93
LNG in-transit	79		137
Natural gas	19		30
Other	19		15
Total inventory	$	458	$	501

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Property, Plant and Equipment, Net of Accumulated Depreciation

9 Months Ended

Sep. 30, 2025

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

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

	September 30,		December 31,
	2025		2024
Terminal and related assets
Terminal and interconnecting pipeline facilities	$	36,492	$	34,282
Land	618		465
Construction-in-process	5,396		5,486
Accumulated depreciation	(8,115)		(7,231)
Total terminal and related assets, net of accumulated depreciation	34,391		33,002
Fixed assets and other
Computer and office equipment	39		36
Furniture and fixtures	33		31
Computer software	124		122
Leasehold improvements	47		47
Other	24		24
Accumulated depreciation	(200)		(188)
Total fixed assets and other, net of accumulated depreciation	67		72
Assets under finance leases
Marine assets	1,060		587
Accumulated depreciation	(173)		(109)
Total assets under finance leases, net of accumulated depreciation	887		478
Property, plant and equipment, net of accumulated depreciation	$	35,345	$	33,552

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Depreciation expense	$	337	$	304	$	973	$	907
Offsets to LNG terminal costs (1)	47		—		102		—

(1)We recognized offsets to LNG terminal costs related to the sale of commissioning volumes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the CCL Project and the SPL Project (collectively, the “Liquefaction Projects”) during the testing phase for its construction.

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Derivative Instruments

9 Months Ended

Sep. 30, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

We have the following derivative instruments:

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

◦natural gas and power supply contracts, including our IPM agreements, 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 derivatives 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 United States.

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
	September 30, 2025								December 31, 2024
	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)	$	—	$	35	$	589	$	624	$	—	$	59	$	(801)	$	(742)
LNG Trading Derivatives asset	—		14		—		14		—		17		—		17
FX Derivatives asset (liability)	—		(4)		—		(4)		—		16		—		16

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 or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

The Level 3 fair value measurements of our natural gas positions within the Liquefaction Supply Derivatives could be materially impacted by a significant 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 September 30, 2025:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$589	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.638) - $0.295 / $(0.087)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	66% - 391% / 177%

(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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Balance, beginning of period	$	(10)	$	(1,729)	$	(801)	$	(2,178)
Realized and change in fair value gains (losses) included in net income (1):
Included in cost of sales, existing deals (2)	413		256		786		470
Included in cost of sales, new deals (3)	(3)		(4)		(13)		11
Purchases and settlements:
Purchases (4)	—		—		—		—
Settlements (5)	190		204		623		426
Transfers out of level 3 (6)	(1)		5		(6)		3
Balance, end of period	$	589	$	(1,268)	$	589	$	(1,268)
Favorable changes in fair value relating to instruments still held at the end of the period	$	410	$	252	$	773	$	481

(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.

(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.

Commodity Derivatives

We hold Liquefaction Supply Derivatives, which are indexed to Henry Hub, global LNG or other natural gas price indices. As of September 30, 2025, 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 or development of infrastructure to support natural gas gathering and transport.

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:

	September 30, 2025		December 31, 2024
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives
Notional amount, net (in TBtu)	12,625	(9)	12,503	(8)

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both September 30, 2025 and December 31, 2024.

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 September 30,				Nine Months Ended September 30,
		2025		2024		2025		2024
LNG Trading Derivatives	LNG revenues	$	96	$	(3)	$	373	$	14
LNG Trading Derivatives	Cost of sales	(67)		(7)		(64)		(27)
Liquefaction Supply Derivatives (2)	LNG revenues	—		(2)		2		—
Liquefaction Supply Derivatives (2)	Cost of sales	636		490		1,373		869

(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.

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 $1,150 million and $642 million as of September 30, 2025 and December 31, 2024, respectively.

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 September 30,				Nine Months Ended September 30,
		2025		2024		2025		2024
FX Derivatives	LNG revenues	$	6	$	(10)	$	(55)	$	5

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

	September 30, 2025
	Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	42	$	47	$	—	$	89
Derivative assets	2,564		—		1		2,565
Total derivative assets	2,606		47		1		2,654
Current derivative liabilities	(518)		(33)		(5)		(556)
Derivative liabilities	(1,464)		—		—		(1,464)
Total derivative liabilities	(1,982)		(33)		(5)		(2,020)
Derivative asset (liability), net	$	624	$	14	$	(4)	$	634
	December 31, 2024
	Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	105	$	32	$	18	$	155
Derivative assets	1,903		—		—		1,903
Total derivative assets	2,008		32		18		2,058
Current derivative liabilities	(885)		(15)		(2)		(902)
Derivative liabilities	(1,865)		—		—		(1,865)
Total derivative liabilities	(2,750)		(15)		(2)		(2,767)
Derivative asset (liability), net	$	(742)	$	17	$	16	$	(709)

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 September 30, 2025
Gross assets	$	3,972	$	48	$	2
Offsetting amounts	(1,366)		(1)		(1)
Net assets (1)	$	2,606	$	47	$	1
Gross liabilities	$	(2,044)	$	(51)	$	(7)
Offsetting amounts	62		18		2
Net liabilities (2)	$	(1,982)	$	(33)	$	(5)
As of December 31, 2024
Gross assets	$	3,064	$	42	$	25
Offsetting amounts	(1,056)		(10)		(7)
Net assets (1)	$	2,008	$	32	$	18
Gross liabilities	$	(2,790)	$	(16)	$	(3)
Offsetting amounts	40		1		1
Net liabilities (2)	$	(2,750)	$	(15)	$	(2)

(1)Includes current and non-current derivative assets of $89 million and $2,565 million, respectively, as of September 30, 2025 and $155 million and $1,903 million, respectively, as of December 31, 2024.

(2)Includes current and non-current derivative liabilities of $556 million and $1,464 million, respectively, as of September 30, 2025 and $902 million and $1,865 million, respectively, as of December 31, 2024.

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

	Consolidated Balance Sheets Location	September 30,		December 31,
		2025		2024
Liquefaction Supply Derivatives	Margin deposits	$	23	$	18
Liquefaction Supply Derivatives	Other current liabilities	1		—
LNG Trading Derivatives	Margin deposits	80		110

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Non-Controlling Interest and Variable Interest Entities

9 Months Ended

Sep. 30, 2025

Noncontrolling Interest and Variable Interest Entity [Abstract]

Non-Controlling Interest and Variable Interest Entities

NON-CONTROLLING INTERESTS AND VARIABLE INTEREST ENTITIES

Substantially all of our consolidated VIEs’ assets and liabilities relate to CQP. 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.

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

	September 30,		December 31,
	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	121	$	270
Restricted cash and cash equivalents	61		125
Trade and other receivables, net of current expected credit losses	360		381
Inventory	152		154
Current derivative assets	15		84
Margin deposits	14		13
Other current assets, net	61		54
Total current assets	784		1,081
Property, plant and equipment, net of accumulated depreciation	15,532		15,880
Operating lease assets	79		80
Derivative assets	14		98
Other non-current assets, net	282		206
Total assets	$	16,691	$	17,345
LIABILITIES
Current liabilities
Accounts payable	$	73	$	70
Accrued liabilities	701		881
Current debt, net of unamortized discount and debt issuance costs	605		351
Deferred revenue	148		120
Current operating lease liabilities	5		4
Current derivative liabilities	139		250
Other current liabilities	8		16
Total current liabilities	1,679		1,692
Long-term debt, net of unamortized discount and debt issuance costs	14,156		14,761
Operating lease liabilities	74		76
Derivative liabilities	1,069		1,213
Other non-current liabilities	163		176
Total liabilities	$	17,141	$	17,918

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Accrued Liabilities

9 Months Ended

Sep. 30, 2025

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2025		2024
Natural gas purchases	$	676	$	886
Terminal and related asset costs	219		272
Interest costs and related debt fees	266		214
Compensation and benefits	176		283
Tax-related liabilities	115		472
Other accrued liabilities	40		52
Total accrued liabilities	$	1,492	$	2,179

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Debt

9 Months Ended

Sep. 30, 2025

Debt Disclosure [Abstract]

Debt

DEBT

Debt consisted of the following (in millions): 

	September 30,		December 31,
	2025		2024
SPL:
Senior Secured Notes:
5.625% due 2025	$	—	$	300
5.875% due 2026	500		1,500
5.00% due 2027	1,500		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 4.747% and 4.746% at September 30, 2025 and December 31, 2024, respectively (1)	1,730		1,782
Total SPL Senior Secured Notes	7,080		8,432
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	7,080		8,432
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 (2)	1,000		—
Total CQP Senior Notes	7,800		6,800
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	7,800		6,800
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”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”)	—		—
Total debt - CCH	4,865		4,865
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
5.650% Senior Notes due 2034	1,500		1,500
Total Cheniere Senior Notes	3,000		3,000
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	3,000		3,000
Total debt	22,745		23,097
Current debt, net of unamortized discount and debt issuance costs (1)	(605)		(351)
Unamortized discount and debt issuance costs	(183)		(192)
Total long-term debt, net of unamortized discount and debt issuance costs	$	21,957	$	22,554

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

(2)Issued in July 2025 pursuant to the same base indenture as the other CQP Senior Notes, as supplemented by the tenth supplemental indenture. See annual report on Form 10-K for the fiscal year ended December 31, 2024 for additional information regarding the guarantee, security and redemption option of CQP Senior Notes.

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of September 30, 2025 (in millions):

	SPL Revolving Credit Facility		CQP Revolving Credit Facility		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility (1)
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	185		—		—		110		—
Available commitment	$	815	$	1,000	$	3,260	$	1,390	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Senior unsecured
Interest rate on available balance (2)	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 credit spread adjustment of 0.1%, plus margin of 1.0% - 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 (2)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.090% - 0.290%
Letter of credit fees (2)	1.0% - 1.75%		1.125% - 2.0%		N/A		1.0% - 1.5%		1.075% - 2.00%
Maturity date	June 23, 2028		June 23, 2028		(3)		June 15, 2027		August 1, 2030

(1)In August 2025, we entered into an amendment and restatement of the Cheniere Revolving Credit Facility, resulting in an extended maturity date, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

(2)The margin on the interest rate, the commitment fees and the letter of credit fees is 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.

(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.

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 September 30, 2025, 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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Total interest cost	$	301	$	304	$	894	$	924
Capitalized interest	(65)		(57)		(192)		(154)
Total interest expense, net of capitalized interest	$	236	$	247	$	702	$	770

Fair Value Disclosures

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

	September 30, 2025				December 31, 2024
	Carrying Amount (1)		Estimated Fair Value (2)		Carrying Amount (1)		Estimated Fair Value (2)
Senior notes	$	22,745	$	22,513	$	23,097	$	22,220

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

(2)As of September 30, 2025 and December 31, 2024, $3.1 billion and $3.0 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 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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Leases

9 Months Ended

Sep. 30, 2025

Leases [Abstract]

Leases

LEASES

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 September 30, 2025 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2025	$	181	$	37
2026	639		141
2027	545		143
2028	376		146
2029	287		146
Thereafter	1,172		646
Total lease payments (1)	3,200		1,259
Less: Interest	(570)		(307)
Present value of lease liabilities	$	2,630	$	952

(1)Does not include approximately $3.0 billion of legally binding minimum payments for leases executed as of September 30, 2025 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:

	September 30, 2025		December 31, 2024
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	7.3	8.8	7.0	8.8
Weighted-average discount rate (1)	5.2%	6.6%	5.0%	7.4%

(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):

	Nine Months Ended September 30,
	2025		2024
Right-of-use assets obtained in exchange for operating lease liabilities (1)	$	408	$	718
Right-of-use assets obtained in exchange for finance lease liabilities (2)	472		59

(1)Net of $33 million reclassified from operating leases to finance leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.

(2)Net of $15 million reclassified from finance leases to operating leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.

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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Fixed income	$	25	$	72	$	66	$	238
Variable income	14		11		36		28
Total sublease income	$	39	$	83	$	102	$	266

Future annual minimum sublease payments to be received from LNG vessel subleases as of September 30, 2025 are as follows (in millions):

Years Ending December 31,	Sublease Payments
2025	$	8
2026	1
Total sublease payments	$	9

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Revenues

9 Months Ended

Sep. 30, 2025

Revenue from Contract with Customer [Abstract]

Revenues

REVENUES

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues from contracts with customers
LNG revenues (excluding net derivative gain (loss) below)	$	4,200	$	3,569	$	13,802	$	10,614
Regasification revenues	34		34		102		102
Other revenues (1)	59		80		185		231
Total revenues from contracts with customers	4,293		3,683		14,089		10,947
Net derivative gain (loss) (see Note 5)	102		(15)		320		19
Sublease income (see Note 9)	39		83		102		266
Other revenues	7		12		15		35
Total revenues	$	4,441	$	3,763	$	14,526	$	11,267

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

For the three and nine months ended September 30, 2025 and 2024, 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):

	September 30,		December 31,
	2025		2024
Contract assets, net of current expected credit losses	$	401	$	331

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):

	Nine Months Ended September 30, 2025
Deferred revenue, beginning of period	$	318
Cash received but not yet recognized in revenue	149
Revenue recognized from prior period deferral	(162)
Deferred revenue, end of period	$	305

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:

	September 30, 2025			December 31, 2024
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	107.6	8	$	104.7	8
Regasification revenues	0.4		2	0.5		3
Total revenues	$	108.0		$	105.2

(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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
LNG revenues	64	%	60	%	67	%	57	%
Regasification revenues	8	%	8	%	8	%	8	%

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Related Party Transactions

9 Months Ended

Sep. 30, 2025

Related Party Transactions [Abstract]

Related Party Transactions

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):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Other revenues
Operating agreement and construction management agreement with equity method investee (1)	$	—	$	3	$	1	$	7
Operating and maintenance expense
Natural gas transportation and storage agreements with equity method investees (1)	8		10		24		15
Natural gas transportation and storage agreements with other related party (2)	—		15		28		44

(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 nine months ended September 30, 2025 and $3 million and $7 million of other revenues and $2 million and $7 million of operating and maintenance expense from the investee during the three and nine months ended September 30, 2024, respectively.

(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.

Below is a summary of our related party balances, all in the ordinary course of business, as reported on our Consolidated Balance Sheets (in millions):

	September 30,		December 31,
	2025		2024
Trade and other receivables, net of current expected credit losses	$	—	$	4
Accrued liabilities	3		8

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Income Taxes

9 Months Ended

Sep. 30, 2025

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

We recorded an income tax provision of $303 million and $850 million during the three and nine months ended September 30, 2025, respectively, and an income tax provision of $231 million and $550 million for the same periods of 2024, respectively, which was calculated using the annual effective tax rate method.

Our effective tax rate was 18.9% and 18.0% during the three and nine months ended September 30, 2025, respectively, as compared to 16.1% and 14.6% for the same periods of 2024, respectively. Our effective tax rate increased between the comparable periods primarily due to: (1) decreased ratio of pre-tax income attributable to CQP, which is partially not taxable to us, (2) increased tax expense due to a valuation allowance on a capital loss carryover generated on the sale of all of our equity interests in an equity method investment during the three months ended March 31, 2025 and (3) a reduced Foreign Derived Intangible Income (“FDII”) deduction. The effective tax rate for the comparable three and nine month periods was lower than the statutory rate of 21.0% primarily due to CQP’s income that is partially not taxable to us.

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law with significant changes to the Internal Revenue Code that impact us, including, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025 and modifying the export-promoting FDII deduction rules, renamed to the Foreign Derived Deduction Eligible Income (“FDDEI”) under the OBBBA beginning in 2026.

We initially applied the relevant and effective provisions of the OBBBA in the third quarter of 2025, including provisions related to bonus depreciation. The legislation did not have a material impact on our income tax expense for the three months ended September 30, 2025, and we do not expect it to materially change our effective income tax rate for 2025. However, the 100% bonus depreciation provision under the OBBBA is expected to defer our tax liability, ultimately reducing our 2025 income taxes payable to a nominal amount, primarily due to the accelerated tax deduction on qualifying Corpus Christi Stage 3 Project assets.

On September 30, 2025, the Internal Revenue Service (the “IRS”) issued Notice 2025-49, which includes, among other provisions, revised interim rules for calculating CAMT adjusted financial statement income, including rules allowing us to utilize and benefit from our existing net operating loss carryovers for both CAMT and regular tax in the same period. As a result, our cash tax obligations have been deferred and we are entitled to a refund of $380 million of previously paid CAMT, which has been recognized as a receivable within trade and other receivables, net of current expected credit losses on our Consolidated Balance Sheets as of September 30, 2025.

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Net Income Per Share Attributable to Common Stockholders

9 Months Ended

Sep. 30, 2025

Earnings Per Share [Abstract]

Net Income Per Share Attributable to Common Stockholders

NET INCOME PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

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 held by a third party in one of our consolidated VIEs is considered participating because, under certain circumstances, it is redeemable for cash at a return. Therefore, the accretion of the redeemable NCI to its redemption value, net of tax, which is recognized as a deemed dividend within retained earnings, is deducted from net income in computing net income per share attributable to common stockholders.

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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Net income attributable to Cheniere	$	1,049	$	893	$	3,028	$	2,275
Less: accretion of redeemable NCI, net of tax	4		—		10		—
Net income attributable to common stockholders	$	1,045	$	893	$	3,018	$	2,275
Weighted average common shares outstanding:
Basic	219.3		226.3		221.5		229.6
Dilutive unvested stock	0.6		0.7		0.6		0.7
Diluted	219.9		227.0		222.1		230.3
Net income per share attributable to common stockholders—basic (1)	$	4.76	$	3.95	$	13.63	$	9.91
Net income per share attributable to common stockholders—diluted (1)	$	4.75	$	3.93	$	13.59	$	9.88

(1)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 October 28, 2025, we declared a quarterly dividend of $0.555 per share of common stock that is payable on November 18, 2025 to stockholders of record as of the close of business on November 7, 2025.

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Share Repurchase Programs

9 Months Ended

Sep. 30, 2025

Equity [Abstract]

Share Repurchase Programs

SHARE REPURCHASE PROGRAMS

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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Total shares repurchased	4.37		1.58		7.37		12.24
Weighted average price paid per share	$	233.14	$	178.84	$	227.05	$	160.96
Total cost of repurchases (1)	$	1,018	$	282	$	1,674	$	1,970

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

As of September 30, 2025, we had approximately $2.2 billion remaining under our share repurchase program. Our share repurchase program authorization is effective through December 31, 2027.

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Segment Information and Customer Concentration

9 Months Ended

Sep. 30, 2025

Segment Reporting [Abstract]

Segment Information and Customer Concentration

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 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 $574 million and $506 million in gains for the three months ended September 30, 2025 and 2024, respectively, and $1.5 billion and $826 million in gains for the nine months ended September 30, 2025 and 2024, respectively. Interest income, which is included in interest and dividend income on our Consolidated Statements of Operations, was $23 million and $41 million for the three months ended September 30, 2025 and 2024, respectively, and $88 million and $149 million for the nine months ended September 30, 2025 and 2024, 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 United States. Total expenditures for additions to long-lived assets is reported on our Consolidated Statements of Cash Flows.

The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2025	2024	2025	2024	2025	2024
Customer A	*	*	*	*	14%	20%
Customer B	*	10%	*	*	*	*

* Less than 10%

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2025

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2025		2024
Cash paid during the period for interest on debt, net of amounts capitalized	$	640	$	823
Cash paid (refunded) for income taxes, net (1)	415		(72)
Non-cash investing activities:
Unpaid purchases of property, plant and equipment (2)(3)	241		175
Conveyance of other non-current assets to equity method investee in exchange for infrastructure support	—		34
Non-cash financing activities (2):
Unpaid excise tax on stock repurchased	15		18
Unpaid repurchase of common stock	20		—

(1)Amount for nine months ended September 30, 2025 includes $380 million of previously paid CAMT, which has been recognized as a tax-related receivable as of September 30, 2025. See Note 12—Income Taxes for additional information.

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

(3)Net of proceeds not yet collected on commissioning sales of LNG of $8 million and zero, respectively.

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

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Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2025
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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Nature of Operations and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2025

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

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, 2024.

Results of operations for the three and nine months ended September 30, 2025 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2025.

Recent Accounting Standards

Recent Accounting Standards

ASU 2023-09

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740). This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. The adoption of this guidance will not have an impact on our results of operations and financial condition but will have an impact on the annual disclosures required in the relevant notes to the consolidated financial statements. This guidance applies prospectively, with retrospective application permitted. We are progressing on the implementation and evaluating the method of adoption. We will adopt this guidance and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2025.

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.

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Trade and Other Receivables, Net of Current Expected Credit Losses (Tables)

9 Months Ended

Sep. 30, 2025

Receivables [Abstract]

Schedule of Accounts 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):

	September 30,		December 31,
	2025		2024
Trade receivables
SPL and CCL	$	518	$	548
Cheniere Marketing	274		109
Other subsidiaries	7		4
Total trade receivables	799		661
Other receivables
Tax-related receivables	441		29
Other	84		37
Total other receivables	525		66
Total trade and other receivables, net of current expected credit losses	$	1,324	$	727

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Inventory (Tables)

9 Months Ended

Sep. 30, 2025

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2025		2024
Materials	$	256	$	226
LNG	85		93
LNG in-transit	79		137
Natural gas	19		30
Other	19		15
Total inventory	$	458	$	501

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Property, Plant and Equipment, Net of Accumulated Depreciation (Tables)

9 Months Ended

Sep. 30, 2025

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

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

	September 30,		December 31,
	2025		2024
Terminal and related assets
Terminal and interconnecting pipeline facilities	$	36,492	$	34,282
Land	618		465
Construction-in-process	5,396		5,486
Accumulated depreciation	(8,115)		(7,231)
Total terminal and related assets, net of accumulated depreciation	34,391		33,002
Fixed assets and other
Computer and office equipment	39		36
Furniture and fixtures	33		31
Computer software	124		122
Leasehold improvements	47		47
Other	24		24
Accumulated depreciation	(200)		(188)
Total fixed assets and other, net of accumulated depreciation	67		72
Assets under finance leases
Marine assets	1,060		587
Accumulated depreciation	(173)		(109)
Total assets under finance leases, net of accumulated depreciation	887		478
Property, plant and equipment, net of accumulated depreciation	$	35,345	$	33,552

Schedule Of Depreciation And Offsets To LNG Terminal Costs

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Depreciation expense	$	337	$	304	$	973	$	907
Offsets to LNG terminal costs (1)	47		—		102		—

(1)We recognized offsets to LNG terminal costs related to the sale of commissioning volumes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the CCL Project and the SPL Project (collectively, the “Liquefaction Projects”) during the testing phase for its construction.

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2025

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

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
	September 30, 2025								December 31, 2024
	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)	$	—	$	35	$	589	$	624	$	—	$	59	$	(801)	$	(742)
LNG Trading Derivatives asset	—		14		—		14		—		17		—		17
FX Derivatives asset (liability)	—		(4)		—		(4)		—		16		—		16

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of September 30, 2025:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$589	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.638) - $0.295 / $(0.087)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	66% - 391% / 177%

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

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

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Balance, beginning of period	$	(10)	$	(1,729)	$	(801)	$	(2,178)
Realized and change in fair value gains (losses) included in net income (1):
Included in cost of sales, existing deals (2)	413		256		786		470
Included in cost of sales, new deals (3)	(3)		(4)		(13)		11
Purchases and settlements:
Purchases (4)	—		—		—		—
Settlements (5)	190		204		623		426
Transfers out of level 3 (6)	(1)		5		(6)		3
Balance, end of period	$	589	$	(1,268)	$	589	$	(1,268)
Favorable changes in fair value relating to instruments still held at the end of the period	$	410	$	252	$	773	$	481

(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.

(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.

Fair Value of Derivative Instruments by Balance Sheet Location

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

	September 30, 2025
	Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	42	$	47	$	—	$	89
Derivative assets	2,564		—		1		2,565
Total derivative assets	2,606		47		1		2,654
Current derivative liabilities	(518)		(33)		(5)		(556)
Derivative liabilities	(1,464)		—		—		(1,464)
Total derivative liabilities	(1,982)		(33)		(5)		(2,020)
Derivative asset (liability), net	$	624	$	14	$	(4)	$	634
	December 31, 2024
	Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	105	$	32	$	18	$	155
Derivative assets	1,903		—		—		1,903
Total derivative assets	2,008		32		18		2,058
Current derivative liabilities	(885)		(15)		(2)		(902)
Derivative liabilities	(1,865)		—		—		(1,865)
Total derivative liabilities	(2,750)		(15)		(2)		(2,767)
Derivative asset (liability), net	$	(742)	$	17	$	16	$	(709)

Derivative Net Presentation on Consolidated Balance Sheets

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 September 30, 2025
Gross assets	$	3,972	$	48	$	2
Offsetting amounts	(1,366)		(1)		(1)
Net assets (1)	$	2,606	$	47	$	1
Gross liabilities	$	(2,044)	$	(51)	$	(7)
Offsetting amounts	62		18		2
Net liabilities (2)	$	(1,982)	$	(33)	$	(5)
As of December 31, 2024
Gross assets	$	3,064	$	42	$	25
Offsetting amounts	(1,056)		(10)		(7)
Net assets (1)	$	2,008	$	32	$	18
Gross liabilities	$	(2,790)	$	(16)	$	(3)
Offsetting amounts	40		1		1
Net liabilities (2)	$	(2,750)	$	(15)	$	(2)

(1)Includes current and non-current derivative assets of $89 million and $2,565 million, respectively, as of September 30, 2025 and $155 million and $1,903 million, respectively, as of December 31, 2024.

(2)Includes current and non-current derivative liabilities of $556 million and $1,464 million, respectively, as of September 30, 2025 and $902 million and $1,865 million, respectively, as of December 31, 2024.

Derivative Liability, Subject to Master Netting Offset, Collateral

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

	Consolidated Balance Sheets Location	September 30,		December 31,
		2025		2024
Liquefaction Supply Derivatives	Margin deposits	$	23	$	18
Liquefaction Supply Derivatives	Other current liabilities	1		—
LNG Trading Derivatives	Margin deposits	80		110

Commodity Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

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

	September 30, 2025		December 31, 2024
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives
Notional amount, net (in TBtu)	12,625	(9)	12,503	(8)

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both September 30, 2025 and December 31, 2024.

Derivative Instruments, Gain (Loss)

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 September 30,				Nine Months Ended September 30,
		2025		2024		2025		2024
LNG Trading Derivatives	LNG revenues	$	96	$	(3)	$	373	$	14
LNG Trading Derivatives	Cost of sales	(67)		(7)		(64)		(27)
Liquefaction Supply Derivatives (2)	LNG revenues	—		(2)		2		—
Liquefaction Supply Derivatives (2)	Cost of sales	636		490		1,373		869

(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.

FX Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Derivative Instruments, Gain (Loss)

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 September 30,				Nine Months Ended September 30,
		2025		2024		2025		2024
FX Derivatives	LNG revenues	$	6	$	(10)	$	(55)	$	5

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Non-Controlling Interest and Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2025

Variable Interest Entities [Member]

Noncontrolling Interest and Variable Interest Entity [Line Items]

Condensed Balance Sheet of Cheniere Partners

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

	September 30,		December 31,
	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	121	$	270
Restricted cash and cash equivalents	61		125
Trade and other receivables, net of current expected credit losses	360		381
Inventory	152		154
Current derivative assets	15		84
Margin deposits	14		13
Other current assets, net	61		54
Total current assets	784		1,081
Property, plant and equipment, net of accumulated depreciation	15,532		15,880
Operating lease assets	79		80
Derivative assets	14		98
Other non-current assets, net	282		206
Total assets	$	16,691	$	17,345
LIABILITIES
Current liabilities
Accounts payable	$	73	$	70
Accrued liabilities	701		881
Current debt, net of unamortized discount and debt issuance costs	605		351
Deferred revenue	148		120
Current operating lease liabilities	5		4
Current derivative liabilities	139		250
Other current liabilities	8		16
Total current liabilities	1,679		1,692
Long-term debt, net of unamortized discount and debt issuance costs	14,156		14,761
Operating lease liabilities	74		76
Derivative liabilities	1,069		1,213
Other non-current liabilities	163		176
Total liabilities	$	17,141	$	17,918

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Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2025

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2025		2024
Natural gas purchases	$	676	$	886
Terminal and related asset costs	219		272
Interest costs and related debt fees	266		214
Compensation and benefits	176		283
Tax-related liabilities	115		472
Other accrued liabilities	40		52
Total accrued liabilities	$	1,492	$	2,179

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Debt (Tables)

9 Months Ended

Sep. 30, 2025

Debt Disclosure [Abstract]

Schedule of Debt Instruments

Debt consisted of the following (in millions): 

	September 30,		December 31,
	2025		2024
SPL:
Senior Secured Notes:
5.625% due 2025	$	—	$	300
5.875% due 2026	500		1,500
5.00% due 2027	1,500		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 4.747% and 4.746% at September 30, 2025 and December 31, 2024, respectively (1)	1,730		1,782
Total SPL Senior Secured Notes	7,080		8,432
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	7,080		8,432
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 (2)	1,000		—
Total CQP Senior Notes	7,800		6,800
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	7,800		6,800
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”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”)	—		—
Total debt - CCH	4,865		4,865
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
5.650% Senior Notes due 2034	1,500		1,500
Total Cheniere Senior Notes	3,000		3,000
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	3,000		3,000
Total debt	22,745		23,097
Current debt, net of unamortized discount and debt issuance costs (1)	(605)		(351)
Unamortized discount and debt issuance costs	(183)		(192)
Total long-term debt, net of unamortized discount and debt issuance costs	$	21,957	$	22,554

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

(2)Issued in July 2025 pursuant to the same base indenture as the other CQP Senior Notes, as supplemented by the tenth supplemental indenture. See annual report on Form 10-K for the fiscal year ended December 31, 2024 for additional information regarding the guarantee, security and redemption option of CQP Senior Notes.

Schedule of Line of Credit Facilities and Delayed Draw Term Loan

Below is a summary of our committed credit facilities outstanding as of September 30, 2025 (in millions):

	SPL Revolving Credit Facility		CQP Revolving Credit Facility		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility (1)
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	185		—		—		110		—
Available commitment	$	815	$	1,000	$	3,260	$	1,390	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Senior unsecured
Interest rate on available balance (2)	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 credit spread adjustment of 0.1%, plus margin of 1.0% - 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 (2)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.090% - 0.290%
Letter of credit fees (2)	1.0% - 1.75%		1.125% - 2.0%		N/A		1.0% - 1.5%		1.075% - 2.00%
Maturity date	June 23, 2028		June 23, 2028		(3)		June 15, 2027		August 1, 2030

(1)In August 2025, we entered into an amendment and restatement of the Cheniere Revolving Credit Facility, resulting in an extended maturity date, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

(2)The margin on the interest rate, the commitment fees and the letter of credit fees is 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.

(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.

Schedule of Interest Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Total interest cost	$	301	$	304	$	894	$	924
Capitalized interest	(65)		(57)		(192)		(154)
Total interest expense, net of capitalized interest	$	236	$	247	$	702	$	770

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	September 30, 2025				December 31, 2024
	Carrying Amount (1)		Estimated Fair Value (2)		Carrying Amount (1)		Estimated Fair Value (2)
Senior notes	$	22,745	$	22,513	$	23,097	$	22,220

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

(2)As of September 30, 2025 and December 31, 2024, $3.1 billion and $3.0 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.

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Leases (Tables)

9 Months Ended

Sep. 30, 2025

Leases [Abstract]

Schedule of Maturity of Lease Liabilities

Future annual minimum lease payments for operating and finance leases as of September 30, 2025 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2025	$	181	$	37
2026	639		141
2027	545		143
2028	376		146
2029	287		146
Thereafter	1,172		646
Total lease payments (1)	3,200		1,259
Less: Interest	(570)		(307)
Present value of lease liabilities	$	2,630	$	952

(1)Does not include approximately $3.0 billion of legally binding minimum payments for leases executed as of September 30, 2025 that will commence in future periods, consisting primarily of vessel charters, with fixed minimum lease terms of up to 15 years.

Lease, Other Quantitative Information

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

	September 30, 2025		December 31, 2024
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	7.3	8.8	7.0	8.8
Weighted-average discount rate (1)	5.2%	6.6%	5.0%	7.4%

(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):

	Nine Months Ended September 30,
	2025		2024
Right-of-use assets obtained in exchange for operating lease liabilities (1)	$	408	$	718
Right-of-use assets obtained in exchange for finance lease liabilities (2)	472		59

(1)Net of $33 million reclassified from operating leases to finance leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.

(2)Net of $15 million reclassified from finance leases to operating leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.

Schedule of Sublease Income

The following table shows the sublease income recognized in other revenues on our Consolidated Statements of Operations (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Fixed income	$	25	$	72	$	66	$	238
Variable income	14		11		36		28
Total sublease income	$	39	$	83	$	102	$	266

Sublease Payment to be Received, Fiscal Year Maturity

Future annual minimum sublease payments to be received from LNG vessel subleases as of September 30, 2025 are as follows (in millions):

Years Ending December 31,	Sublease Payments
2025	$	8
2026	1
Total sublease payments	$	9

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Revenues (Tables)

9 Months Ended

Sep. 30, 2025

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues from contracts with customers
LNG revenues (excluding net derivative gain (loss) below)	$	4,200	$	3,569	$	13,802	$	10,614
Regasification revenues	34		34		102		102
Other revenues (1)	59		80		185		231
Total revenues from contracts with customers	4,293		3,683		14,089		10,947
Net derivative gain (loss) (see Note 5)	102		(15)		320		19
Sublease income (see Note 9)	39		83		102		266
Other revenues	7		12		15		35
Total revenues	$	4,441	$	3,763	$	14,526	$	11,267

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

Contract Assets

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):

	September 30,		December 31,
	2025		2024
Contract assets, net of current expected credit losses	$	401	$	331

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):

	Nine Months Ended September 30, 2025
Deferred revenue, beginning of period	$	318
Cash received but not yet recognized in revenue	149
Revenue recognized from prior period deferral	(162)
Deferred revenue, end of period	$	305

Transaction Price Allocated to Future Performance Obligations

The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied:

	September 30, 2025			December 31, 2024
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	107.6	8	$	104.7	8
Regasification revenues	0.4		2	0.5		3
Total revenues	$	108.0		$	105.2

(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.

Revenue, Remaining Performance Obligation, Variable Consideration

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
LNG revenues	64	%	60	%	67	%	57	%
Regasification revenues	8	%	8	%	8	%	8	%

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2025

Related Party Transactions [Abstract]

Schedule of 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):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Other revenues
Operating agreement and construction management agreement with equity method investee (1)	$	—	$	3	$	1	$	7
Operating and maintenance expense
Natural gas transportation and storage agreements with equity method investees (1)	8		10		24		15
Natural gas transportation and storage agreements with other related party (2)	—		15		28		44

(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 nine months ended September 30, 2025 and $3 million and $7 million of other revenues and $2 million and $7 million of operating and maintenance expense from the investee during the three and nine months ended September 30, 2024, respectively.

(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.

Below is a summary of our related party balances, all in the ordinary course of business, as reported on our Consolidated Balance Sheets (in millions):

	September 30,		December 31,
	2025		2024
Trade and other receivables, net of current expected credit losses	$	—	$	4
Accrued liabilities	3		8

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Net Income Per Share Attributable to Common Stockholders (Tables)

9 Months Ended

Sep. 30, 2025

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Net income attributable to Cheniere	$	1,049	$	893	$	3,028	$	2,275
Less: accretion of redeemable NCI, net of tax	4		—		10		—
Net income attributable to common stockholders	$	1,045	$	893	$	3,018	$	2,275
Weighted average common shares outstanding:
Basic	219.3		226.3		221.5		229.6
Dilutive unvested stock	0.6		0.7		0.6		0.7
Diluted	219.9		227.0		222.1		230.3
Net income per share attributable to common stockholders—basic (1)	$	4.76	$	3.95	$	13.63	$	9.91
Net income per share attributable to common stockholders—diluted (1)	$	4.75	$	3.93	$	13.59	$	9.88

(1)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.

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Share Repurchase Programs (Tables)

9 Months Ended

Sep. 30, 2025

Equity [Abstract]

Shares repurchased

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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Total shares repurchased	4.37		1.58		7.37		12.24
Weighted average price paid per share	$	233.14	$	178.84	$	227.05	$	160.96
Total cost of repurchases (1)	$	1,018	$	282	$	1,674	$	1,970

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

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Segment Information and Customer Concentration (Tables)

9 Months Ended

Sep. 30, 2025

Segment Reporting [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2025	2024	2025	2024	2025	2024
Customer A	*	*	*	*	14%	20%
Customer B	*	10%	*	*	*	*

* Less than 10%

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2025

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Nine Months Ended September 30,
	2025		2024
Cash paid during the period for interest on debt, net of amounts capitalized	$	640	$	823
Cash paid (refunded) for income taxes, net (1)	415		(72)
Non-cash investing activities:
Unpaid purchases of property, plant and equipment (2)(3)	241		175
Conveyance of other non-current assets to equity method investee in exchange for infrastructure support	—		34
Non-cash financing activities (2):
Unpaid excise tax on stock repurchased	15		18
Unpaid repurchase of common stock	20		—

(1)Amount for nine months ended September 30, 2025 includes $380 million of previously paid CAMT, which has been recognized as a tax-related receivable as of September 30, 2025. See Note 12—Income Taxes for additional information.

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

(3)Net of proceeds not yet collected on commissioning sales of LNG of $8 million and zero, respectively.

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Nature of Operations and Basis of Presentation (Details)	9 Months Ended
	Sep. 30, 2025 mi unit item
Minimum [Member]
Nature of Operations and Basis of Presentation [Table]
Total Production Capability	60
Under Construction [Member] | Minimum [Member]
Nature of Operations and Basis of Presentation [Table]
Total Production Capability	12
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Table]
Number of LNG Storage Tanks	5
Number of Marine Berths Operating | item	3
Sabine Pass LNG Terminal [Member] | Operational [Member] | Minimum [Member]
Nature of Operations and Basis of Presentation [Table]
Total Production Capability	30
Creole Trail Pipeline [Member]
Nature of Operations and Basis of Presentation [Table]
Length of Natural Gas Pipeline | mi	94
Corpus Christi LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Table]
Number of LNG Storage Tanks	3
Number of Marine Berths Operating | item	2
Asset ownership percentage	100.00%
Corpus Christi LNG Terminal [Member] | Minimum [Member]
Nature of Operations and Basis of Presentation [Table]
Total Production Capability	30
Corpus Christi LNG Terminal [Member] | Under Construction [Member] | Minimum [Member]
Nature of Operations and Basis of Presentation [Table]
Total Production Capability	12
Corpus Christi Pipeline [Member]
Nature of Operations and Basis of Presentation [Table]
Length of Natural Gas Pipeline | mi	21
Corpus Christi Stage 3 Project
Nature of Operations and Basis of Presentation [Table]
Number of Midscale Trains	7
Corpus Christi Stage 3 Project | Minimum [Member]
Nature of Operations and Basis of Presentation [Table]
Total Production Capability	10
Corpus Christi Stage 3 Project | Operational [Member]
Nature of Operations and Basis of Presentation [Table]
Number of Midscale Trains	2
Corpus Christi Stage 3 Project | Under Construction [Member]
Nature of Operations and Basis of Presentation [Table]
Total Production Capability	7
Midscale Trains 8 & 9 Project
Nature of Operations and Basis of Presentation [Table]
Number of Midscale Trains	2
Midscale Trains 8 & 9 Project | Under Construction [Member]
Nature of Operations and Basis of Presentation [Table]
Total Production Capability	5
CQP [Member]
Nature of Operations and Basis of Presentation [Table]
General Partner ownership percentage	2.00%
Limited Partner ownership percentage	48.60%
Incentive Distribution Right Ownership Percentage	100.00%
CQP [Member] | General Partner
Nature of Operations and Basis of Presentation [Table]
General Partner ownership percentage	100.00%

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Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Sep. 30, 2025	Dec. 31, 2024
Accounts and Other Receivables [Line Items]
Trade receivables	$ 799	$ 661
Other receivables	525	66
Total trade and other receivables, net of current expected credit losses	1,324	727
Income Tax Receivable [Member]
Accounts and Other Receivables [Line Items]
Other receivables	441	29
Other Receivable [Member]
Accounts and Other Receivables [Line Items]
Other receivables	84	37
SPL and CCL
Accounts and Other Receivables [Line Items]
Trade receivables	518	548
Cheniere Marketing
Accounts and Other Receivables [Line Items]
Trade receivables	274	109
Other subsidiaries
Accounts and Other Receivables [Line Items]
Trade receivables	$ 7	$ 4

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Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2025	Dec. 31, 2024
Inventory [Line Items]
Inventory	$ 458	$ 501
Materials [Member]
Inventory [Line Items]
Inventory	256	226
LNG [Member]
Inventory [Line Items]
Inventory	85	93
LNG in-transit [Member]
Inventory [Line Items]
Inventory	79	137
Natural gas [Member]
Inventory [Line Items]
Inventory	19	30
Other [Member]
Inventory [Line Items]
Inventory	$ 19	$ 15

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions	Sep. 30, 2025	Dec. 31, 2024
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 35,345	$ 33,552
Terminal and related assets [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(8,115)	(7,231)
Property, plant and equipment, net of accumulated depreciation	34,391	33,002
Terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	36,492	34,282
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	618	465
Construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	5,396	5,486
Fixed assets and other [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(200)	(188)
Property, plant and equipment, net of accumulated depreciation	67	72
Computer and office equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	39	36
Furniture and fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	33	31
Computer software [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	124	122
Leasehold improvements [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	47	47
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	24	24
Assets under finance leases [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,060	587
Accumulated depreciation	(173)	(109)
Property, plant and equipment, net of accumulated depreciation	$ 887	$ 478

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2024
Property, Plant and Equipment [Abstract]
Depreciation expense		$ 337	$ 304	$ 973	$ 907
Offsets to LNG terminal costs (1)	[1]	$ 47	$ 0	$ 102	$ 0

[1] We recognized offsets to LNG terminal costs related to the sale of commissioning volumes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the CCL Project and the SPL Project (collectively, the “Liquefaction Projects”) during the testing phase for its construction.

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Derivative Instruments - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2025	Dec. 31, 2024
Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	15 years
LNG Trading Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	1 year
FX Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount	$ 1,150	$ 642
FX Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	1 year

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2025	Dec. 31, 2024
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 624	$ (742)
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	35	59
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	589	(801)
LNG Trading Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	14	17
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	14	17
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
FX Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(4)	16
FX Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
FX Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(4)	16
FX Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Liquefaction Supply Derivatives [Member] - USD ($)		9 Months Ended
		Sep. 30, 2025	Dec. 31, 2024
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Net Fair Value Liabilities		$ 624,000,000	$ (742,000,000)
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Net Fair Value Liabilities		589,000,000	$ (801,000,000)
Valuation, Market Approach [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	[1]	(0.638)
Valuation, Market Approach [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	[1]	0.295
Valuation, Market Approach [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	[1]	$ (0.087)
Valuation Technique, Option Pricing Model [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	66.00%
Valuation Technique, Option Pricing Model [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	391.00%
Valuation Technique, Option Pricing Model [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	177.00%

[1] Unobservable inputs were weighted by the relative fair value of the instruments.

[2] Spread contemplates U.S. dollar-denominated pricing.

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Derivative Instruments - Schedule of Level 3 Derivatives Activity (Details) - Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2024
Fair Value, Assets (Liabilities) Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (10)	$ (1,729)	$ (801)	$ (2,178)
Realized and change in fair value gains included in net income:
Included in cost of sales, existing deals	[1],[2]	413	256	786	470
Included in cost of sales, new deals	[1],[3]	(3)	(4)	(13)	11
Purchases and settlements:
Purchases	[4]	0	0	0	0
Settlements	[5]	190	204	623	426
Transfers out of level 3	[6]	(1)	5	(6)	3
Balance, end of period		589	(1,268)	589	(1,268)
Favorable changes in fair value relating to instruments still held at the end of the period		$ 410	$ 252	$ 773	$ 481

[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.

[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

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Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) - tbtu		Sep. 30, 2025	Dec. 31, 2024
Liquefaction Supply Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	[1]	12,625	12,503
LNG Trading Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		(9)	(8)

[1] Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both September 30, 2025 and December 31, 2024.

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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2024
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 102	$ (15)	$ 320	$ 19
LNG Trading Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	96	(3)	373	14
LNG Trading Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	(67)	(7)	(64)	(27)
Liquefaction Supply Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	0	(2)	2	0
Liquefaction Supply Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	636	490	1,373	869
FX Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 6	$ (10)	$ (55)	$ 5
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Revenues	Revenues	Revenues	Revenues

[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.

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions	Sep. 30, 2025	Dec. 31, 2024
Derivatives, Fair Value [Line Items]
Current derivative assets	$ 89	$ 155
Derivative assets	2,565	1,903
Total derivative assets	2,654	2,058
Current derivative liabilities	(556)	(902)
Derivative liabilities	(1,464)	(1,865)
Total derivative liabilities	(2,020)	(2,767)
Derivative asset (liability), net	$ 634	$ (709)
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration]	Current derivative assets	Current derivative assets
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Derivative assets	Derivative assets
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]	Current derivative liabilities	Current derivative liabilities
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Derivative liabilities	Derivative liabilities
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	$ 42	$ 105
Derivative assets	2,564	1,903
Total derivative assets	2,606	2,008
Current derivative liabilities	(518)	(885)
Derivative liabilities	(1,464)	(1,865)
Total derivative liabilities	(1,982)	(2,750)
Derivative asset (liability), net	624	(742)
LNG Trading Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	47	32
Derivative assets	0	0
Total derivative assets	47	32
Current derivative liabilities	(33)	(15)
Derivative liabilities	0	0
Total derivative liabilities	(33)	(15)
Derivative asset (liability), net	14	17
FX Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	0	18
Derivative assets	1	0
Total derivative assets	1	18
Current derivative liabilities	(5)	(2)
Derivative liabilities	0	0
Total derivative liabilities	(5)	(2)
Derivative asset (liability), net	$ (4)	$ 16

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Derivative Instruments - Derivative Net Presentation on Consolidated Balance Sheets (Details) - USD ($) $ in Millions		Sep. 30, 2025	Dec. 31, 2024
Derivative [Line Items]
Current derivative assets		$ 89	$ 155
Derivative assets		2,565	1,903
Current derivative liabilities		556	902
Derivative liabilities		1,464	1,865
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		3,972	3,064
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(1,366)	(1,056)
Derivative Assets (Liabilities), at Fair Value, Net	[1]	2,606	2,008
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(2,044)	(2,790)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		62	40
Derivative Assets (Liabilities), at Fair Value, Net	[2]	(1,982)	(2,750)
LNG Trading Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		48	42
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(1)	(10)
Derivative Assets (Liabilities), at Fair Value, Net	[1]	47	32
LNG Trading Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(51)	(16)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		18	1
Derivative Assets (Liabilities), at Fair Value, Net	[2]	(33)	(15)
FX Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		2	25
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(1)	(7)
Derivative Assets (Liabilities), at Fair Value, Net	[1]	1	18
FX Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(7)	(3)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		2	1
Derivative Assets (Liabilities), at Fair Value, Net	[2]	$ (5)	$ (2)

[1] Includes current and non-current derivative assets of $89 million and $2,565 million, respectively, as of September 30, 2025 and $155 million and $1,903 million, respectively, as of December 31, 2024.

[2] Includes current and non-current derivative liabilities of $556 million and $1,464 million, respectively, as of September 30, 2025 and $902 million and $1,865 million, respectively, as of December 31, 2024.

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Derivative Instruments - Collateral Not Netted (Details) - USD ($) $ in Millions	Sep. 30, 2025	Dec. 31, 2024
Liquefaction Supply Derivatives [Member]
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 23	$ 18
Derivative, collateral posted by counterparties	1	0
LNG Trading Derivatives [Member]
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 80	$ 110

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Non-Controlling Interest and Variable Interest Entities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2025		Dec. 31, 2024
Noncontrolling Interest and Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 1,075	[1]	$ 2,638
Restricted cash and cash equivalents	323	[1]	552
Trade and other receivables, net of current expected credit losses	1,324		727
Inventory	458		501
Current derivative assets	89		155
Margin deposits	103		128
Other current assets, net	129		100
Total current assets	3,501		4,801
Property, plant and equipment, net of accumulated depreciation	35,345		33,552
Right-of-use assets—Operating	2,627		2,684
Derivative assets	2,565		1,903
Other non-current assets, net	1,047		899
Total assets	45,102	[1]	43,858
Accounts payable	279		171
Accrued liabilities	1,492		2,179
Current debt, net of unamortized discount and debt issuance costs	605		351
Deferred revenue	176		163
Current operating lease liabilities	539		592
Current derivative liabilities	556		902
Other current liabilities	92		83
Total current liabilities	3,739		4,441
Long-term debt, net of unamortized discount and debt issuance costs	21,957		22,554
Non-current operating lease liabilities	2,091		2,090
Derivative liabilities	1,464		1,865
Other non-current liabilities	1,315		992
Total liabilities	$ 33,641		33,798
CQP [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Limited Partner ownership percentage	48.60%
General Partner ownership percentage	2.00%
Incentive Distribution Right Ownership Percentage	100.00%
Blackstone Inc. and Brookfield Asset Management, Inc. and the public
Noncontrolling Interest and Variable Interest Entity [Line Items]
Limited Partner ownership percentage	49.40%
Variable Interest Entities [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 121		270
Restricted cash and cash equivalents	61		125
Trade and other receivables, net of current expected credit losses	360		381
Inventory	152		154
Current derivative assets	15		84
Margin deposits	14		13
Other current assets, net	61		54
Total current assets	784		1,081
Property, plant and equipment, net of accumulated depreciation	15,532		15,880
Right-of-use assets—Operating	79		80
Derivative assets	14		98
Other non-current assets, net	282		206
Total assets	16,691		17,345
Accounts payable	73		70
Accrued liabilities	701		881
Current debt, net of unamortized discount and debt issuance costs	605		351
Deferred revenue	148		120
Current operating lease liabilities	5		4
Current derivative liabilities	139		250
Other current liabilities	8		16
Total current liabilities	1,679		1,692
Long-term debt, net of unamortized discount and debt issuance costs	14,156		14,761
Non-current operating lease liabilities	74		76
Derivative liabilities	1,069		1,213
Other non-current liabilities	163		176
Total liabilities	$ 17,141		$ 17,918

[1] Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), substantially all of which are related to CQP, as further discussed in Note 6—Non-Controlling Interests and Variable Interest Entities. As of September 30, 2025, total assets and liabilities of our VIEs were $16.7 billion and $17.1 billion, respectively, including $121 million of cash and cash equivalents and $61 million of restricted cash and cash equivalents.

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Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2025	Dec. 31, 2024
Accrued Liabilities, Current [Abstract]
Natural gas purchases	$ 676	$ 886
Terminal and related asset costs	219	272
Interest costs and related debt fees	266	214
Compensation and benefits	176	283
Tax-related liabilities	115	472
Other accrued liabilities	40	52
Total accrued liabilities	$ 1,492	$ 2,179

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Debt - Narrative (Details)	9 Months Ended
	Sep. 30, 2025 units
SPL and CCH [Member]
Debt Instrument [Line Items]
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio	1.25

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Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 22,745	$ 23,097
Current portion of long-term debt	[1]	(605)	(351)
Unamortized discount and debt issuance costs		(183)	(192)
Total long-term debt, net of unamortized discount and debt issuance costs		21,957	22,554
SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		7,080	8,432
2025 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	300
Debt Instrument, Interest Rate, Stated Percentage		5.625%
2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 500	1,500
Debt Instrument, Interest Rate, Stated Percentage		5.875%
2027 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		5.00%
2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,350	1,350
Debt Instrument, Interest Rate, Stated Percentage		4.20%
2030 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage		4.50%
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[1]	$ 1,730	$ 1,782
2037 SPL Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.747%	4.746%
SPL Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	$ 0
CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		7,800	6,800
2029 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		4.50%
2031 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		4.00%
2032 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,200	1,200
Debt Instrument, Interest Rate, Stated Percentage		3.25%
2033 Cheniere Energy Partners Senior Notes
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,400	1,400
Debt Instrument, Interest Rate, Stated Percentage		5.95%
2034 Cheniere Energy Partners Senior Notes
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,200	1,200
Debt Instrument, Interest Rate, Stated Percentage		5.75%
2035 Cheniere Energy Partners Senior Notes
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[2]	$ 1,000	0
Debt Instrument, Interest Rate, Stated Percentage		5.55%
CQP Revolving Credit Facility
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		4,865	4,865
2027 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,201	1,201
Debt Instrument, Interest Rate, Stated Percentage		5.125%
2029 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,125	1,125
Debt Instrument, Interest Rate, Stated Percentage		3.70%
2039 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[1]	$ 2,539	2,539
2039 CCH Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.788%
CCH Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
CCH Working Capital Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		0	0
Cheniere Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		3,000	3,000
2028 Cheniere Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		4.625%
2034 Cheniere Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		5.65%
Cheniere Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
Cheniere [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		3,000	3,000
SPL [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		7,080	8,432
CQP [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		7,800	6,800
CCH [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 4,865	$ 4,865

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

[2] Issued in July 2025 pursuant to the same base indenture as the other CQP Senior Notes, as supplemented by the tenth supplemental indenture. See annual report on Form 10-K for the fiscal year ended December 31, 2024 for additional information regarding the guarantee, security and redemption option of CQP Senior Notes.

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Debt - Credit Facilities Table (Details) $ in Millions	9 Months Ended
	Sep. 30, 2025 USD ($)
SPL Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,000
Outstanding balance	0
Letters of credit issued	185
Available commitment	$ 815
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Jun. 23, 2028
SPL Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.075%	[1]
SPL Revolving Credit Facility [Member] | Minimum [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Letter of credit fees	1.00%	[1]
SPL Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%	[1]
SPL Revolving Credit Facility [Member] | Maximum [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Letter of credit fees	1.75%	[1]
SPL Revolving Credit Facility [Member] | SOFR [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1]
SPL Revolving Credit Facility [Member] | SOFR [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%	[1]
SPL Revolving Credit Facility [Member] | SOFR [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%	[1]
SPL Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.00%	[1]
SPL Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%	[1]
CQP Revolving Credit Facility
Line of Credit Facility [Line Items]
Total facility size	$ 1,000
Outstanding balance	0
Letters of credit issued	0
Available commitment	$ 1,000
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Jun. 23, 2028
CQP Revolving Credit Facility | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%	[1]
CQP Revolving Credit Facility | Minimum [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Letter of credit fees	1.125%	[1]
CQP Revolving Credit Facility | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%	[1]
CQP Revolving Credit Facility | Maximum [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Letter of credit fees	2.00%	[1]
CQP Revolving Credit Facility | SOFR [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1]
CQP Revolving Credit Facility | SOFR [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.125%	[1]
CQP Revolving Credit Facility | SOFR [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%	[1]
CQP Revolving Credit Facility | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.125%	[1]
CQP Revolving Credit Facility | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%	[1]
CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 3,260
Outstanding balance	0
Letters of credit issued	0
Available commitment	$ 3,260
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Line of Credit Facility, Commitment Fee Percentage	0.525%	[1]
CCH Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Maturity date	Jun. 15, 2029
Debt Instrument, Maturity Date, Years after Substantial Completion	2 years
CCH Credit Facility [Member] | SOFR [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1]
Debt Instrument, Basis Spread on Variable Rate	1.50%	[1]
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%	[1]
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,500
Outstanding balance	0
Letters of credit issued	110
Available commitment	$ 1,390
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Jun. 15, 2027
CCH Working Capital Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%	[1]
CCH Working Capital Facility [Member] | Minimum [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Letter of credit fees	1.00%	[1]
CCH Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.20%	[1]
CCH Working Capital Facility [Member] | Maximum [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Letter of credit fees	1.50%	[1]
CCH Working Capital Facility [Member] | SOFR [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1]
CCH Working Capital Facility [Member] | SOFR [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%	[1]
CCH Working Capital Facility [Member] | SOFR [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%	[1]
CCH Working Capital Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.00%	[1]
CCH Working Capital Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%	[1]
Cheniere Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,250	[2]
Outstanding balance	0	[2]
Letters of credit issued	0	[2]
Available commitment	$ 1,250	[2]
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Aug. 01, 2030	[2]
Cheniere Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.09%	[1],[2]
Cheniere Revolving Credit Facility [Member] | Minimum [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Letter of credit fees	1.075%	[1],[2]
Cheniere Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.29%	[1],[2]
Cheniere Revolving Credit Facility [Member] | Maximum [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Letter of credit fees	2.00%	[1],[2]
Cheniere Revolving Credit Facility [Member] | SOFR [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.075%	[1],[2]
Cheniere Revolving Credit Facility [Member] | SOFR [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%	[1],[2]
Cheniere Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.075%	[1],[2]
Cheniere Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%	[1],[2]

[1] The margin on the interest rate, the commitment fees and the letter of credit fees is 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] In August 2025, we entered into an amendment and restatement of the Cheniere Revolving Credit Facility, resulting in an extended maturity date, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2024
Debt Disclosure [Abstract]
Total interest cost	$ 301	$ 304	$ 894	$ 924
Capitalized interest	(65)	(57)	(192)	(154)
Total interest expense, net of capitalized interest	$ 236	$ 247	$ 702	$ 770

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2025	Dec. 31, 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 22,745	$ 23,097
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 and Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	22,745	23,097
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 and Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	22,513	22,220
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value		$ 3,100	$ 3,000

[1] Carrying amounts exclude unamortized discount and debt issuance costs.

[2] As of September 30, 2025 and December 31, 2024, $3.1 billion and $3.0 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.

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Leases - Future Minimum Payments Table (Details) $ in Millions	Sep. 30, 2025 USD ($)
Operating Leases, Future Minimum Payments
2025	$ 181
2026	639
2027	545
2028	376
2029	287
Thereafter	1,172
Total lease payments	3,200	[1]
Less: Interest	(570)
Present value of lease liabilities	2,630
Finance Leases, Future Minimum Payments
2025	37
2026	141
2027	143
2028	146
2029	146
Thereafter	646
Total lease payments	1,259	[1]
Less: Interest	(307)
Present value of lease liabilities	952
Operating Lease, Lease Not yet Commenced, Payments Due	$ 3,000
Maximum [Member]
Finance Leases, Future Minimum Payments
Operating Leases, Lease Not yet Commenced, Term of Contract	15 years

[1] Does not include approximately $3.0 billion of legally binding minimum payments for leases executed as of September 30, 2025 that will commence in future periods, consisting primarily of vessel charters, with fixed minimum lease terms of up to 15 years.

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Leases - Other Quantitative Information (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024	Dec. 31, 2024
Operating Leases
Weighted-average remaining lease term		7 years 3 months 18 days		7 years
Weighted-average discount rate	[1]	5.20%		5.00%
Finance Leases
Weighted-average remaining lease term		8 years 9 months 18 days		8 years 9 months 18 days
Weighted-average discount rate	[1]	6.60%		7.40%
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	[2]	$ 408	$ 718
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	[3]	$ 472	59
Right-Of-Use Asset Obtained In Exchange For Finance Lease Liability, Reclassification From Operating Lease			33
Right-Of-Use Asset Obtained In Exchange For Operating Lease Liability, Reclassification From Finance Lease			$ 15

[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.

[2] Net of $33 million reclassified from operating leases to finance leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.

[3] Net of $15 million reclassified from finance leases to operating leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.

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Leases - Subleases (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2024
Lessor, Operating Lease, Description
Sublease Income, Fixed	$ 25	$ 72	$ 66	$ 238
Sublease Income, Variable	14	11	36	28
Sublease Income, Total	39	$ 83	102	$ 266
Operating Leases, Future Minimum Payments Receivable
2025	8		8
2026	1		1
Total sublease payments	$ 9		$ 9

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Revenues - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2024
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 4,293	$ 3,683	$ 14,089	$ 10,947
Net derivative gain (loss)		102	(15)	320	19
Sublease Income		39	83	102	266
Other revenues		7	12	15	35
Total revenues		4,441	3,763	14,526	11,267
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		4,200	3,569	13,802	10,614
Total revenues		4,302	3,554	14,122	10,633
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		34	34	102	102
Total revenues		34	34	102	102
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	[1]	59	80	185	231
Total revenues		$ 105	$ 175	$ 302	$ 532

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

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Revenues - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2025	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 401	$ 331
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenue, beginning of period	318
Cash received but not yet recognized in revenue	149
Revenue recognized from prior period deferral	(162)
Deferred revenue, end of period	$ 305

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Revenues - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Sep. 30, 2025	Dec. 31, 2024
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 105.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 108.0
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 104.7
Weighted Average Recognition Timing	[1]		8 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 107.6
Weighted Average Recognition Timing	[1]	8 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 0.5
Weighted Average Recognition Timing	[1]		3 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 0.4
Weighted Average Recognition Timing	[1]	2 years

[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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Revenues - Remaining Performance Obligation, Variable Consideration (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2024
LNG [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	64.00%	60.00%	67.00%	57.00%
Regasification [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	8.00%	8.00%	8.00%	8.00%

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2024	Dec. 31, 2024
Related Party Transaction [Line Items]
Revenues		$ 4,441	$ 3,763	$ 14,526	$ 11,267
Operating and maintenance expense		447	450	1,479	1,364
Trade and other receivables, net of current expected credit losses		1,324		1,324		$ 727
Accrued liabilities		1,492		1,492		2,179
Other [Member]
Related Party Transaction [Line Items]
Revenues		105	175	302	532
Equity Method Investee | Operation Agreement and Construction Management Agreement | Other [Member]
Related Party Transaction [Line Items]
Revenues	[1]	0	3	1	7
Equity Method Investee | Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense	[1]	8	10	24	15
Related Party
Related Party Transaction [Line Items]
Trade and other receivables, net of current expected credit losses		0		0		4
Accrued liabilities		3		3		$ 8
Related Party | Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense	[2]	$ 0	15	28	44
Equity Method Investee Sold | Operation Agreement and Construction Management Agreement | Other [Member]
Related Party Transaction [Line Items]
Revenues			3	1	7
Equity Method Investee Sold | Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense			$ 2	$ 1	$ 7

[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 nine months ended September 30, 2025 and $3 million and $7 million of other revenues and $2 million and $7 million of operating and maintenance expense from the investee during the three and nine months ended September 30, 2024, respectively.

[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.

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Income Taxes (Details) - USD ($) $ in Millions		3 Months Ended		8 Months Ended	9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2025	Sep. 30, 2024
Income Tax Disclosure [Abstract]
Income tax provision		$ 303	$ 231		$ 850	$ 550
Effective Income Tax Rate		18.90%	16.10%		18.00%	14.60%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	21.00%		21.00%	21.00%
Bonus Depreciation on Qualifying Assets, OBBBA				100.00%
Tax-related receivables	[1]	$ 380		$ 380	$ 380

[1] Amount for nine months ended September 30, 2025 includes $380 million of previously paid CAMT, which has been recognized as a tax-related receivable as of September 30, 2025. See Note 12—Income Taxes for additional information.

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Net Income Per Share Attributable to Common Stockholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			3 Months Ended			9 Months Ended
		Oct. 28, 2025	Sep. 30, 2025	Sep. 30, 2024		Sep. 30, 2025	Sep. 30, 2024
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net income attributable to common stockholders			$ 1,049	$ 893		$ 3,028	$ 2,275
Less: accretion of redeemable NCI, net of tax			4	0		10	0
Net income attributable to common stockholders			$ 1,045	$ 893		$ 3,018	$ 2,275
Weighted average number of common shares outstanding, basic			219.3	226.3		221.5	229.6
Dilutive Unvested Stock			0.6	0.7		0.6	0.7
Weighted Average Number of Shares Outstanding, Diluted			219.9	227.0		222.1	230.3
Net income per share attributable to common stockholders—basic (1)	[1]		$ 4.76	$ 3.95	[2]	$ 13.63	$ 9.91	[2]
Net income per share attributable to common stockholders—diluted (1)	[1]		$ 4.75	$ 3.93	[2]	$ 13.59	$ 9.88	[2]
Subsequent Event [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Common Stock, Dividends, Per Share, Declared		$ 0.555

[1] 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.

[2] In computing basic and diluted net income per share attributable to common stockholders, net income attributable to Cheniere is adjusted for the remeasurement of the redeemable NCI, net of tax, to its redemption value, as required under the two-class method. See Note 13—Net Income per Share Attributable to Common Stockholders for the full computation.

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Share Repurchase Programs (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024	Sep. 30, 2025	Sep. 30, 2024
Equity [Abstract]
Total shares repurchased		4,370	1,580	7,370	12,240
Weighted average price paid per share		$ 233.14	$ 178.84	$ 227.05	$ 160.96
Total cost of repurchases	[1]	$ 1,018	$ 282	$ 1,674	$ 1,970
Stock Repurchase Program, Remaining Authorized Repurchase Amount		$ 2,200		$ 2,200

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

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Segment Information and Customer Concentration - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2025 USD ($)	Sep. 30, 2024 USD ($)	Sep. 30, 2025 USD ($) unit	Sep. 30, 2024 USD ($)
Segment Reporting [Abstract]
Number of reportable segments | unit			1
Unrealized gain on derivatives	$ 574	$ 506	$ 1,500	$ 826
Interest income	$ 23	$ 41	$ 88	$ 149

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Segment Information and Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2025	Dec. 31, 2024
Total Revenues from External Customers [Member] | Customer B [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
Accounts Receivable And Contract Assets | Customer A [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		14.00%	20.00%

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2025	Sep. 30, 2024
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest on debt, net of amounts capitalized		$ 640	$ 823
Cash paid (refunded) for income taxes, net		415	(72)
Unpaid purchases of property, plant and equipment	[1],[2]	241	175
Conveyance of other non-current assets to equity method investee in exchange for infrastructure support		0	34
Unpaid excise tax on stock repurchased	[2]	15	18
Unpaid repurchase of common stock		20	0	[2]
Tax-related receivables	[3]	380
Property, Plant And Equipment, reduction for proceeds not yet collected on commissioning sales of LNG		$ 8	$ 0

[1] Net of proceeds not yet collected on commissioning sales of LNG of $8 million and zero, respectively.

[2] Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.

[3] Amount for nine months ended September 30, 2025 includes $380 million of previously paid CAMT, which has been recognized as a tax-related receivable as of September 30, 2025. See Note 12—Income Taxes for additional information.