Cheniere Energy Partners - 10-Q quarterly report FY2026 Q3

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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, 2026

☐ 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 001-33366

Cheniere Energy Partners, L.P.

(Exact name of registrant as specified in its charter)


Delaware			20-5913059
(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 Units Representing Limited Partner Interests	CQP	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 23, 2026, the registrant had 484,057,704 common units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

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 Partners’ Equity (Deficit)	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7
	Note 1—Nature of Operations and Basis of Presentation	7
	Note 2—Unitholders’ Equity	8

	Note 3—Trade and Other Receivables, Net of Current Expected Credit Losses	9
	Note 4—Inventory	9
	Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation	10
	Note 6—Derivative Instruments	10

	Note 7—Accrued Liabilities	13
	Note 8—Debt	14
	Note 9—Revenues	16
	Note 10—Related Party Transactions	17
	Note 11—Net Income per Common Unit	18
	Note 12—Segment Information and Customer Concentration	19
	Note 13—Supplemental Cash Flow Information	20

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33

Item 4.	Controls and Procedures	33

Part II. Other Information
Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	34

Item 5.	Other Information	34

Item 6.	Exhibits	34

	Signatures	35

Table of Contents

DEFINITIONS

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

Common Industry and Other Terms


ASU						Accounting Standards Update

Bcf/d						billion cubic feet per day

Bcfe						billion cubic feet equivalent

DOE						U.S. Department of Energy
EPC						engineering, procurement and construction

FASB						Financial Accounting Standards Board
FERC						Federal Energy Regulatory Commission
FID						final investment decision

FTA countries						countries with which the U.S. has a free trade agreement providing for national treatment for trade in natural gas
GAAP						generally accepted accounting principles in the U.S.
Henry Hub						the final settlement price (in U.S. dollars per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin

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


LNG						liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu						million British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
mtpa						million tonnes per annum
NGA						Natural Gas Act of 1938, as amended
non-FTA countries						countries with which the U.S. does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
NPNS						normal purchases and normal sales, an elective scope exception available under Accounting Standards Codification Topic 815, Derivatives and Hedging, which excludes qualifying physical commodity contracts from derivative accounting
SEC						U.S. Securities and Exchange Commission
SOFR						Secured Overnight Financing Rate
SPA						LNG sale and purchase agreement
TBtu						trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit

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

Table of Contents

Abbreviated Legal Entity Structure

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

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

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

(unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Revenues
LNG revenues	$	1,956	$	1,837	$	6,561	$	5,961
LNG revenues—affiliate	567		518		2,044		1,738

Regasification revenues	34		34		102		102

Other revenues	17		15		50		47

Total revenues	2,574		2,404		8,757		7,848

Operating costs and expenses
Cost of sales (excluding operating and maintenance expense and depreciation and amortization expense shown separately below)	1,276		1,278		4,757		4,177
Cost of sales—affiliate	—		—		46		—

Operating and maintenance expense	236		191		692		683
Operating and maintenance expense—affiliate	43		40		136		126
Operating and maintenance expense—related party	—		—		—		28


General and administrative expense	3		3		9		9
General and administrative expense—affiliate	25		23		72		70
Depreciation and amortization expense	174		173		522		515
Other operating costs and expenses	2		—		6		2
Other operating costs and expenses—affiliate	—		—		1		1
Total operating costs and expenses	1,759		1,708		6,241		5,611

Income from operations	815		696		2,516		2,237

Other income (expense)
Interest expense, net of capitalized interest	(182)		(189)		(546)		(567)


Other income (expense), net	6		(2)		13		7
Other income—affiliate	—		1		3		23
Total other expense	(176)		(190)		(530)		(537)

Net income	$	639	$	506	$	1,986	$	1,700

Basic and diluted net income per common unit(1)	$	1.01	$	0.80	$	3.34	$	2.79


Weighted average basic and diluted number of common units outstanding	484		484		484		484

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

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

Table of Contents

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

(unaudited)


	September 30,		December 31,

	2026		2025
ASSETS
Current assets
Cash and cash equivalents	$	569	$	182
Restricted cash and cash equivalents	35		19
Trade and other receivables, net of current expected credit losses	327		511
Trade and other receivables—affiliate	290		238

Advances to affiliates	152		145
Inventory	165		180

Prepaid expenses	50		42

Other current assets, net	16		21

Total current assets	1,604		1,338


Property, plant and equipment, net of accumulated depreciation	15,087		15,259
Operating lease assets	73		76

Deferred NPNS assets	669		—
Derivative assets	1		541
Other non-current assets, net	405		223

Total assets	$	17,839	$	17,437

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	97	$	53
Accrued liabilities	738		990

Current debt, net of unamortized discount and debt issuance costs	112		306
Due to affiliates	50		57
Deferred revenue	144		119


Current portion of deferred NPNS liabilities	103		—
Current derivative liabilities	84		164
Other current liabilities	14		15
Other current liabilities—affiliate	6		4
Total current liabilities	1,348		1,708

Long-term debt, net of unamortized discount and debt issuance costs	14,283		14,161



Deferred NPNS liabilities	1,055		—
Derivative liabilities	41		900
Other non-current liabilities	216		231
Other non-current liabilities—affiliate	17		23
Total liabilities	16,960		17,023



Partners’ equity
Common unitholders’ interest (484 million units issued and outstanding at both September 30, 2026 and December 31, 2025)	3,921		3,156
General partner’s interest (2% interest with 10 million units issued and outstanding at both September 30, 2026 and December 31, 2025)	(3,042)		(2,742)
Total partners’ equity	879		414
Total liabilities and partners’ equity	$	17,839	$	17,437

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

Table of Contents

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY (DEFICIT)

(in millions)

(unaudited)


Three and Nine Months Ended September 30, 2026
	Common Unitholders’ Interest			General Partner’s Interest			Total Partners’ Equity
	Units	Amount		Units	Amount
















Balance at December 31, 2025	484	$	3,156	10	$	(2,742)	$	414
Net income	—	182		—	4		186

Distributions
Common units, $0.830/unit	—	(402)		—	—		(402)

General partner units	—	—		—	(120)		(120)
Balance at March 31, 2026	484	2,936		10	(2,858)		78
Net income	—	1,138		—	23		1,161
Distributions
Common units, $0.790/unit	—	(382)		—	—		(382)
General partner units	—	—		—	(103)		(103)
Balance at June 30, 2026	484	3,692		10	(2,938)		754
Net income	—	626		—	13		639
Distributions
Common units, $0.820/unit	—	(397)		—	—		(397)
General partner units	—	—		—	(117)		(117)
Balance at September 30, 2026	484	$	3,921	10	$	(3,042)	$	879


Three and Nine Months Ended September 30, 2025
	Common Unitholders’ Interest			General Partner’s Interest	Total Partners’ Deficit
	Units	Amount				Units			Amount
Balance at December 31, 2024	484	$	1,821		10		$	(2,330)		$	(509)
Net income	—	628			—		13			641

Distributions
Common units, $0.820/unit	—	(397)			—		—			(397)
General partner units	—	—			—		(115)			(115)
Balance at March 31, 2025	484	2,052			10		(2,432)			(380)
Net income	—	542			—		11			553
Distributions
Common units, $0.820/unit	—	(397)			—		—			(397)
General partner units	—	—			—		(116)			(116)
Balance at June 30, 2025	484	2,197			10		(2,537)			(340)
Net income	—	496			—		10			506
Distributions
Common units, $0.820/unit	—	(397)			—		—			(397)
General partner units	—	—			—		(117)			(117)
Balance at September 30, 2025	484	$	2,296		10		$	(2,644)		$	(348)

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)


	Nine Months Ended September 30,
	2026		2025
Cash flows from operating activities
Net income	$	1,986	$	1,700
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	522		515


Total losses (gains) on derivative instruments, net	140		(109)

Net cash provided by (used for) settlement of derivative instruments	(22)		6

Other, net	6		37

Changes in operating assets and liabilities:
Trade and other receivables	184		21
Trade and other receivables—affiliate	(53)		(47)
Trade receivables—related party	—		1

Inventory	15		3


Accounts payable and accrued liabilities	(211)		(130)
Accounts payable and accrued liabilities—related party	—		(5)
Due to affiliates	(5)		(22)

Other, net	(17)		(39)
Other, net—affiliate	5		(50)
Net cash provided by operating activities	2,550		1,881

Cash flows from investing activities
Property, plant and equipment	(526)		(176)
Other, net	(5)		(4)
Net cash used in investing activities	(531)		(180)

Cash flows from financing activities
Proceeds from issuances of debt and borrowings	1,903		1,262
Redemptions and repayments of debt and borrowings	(1,967)		(1,617)



Distributions	(1,521)		(1,539)
Other, net	(31)		(22)
Net cash used in financing activities	(1,616)		(1,916)

Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	403		(215)
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	201		379
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$	604	$	164

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We own a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), which has natural gas liquefaction facilities with total production capacity of over 30 mtpa of LNG (the “Liquefaction Project”) as of September 30, 2026. The Sabine Pass LNG Terminal also has five LNG storage tanks, vaporizers and three marine berths. We also own and operate a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the “Creole Trail Pipeline”).

We are developing a two-phased expansion project adjacent to the Liquefaction Project to provide additional liquefaction capacity, inclusive of three liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”), and we are commercializing to support the additional liquefaction capacity associated with this potential expansion project. In May 2026, SPL Stage V entered into a lump sum, turnkey EPC contract with Bechtel Energy, Inc. for the first phase of the SPL Expansion Project and has commenced early engineering and procurement pursuant to the limited notices to proceed issued. The development of this project or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, regulatory approvals and acceptable commercial and financing arrangements before the Board of Directors of our general partner makes a positive FID.

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

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

Basis of Presentation

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

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

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

Accounting for Derivative Instruments

In June 2026, we designated the NPNS scope exception under Accounting Standards Codification Topic 815, Derivatives and Hedging, for our IPM agreements. The NPNS exception is available for contracts that are expected to be physically settled and used or sold in the normal course of business, which is consistent with our intended purpose to consume the delivered physical natural gas to produce LNG. Our designation considered increased observable U.S. Gulf Coast third-party physical natural gas market activity involving contracts indexed to global LNG or natural gas prices, among other factors, in evaluating whether the pricing mechanism is consistent with the economics of the underlying physical market. Following the NPNS designation, physical natural gas purchases under these agreements are no longer remeasured at fair value through earnings. Amounts are recognized under the applicable inventory and cost-of-sales guidance as the natural gas is received, consumed in the production process and the related LNG is sold. The estimated fair values of these agreements as of the designation date were established as the new cost basis and are being amortized into cost of sales on a systematic basis over the remaining expected terms of the agreements. Because recognition is based on the timing and volume of contract deliveries, the amounts recognized in any reporting period are expected to vary and are not expected to follow a linear pattern. These non-cash amounts reflect the amortization of deferred gains and losses established at the designation date rather than changes in current-period

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

market prices. If it is determined that the contracts designated as NPNS no longer meet the scope exception, the contracts would be recorded at fair value and any gains and losses would be immediately recognized in earnings.

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


New Consolidated Balance Sheets Location	Amount Reclassified
Deferred NPNS assets	$	669
Current portion of deferred NPNS liabilities	(108)
Deferred NPNS liabilities	(1,081)
Total deferred NPNS assets and liabilities	$	(520)

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


Years Ending December 31,	Estimated net reduction to cost of sales from amortization of deferred NPNS assets and liabilities
2026(1)	$	57
2027	103
2028	103
2029	88
2030	58
Thereafter	111
Total estimated amortization	$	520

(1)For the three and nine months ended September 30, 2026, we recorded a net reduction to cost of sales from amortization of $26 million and $31 million, respectively.

Prior to the designation date, we recognized $126 million of derivative losses during the nine months ended September 30, 2026, and derivative gains of $127 million and $315 million for the three and nine months ended September 30, 2025, respectively, for the designated agreements.

Recent Accounting Standards

ASU 2024-03

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

NOTE 2—UNITHOLDERS’ EQUITY

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

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds IDRs, which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

surplus as additional target levels are met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.

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

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

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

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


	September 30,		December 31,

	2026		2025
Trade receivables	$	305	$	473
Other receivables	22		38
Total trade and other receivables, net of current expected credit losses	$	327	$	511

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

NOTE 4—INVENTORY

Inventory consisted of the following (in millions):


	September 30,		December 31,

	2026		2025
Materials	$	140	$	123
LNG	12		31
Natural gas	11		24
Other	2		2
Total inventory	$	165	$	180

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 5—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,

	2026		2025
Terminal and related assets
Terminal and interconnecting pipeline facilities	$	20,521	$	20,480

Construction-in-process	517		214
Accumulated depreciation	(6,011)		(5,502)
Total terminal and related assets, net of accumulated depreciation	15,027		15,192
Assets under finance leases
Tug vessels	75		76
Accumulated depreciation	(20)		(14)
Total assets under finance leases, net of accumulated depreciation	55		62
Other assets
Other assets	26		26
Accumulated depreciation	(21)		(21)
Total other assets, net of accumulated depreciation	5		5
Property, plant and equipment, net of accumulated depreciation	$	15,087	$	15,259

Depreciation expense was $173 million and $172 million during the three months ended September 30, 2026 and 2025, respectively, and $518 million and $511 million during the nine months ended September 30, 2026 and 2025, respectively.

NOTE 6—DERIVATIVE INSTRUMENTS

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

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


	Fair Value Measurements as of
	September 30, 2026								December 31, 2025
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total

Liquefaction Supply Derivatives liability(1)	$	—	$	(4)	$	(117)	$	(121)	$	—	$	(23)	$	(500)	$	(523)

(1)As described in Note 1—Nature of Operations and Basis of Presentation, in June 2026, we designated the NPNS scope exception for our IPM agreements. As a result, these agreements ceased to be accounted for as derivative instruments, with the then-current carrying amounts of the related derivative assets and liabilities reclassified to the applicable financial statement line items described in Note 1—Nature of Operations and Basis of Presentation. These agreements are therefore no longer included in the fair value amounts presented as of September 30, 2026. As of December 31, 2025, these agreements had a fair value of $394 million, classified as a liability within Level 3 of the fair value hierarchy. Accordingly, the reduction in Level 3 fair value balances between the periods reflects, in part, the exclusion of these agreements following the June 2026 NPNS designation, in addition to market movements, settlements and other fair value activity.

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

We include a significant portion of the Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models, which incorporate significant unobservable inputs. In instances

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. We consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value, for which we make judgments about market risk related to liquidity of commodity indices utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. Our fair value estimates incorporate market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points. We may recognize changes in fair value through earnings that could impact our results of operations if and when such uncertainties are resolved.

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

Net Fair Value Liability

(in millions)

Valuation Approach

Significant Unobservable Input

Range of Significant Unobservable Inputs / Weighted Average(1)

Liquefaction Supply Derivatives

$(117)

Market approach incorporating present value techniques

Henry Hub basis spread

$(0.568) - $0.275 / $(0.036)

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

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

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,
	2026		2025		2026		2025
Balance, beginning of period	$	(106)	$	(1,147)	$	(500)	$	(1,307)
Realized and change in fair value losses included in net income(1):
Included in cost of sales, existing deals(2)	(14)		(93)		(198)		(7)
Included in cost of sales, new deals(3)	(35)		(2)		(38)		(12)
Purchases and settlements:
Purchases(4)	—		—		—		—
Settlements(5)	37		60		98		147


Transfers out of level 3(6)	1		(2)		1		(5)
Agreements designated as NPNS and no longer measured at fair value on a recurring basis(7)	—		—		520		—
Balance, end of period	$	(117)	$	(1,184)	$	(117)	$	(1,184)
Unfavorable changes in fair value relating to instruments still held at the end of the period	$	(49)	$	(95)	$	(90)	$	(19)

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

Liquefaction Supply Derivatives

We hold Liquefaction Supply Derivatives, which are indexed to Henry Hub or other natural gas price indices. As of September 30, 2026, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 10 years.

The forward notional amount for the Liquefaction Supply Derivatives was approximately 4,873 TBtu and 5,028 TBtu as of September 30, 2026 and December 31, 2025, respectively. As of December 31, 2025, our Liquefaction Supply Derivatives included 1,381 TBtu that were designated as NPNS in June 2026, which resulted in these agreements being no longer accounted for as derivative instruments as of the designation date. See Note 1—Nature of Operations and Basis of Presentation for further discussion.

The following table shows the effect and location of the Liquefaction Supply 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,
	2026		2025		2026		2025
LNG revenues	$	(1)	$	—	$	—	$	—
Cost of sales(2)	3		(12)		(140)		109

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

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

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




	Fair Value Measurements as of
Consolidated Balance Sheets Location	September 30, 2026		December 31, 2025
Current derivative assets	$	3	$	—
Derivative assets	1		541
Total derivative assets	4		541

Current derivative liabilities	(84)		(164)
Derivative liabilities	(41)		(900)
Total derivative liabilities	(125)		(1,064)

Derivative liability, net	$	(121)	$	(523)

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CHENIERE ENERGY PARTNERS, L.P. 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
	September 30, 2026		December 31, 2025
Gross assets	$	28	$	663
Offsetting amounts	(24)		(122)
Net assets	$	4	$	541

Gross liabilities	$	(160)	$	(1,084)
Offsetting amounts	35		20
Net liabilities	$	(125)	$	(1,064)

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


	Consolidated Balance Sheets Location	September 30,		December 31,
		2026		2025
Liquefaction Supply Derivatives	Other current assets, net	$	10	$	11
Liquefaction Supply Derivatives	Other current liabilities	—		(3)

NOTE 7—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):


	September 30,		December 31,

	2026		2025
Natural gas purchases	$	463	$	714
Interest costs and debt fees	174		181
Terminal and related asset costs	71		86
Other accrued liabilities	30		9
Total accrued liabilities	$	738	$	990

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—DEBT

Debt consisted of the following (in millions):


	September 30,		December 31,

	2026		2025
SPL:
Senior Secured Notes:




5.875% due 2026	$	—	$	200
5.00% due 2027	—		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
due 2037 with weighted average rate of 4.749% and 4.747% at September 30, 2026 and December 31, 2025, respectively(1)	1,623		1,730
Total SPL Senior Secured Notes	4,973		6,780

Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	4,973		6,780

CQP:
Senior Notes:


4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
5.950% due 2033	1,400		1,400
5.750% due 2034	1,200		1,200
5.550% due 2035	1,000		1,000
5.350% due 2036 (the “2036 CQP Senior Notes”)(2)	1,000		—
6.050% due 2056 (the “2056 CQP Senior Notes”)(2)	750		—
Total CQP Senior Notes	9,550		7,800

Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	9,550		7,800
Total debt	14,523		14,580

Current debt, net of unamortized discount and debt issuance costs(1)	(112)		(306)

Unamortized discount and debt issuance costs	(128)		(113)
Total long-term debt, net of unamortized discount and debt issuance costs	$	14,283	$	14,161

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Credit Facilities

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


	SPL Revolving Credit Facility		CQP Revolving Credit Facility
Total facility size	$	1,000	$	1,000
Less:
Outstanding balance	—		—

Letters of credit issued	127		—
Available commitment	$	873	$	1,000

Priority ranking	Senior secured		Senior unsecured
Interest rate on available balance(1)	SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%

Commitment fees on undrawn balance(1)	0.075% - 0.30%		0.10% - 0.30%
Letter of credit fees(1)	1.0% - 1.75%		1.125% - 2.0%
Maturity date	June 23, 2028		June 23, 2028

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

Restrictive Debt Covenants

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

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

Interest Expense

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Total interest cost	$	186	$	192	$	554	$	574
Capitalized interest	(4)		(3)		(8)		(7)
Total interest expense, net of capitalized interest	$	182	$	189	$	546	$	567

Fair Value Disclosures

As of September 30, 2026 and December 31, 2025, the estimated fair value of our senior notes was $13.8 billion and $14.6 billion, respectively, of which $1.1 billion and $1.3 billion, respectively, were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of the fair value of our senior notes was classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 9—REVENUES

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Revenues from contracts with customers
LNG revenues (excluding net derivative loss below)	$	1,957	$	1,837	$	6,561	$	5,961
LNG revenues—affiliate	567		518		2,044		1,738

Regasification revenues	34		34		102		102
Other revenues	17		15		50		47

Total revenues from contracts with customers	2,575		2,404		8,757		7,848
Net derivative loss (see Note 6)	(1)		—		—		—
Total revenues	$	2,574	$	2,404	$	8,757	$	7,848

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

Contract Liabilities

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


	Nine Months Ended September 30, 2026

Balance, beginning of period	$	216
Cash received but not yet recognized in revenue	133
Revenue recognized from prior period deferral	(116)
Balance, end of period	$	233

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


	Nine Months Ended September 30, 2026

Balance—affiliate, beginning of period	$	10
Cash received but not yet recognized in revenue	3
Revenue recognized from prior period deferral	(7)
Balance—affiliate, end of period	$	6

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, 2026			December 31, 2025
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years)(1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years)(1)
LNG revenues	$	43.3	7	$	41.0	7
LNG revenues—affiliate	0.2		1	0.5		1
Regasification revenues	0.3		2	0.4		2
Total revenues	$	43.8		$	41.9

(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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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,
	2026		2025		2026		2025
LNG revenues	58	%	58	%	62	%	60	%
LNG revenues—affiliate	71	%	68	%	72	%	72	%
Regasification revenues	8	%	8	%	8	%	8	%

NOTE 10—RELATED PARTY TRANSACTIONS

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


		Three Months Ended September 30,						Nine Months Ended September 30,
		2026			2025			2026			2025
LNG revenues—affiliate
Cheniere Marketing Agreements		$	567		$	518		$	2,044		$	1,738












Cost of sales—affiliate
Cheniere Marketing Agreements		—			—			44			—
Contracts for Sale and Purchase of Natural Gas		—			—			2			—
Total cost of sales—affiliate		—			—			46			—






Operating and maintenance expense—affiliate

Services Agreements (see Note 1)		43			40			136			126



Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements(1)		—			—			—			28

General and administrative expense—affiliate
Services Agreements (see Note 1)		25			23			72			70

Other operating costs and expenses—affiliate
Services Agreements (see Note 1)		—			—			1			1

Other income—affiliate
Services Agreements (see Note 1)	—			1			3			23

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

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

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

See our annual report on Form 10-K for the fiscal year ended December 31, 2025 for additional information regarding the agreements referenced in the above table, as well as a description of other agreements we have with our affiliates, including the Terminal Marine Services Agreement. Under this agreement, Tug Services distributed $3 million and $2 million during the three months ended September 30, 2026 and 2025, respectively, and $8 million and $6 million during the nine months ended September 30, 2026 and 2025, respectively, to Cheniere Terminals, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Equity (Deficit).

NOTE 11—NET INCOME PER COMMON UNIT

Net income per common unit for a given period is based on the distributions we incur to the common unitholders with respect to earnings or losses of the reporting period plus an allocation of undistributed net income or loss based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions declared by us during the period are presented on the Consolidated Statements of Partners’ Equity (Deficit). On October 23, 2026, we declared a cash distribution of $0.890 per common unit to unitholders of record as of November 3, 2026, and the related general partner distribution, to be paid on November 13, 2026 with respect to the three months ended September 30, 2026. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.115 per unit.

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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



	Total		Limited Partner Common Units		General Partner Units		IDR
Three Months Ended September 30, 2026
Net income	$	639
Less: declared distributions(1)	579		431		12		136
Assumed allocation of undistributed net income(2)	$	60	59		1		—
Assumed allocation of net income			$	490	$	13	$	136

Weighted average units outstanding			484
Basic and diluted net income per unit			$	1.01

Three Months Ended September 30, 2025
Net income	$	506
Less: declared distributions(1)	520		402		10		108
Assumed allocation of undistributed net loss(2)	$	(14)	(14)		—		—
Assumed allocation of net income			$	388	$	10	$	108

Weighted average units outstanding			484
Basic and diluted net income per unit			$	0.80

Nine Months Ended September 30, 2026
Net income	$	1,986
Less: declared distributions(1)	1,571		1,210		32		329
Assumed allocation of undistributed net income(2)	$	415	407		8		—
Assumed allocation of net income			$	1,617	$	40	$	329

Weighted average units outstanding			484
Basic and diluted net income per unit			$	3.34


Nine Months Ended September 30, 2025
Net income	$	1,700
Less: declared distributions(1)	1,542		1,196		31		315

Assumed allocation of undistributed net income(2)	$	158	155		3		—
Assumed allocation of net income			$	1,351	$	34	$	315

Weighted average units outstanding			484
Basic and diluted net income per unit			$	2.79

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

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

NOTE 12—SEGMENT INFORMATION AND CUSTOMER CONCENTRATION

We have determined that we operate as a single operating and reportable segment. The measure of profit and loss regularly provided to the chief operating decision maker (“CODM”) that is most consistent with GAAP is net income, as presented in our Consolidated Statements of Operations. This measure contributes to the CODM’s assessment of performance and resource allocation, which includes monitoring of budget versus actual results, establishing compensation and deciding on capital allocation priorities. Significant expenses regularly provided to the CODM, and included in the measure of profit and loss, are cost of sales, operating and maintenance expense and general and administrative expense, as reported in our Consolidated Statements of Operations. Also provided regularly to the CODM are changes in the fair value of our derivative

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

instruments, which are inclusive of significant noncash items, which were $9 million in gains and $105 million in losses for the three and nine months ended September 30, 2026, respectively, and $16 million in losses and $103 million in gains for the same periods of 2025, respectively. Interest income, which is included in other income (expense), net on our Consolidated Statements of Operations, was $6 million and $15 million for the three and nine months ended September 30, 2026, respectively, and $5 million and $11 million for the same periods of 2025, respectively.

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

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


	Percentage of Total Revenues from Contracts with External Customers				Percentage of Trade Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2026	2025	2026	2025	2026	2025
Customer A	17%	17%	21%	22%	20%	28%
Customer B	14%	14%	14%	15%	*	19%
Customer C	16%	17%	15%	15%	15%	12%
Customer D	14%	16%	13%	14%	12%	21%
Customer E	*	*	10%	10%	*	*
Customer F	*	*	*	*	16%	—%

* Less than 10%

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION

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


	Nine Months Ended September 30,
	2026		2025
Cash paid during the period for interest on debt, net of amounts capitalized	$	527	$	575

Non-cash investing activities:
Unpaid purchases of property, plant and equipment(1)	10		10
Right-of-use assets obtained in exchange for lease liabilities:
Operating lease liabilities	—		2

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

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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.” 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 regarding our ability to pay distributions to our unitholders;

•statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL;

•statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction facility, pipeline facility 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 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; 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 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

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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, 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

We are a publicly traded Delaware limited partnership formed by Cheniere. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

LNG is natural gas (primarily methane) in liquid form and is a cleaner dispatchable fuel for power generation. The LNG we produce is shipped all over the world, converted back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses.

We own a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, with a total production capacity of over 30 mtpa of LNG (the “Liquefaction Project”) as of September 30, 2026. The Sabine Pass LNG Terminal also has five LNG storage tanks with aggregate capacity of approximately 17 Bcfe and vaporizers with regasification capacity of approximately 4 Bcf/d, as well as three marine berths, two of which can accommodate vessels with nominal capacity of up to 266,000 cubic meters and the third berth, which can accommodate vessels with nominal capacity of up to 200,000 cubic meters. We also own and operate a 94-mile natural gas supply pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the “Creole Trail Pipeline”).

Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows, and include SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and long-term IPM agreements, in which a gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is primarily indexed to Henry Hub and generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. Through our SPAs and long-term IPM agreements currently in effect, with approximately 13 years of weighted average remaining life as of September 30, 2026, we have contracted with third parties approximately 90% of the total anticipated production from the Liquefaction Project through the mid-2030s. Additionally, there are SPAs that Cheniere Marketing currently holds that may be novated to us in the future. LNG produced by the Liquefaction

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Project that is not contracted under long-term contracts is available for Cheniere Marketing, Cheniere’s integrated marketing function, pursuant to an SPA it has with us.

Disciplined Accretive Growth

We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. Capital investment parameters are the foundation of our disciplined, accretive growth, and include consideration to:

•Achieve value accretive returns through long-term commercial contracts: We aim to contract approximately 90% of our current and planned liquefaction capacity under long-term SPAs and long-term IPM agreements with creditworthy counterparties under the pricing structures described above, with financial parameters that consider, among other things, targeted unlevered returns, project leverage and distributions. Our success in securing long-term commercial contracts at desired returns is influenced by global LNG and natural gas market conditions and other uncertainties described in the risk factors of our annual report on Form 10-K for the fiscal year ended December 31, 2025.

•Achieve credit accretive returns: We aim to conservatively fund our projects through financing structures that sustain our long-term, run-rate leverage and credit metrics. Our ability to secure the required financing is influenced by market interest rates and other factors described in the risk factors of our annual report on Form 10-K for the fiscal year ended December 31, 2025.

We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We believe these factors provide a foundation for additional growth in our portfolio of customer contracts in the future. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. We are developing a two-phased expansion adjacent to the Liquefaction Project, inclusive of three liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”), and we are commercializing to support the additional liquefaction capacity associated with this project. The first phase is expected to include one liquefaction train, a boil-off gas re-liquefaction unit and related infrastructure and tie-ins to the existing Sabine Pass LNG Terminal. Inclusive of estimated debottlenecking opportunities, the first phase is expected to have total production capacity of over 6 mtpa of LNG. As discussed below, we have advanced certain commercialization, financing, engineering and procurement activities for the first phase.

Our activities, including our expansion activities, are highly regulated and require regulatory approvals at various stages, including approvals of the FERC and DOE under Sections 3 and 7 of the NGA, as well as several other material governmental and regulatory approvals and permits. The progression of our expansion project is dependent on receiving all regulatory approvals required within the respective stages. See our annual report on Form 10-K for the fiscal year ended December 31, 2025 for further discussion of the regulations under federal, state and local statutes, rules, regulations and laws to which we are subject and associated risk factors relating to regulations. The production capacity of the SPL Expansion Project is anticipated based on capacity, scale, location and infrastructure, as well as subject to regulatory review and approval, and may change based on design considerations, engagement with contractors and other factors. The expected production capacity is further subject to adjustment for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities.

The SPL Expansion Project requires, among other things, regulatory approvals and acceptable commercial and financing arrangements before we make a positive FID. Risks associated with cost overruns and delays in the completion of our expansion projects are described in the risk factors of our annual report on Form 10-K for the fiscal year ended December 31, 2025.

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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

Up to ~ 20 mtpa

Milestone

Regulatory

FERC authorizations:

Final environmental impact statement

Order under Section 3 of NGA

Pending

Certification to commence construction

Pending

DOE export authorization:

FTA countries

Non-FTA countries

Pending

Commercialization and Other Contracting

Definitive SPAs and IPM agreements

Secured – first phase(1)

Financing

Commitments obtained – first phase(2)

Definitive full-scope EPC contract

Executed – first phase(3)

Target Milestone

FID

2026/2027 – first phase

ü indicates that the applicable regulatory approval or development milestone has been received or completed, as applicable, and may remain subject to conditionality

(1)Commercial support of the SPL Expansion Project includes the definitive agreements entered into by project entities and affiliates, including agreements available for assignment or novation to the applicable project entity.

(2)We have obtained commitments for a term loan credit facility to finance the construction costs of the first phase of the SPL Expansion Project that are not expected to be funded with available cash. Closing and funding under the financing remain subject to customary conditions, including the issuance of a positive FID with respect to the first phase of the SPL Expansion Project.

(3)In May 2026, SPL Stage V entered into a lump sum, turnkey EPC contract with Bechtel Energy, Inc. (“Bechtel”) for the first phase of the SPL Expansion Project and has commenced early engineering and procurement pursuant to the limited notices to proceed (“LNTPs”) issued.

Overview of Significant Events

Our significant events since January 1, 2026 and through the filing date of this Form 10-Q include the following:

Strategic

•In October 2026, SPL entered into long-term LNG SPA with QatarEnergy to supply up to 2 mtpa of LNG on an FOB basis beginning in the early 2030s through 2054, with 1 mtpa subject to, among other things, a positive FID with respect to the first phase of the SPL Expansion Project.

•In September 2026, we received a final environmental impact statement from the FERC relating to the SPL Expansion Project.

•In May 2026, SPL Stage V entered into a lump sum, turnkey EPC contract with Bechtel for the first phase of the SPL Expansion Project and has commenced early engineering and procurement pursuant to the LNTPs issued.

Operational

•As of October 23, 2026, approximately 3,560 cumulative LNG cargoes totaling over 245 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

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Financial

•In June 2026, we issued and sold $1.0 billion aggregate principal amount of 5.350% Senior Notes due 2036 (the “2036 CQP Senior Notes”) and $750 million aggregate principal amount of 6.050% Senior Notes due 2056 (the “2056 CQP Senior Notes”), and a portion of the net proceeds were used to fully redeem $1.5 billion aggregate principal amount of SPL’s 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), as well as for general corporate purposes, including funding a portion of the LNTP related to the first phase of the SPL Expansion Project.

•SPL repaid $54 million and $307 million aggregate principal amount of its senior notes during the three and nine months ended September 30, 2026, respectively, exclusive of amounts refinanced, as noted above.

•On October 23, 2026, with respect to the third quarter of 2026, we declared a cash distribution of $0.890 per common unit to unitholders of record as of November 3, 2026, and the related general partner distribution, to be paid on November 13, 2026. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.115 per unit.

Results of Operations


	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per unit data)	2026		2025		Variance		2026		2025		Variance
Revenues
LNG revenues	$	1,956	$	1,837	$	119	$	6,561	$	5,961	$	600
LNG revenues—affiliate	567		518		49		2,044		1,738		306

Regasification revenues	34		34		—		102		102		—

Other revenues	17		15		2		50		47		3

Total revenues	2,574		2,404		170		8,757		7,848		909

Operating costs and expenses
Cost of sales (excluding operating and maintenance expense and depreciation and amortization expense shown separately below)	1,276		1,278		(2)		4,757		4,177		580
Cost of sales—affiliate	—		—		—		46		—		46

Operating and maintenance expense	236		191		45		692		683		9
Operating and maintenance expense—affiliate	43		40		3		136		126		10
Operating and maintenance expense—related party	—		—		—		—		28		(28)


General and administrative expense	3		3		—		9		9		—
General and administrative expense—affiliate	25		23		2		72		70		2
Depreciation and amortization expense	174		173		1		522		515		7
Other operating costs and expenses	2		—		2		6		2		4
Other operating costs and expenses—affiliate	—		—		—		1		1		—
Total operating costs and expenses	1,759		1,708		51		6,241		5,611		630

Income from operations	815		696		119		2,516		2,237		279

Other income (expense)
Interest expense, net of capitalized interest	(182)		(189)		7		(546)		(567)		21


Other income (expense), net	6		(2)		8		13		7		6
Other income—affiliate	—		1		(1)		3		23		(20)
Total other expense	(176)		(190)		14		(530)		(537)		7

Net income	$	639	$	506	$	133	$	1,986	$	1,700	$	286

Basic and diluted net income per common unit	$	1.01	$	0.80	$	0.21	$	3.34	$	2.79	$	0.55

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Volumes recognized as revenues


	Three Months Ended September 30,			Nine Months Ended September 30,
	2026	2025	Variance	2026	2025	Variance

Volumes recognized as revenues (in TBtu)	378	374	4	1,187	1,130	57

Net income

Net income increased by $133 million and $286 million during the three and nine months ended September 30, 2026, respectively, as compared to the same periods of 2025.

The increase between the three month periods was primarily due to a $170 million increase in LNG revenues, net of cost of sales, as a result of favorable pricing effects associated with LNG volumes delivered during the comparative periods. The net impact of changes in the fair value of our derivative instruments was immaterial, reflecting offsetting fair value changes primarily from our IPM agreements and other natural gas supply contracts.

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

•$488 million increase in LNG revenues, net of cost of sales and excluding changes in fair value of agreements accounted for as derivative instruments, from favorable pricing effects associated with LNG volumes delivered during the comparative periods, and to a lesser degree from higher production volume; partially offset by:

•$208 million of unfavorable changes in fair value of our derivative instruments, comprised of:

◦$441 million of unfavorable changes in the fair value of our long-term IPM agreements prior to the NPNS designation in June 2026, as further described below, due to widening spreads between global and U.S. domestic natural gas benchmarks and elevated global natural gas price volatility influenced in part by the tightening supply conditions, transit constraints and heightened geopolitical uncertainties from the conflict and instabilities across parts of the Middle East during 2026; partially offset by:

◦$233 million of favorable changes in the fair value of other agreements accounted for as derivative instruments, largely due to changes in market-based locational forward price differentials for North American natural gas deliveries.

The following is an expanded discussion of the material drivers of the variance in net income:

Revenues

Total revenues increased by $170 million and $909 million during the three and nine months ended September 30, 2026, respectively, as compared to the same periods of 2025.

The increase between the three month periods was primarily attributable to a $131 million increase from higher pricing per MMBtu, primarily as a result of increased global LNG pricing associated with geopolitical uncertainties and instabilities,

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related to the SPA linked to the same global market prices as one of our long-term IPM agreements, and favorable pricing effects associated with the remaining LNG volumes delivered during the comparative periods.

The increase between the nine month periods was primarily attributable to:

•$551 million increase from higher pricing per MMBtu as a result of increased Henry Hub pricing; and

•$381 million increase due to higher production volume as a result of planned large-scale maintenance activities that occurred during the nine months ended September 30, 2025, but did not recur during the same period of 2026.

Operating costs and expenses

Total operating costs and expenses had a relatively immaterial change during the three months ended September 30, 2026 and increased by $630 million during the nine months ended September 30, 2026, respectively, as compared to the same periods of 2025.

The increase between the nine month periods was primarily attributable to:

•$338 million increase in the cost of natural gas feedstock between the nine month periods, largely due to the increase in U.S. natural gas prices and to a lesser degree from higher production volume, partially offset by a decrease in costs associated with the sale of certain unutilized natural gas procured for the liquefaction process; and

•$208 million of unfavorable changes in the fair value of agreements accounted for as derivative instruments included in cost of sales, of which $441 million of unfavorable changes related to the changes in fair value of the IPM agreements prior to the NPNS designation date in June 2026, as further described above under the caption Net income, due to favorable fair value changes recognized on these agreements in 2025 that did not recur following the NPNS designation because these agreements were no longer subject to recurring fair value measurement. The changes in the fair value of our long-term IPM agreements were partially offset by $233 million of favorable changes in the fair value of natural gas supply contracts accounted for as derivative instruments included in cost of sales, largely due to changes in market-based locational forward price differentials for North American natural gas deliveries.

Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements unless they qualify for, and we designate, an applicable scope exception under Accounting Standards Codification Topic 815, including the NPNS scope exception.

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

Conversely, commodity contracts accounted for as derivative instruments and for which we have not designated the NPNS exception remain subject to fair value accounting in which gains and losses arising from changes in fair value affect earnings. For such contracts, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties,

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including those related to the availability of market information for delivery points. We may recognize changes in fair value through earnings that could impact our results of operations if and when such uncertainties are resolved.

Business Seasonality

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

Liquidity and Capital Resources

The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt offerings by us or our subsidiaries and equity offerings by us.

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


	September 30, 2026


Cash and cash equivalents	$	569
Restricted cash and cash equivalents designated for the Liquefaction Project	35

Available commitments under our credit facilities(1):

SPL Revolving Credit Facility	873
CQP Revolving Credit Facility	1,000

Total available commitments under our credit facilities	1,873

Total available liquidity	$	2,477

(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of September 30, 2026. Additionally, we have secured commitments for a term loan credit facility to finance the construction costs of the first phase of the SPL Expansion Project, as discussed above in Overview, and to amend and extend the maturity of our $2.0 billion of aggregate revolving credit facilities at CQP and SPL, including the reallocation of $250 million in commitments from the SPL Revolving Credit Facility to the CQP Revolving Credit Facility. 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, 2026 will be driven by future sources of liquidity and future cash requirements. For a discussion of our future sources and uses of liquidity, see the liquidity and capital resources disclosures in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the fiscal year ended December 31, 2025.

Although our sources and uses of cash are presented below from a consolidated standpoint, we and our subsidiary SPL operate with independent capital structures. Certain restrictions or requirements under debt instruments executed by SPL limit its ability to distribute cash, including the following:

•SPL is required to deposit all cash received into restricted cash and cash equivalents accounts under certain of its debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments. In addition, SPL’s operating costs are managed by subsidiaries of Cheniere under affiliate agreements, which may require SPL to advance cash to the respective affiliates; and

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•SPL is restricted by affirmative and negative covenants included in certain of its debt agreements in its ability to make certain payments, including distributions, unless specific requirements are satisfied. See Note 8—Debt of our Notes to Consolidated Financial Statements for additional information on these covenants.

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

Supplemental Guarantor Information

Certain debt obligations of CQP (the “Guaranteed Obligations”), consisting of the $1.5 billion of 4.500% Senior Notes due 2029, $1.5 billion of 4.000% Senior Notes due 2031, $1.2 billion of 3.25% Senior Notes due 2032, $1.4 billion of 5.950% Senior Notes due 2033, $1.2 billion of 5.750% Senior Notes due 2034, $1.0 billion of 5.550% Senior Notes due 2035, $1.0 billion of 5.350% Senior Notes due 2036 and $750 million of 6.050% Senior Notes due 2056 (collectively, the “CQP Senior Notes”) are jointly and severally guaranteed by certain subsidiaries of CQP (each a “Guarantor” and collectively, the “CQP Guarantors”), as prescribed within the respective debt agreements governing such Guaranteed Obligation.

The CQP Guarantors’ guarantees of such Guaranteed Obligations are full and unconditional, subject to certain release provisions including, as applicable, (1) the sale, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of a Guarantor, (2) the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from another guarantee that resulted in the creation of its guarantee of the Guaranteed Obligation and (4) the legal defeasance or satisfaction and discharge of obligations under the indenture governing the CQP Senior Notes. In the event of a default in payment of the principal or interest by us, whether at maturity of the respective debt obligation or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the CQP Guarantors to enforce the guarantee.

The Guaranteed Obligations contain affirmative and negative covenants that are customary for the respective debt instrument, including, with limited exceptions, restrictions on CQP’s and the CQP Guarantors’ ability to incur additional indebtedness and/or liens, enter into hedging arrangements and/or engage in transactions with affiliates. The Guaranteed Obligations also include events of default that are customary for the respective debt instrument, which are subject to customary grace periods and materiality standards.

The rights of holders of the Guaranteed Obligations against the CQP Guarantors may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the CQP Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

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The following tables include summarized financial information of CQP (the “Parent Issuer”) and the CQP Guarantors (together with the Parent Issuer, the “Obligor Group”) on a combined basis. Investments in and equity in the earnings of SPL and, subject to certain conditions governing its guarantee, certain other subsidiaries of CQP (collectively with SPL, the “Non-Guarantors”), which are not currently members of the Obligor Group, have been excluded. Intercompany balances and transactions between entities in the Obligor Group have been eliminated. Although the creditors of the Obligor Group have no claim against the Non-Guarantors, the Obligor Group may gain access to the assets of the Non-Guarantors upon bankruptcy, liquidation or reorganization of the Non-Guarantors due to its investment in these entities. However, such claims to the assets of the Non-Guarantors would be subordinated to any claims by the Non-Guarantors’ creditors, including trade creditors.


Summarized Balance Sheets (in millions)	September 30,		December 31,

	2026		2025
ASSETS
Current assets



Current assets, net	$	617	$	226
Current assets—affiliate	152		146
Current assets with Non-Guarantors	48		56
Total current assets	817		428


Non-current assets, net	2,792		2,851
Total assets	$	3,609	$	3,279

LIABILITIES
Current liabilities


Current liabilities	$	210	$	154
Current liabilities—affiliate	43		50
Current liabilities due to Non-Guarantors	146		151
Total current liabilities	399		355

Long-term debt, net of unamortized discount and debt issuance costs	9,450		7,724

Other non-current liabilities	119		130
Non-current liabilities—affiliate	16		18
Non-current liabilities—Non-Guarantors	3		—
Total liabilities	$	9,987	$	8,227


Summarized Statement of Operations (in millions)	Nine Months Ended September 30, 2026

Revenues	$	151
Revenues from Non-Guarantors	426
Total revenues	577

Operating costs and expenses	192
Operating costs and expenses—affiliate	169
Recovery of operating costs and expenses from Non-Guarantors	(2)
Total operating costs and expenses	359

Income from operations	218
Net loss	$	(100)

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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,
	2026		2025

Net cash provided by operating activities	$	2,550	$	1,881
Net cash used in investing activities	(531)		(180)
Net cash used in financing activities	(1,616)		(1,916)
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	$	403	$	(215)

Operating Cash Flows

The $669 million increase between the periods was primarily related to higher net cash inflows from the sale of LNG cargoes, largely due to higher revenue from higher pricing per MMBtu. Also contributing to the increase was a favorable change in net operating assets and liabilities, mainly due to differences in timing of payments to suppliers and cash collections from the sale of LNG cargoes.

Investing Cash Flows

Cash outflows for property, plant and equipment during the nine months ended September 30, 2026 and 2025 primarily related to costs paid for the following projects, excluding associated capitalized interest: (1) $203 million for the SPL Expansion Project during the nine months ended September 30, 2026, primarily related to procurement activities and work performed by Bechtel under the LNTPs and (2) optimization and other site improvement projects during both periods. We expect to continue to incur capital expenditures for engineering and procurement activities under the SPL Expansion Project LNTPs.

Financing Cash Flows

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


	Nine Months Ended September 30,
	2026		2025
Proceeds from issuances of debt and borrowings	$	1,903	$	1,262
Redemptions and repayments of debt and borrowings	(1,967)		(1,617)



Distributions	(1,521)		(1,539)
Other, net	(31)		(22)
Net cash used in financing activities	$	(1,616)	$	(1,916)

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Proceeds from Issuances of Debt and Borrowings

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


	Nine Months Ended September 30,
	2026		2025
CQP:
2036 CQP Senior Notes	$	995	$	—
2056 CQP Senior Notes	748		—
5.550% Senior Notes due 2035	—		997

SPL:
SPL Revolving Credit Facility	160		265
Total proceeds from issuances of debt and borrowings	$	1,903	$	1,262

Redemptions and Repayments of Debt and Borrowings

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


	Nine Months Ended September 30,
	2026		2025



SPL:

5.625% Senior Secured Notes due 2025	$	—	$	(300)
5.875% Senior Secured Notes due 2026	(200)		(1,000)
5.00% Senior Secured Notes due 2027	(1,500)		—
Senior Notes due 2037 with weighted average rate of 4.748% and 4.746%, respectively	(107)		(52)
SPL Revolving Credit Facility	(160)		(265)
Total redemptions and repayments of debt and borrowings	$	(1,967)	$	(1,617)

Cash Distributions to Unitholders

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

The following provides a summary of distributions paid by us during the nine months ended September 30, 2026 and 2025:


				Total Distribution (in millions)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Common Units		General Partner Units		Incentive Distribution Rights

August 14, 2026	April 1 - June 30, 2026	$	0.820	$	397	$	10	$	104
May 15, 2026	January 1 - March 31, 2026	0.790		382		10		90
February 13, 2026	October 1 - December 31, 2025	0.830		402		10		108


August 14, 2025	April 1 - June 30, 2025	$	0.820	$	397	$	10	$	104
May 15, 2025	January 1 - March 31, 2025	0.820		397		10		104
February 14, 2025	October 1 - December 31, 2024	0.820		397		10		104

In addition, Tug Services distributed $8 million and $6 million during the nine months ended September 30, 2026 and 2025, respectively, to Cheniere Terminals in accordance with its terminal marine service agreement, which is recognized as part of the distributions to the holder of our general partner interest. Refer to Note 10—Related Party Transactions of our Notes to Consolidated Financial Statements for further discussion of this agreement.

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On October 23, 2026, with respect to the third quarter of 2026, we declared a cash distribution of $0.890 per common unit to unitholders of record as of November 3, 2026, and the related general partner distribution, to be paid on November 13, 2026. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.115 per unit.

Summary of Critical Accounting Estimates

The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2025.

Recent Accounting Standards

For a summary of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation of our Notes to Consolidated Financial Statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketing and Trading Commodity Price Risk

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


	September 30, 2026				December 31, 2025
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(121)	$	18	$	(523)	$	588

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

ITEM 4. CONTROLS AND PROCEDURES

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

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

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

ITEM 5. OTHER INFORMATION

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

ITEM 6. EXHIBITS

Exhibit No.

Description

10.1*

Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 5 Liquefaction Project, dated May 22, 2026, by and between SPL Stage V and Bechtel Energy, Inc.: (i) the Change Order CO-00001 HVO True Up – Phase 1, dated June 10, 2026 and (ii) the Change Order CO-00002 (I) Revised Schedule C; and (II) AEP/ALS Correction, dated June 22, 2026 (Portions of this exhibit have been omitted)

10.2*

First Amendment to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 5 Liquefaction Project, dated May 22, 2026, by and between SPL Stage V, LLC and Bechtel Energy Inc., dated September 30 , 2026 (Portions of this exhibit have been omitted)

22.1

List of Issuers and Guarantor Subsidiaries (Incorporated by reference to Exhibit 22.1 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on August 6, 2026)

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.

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 PARTNERS, L.P.
		By:	Cheniere Energy Partners GP, LLC, its general partner


Date:	October 28, 2026	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 28, 2026	By:	/s/ David Slack
			David Slack
			Senior Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

Cheniere Energy Partners - 10-Q quarterly report FY2026 Q3

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