Sabine Pass Liquefaction 10K 2024 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2024

☐ 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 333-192373

Sabine Pass Liquefaction, LLC

(Exact name of registrant as specified in its charter)


Delaware			27-3235920
(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
None	None	None

Securities registered pursuant to Section 12(g) of the Act: None

The registrant meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☒ No ☐

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 ☒

Note: The registrant is a voluntary filer not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934. However, the registrant has filed all reports required pursuant to Sections 13 or 15(d) during the preceding 12 months as if the registrant was subject to such filing requirements.

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates: Not applicable

Indicate the number of shares outstanding of the issuer’s classes of common stock, as of the latest practicable date: Not applicable

Documents incorporated by reference: None

SABINE PASS LIQUEFACTION, LLC

TABLE OF CONTENTS


			PART I
			Items 1. and 2. Business and Properties			3
			Item 1A. Risk Factors			10
			Item 1B. Unresolved Staff Comments			18
			Item 1C. Cybersecurity			18
			Item 3. Legal Proceedings			19
			Item 4. Mine Safety Disclosure			19
			PART II
			Item 5. Market for Registrant’s Common Equity, Related Member Matters and Issuer Purchases of Equity Securities			20
			Item 6. [Reserved]			20
			Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
			Item 7A. Quantitative and Qualitative Disclosures about Market Risk			30
			Item 8. Financial Statements and Supplementary Data			31
			Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			56
			Item 9A. Controls and Procedures			56
			Item 9B. Other Information			56
			Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections			56
			PART III
			Item 10. Managers, Executive Officers and Company Governance			57
			Item 11. Executive Compensation			57
			Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Member Matters			57
			Item 13. Certain Relationships and Related Transactions, and Manager Independence			57
			Item 14. Principal Accountant Fees and Services			57
			PART IV
			Item 15. Exhibits and Financial Statement Schedules			58
			Item 16. Form 10-K Summary			62
			Signatures			63

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DEFINITIONS

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

Common Industry and Other Terms


ASU						Accounting Standards Update
Bcf						billion cubic feet
Bcf/d						billion cubic feet per day
Bcf/yr						billion cubic feet per year


DOE						U.S. Department of Energy
EPC						engineering, procurement and construction
ESG						environmental, social and governance
FASB						Financial Accounting Standards Board
FERC						Federal Energy Regulatory Commission
FID						final investment decision
FOB						free-on-board
FTA countries						countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP						generally accepted accounting principles in the United States
Henry Hub						the final settlement price (in U.S. dollars per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
IPM agreement						integrated production marketing agreement 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
non-FTA countries						countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC						U.S. Securities and Exchange Commission
SOFR						Secured Overnight Financing Rate
SPA						LNG sale and purchase agreement
TBtu						trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
Tcf						trillion cubic feet
Train						an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA						terminal use agreement

Affiliate Entity Abbreviations


Cheniere						Cheniere Energy, Inc.
Cheniere Investments						Cheniere Energy Investments, LLC
Cheniere Marketing						Cheniere Marketing, LLC and its subsidiaries
CQP						Cheniere Energy Partners, L.P.
Cheniere Terminals						Cheniere LNG Terminals, LLC
CTPL						Cheniere Creole Trail Pipeline, L.P.
SPLNG						Sabine Pass LNG, L.P.

Unless the context requires otherwise, references to “SPL,” the “Company,” “we,” “us” and “our” refer to Sabine Pass Liquefaction, LLC.

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual 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 that we expect to commence or complete construction of our natural gas liquefaction project, 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, 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 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, including the financing of such Trains;

•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;

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

•other factors described in Item 1A. Risk Factors in this Annual Report on Form 10-K.

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 annual 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 annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. 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.

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PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

We are a Delaware limited liability company formed by CQP. 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 (methane) in liquid form. 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, other industrial uses and back up for intermittent energy sources. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.

We own six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”), at 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. The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks and three marine berths owned and operated by SPLNG, a subsidiary of CQP, and a 94-mile natural gas supply pipeline owned and operated by CTPL, a subsidiary of CQP.

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 an IPM agreement, in which a gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is primarily indexed to Henry Hub and generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. Through our SPAs and IPM agreement, with approximately 13 years of weighted average remaining life as of December 31, 2024, we have contracted approximately 80% of the total anticipated production from the Liquefaction Project, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.

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. 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. A subsidiary of CQP is developing an expansion adjacent to the Liquefaction Project with a total production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “Expansion Project”). In February 2024, we and other subsidiaries of CQP submitted an application to the FERC under the Natural Gas Act of 1938, as amended (the “NGA”), for authorization to site, construct and operate the Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking. In October 2024, the authorization from the DOE to export LNG to FTA countries was received. This expansion may be developed and constructed by an affiliate of ours outside of the Liquefaction Project. The development of the Expansion Project or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before a positive FID is made.

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Our Business Strategy

Our primary business strategy is to develop, construct and operate assets to meet our long-term customers’ energy demands. We plan to implement our strategy by:

•safely, efficiently and reliably operating and maintaining our assets, including our Trains;

•procuring natural gas and pipeline transport capacity to our facility;

•commencing commercial delivery for our long-term SPA customers, of which we have initiated for ten of eleven third party long-term SPA customers as of December 31, 2024;

•maximizing the production of LNG to serve our customers and generating steady and stable revenues and operating cash flows;

•optimizing the Liquefaction Project by leveraging existing infrastructure;

•maintaining a prudent and cost-effective capital structure; and

•strategically identifying actionable and economic environmental solutions.

Our Business

We shipped our first LNG cargo in February 2016 and as of February 14, 2025, approximately 2,840 cumulative LNG cargoes totaling over 195 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Liquefaction Project and Expansion Project

The Liquefaction Project, as described above under the caption General, is one of the largest LNG production facilities in the world with six Trains. In February 2024, we and other subsidiaries of CQP submitted an application to the FERC under the NGA for authorization to site, construct and operate the Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking. In October 2024, the authorization from the DOE to export LNG to FTA countries was received for the Expansion Project.

The following summarizes the volumes of natural gas for which we have received approvals from the FERC to site, construct and operate the Trains at the Liquefaction Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050:


	FERC Approved Volume		DOE Approved Volume
	(in Bcf/yr)	(in mtpa)	(in Bcf/yr)	(in mtpa)
FTA countries (1)	1,661.94	33	1,661.94	33
Non-FTA countries	1,661.94	33	1,661.94	33

(1)Excludes 899 Bcf/yr to FTA countries authorized in October 2024 for the Expansion Project that is not effective until the date of first commercial export from the Expansion Project.

Natural Gas Supply, Transportation and Storage

We have secured natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements, including an IPM agreement. Additionally, to ensure that we are able to transport and manage the natural gas feedstock to the Liquefaction Project, we have transportation precedent and other agreements to secure firm pipeline transportation and storage capacity from third parties and CTPL.

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Terminal Use Agreements

We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. Additionally, we have a partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), another TUA customer, to provide us with additional berthing and storage capacity at the Sabine Pass LNG Terminal. Refer to Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of our TUAs.

Major Customers

Customers accounting for 10% or more of total revenues were as follows:


		Percentage of Total Revenues from External Customers
	Year Ended December 31,
		2024	2023	2022
BG Gulf Coast LNG, LLC and affiliates		23%	24%	24%
Korea Gas Corporation		16%	17%	17%
GAIL (India) Limited		15%	16%	17%
Naturgy LNG GOM, Limited		14%	15%	16%

All of the above customers contribute to our LNG revenues through SPA contracts.

Additional information regarding our customer contracts can be found in Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 13—Segment Information and Customer Concentration of our Notes to Financial Statements.

Governmental Regulation

The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These rigorous regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.

Federal Energy Regulatory Commission

The design, construction, operation, maintenance and expansion of the Liquefaction Project and the export of LNG are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA. Under the NGA, the FERC’s jurisdiction generally extends to the sale for resale of natural gas in interstate commerce and to the construction, operation, maintenance and expansion of liquefaction facilities.

On February 18, 2022, the FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for the FERC’s decision-making process, modifying the standards that the FERC uses to evaluate applications to include, among other things, reasonably foreseeable greenhouse gas (“GHG”) emissions that may be attributable to the project and the project’s impact on environmental justice communities. On March 24, 2022, the FERC rescinded the Policy Statement, re-issued it as a draft and it remains pending. At this time, we do not expect it to have a material adverse effect on our operations.

In February 2024, we and other subsidiaries of CQP submitted an application to the FERC under the NGA for authorization to site, construct and operate the Expansion Project.

All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.5 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.

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Several other governmental and regulatory approvals and permits are required throughout the life of the Liquefaction Project. In addition, our FERC orders require us to comply with certain ongoing conditions and reporting obligations and maintain other regulatory agency approvals throughout the life of the Liquefaction Project. For example, throughout the life of our liquefaction facility, we are subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facility. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations has not materially affected our construction or operations.

DOE Export Licenses

The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal as discussed in Liquefaction Project and Expansion Project. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.

Under Section 3 of the NGA, applications for exports of natural gas (including LNG) to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations, which did not have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity for the year ended December 31, 2024. The DOE publicly released the updated analyses on December 17, 2024, and has solicited public comments on the analyses. On January 20, 2025, President Trump signed an Executive Order revoking the Biden Administration pause and extending the time for public comment. We do not expect the publication of the analyses to have a material effect on future DOE non-FTA export authorizations. The Expansion Project is currently pending non-FTA export approval with the DOE, although such approval is subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application. See Liquefaction Project and Expansion Project section above for FERC and DOE approved volumes on our existing Liquefaction Project.

Other Governmental Permits, Approvals and Authorizations

Construction and operation of the Liquefaction Project requires additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including the DOT, U.S. Army Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the U.S. Environmental Protection Agency (the “EPA”), U.S. Department of Homeland Security and the Louisiana Department of Environmental Quality (the “LDEQ”).

The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10). The EPA administers the Clean Air Act (“CAA”), and has delegated authority to the LDEQ to issue the Title V Operating Permit and the Prevention of Significant Deterioration Permit. These two permits are issued by the LDEQ for the Liquefaction Project.

Commodity Futures Trading Commission (“CFTC”)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in those markets. The CFTC has enacted a number of regulations pursuant to the Dodd-Frank Act.

As required by the Dodd-Frank Act, the CFTC and federal banking regulators also adopted rules requiring swap dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end

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user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We qualify as a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.

Pursuant to the Dodd-Frank Act, the CFTC adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.

Environmental Regulation

The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.

Clean Air Act

The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. However, we do not believe any such requirements will have a material adverse effect on our operations.

On February 28, 2022, the EPA removed a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant (“HAP”) emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that the construction and operations of our Liquefaction Project will be materially and adversely affected by such regulatory actions.

We are supportive of regulations reducing GHG emissions over time. Since 2009, the EPA has promulgated and finalized multiple GHG emissions regulations related to reporting and reductions of GHG emissions from our facilities. On December 2, 2023, the EPA issued final rules to reduce methane and volatile organic compounds (“VOC”) emissions from new, existing and modified emission sources in the oil and gas sector. These regulations require monitoring of methane and VOC emissions at our compressor stations. We do not believe such regulations will have a material adverse effect on our operations, financial condition or results of operations.

From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. On August 16, 2022, President Biden signed H.R. 5376 (P.L. 117-169), the Inflation Reduction Act of 2022 (“IRA”) which includes a charge on methane emissions above a certain methane intensity threshold for facilities that report their GHG emissions under the EPA’s Greenhouse Gas Emissions Reporting Program Part 98 regulations. The charge started at $900 per metric ton of methane in 2024, increased to $1,200 per metric ton in 2025, and is increasing to $1,500 per metric ton in 2026 and beyond. On November 12, 2024, the EPA finalized a rule to impose and collect the methane emissions charge authorized under the IRA. We do not believe the methane charge will have a material adverse effect on our operations, financial condition or results of operations.

The timing, extent and impact of these rules and other Biden Administration initiatives remain uncertain as the Trump Administration has undertaken steps to delay their implementation, and to review, repeal and potentially replace them.

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Coastal Zone Management Act (“CZMA”)

The siting and construction of the Liquefaction Project within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act

The Liquefaction Project is subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.

Resource Conservation and Recovery Act (“RCRA”)

The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

Protection of Species, Habitats and Wetlands

Various federal and state statutes, such as the Endangered Species Act, the Migratory Bird Treaty Act, the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If the Liquefaction Project may adversely affect a protected species or its habitat, we may be required to develop and follow a plan to remediate those impacts. In that case, siting, construction or operation may be delayed or restricted and cause us to incur increased costs.

It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe such regulatory actions will have a material adverse effect on our operations.

Market Factors and Competition

Market Factors

Our ability to enter into additional long-term SPAs to underpin the development of additional Trains or develop new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the extent of energy security needs in the European Union and elsewhere, the rate of fuel switching from coal, nuclear or oil to natural gas and other overarching factors such as global economic growth and the pace of any transition from fossil-based systems of energy production and consumption to alternative energy sources. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our ability to access capital markets.

We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Market participants around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure growth. Currently, significant amounts of money are being invested across Europe and Asia in natural gas projects under construction, and more continues to be earmarked to planned projects globally. In Europe, there are various plans to install more than 75 mtpa of import capacity over the near-term to secure access to LNG and displace Russian gas imports. In India, there are more than 5,600 kilometers of gas pipelines under construction to expand the gas distribution network and increase access to natural gas. And in China, billions of U.S. dollars have already been invested and hundreds of billions of U.S. dollars

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are expected to be further invested all along the natural gas value chain to enable growth and decrease harmful emissions. Furthermore, some of the existing integrated liquefaction facilities outside of the U.S. have been experiencing issues related to reduced feed gas as a result of depleting upstream resources. Global supply contributions from these plants have been decreasing and LNG supply growth is expected to help support these shortages.

As a result of these dynamics, we expect natural gas and LNG to continue to play an important role in satisfying energy demand going forward. In its forecast published in the third quarter of 2024, Wood Mackenzie Limited (“WoodMac”) forecasted that global demand for LNG would increase by approximately 61%, from approximately 418 mtpa, or 20.1 Tcf, in 2023, to 675 mtpa, or 32.4 Tcf, in 2040 and by approximately 65% to 691 mtpa or 33.1 Tcf in 2050. WoodMac also forecasted LNG production from existing operational facilities and new facilities already under construction would be able to supply the market with approximately 532 mtpa in 2040, declining to 463 mtpa in 2050. This could result in a market need for construction of an additional approximately 142 mtpa of LNG production by 2040 and about 227 mtpa by 2050. As a cleaner burning fuel with lower emissions than coal or liquid fuels in power generation, we expect natural gas and LNG to play a central role in balancing grids, serving as back up for intermittent energy sources and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of the Liquefaction Project, as well as the proposed expansion at Sabine Pass is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

As described above under the caption General, we have limited exposure to oil price movements as we have contracted a significant portion of our LNG production capacity under long-term SPAs and the IPM agreement, which are structured to generate fixed fees in addition to variable fees indexed to Henry Hub or international LNG pricing. Refer to General for further discussion of our long-term agreements.

Competition

Despite the long term nature of our SPAs, when we need to replace or amend any existing SPA or enter into new SPAs, we will compete with other natural gas liquefaction projects throughout the world primarily on the basis of price per contracted volume of LNG at that time, as well as attributes such as commercial innovation, reliable production and customer-focused operations to provide flexible and tailored solutions to LNG buyers. Our competition includes our affiliate Corpus Christi Liquefaction, LLC (“CCL”), which operates three Trains, and is constructing an additional seven midscale Trains as part of the Corpus Christi Stage 3 Project, at a natural gas liquefaction facility near Corpus Christi, Texas. Revenues associated with any incremental volumes of the Liquefaction Project, including those made available to Cheniere Marketing, will also be subject to market-based price competition.

Corporate Responsibility

As described in Market Factors and Competition, we expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Our vision is to provide clean, secure and affordable energy to the world. This vision underpins our focus on responding to the world’s shared energy challenges — expanding the global supply of clean, secure and affordable energy, improving air quality, reducing emissions and supporting the transition to a lower-carbon future. Our approach to corporate responsibility is guided by our Climate and Sustainability Principles: Transparency, Science, Supply Chain and Operational Excellence. In August 2024, Cheniere published Energy Secured, Benefits Delivered, its fifth Corporate Responsibility (“CR”) report, which details Cheniere’s approach and progress on ESG matters. Cheniere’s CR report is available at www.cheniere.com/our-responsibility/reporting-center. Information on Cheniere’s website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K.

Cheniere’s climate strategy is to measure and mitigate emissions so that it may better position its LNG supplies to remain competitive in a lower carbon future and provide energy, economic and environmental security to its customers across the world. To maximize the environmental benefits of our LNG, we believe it is important to develop our climate goals and strategies based on an accurate and holistic assessment of the emissions profile of our LNG, accounting for all steps in the supply chain.

Consequently, Cheniere has collaborated with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment (“LCA”) models, quantification, monitoring, reporting and verification (“QMRV”) of GHG emissions and other research and development projects. Cheniere also co-founded and sponsored the

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Energy Emissions Modeling and Data Lab (“EEMDL”), a multidisciplinary research and education initiative led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines. In addition, Cheniere commenced providing Cargo Emissions Tags (“CE Tags”) to its long-term customers in June 2022, and in October 2022 joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative. To ensure transparency and rigor, Cheniere works with academics and scientists to publish methodologies and results in multiple peer-reviewed journals.

Our total incremental expenditures related to climate initiatives, including capital expenditures, were not material to our Financial Statements during the years ended December 31, 2024, 2023 and 2022. However, as governments consider and implement actions to reduce GHG emissions and the transition to a lower-carbon economy continues to evolve, as described in Market Factors and Competition, we expect the scope and extent of our future climate and sustainability initiatives to evolve accordingly. While we have not incurred material direct expenditures related to climate change, we are proactive in our management of climate risks and opportunities, including compliance with existing and future government regulations. We face certain business and operational risks associated with physical impacts from climate change, such as exposure to severe weather events or changes in weather patterns, in addition to transition risks. Please see Item 1A. Risk Factors for additional discussion.

Employees

We have no employees. We have contracts with CQP and other subsidiaries of Cheniere for operations, maintenance and management services. See Note 11—Related Party Transactions of our Notes to Financial Statements for a discussion of such services agreements with our affiliate entities. As of December 31, 2024, Cheniere and its subsidiaries had 1,714 full-time employees, including 501 employees who directly supported the Sabine Pass LNG Terminal operations.

Available Information

Our principal executive offices are located at 845 Texas Avenue, Suite 1250, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers.

ITEM 1A. RISK FACTORS

The following are some of the important risk factors that could adversely affect our business, financial condition, results of operations or cash flows or have other adverse impacts and could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

The risk factors in this report are grouped into the following categories:

•Risks Relating to Our Financial Matters;

•Risks Relating to Our Operations and Industry; and

•Risks Relat ing to Regulations.

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Risks Relating to Our Financial Matters

An inability to source capital to supplement our available cash resources and existing revolving credit facility could cause us to have inadequate liquidity and could materially and adversely affect us.

As of December 31, 2024, we had $109 million of restricted cash and cash equivalents, $776 million of available commitments under our $1.0 billion senior secured revolving credit facility (the “Revolving Credit Facility”) and $8.4 billion of total debt outstanding (before unamortized, discount and debt issuance costs). We incur, and will incur, significant interest expense relating to financing the assets at the Liquefaction Project. Our ability to refinance our indebtedness may depend on our ability to access the debt capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, lending institutions’ evolving policies on financing businesses linked to fossil fuels and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant customer fails to perform its contractual obligations for any reason.

Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2024, we had SPAs with a total of 11 different third party customers.

While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.

Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we fail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs upon the occurrence of certain events of force majeure.

Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.

Our use of derivative instruments, including our IPM agreement, to manage risks could adversely affect our earnings reported under GAAP and our liquidity.

We use derivative instruments to manage our commodity-related price risk. The extent of our derivative position at any given time depends on our assessment of risks and related exposures for these commodities. We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements. Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile, which could have a significant adverse effect on our earnings reported under GAAP. For example, as described in Results of Operations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our net income for the years ended December 31, 2024 and 2023 included $0.4 billion and $2.1 billion of gains, respectively, resulting from changes in the fair values of our derivatives, substantially all of which were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreement.

These transactions and other derivative transactions have and may continue to result in substantial volatility in results of operations reported under GAAP, particularly in periods of significant commodity, currency or financial market variability. For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the

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value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, our liquidity may be adversely impacted by the cash margin requirements of the respective commodity exchanges or over-the-counter arrangements, or the failure of a counterparty to perform in accordance with a contract. As of December 31, 2024 and 2023, we had collateral posted with counterparties by us of $13 million and zero, respectively, which are included in other current assets, net in our Balance Sheets.

Risks Relating to Our Operations and Industry

Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us.

Weather events such as major hurricanes and winter storms have caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our facilities. In August 2020, we entered into an arrangement with our affiliate to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers from the other facility in the event operational conditions impact operations at the Sabine Pass LNG Terminal or at our affiliate’s terminal. During the year ended December 31, 2021, eight TBtu was loaded at affiliate facilities pursuant to this agreement. Our risk of loss related to weather events or other disasters is limited by contractual provisions in our SPAs, which can provide under certain circumstances relief from operational events, and partially mitigated by insurance we maintain. Aggregate direct and indirect losses associated with the aforementioned weather events, net of insurance reimbursements, have not historically been material to our Financial Statements, and we believe our insurance coverages maintained, existence of certain protective clauses within our SPAs and other risk management strategies mitigate our exposure to material losses. However, future adverse weather events and collateral effects, or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or interruption of operations at our terminal or related infrastructure, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of the Liquefaction Project or our other facilities. Our LNG terminal infrastructure and LNG facility located in or near Sabine Pass, Louisiana are designed in accordance with requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards, and all applicable industry codes and standards.

Disruptions to the third party supply of natural gas to our facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We depend upon third party pipelines and other facilities that provide gas delivery options to our Liquefaction Project. If any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be adversely impacted. Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the risk factor Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Project to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including composition changes in the quality of feed gas received from third parties, non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply of

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natural gas to our facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in part mitigated by the diversification of our natural gas supply and transportation across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the criticality of natural gas supply to our production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The operation of the Liquefaction Project is, and will be, subject to the inherent risks associated with this type of operation as discussed throughout our risk factors, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. Although losses incurred as a result of self- insured risk have not been material historically, the occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:

•competitive liquefaction capacity in North America;

•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;

•insufficient LNG tanker capacity;

•weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;

•reduced demand and lower prices for natural gas;

•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

•decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;

•cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;

•changes in supplies of, and prices for, alternative energy sources which may reduce the demand for natural gas;

•changes in regulatory, tax or other governmental policies regarding exported LNG, natural gas or alternative energy sources, which may reduce the demand for exported LNG and/or natural gas;

•political conditions in customer regions;

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•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;

•adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and

•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect our business and the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Failure of exported LNG to be a long term competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Operations of the Liquefaction Project are dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from the United States and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.

Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or from our competitors’ liquefaction facilities in the United States.

As described in Market Factors and Competition in Items 1. and 2. Business and Properties, it is expected that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to alternative fossil fuel energy sources such as oil and coal. However, as a result of transitions globally from fossil-based systems of energy production and consumption to renewable energy sources, LNG may face increased competition from alternative, cleaner sources of energy as such alternative sources emerge. Additionally, LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in the United States.

As described in General in Items 1. and 2. Business and Properties, we have contracted through our SPAs and IPM agreement approximately 80% of the total anticipated production from the Liquefaction Project with approximately 13 years of weighted average remaining life as of December 31, 2024, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. However, as a result of the factors described above and other factors, the LNG we produce may not remain a long term competitive source of energy internationally, particularly when our existing long term contracts begin to expire. Any significant impediment to the ability to continue to secure long term commercial contracts or deliver LNG from the United States could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We face competition based upon the international market price for LNG.

Our Liquefaction Project is subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity

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and prospects. Factors which may negatively affect potential demand for LNG from our Liquefaction Project are diverse and include, among others:

•increases in worldwide LNG production capacity and availability of LNG for market supply;

•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;

•increases in the cost to supply natural gas feedstock to our Liquefaction Project;

•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;

•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;

•increases in capacity and utilization of nuclear power and related facilities; and

•displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

A cyber attack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Project, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.

The LNG industry is increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our liquefaction operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Project. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should multiple of the third party pipelines which supply our Liquefaction Project suffer similar concurrent attacks, our Liquefaction Project may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A cyber attack involving our business or operational control systems or related infrastructure, or that of third parties pipelines with whom we do business, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.

Outbreaks of infectious diseases, such as COVID-19, at our facilities could adversely affect our operations.

Our facilities at the Liquefaction Project are critical infrastructure and continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including subsequent variants, had no adverse impact on our on-going operations, the risk of future variants and other infectious diseases is unknown and the outbreak of a more potent variant or another infectious disease in the future at one or more of our facilities could adversely affect our operations.

We are entirely dependent on Cheniere and CQP for key personnel, and the unavailability of skilled workers or Cheniere or CQP’s failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our key personnel could affect our business results.

As of December 31, 2024, Cheniere and its subsidiaries had 1,714 full-time employees, including 501 employees who directly supported our operations. We have contracted with subsidiaries of Cheniere and CQP to provide the personnel necessary for the operation, maintenance and management of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel to provide sufficient support for the aforementioned services. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to support us and to provide our customers with the highest quality service. We also compete with any other project Cheniere is operating or developing, including, as further described in Market Factors and Competition in Items 1. and 2. Business Properties, the operation and construction of its liquefaction project near Corpus Christi, Texas, for the time and expertise of Cheniere’s personnel. Further, Cheniere faces competition for these

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highly skilled employees in the vicinity of our operations and more generally from the Gulf Coast hydrocarbon processing and construction industries.

Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our future success will depend in part on our ability to engage, and Cheniere’s ability to attract and retain, additional qualified personnel.

A shortage in the labor pool of skilled workers, remoteness of our site locations, general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered. In addition, we are also subject to increased competition for skilled workers from new entrants to the LNG market. Any increase in our operating costs could materially and adversely affect our business results.

We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.

We have agreements to compensate and to reimburse expenses of Cheniere’s affiliates. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently operating three Trains and constructing or developing expansion projects at a natural gas liquefaction facility near Corpus Christi, Texas through its subsidiaries, and CCL has entered into fixed price SPAs with third-parties for the sale of LNG from this natural gas liquefaction facility, and may continue to enter into commercial arrangements with respect to this liquefaction facility that might otherwise have been entered into with respect to any of our future Trains.

We have or will have numerous contracts and commercial arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements, as well as servicing and other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest may be involved.

We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.

Risks Relating to Regulations

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of the Liquefaction Project and the export of LNG could impede operations and construction and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The design, construction and operation of the Liquefaction Project and the Expansion Project, as well as the export of LNG are highly regulated activities. Approvals of the FERC and DOE under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and export LNG.

To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the Liquefaction Project. In February 2024, we and other subsidiaries of CQP submitted an application to the FERC under the NGA for authorization to site, construct and operate the Expansion Project. To date, the DOE has also issued orders under Section 4 of the NGA authorizing us to export domestically produced LNG. We currently have the Expansion Project pending non-FTA export approval with the DOE, although approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application.

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with or our inability to obtain and maintain existing or newly imposed approvals,

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permits and filings that may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to our operations could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.

Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources, and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our terminal, including FERC, PHMSA, EPA and the United States Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, difficulty obtaining and maintaining permits from regulatory agencies or increased capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.

The EPA has finalized or proposed multiple GHG regulations that impact our assets and supply chain. On December 2, 2023, the EPA issued final rules to reduce methane and VOC emissions from new, existing and modified emission sources in the oil and gas sector. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that applied to our facilities beginning in calendar year 2024. On November 12, 2024, the EPA finalized a rule to impose and collect methane emissions charges authorized under the IRA. In addition, other international, federal and state initiatives may be considered in the future to address GHG emissions through treaty commitments, direct regulation, market-based regulations such as a GHG emissions tax or cap-and-trade programs or clean energy or performance-based standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our Liquefaction Project, or could increase compliance costs for our operations.

Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.

In 2022, the EPA removed a stay of formaldehyde standards in the NESHAP Subpart YYYY for stationary combustion turbines located at major sources of HAP emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY beginning in 2022.

Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from the Sabine Pass LNG Terminal or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national or international climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.

Total expenditures related to environmental and similar laws and governmental regulations, including capital expenditures, were immaterial to our Financial Statements for the years ended December 31, 2024, 2023 and 2022. Revised, reinterpreted or additional laws and regulations that result in increased compliance, operating or construction costs or

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restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity.

We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact. Any changes to local, domestic or international tax laws and regulations, or their interpretation and application, including those related to tariffs and duties, could affect our obligations, profitability and cash flows in the future. In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control. We continuously monitor and assess proposed tax legislation that could negatively impact our business.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Cyberattacks represent a potentially significant risk to the Company and our industry. We rely on subsidiaries of Cheniere, through our service agreements with them, as further discussed in Note 11—Related Party Transactions of our Notes to Financial Statements, and the board of directors of CQP’s general partner (the “Board”), which has oversight of our operations, to implement policies and procedures that are intended to manage and reduce this risk.

Risk Management and Strategy

As part of its broader approach to risk management, Cheniere’s cybersecurity program is designed to follow an “identify, protect, detect, respond and recover” approach to cybersecurity that is based off of the National Institute of Standards and Technology Cybersecurity Framework (“CSF”). Cheniere’s strategy also includes segmentation of corporate and operations networks, defense in depth and the least privileged access principle. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, Cheniere routinely evaluates opportunities to refine its cybersecurity program in order to mitigate operational network risks. Cheniere includes business continuity planning as a component of its strategy to help ensure critical systems are available to support the Company in the instance of a disruptive event. Cheniere also participates in various industry organizations to stay abreast of recent trends and developments.

On an ongoing basis, Cheniere assesses its people, processes and technology and, when necessary, adjusts the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. Cheniere conducts regular assessments and audits, cross-functional risk mitigation exercises and risk strategy sessions to identify cybersecurity risks, applicable regulatory requirements and industry standards. These engagements are also designed to exercise, assess the maturity of and enhance Cheniere’s Cyber Incident Response Plan. To support these efforts, Cheniere has contracted with third parties to perform facility and system penetration tests, compromise assessments of IT systems and security maturity assessments of its corporate and operational networks. Cheniere maintains a training program to help its personnel identify and assist in mitigating cybersecurity and data security risks. Cheniere’s employees and the members of the Board participate in annual training, user awareness campaigns and additional issue-specific training as needed. Cheniere also provides annual training for certain contractors who have access to its information technology networks.

With respect to third party service providers, Cheniere’s information security program includes conducting risk-based due diligence of certain service providers’ information security programs prior to onboarding. Cheniere strives to contractually require third party service providers with access to its information technology systems, sensitive business data or personal information to maintain reasonable security controls and restrict their ability to use Cheniere’s data, including personal information, for purposes other than to provide services to them, except as required by applicable law. Cheniere also seeks to negotiate contractual requirements which compel its service providers to notify them of information security incidents occurring on their systems which may affect Cheniere’s systems or data, including personal information.

During the year ended December 31, 2024, cybersecurity incidents and threats did not materially affect our business, results of operations or financial condition.

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Governance

We rely on Cheniere’s cybersecurity leadership team, which consists of its Director and Chief Information Security Officer, Vice President and Chief Information Officer and Senior Vice President of Shared Services. These individuals collectively provide the strategic oversight of Cheniere’s cybersecurity governance, cyber risk management and security operations and are responsible for maintaining Cheniere’s technology defense posture and program. As part of their governance and risk management responsibilities, these individuals oversee the efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents, including the systems deployed in our technology infrastructure to monitor for threats, perform security control testing and assessments, and incorporate threat intelligence into our day-to-day cybersecurity operations and strategic initiatives. They have decades of experience managing strategic technology operations, including the identification of cybersecurity risk and the defense of information technology assets from global threats.

Risks that could affect us are an integral part of Board and Audit Committee deliberations throughout the year. The Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management’s plan for mitigating these risks, while the Audit Committee of the Board has been delegated the authority to oversee and periodically review the security of CQP’s information technology systems and controls, including programs and defenses against cybersecurity threats. The Audit Committee discusses with the management of CQP’s general partner its cybersecurity risk exposures and the steps management has taken to mitigate such exposures, including risk assessment and risk management policies. On a quarterly basis, Cheniere’s cybersecurity leadership team updates the Audit Committee on the overall status of its cybersecurity program, key operational metrics, current assessments, cybersecurity issues or events and pertinent events related to cybersecurity.

For additional information about cybersecurity risks, see the risk A cyber attack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Project, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation under Risks Relating to Our Operations and Industry in Item 1A.Risk Factors.

ITEM 3. LEGAL PROCEEDINGS

LDEQ Matter

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

ITEM 4. MINE SAFETY DISCLOSURE

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Not applicable.

ITEM 6. [Reserved]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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. Discussion of items for the year ended December 31, 2022 and variance drivers between the year ended December 31, 2023 as compared to December 31, 2022 are not included herein and can be found in “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, 2023.

Our discussion and analysis includes the following subjects:

•Overview

•Overview of Significant Events

•Market Environment

•Results of Operations

•Liquidity and Capital Resources

•Summary of Critical Accounting Estimates

•Recent Accounting Standards

Overview

We are a limited liability company formed by CQP to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We own the natural gas liquefaction and export facility at Sabine Pass, Louisiana. For further discussion of our business, see Items 1. and 2. Business and Properties.

Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Through our SPAs and IPM agreement, with approximately 13 years of weighted average remaining life as of December 31, 2024, we have contracted approximately 80% of the total anticipated production from the Liquefaction Project. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees 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. We believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, will provide a foundation for additional growth in our business in the future.

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Overview of Significant Events

Our significant events since January 1, 2024 and through the filing date of this Form 10-K include the following:

Strategic

•In February 2024, we and other subsidiaries of CQP submitted an application to the FERC under the NGA for authorization to site, construct and operate the Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking. In October 2024, the authorization from the DOE to export LNG to FTA countries was received for the Expansion Project.

Operational

•As of February 14, 2025, approximately 2,840 cumulative LNG cargoes totaling over 195 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

Financial

•In May 2024, CQP issued $1.2 billion aggregate principal amount of 5.750% Senior Notes due 2034 (the “2034 CQP Senior Notes”). The net proceeds from the 2034 CQP Senior Notes, together with cash on hand, were used in June 2024 to redeem $1.2 billion of the outstanding aggregate principal amount of our 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes”).

•In May 2024, Moody’s Ratings (“Moody’s”) upgraded our issuer credit rating to Baa1 from Baa2 and revised our outlook to stable from positive.

•Excluding amounts refinanced, we redeemed $800 million of outstanding aggregate principal amount of our senior secured notes during the year ended December 31, 2024

Market Environment

The LNG market in 2024 remained relatively tight as a result of low supply capacity growth, strong demand outside Europe and continued geopolitical tensions. Global LNG imports registered a very modest growth in 2024, increasing by less than 4 mtpa year on year due to constrained supply from delays to projects under construction, Russian sanctions and a fallow period for new projects coming on-line. Consequently, a recovery in Asia’s LNG consumption had to be satisfied at the expense of other regions. Asian demand increased significantly from 2023, adding over 20 mtpa of import year-over-year. The largest single country contribution to this growth came from China, which increased 6.8 mtpa year-over-year after a slowdown during the previous two years. Growth outside of Asia tightened the balances further this year by increasing the call on supply away from Europe. Egypt and Brazil propelled imports from the Middle East, North Africa and Latin America regions by 6.2 mtpa to a total of 25.5 mtpa in 2024. In contrast, Europe’s imports declined 19% year-over-year, down approximately 22.7 mtpa, due to weak gas-fired power generation demand and sluggish growth in the industrial sector.

These market conditions contributed to a strong spot price environment albeit annual spot prices in 2024 were overall lower than in the previous year. The TTF monthly settlement prices averaged $10.91/MMBtu in 2024, 20.5% lower than the 2023 average of $13.73/MMBtu. Similarly, the average settlement price for the Japan Korea Marker (“JKM”) was $11.83/MMBtu in 2024, 26.6% lower than the 2023 average of $16.13/MMBtu. The Henry Hub benchmark also dropped from an average settlement price of $2.74/MMBtu in 2023 to $2.27/MMBtu in 2024, down 17.1% year-over-year.

However, a drop in temperatures in Europe toward the end of 2024 and into the beginning of 2025 has resulted in faster drawdowns from underground storage and a rebound in spot prices relative to the third quarter. This, along with the expiry of the gas transit agreement between Russia and Ukraine on December 31, 2024, is likely to increase the call on LNG imports in the coming months in order to replenish European gas storage facilities to 90% capacity by November 1, as required by the EU each year.

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Results of Operations


	Year Ended December 31,
(in millions)		2024		2023		Variance
Revenues
LNG revenues		$	6,550	$	6,991	$	(441)
LNG revenues—affiliate		1,954		2,475		(521)


Total revenues		8,504		9,466		(962)

Operating costs and expenses
Cost of sales (excluding items shown separately below)		3,569		2,721		848
Cost of sales—affiliate		55		76		(21)

Operating and maintenance expense		701		759		(58)
Operating and maintenance expense—affiliate		493		488		5
Operating and maintenance expense—related party		58		62		(4)


General and administrative expense		5		4		1
General and administrative expense—affiliate		62		61		1
Depreciation and amortization expense		559		554		5
Other operating costs and expenses		2		3		(1)

Total operating costs and expenses		5,504		4,728		776

Income from operations		3,000		4,738		(1,738)

Other income (expense)
Interest expense, net of capitalized interest		(489)		(595)		106
Loss on modification or extinguishment of debt		(3)		(6)		3
Other income, net		12		14		(2)
Total other expense		(480)		(587)		107

Net income		$	2,520	$	4,151	$	(1,631)

Volumes loaded and recognized from the Liquefaction Project


	Year Ended December 31,
		2024	2023	Variance

Volumes loaded and recognized as revenues (in TBtu)		1,567	1,536	31

Net income

Net income declined by $1.6 billion during the year ended December 31, 2024 as compared to the same period of 2023 and was primarily attributable to $1.7 billion of decreases in gains from changes in fair value of derivatives. The decrease was primarily related to our IPM agreement with Tourmaline Oil Marketing Corp, where the associated gains that are primarily included in cost of sales decreased from $1.8 billion during the year ended December 31, 2023 to $251 million during the year ended December 31, 2024, mainly due to the impact on fair value of the decline and sustained moderation of global LNG and gas price volatility and more subdued changes in the current period relative to the same period of 2023 as global gas prices and spreads narrowed as a result of market rebalancing. The remaining $189 million of decreases in gains from changes in fair value of derivatives during the comparable years was primarily due to an unfavorable shift in long-term U.S. natural gas basis spreads.

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The following is an additional discussion of the significant drivers of the variance in net income by line item:

Revenues

The $962 million decrease in revenues during the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to a $1.1 billion decrease from lower pricing per MMBtu as a result of declining Henry Hub pricing, partially offset by a $188 million increase from higher production volume largely due to reduced operating and maintenance activities compared to the same period of 2023 and cooler weather.

Operating costs and expenses

The $776 million increase in operating costs and expenses during the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to $1.7 billion of decreases in gains from changes in fair value of derivatives included in cost of sales, as discussed above under Net income. The unfavorable variance between the comparative years was partially offset by a $740 million decrease in cost of natural gas feedstock, largely due to the decline and sustained moderation of global LNG and gas prices as well as lower U.S. natural gas prices during the year ended December 31, 2024 as compared to the same period of 2023.

Other income (expense)

Substantially all of the $107 million favorable variance during the year ended December 31, 2024 as compared to the same period of 2023 was attributable to a decrease in interest expense, net of capitalized interest, primarily due to a decrease in total indebtedness. Total debt decreased from $12.1 billion as of December 31, 2022 to $8.4 billion as of December 31, 2024 as debt continued to be paid down as part of Cheniere’s long-term capital allocation plan.

Significant factor affecting our results of operations

Below is a significant factor that affects 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 Financial Statements. For commodity derivative instruments, including those related to our IPM agreement, 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 Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

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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 restricted cash and cash equivalents and available commitments under our credit facility. 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. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.


	December 31, 2024



Restricted cash and cash equivalents designated for the Liquefaction Project	$	109


Revolving Credit Facility (1)	776

Total available liquidity	$	885

(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under the Revolving Credit Facility as of December 31, 2024. See Note 9—Debt of our Notes to Financial Statements for additional information on the Revolving Credit Facility and other debt instruments.

Our liquidity position subsequent to December 31, 2024 will be driven by future sources of liquidity and future cash requirements, as further discussed under the caption Future Sources and Uses of Liquidity.

Future Sources and Uses of Liquidity

The following discussion of our future sources and uses of liquidity includes estimates that reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2024. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.

Future Sources of Liquidity under Executed Contracts

We are contractually entitled to significant future consideration contracted under our long-term SPAs that has not yet been recognized as revenue. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be significant to our future liquidity. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We have estimated revenues under agreements with terms dependent on project milestone dates based on the estimated dates as of December 31, 2024. The following table summarizes our estimate of revenues to be received from executed long-term SPAs as of December 31, 2024 (in billions):


	Estimated Revenues Under Executed SPAs by Period (1) (2)

	2025		2026 - 2029		Thereafter		Total
LNG revenues (fixed fees)	$	3.8	$	13.8	$	27.5	$	45.1

LNG revenues (variable fees) (3)	6.0		22.1		49.0		77.1



Total	$	9.8	$	35.9	$	76.5	$	122.2

(1)LNG revenues exclude revenues from contracts with original expected durations of one year or less.

(2)LNG revenues (including $0.7 billion and $1.4 billion of fixed fees and variable fees, respectively, from affiliates) exclude the SPA with Cheniere Marketing associated with our IPM agreement, for which pricing is linked to international natural gas prices.

(3)LNG revenues (variable fees) reflect the assumption of delivery of all contractual volumes, irrespective of any contractual right of non-delivery. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2024.

Under our long-term SPAs, we have contracted approximately 80% of the total anticipated production though the mid-2030s from our liquefaction capacity that is currently in construction or operation. Under our SPAs, customers purchase LNG on an FOB basis (delivered to the customer at the Sabine Pass LNG Terminal) generally for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The variable fees under our SPAs were generally sized with the intention to

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cover the supply and transportation of natural gas and the liquefaction fuel consumed to produce the LNG to be sold under each such SPA, thus limiting our exposure to future U.S. natural gas price increases. Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension.

The table above excludes an SPA with Cheniere Marketing under which we sell LNG produced from natural gas procured under our IPM agreement in effect at pricing linked to global gas market prices. The IPM agreement in effect, under which we pay for natural gas feedstock based on global gas prices less liquefaction fees and certain costs incurred by us, generates a take-or-pay style fixed liquefaction fee when viewed in conjunction with the associated SPA. Over a remaining fixed term of 13 years, we expect to generate liquidity from the approximately 575 TBtu of LNG yet to be delivered under this SPA as of December 31, 2024.

Additional Future Sources of Liquidity

Available Commitments under Credit Facilities

As of December 31, 2024, we had $776 million in available commitments under the Revolving Credit Facility, as detailed earlier in the table summarizing our available liquidity, subject to compliance with the applicable covenants, to potentially meet liquidity needs. The Revolving Credit Facility matures in 2028.

Disciplined Accretive Growth

Our significant land position at the Sabine Pass LNG Terminal provides potential development and investment opportunities for further liquefaction capacity expansion at a strategically advantaged location with proximity to pipeline infrastructure and resources. In February 2024, we and other subsidiaries of CQP submitted an application to the FERC under the NGA for authorization to site, construct and operate the Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking. In October 2024, the authorization from the DOE to export LNG to FTA countries was received. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts

We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations related to our core operations under executed contracts as of December 31, 2024 (in billions):


	Estimated Payments Due Under Executed Contracts by Period (1)

	2025		2026 - 2029		Thereafter		Total
Purchase obligations (2):
Natural gas supply agreements excluding our IPM agreement (3) (4)	$	4.2	$	8.5	$	1.5	$	14.2
Natural gas transportation and storage service agreements (5)	0.4		1.3		2.5		4.2



TUAs (6)	0.4		1.5		1.8		3.7
Other purchase obligations (7)	0.1		0.3		0.9		1.3
Total	$	5.1	$	11.6	$	6.7	$	23.4

(1)Agreements in force as of December 31, 2024 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2024.

(2)Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. We include contracts for which we have an early termination option if the option is not currently expected to be exercised. We include contracts with unsatisfied contractual conditions if the conditions are currently expected to be met.

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(3)Natural gas supply agreements exclude the IPM agreement, which, as described in Future Sources of Liquidity under Executed Contracts, is structured to generate a fixed margin when viewed in conjunction with the associated SPA with Cheniere Marketing.

(4)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2024.

(5)Natural gas transportation and storage services agreements include $1.0 billion in obligations to affiliates and $0.2 billion in obligations to related parties.

(6)TUAs include $3.1 billion of purchase obligations to affiliates under the TUA and $0.6 billion of payments under our partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”).

(7)Other purchase obligations include $1.1 billion of purchase obligations to affiliates under services agreements.

Natural Gas Supply, Transportation and Storage Service Agreements

Excluding our IPM agreement, we have secured approximately 3,900 TBtu of natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements with remaining fixed terms of up to 7 years. As of December 31, 2024, we have secured approximately 73% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2025, excluding the 3% of which has been secured under our IPM agreement. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2025. As further described in the Future Sources of Liquidity under Executed Contracts section, the pricing structure of our SPAs often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices.

To ensure that we are able to transport natural gas feedstock to the Sabine Pass LNG Terminal, we have transportation precedent and other agreements to secure firm pipeline transportation capacity from CTPL and third party interstate and intrastate pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project.

Capital Expenditures

Although we do not currently have any material capital expenditures under executed contracts, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity. See Disciplined Accretive Growth section for further discussion.

Terminal Use Agreements

We have a TUA with SPLNG to provide berthing for LNG vessels and for unloading, loading, storage and regasification of LNG.

Additionally, we have a partial TUA assignment agreement with TotalEnergies, another TUA customer, under which we gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG Terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG storage capacity.

Additional Future Cash Requirements for Operations and Capital Expenditures

Operational Services

We do not have any employees, and thus have contracts with subsidiaries of Cheniere and CQP for operations, maintenance and management services. As of December 31, 2024, Cheniere and its subsidiaries had 1,714 full-time employees, including 501 employees who directly supported the Liquefaction Project.

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Disciplined Accretive Growth

The FID of any expansion projects will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.

Future Cash Requirements for Financing under Executed Contracts

We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2024 (in billions):


	Estimated Payments Due Under Executed Contracts by Period (1)

	2025		2026 - 2029		Thereafter		Total
Debt	$	0.4	$	4.7	$	3.3	$	8.4
Interest payments	0.4		1.0		0.3		1.7
Total	$	0.8	$	5.7	$	3.6	$	10.1

(1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2024. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.

Debt

As of December 31, 2024, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $8.4 billion and the Revolving Credit Facility with no outstanding loan balances. As of December 31, 2024, we were in compliance with all covenants related to our debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 9—Debt of our Notes to Financial Statements.

Interest

As of December 31, 2024, our senior notes had a weighted average contractual interest rate of 4.88%. Borrowings under the Revolving Credit Facility are indexed to SOFR. Undrawn commitments under the Revolving Credit Facility are subject to commitment fees ranging from 0.075% to 0.30%, subject to change based on our credit rating. Issued letters of credit under the Revolving Credit Facility are subject to letter of credit fees ranging from 1.0% to 1.75%, subject to change based on our credit rating. We had $224 million aggregate amount of issued letters of credit under the Revolving Credit Facility as of December 31, 2024.

Additional Future Cash Requirements for Financing

Capital Allocation Plan

In June 2024, the board of directors of Cheniere approved an updated comprehensive long-term capital allocation plan, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of debt, including our senior notes.

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Sources and Uses of Cash

The following table summarizes the sources and uses of our 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.


	Year Ended December 31,
	2024		2023

Net cash provided by operating activities	$	2,840	$	2,826
Net cash used in investing activities	(97)		(152)
Net cash used in financing activities	(2,690)		(2,710)













Net increase (decrease) in restricted cash and cash equivalents	$	53	$	(36)

Operating Cash Flows

The $14 million increase between the years ended December 31, 2024 and 2023 was due to the net effect of price changes on our LNG sales and natural gas feedstock purchases between the respective periods, partially offset by lower cash flows attributed to working capital from 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 both the years ended December 31, 2024 and 2023 were primarily related to optimization and other site improvement projects.

Financing Cash Flows

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


	Year Ended December 31,
	2024		2023
Proceeds from issuances of debt	$	30	$	—
Redemptions, repayments and repurchases of debt	(2,030)		(1,700)


Contributions	1,130		1,190
Distributions	(1,820)		(2,194)
Other	—		(6)
Net cash used in financing activities	$	(2,690)	$	(2,710)

Debt Activity

During the year ended December 31, 2024, we redeemed $1.7 billion of the outstanding aggregate principal amount of the 2025 SPL Senior Notes, of which a portion was paid with contributions received from CQP during the current year, as well as repaid the outstanding aggregate principal amount of $300 million of the 5.750% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”). We also borrowed and repaid $30 million under the Revolving Credit Facility during the year ended December 31, 2024. During the year ended December 31, 2023, we redeemed $1.5 billion of the 2024 Senior Notes with contributions received from CQP and repurchased $200 million of the 2024 Senior Notes in the open market.

Summary of Critical Accounting Estimates

The preparation of our Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.

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Fair Value of Level 3 Liquefaction Supply Derivatives

All of our derivative instruments are recorded at fair value, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements. We record changes in the fair value of our derivative positions through earnings based on the value for which the derivative instrument could be exchanged between willing parties. Valuation of our liquefaction supply derivative contracts is often developed through the use of internal models which includes significant unobservable inputs representing Level 3 fair value measurements as further described in Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.

Our fair value estimates incorporate market participant-based assumptions pertaining to applicable contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.

Additionally, the valuation of certain liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2024 and 2023 (in millions), which entirely consisted of liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the end of each respective period.


	Year Ended December 31,
		2024		2023
Favorable changes in fair value relating to instruments still held at the end of the period		$	184	$	1,318

The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our Tourmaline IPM Agreement in effect during the years ended December 31, 2024 and 2023.

The estimated fair value of level 3 derivatives recognized in our Balance Sheets as of December 31, 2024 and 2023 amounted to a liability of $1.3 billion and $1.7 billion, respectively.

The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as it relates to commodity prices impacting the valuation of our liquefaction supply derivatives, given the level of volatility to which such prices are subjected. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices.

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Recent Accounting Standards

For a summary of recently issued accounting standards, see Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketing and Trading Commodity Price Risk

We have commodity derivatives consisting of natural gas supply contracts for the operation of the Liquefaction Project, 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):


	December 31, 2024				December 31, 2023
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(1,281)	$	342	$	(1,657)	$	362

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

SABINE PASS LIQUEFACTION, LLC


Management’s Report to the Member of Sabine Pass Liquefaction, LLC			32
Report of Independent Registered Public Accounting Firm			33
Statements of Operations			35
Balance Sheets			36
Statements of Member’s Equity (Deficit)			37
Statements of Cash Flows			38
Notes to Financial Statements			39
Note 1—Organization and Nature of Operations			39
Note 2—Summary of Significant Accounting Policies			39

Note 3—Trade and Other Receivables, Net of Current Expected Credit Losses			43
Note 4—Inventory			44
Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation			44
Note 6—Derivative Instruments			45
Note 7—Other Non-current Assets, Net			48
Note 8—Accrued Liabilities			48
Note 9—Debt			48
Note 10—Revenues			50
Note 11—Related Party Transactions			52
Note 12—Commitments and Contingencies			54
Note 13—Segment Information and Customer Concentration			54
Note 14—Supplemental Cash Flow Information			55

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MANAGEMENT’S REPORT TO THE MEMBER OF SABINE PASS LIQUEFACTION, LLC

Management’s Report on Internal Control Over Financial Reporting

As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Sabine Pass Liquefaction. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Sabine Pass Liquefaction’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.

Based on our assessment, we have concluded that Sabine Pass Liquefaction maintained effective internal control over financial reporting as of December 31, 2024, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.

This annual report does not include an attestation report of Sabine Pass Liquefaction’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Sabine Pass Liquefaction’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

Management’s Certifications

The certifications of Sabine Pass Liquefaction’s Principal Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Sabine Pass Liquefaction’s Form 10-K.

By:

/s/ Jack A. Fusco

By:

/s/ Zach Davis

Jack A. Fusco

Zach Davis

Chief Executive Officer
(Principal Executive Officer)

Manager and Chief Financial Officer
(Principal Financial Officer)

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Report of Independent Registered Public Accounting Firm

To the Member of Sabine Pass Liquefaction, LLC and

Board of Directors of Cheniere Energy Partners GP, LLC

Sabine Pass Liquefaction, LLC:

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Sabine Pass Liquefaction, LLC (the Company) as of December 31, 2024 and 2023, the related statements of operations, member’s equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2024, and the related notes (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Fair value of the level 3 liquefaction supply derivatives

As discussed in Notes 2 and 6 to the financial statements, the Company recorded fair value of level 3 liquefaction supply derivatives of $(1,307) million as of December 31, 2024, which included the fair value of the IPM agreement. The IPM agreement is a natural gas supply contract for the operation of the liquefied natural gas facilities. The fair value of the IPM agreement is developed using internal models, including option pricing models. The models incorporate significant unobservable inputs, including future prices of energy units in unobservable periods and volatility.

We identified the evaluation of the fair value of the level 3 liquefaction supply derivatives for the IPM agreement as a critical audit matter. Specifically, complex auditor judgment and specialized skills and knowledge were required to evaluate the appropriateness and application of the option pricing model as well as the assumptions for future prices of energy units in unobservable periods and volatility.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the valuation of liquefaction supply derivatives, including those under the IPM agreement. This included controls related to the appropriateness and application of the

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option pricing model and the evaluation of assumptions for future prices of energy units in unobservable periods and volatility. We involved valuation professionals with specialized skills and knowledge who assisted in testing management’s process for developing the fair value of the IPM agreement by:

•evaluating the design and testing the operating effectiveness of certain internal controls related to the appropriateness and application of the option pricing model

•evaluating the appropriateness and application of the option pricing model by inspecting the contractual agreements and model documentation to determine whether the model is suitable for its intended use

•evaluating the reasonableness of management’s assumptions for future prices of energy units in unobservable periods and volatility by comparing to market data.


/s/ KPMG LLP
KPMG LLP

We have served as the Company’s auditor since 2014.

Houston, Texas

February 19, 2025

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SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF OPERATIONS

(in millions)


	Year Ended December 31,
		2024		2023		2022
Revenues
LNG revenues		$	6,550	$	6,991	$	11,507
LNG revenues—affiliate		1,954		2,475		4,568


Total revenues		8,504		9,466		16,075

Operating costs and expenses
Cost of sales (excluding items shown separately below)		3,569		2,721		11,885
Cost of sales—affiliate		55		76		262

Operating and maintenance expense		701		759		652
Operating and maintenance expense—affiliate		493		488		482
Operating and maintenance expense—related party		58		62		72


General and administrative expense		5		4		—
General and administrative expense—affiliate		62		61		66
Depreciation and amortization expense		559		554		539
Other operating costs and expenses		2		3		—

Total operating costs and expenses		5,504		4,728		13,958

Income from operations		3,000		4,738		2,117

Other income (expense)
Interest expense, net of capitalized interest		(489)		(595)		(667)
Loss on modification or extinguishment of debt		(3)		(6)		(2)
Other income, net		12		14		7
Total other expense		(480)		(587)		(662)

Net income		$	2,520	$	4,151	$	1,455

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

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SABINE PASS LIQUEFACTION, LLC

BALANCE SHEETS

(in millions)



	December 31,
	2024		2023
ASSETS
Current assets

Restricted cash and cash equivalents	$	109	$	56
Trade and other receivables, net of current expected credit losses	373		368
Trade receivables—affiliate	161		277
Trade receivables, net of current expected credit losses—related party	1		—
Advances to affiliates	98		75
Inventory	131		122
Current derivative assets	84		30


Other current assets, net	51		27
Other current assets—affiliate	22		22
Total current assets	1,030		977


Property, plant and equipment, net of accumulated depreciation	12,865		13,322


Derivative assets	98		40
Other non-current assets, net	170		175

Total assets	$	14,163	$	14,514

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	49	$	63
Accrued liabilities	725		686
Accrued liabilities—related party	5		5
Current debt, net of unamortized discount and debt issuance costs	351		300
Due to affiliates	62		64
Deferred revenue	108		101

Current derivative liabilities	250		196
Other current liabilities	10		5

Total current liabilities	1,560		1,420

Long-term debt, net of unamortized discount and debt issuance costs	8,030		10,063

Derivative liabilities	1,213		1,531
Other non-current liabilities	115		82
Other non-current liabilities—affiliate	21		21
Total liabilities	10,939		13,117

Commitments and contingencies (see Note 12)

Member’s equity	3,224		1,397
Total liabilities and member’s equity	$	14,163	$	14,514

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

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SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF MEMBER’S EQUITY (DEFICIT)

(in millions)



	Sabine Pass LNG-LP, LLC		Total Member’s Equity (Deficit)
Balance at December 31, 2021	$	1,621	$	1,621
Contributions	225		225
Distributions (excluding items shown separately below)	(1,761)		(1,761)
Non-cash novation of IPM agreement from affiliate (see Note 14)	(2,712)		(2,712)
Non-cash distributions to affiliates for conveyance of property, plant and equipment (see Note 11)	(576)		(576)
Net income	1,455		1,455
Balance at December 31, 2022	(1,748)		(1,748)
Contributions (excluding items shown separately below)	1,190		1,190
Non-cash contributions related to extinguishment of debt	2		2
Distributions (excluding items shown separately below)	(2,194)		(2,194)

Non-cash distributions to affiliates for conveyance of property, plant and equipment (see Note 11)	(4)		(4)
Net income	4,151		4,151
Balance at December 31, 2023	1,397		1,397
Contributions	1,130		1,130
Distributions (excluding the item shown separately below)	(1,820)		(1,820)
Non-cash distributions for conveyance of property, plant and equipment (see Note 11)	(3)		(3)
Net income	2,520		2,520








Balance at December 31, 2024	$	3,224	$	3,224

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

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SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF CASH FLOWS

(in millions)


	Year Ended December 31,
	2024		2023		2022
Cash flows from operating activities
Net income	$	2,520	$	4,151	$	1,455
Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization expense	559		554		539
Amortization of discount and debt issuance costs	17		21		24
Loss on modification or extinguishment of debt	3		6		2
Total losses (gains) on derivative instruments, net	(402)		(2,082)		1,158

Net cash provided by (used for) settlement of derivative instruments	26		(2)		(102)
Other	3		4		7
Changes in operating assets and liabilities:
Trade and other receivables	(5)		254		(116)
Trade receivables—affiliate	116		276		(337)
Trade receivables—related party	(1)		—		—

Inventory	(9)		20		15

Accounts payable and accrued liabilities	8		(513)		348
Accrued liabilities—related party	—		(2)		3

Total deferred revenue	39		45		—

Other, net	(16)		40		(26)
Other, net—affiliate	(18)		54		3
Net cash provided by operating activities	2,840		2,826		2,973

Cash flows from investing activities
Property, plant and equipment, net	(97)		(146)		(434)
Other	—		(6)		—

Net cash used in investing activities	(97)		(152)		(434)

Cash flows from financing activities
Proceeds from issuances of debt	30		—		560
Redemptions, repayments and repurchases of debt	(2,030)		(1,700)		(1,560)


Contributions	1,130		1,190		225
Distributions	(1,820)		(2,194)		(1,761)
Other	—		(6)		(9)
Net cash used in financing activities	(2,690)		(2,710)		(2,545)

Net increase (decrease) in restricted cash and cash equivalents	53		(36)		(6)
Restricted cash and cash equivalents—beginning of period	56		92		98
Restricted cash and cash equivalents—end of period	$	109	$	56	$	92

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

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a Delaware limited liability company formed by CQP and based in Houston with one member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of CQP. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of CQP, a publicly traded limited partnership (NYSE MKT: CQP). CQP is a 48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses. Cheniere also owns 100% of the general partner interest in CQP through ownership in Cheniere Energy Partners GP, LLC.

Another subsidiary of CQP is pursuing an expansion project to provide additional liquefaction capacity at the Sabine Pass LNG Terminal, and it has commenced commercialization to support the additional liquefaction capacity associated with this potential expansion project.

We do not have employees and thus we 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 11—Related Party Transactions for additional details of the activity under these services agreements during the years ended December 31, 2024, 2023 and 2022.

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss is included in the federal income tax return of CQP. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP’s taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. At December 31, 2024, the tax basis of our assets and liabilities was $8.1 billion less than the reported amounts of our assets and liabilities. See Note 11—Related Party Transactions for details about income taxes under our tax sharing agreement.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Financial Statements have been prepared in accordance with GAAP.

Estimates

The preparation of our Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment and certain valuations including asset retirement obligations (“AROs”), each as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

participants would take into account in measuring fair value. We attempt to maximize our use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments, as disclosed in Note 6—Derivative Instruments.

The carrying amount of restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, accounts payable and accrued liabilities reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Refer to Note 9—Debt for our debt fair value estimates, including our estimation methods.

Revenue Recognition

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG Terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is not included in the transaction price.

Sales generated during the commissioning phase of a Train, which includes test activities such as production and removal of LNG from storage, are offset against the cost of construction for the respective Train, as commissioning is necessary to test the facility and bring the asset to the condition necessary for its intended use. After substantial completion of a Train is achieved, fees received for LNG volumes produced are recognized as LNG revenues.

For transactions where we receive consideration from the customer, we assess whether we are the principal or the agent in the arrangement. Arrangements where we have concluded that we act as a principal are presented within our Statements of Operations on a gross basis, and arrangements where we have concluded that we act as an agent are presented within our S tatements of Operations on a net basis.

See Note 10—Revenues for additional information regarding our LNG revenues.

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Our restricted cash and cash equivalents were primarily restricted for the payment of liabilities related to the Liquefaction Project as required under certain debt arrangements. Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee.

Inventory

LNG, natural gas and other commodity inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or, for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction, acquisition, commissioning activities and costs that significantly extend the useful life or increase the functionality and/or capacity of an asset are capitalized.

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Expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.

Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction.

Generally, costs that benefit us more broadly than for a specific project are capitalized prior to a project meeting the criteria otherwise necessary for capitalization and typically include engineering design work.

We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives. Refer to Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in other operating costs and expenses.

Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.

We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2024, 2023 and 2022.

Interest Capitalization

We capitalize interest costs mainly during the construction period of our LNG terminal and related assets. Upon placing the underlying asset in service, these costs are depreciated over the estimated useful life of the corresponding assets for which interest costs were incurred, except for capitalized interest associated with land, which is not depreciated.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement.

We did not have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2024, 2023 and 2022; therefore, the changes in the fair value of our derivative instruments are recorded in earnings.

As described in Concentration of Credit Risk below, the use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees. Variation margins or other daily margining posted for exchange-traded transactions that are contractually characterized as settlement of the respective derivative position are netted against the respective derivative asset or liability positions.

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We have elected to report derivative assets and liabilities under master netting arrangements with the same counterparty on a net basis. Additionally, the fair value amounts recognized as cash collateral pledged or received, such as initial margins and other collateral that are not contractually characterized as settlement of the respective derivative positions, are offset against the fair value of derivatives executed with the same counterparty under a master netting arrangement. Collateral balances not offset against a derivative position are presented on our Balance Sheets within other current assets, net. Derivative assets and liabilities not subject to master netting arrangements are presented net when we have a legally enforceable right and the intent to offset amounts with the same counterparty.

See Note 6—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of (1) derivative instruments and (2) accounts receivable and contract assets related to our long-term SPAs, each discussed further above. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivatives executed over-the-counter or through an exchange are subject to nominal credit risk as these transactions often require collateral that is returned to us (or to the counterparty) on or near the settlement date or are settled on a daily margin basis with investment grade financial institutions, and are primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required for non-exchange traded transactions when the value of a derivative exceeds the pre-established credit limit with the counterparty. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

Our contracted LNG sales are primarily under SPAs with terms exceeding 10 years. As of December 31, 2024, we had SPAs with initial terms of 10 or more years with a total of 11 different third party customers and had agreements with Cheniere Marketing. We are dependent on the respective customers’ creditworthiness and their ability to perform under their respective SPAs. While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.

Debt

Our debt consists of current and long-term secured and unsecured debt securities and a credit facility with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.

Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and commitment fees. Costs associated with entering into a line of credit or on undrawn funds are presented as an asset and classified as current or non-current, consistent with the respective credit facility. As of December 31, 2024 and 2023, all of such costs were classified as other non-current assets, net, on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method except in the case of our credit facility, in which any discount, premium and/or debt issuance costs are amortized on a straight-line basis over the contractual term.

We classify debt on our Balance Sheets based on contractual maturity, with the following exceptions:

•We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.

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•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.

Asset Retirement Obligations

We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.

Our real property lease agreements at the Sabine Pass LNG Terminal require us to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty excepted, at the expiration of the term of the leases, with such terms being up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG Terminal in good order and repair, with normal wear and tear and casualty excepted, is immaterial, thus we have not recorded an ARO associated with the liquefaction facilities at the Sabine Pass LNG Terminal.

Recent Accounting Standards

ASU 2023-07

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280), which we adopted on December 31, 2024. This guidance requires a public entity, including entities with a single reportable segment, to disclose significant segment expenses and other segment information on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. Refer to Note 1 3 —Segment Information and Customer Concentration for the required disclosures.

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 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):



	December 31,
	2024		2023
Trade receivables	$	367	$	361
Other receivables	6		7
Total trade and other receivables, net of current expected credit losses	$	373	$	368

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NOTE 4—INVENTORY

Inventory consisted of the following (in millions):



	December 31,
	2024		2023
Materials	$	95	$	89
Natural gas	22		22
LNG	13		11
Other	1		—
Total inventory	$	131	$	122

NOTE 5—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

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



	December 31,
	2024		2023
LNG terminal
Terminal	$	16,387	$	16,309
Construction-in-process	125		110
Accumulated depreciation	(3,652)		(3,100)
Total LNG terminal, net of accumulated depreciation	12,860		13,319
Fixed assets
Fixed assets	20		19
Accumulated depreciation	(15)		(16)
Total fixed assets, net of accumulated depreciation	5		3
Property, plant and equipment, net of accumulated depreciation	$	12,865	$	13,322

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


	Year Ended December 31,
		2024		2023		2022
Depreciation expense		$	554	$	549	$	534
Offsets to LNG terminal costs (1)		—		—		148

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

LNG Terminal Costs

LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 6 and 50 years, as follows:


Components						Useful life (years)
Water pipelines						30
Liquefaction processing equipment						6-50
Other						10-30

Fixed Assets

Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

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NOTE 6—DERIVATIVE INSTRUMENTS

We have commodity derivatives consisting of natural gas supply contracts, including those under our IPM agreement, for the operation of the Liquefaction Project and expansion project, 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
	December 31, 2024								December 31, 2023
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total

Liquefaction Supply Derivatives asset (liability)	$	—	$	26	$	(1,307)	$	(1,281)	$	18	$	1	$	(1,676)	$	(1,657)

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

We include a significant portion of the Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.

In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility includes the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control. Our fair value estimates incorporate market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

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The Level 3 fair value measurements of our natural gas positions within the Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of December 31, 2024:

Net Fair Value Liability

(in millions)

Valuation Approach

Significant Unobservable Input

Range of Significant Unobservable Inputs / Weighted Average (1)

Liquefaction Supply Derivatives

$(1,307)

Market approach incorporating present value techniques

Henry Hub basis spread

$(0.495) - $1.144 / $0.056

Option pricing model

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

127% - 410% / 242%

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

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

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

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


	Year Ended December 31,
		2024		2023		2022
Balance, beginning of period		$	(1,676)	$	(3,719)	$	38
Realized and change in fair value gains (losses) included in net income (1):
Included in cost of sales, existing deals (2)		165		1,302		(228)
Included in cost of sales, new deals (3)		19		16		(804)
Purchases and settlements:
Purchases (4)		—		—		(2,712)
Settlements (5)		185		724		(13)


Transfers out of level 3 (6)		—		1		—
Balance, end of period		$	(1,307)	$	(1,676)	$	(3,719)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period		$	184	$	1,318	$	(1,032)

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

(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.

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

(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. For further discussion of the IPM agreement that was novated to us in 2022, see Note 14—Supplemental Cash Flow Information.

(5)Roll-off in the current period of amounts recognized in our 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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Liquefaction Supply Derivatives

We hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of December 31, 2024, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 13 years, some of which commence or accelerate upon the satisfaction of certain events or development of infrastructure to support natural gas gathering and transport.

The forward notional amount for the Liquefaction Supply Derivatives was approximately 4,733 TBtu and 5,478 TBtu as of December 31, 2024 and 2023, respectively, inclusive of amounts under contracts with unsatisfied contractual conditions, and exclusive of extension options that were uncertain to be taken as of both December 31, 2024 and 2023.

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


		Gain (Loss) Recognized in Statements of Operations
Statements of Operations Location (1)	Year Ended December 31,
		2024		2023		2022
LNG revenues		$	—	$	—	$	1
Cost of sales		402		2,082		(1,159)

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

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




	Fair Value Measurements as of
Balance Sheets Location	December 31, 2024		December 31, 2023
Current derivative assets	$	84	$	30
Derivative assets	98		40
Total derivative assets	182		70

Current derivative liabilities	(250)		(196)
Derivative liabilities	(1,213)		(1,531)
Total derivative liabilities	(1,463)		(1,727)

Derivative liability, net	$	(1,281)	$	(1,657)

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 Balance Sheets after offsetting for any balances with the same counterparty under master netting arrangements or other relevant netting criteria under GAAP that are met (in millions):


	Liquefaction Supply Derivatives
	December 31, 2024		December 31, 2023
Gross assets	$	228	$	88
Offsetting amounts	(46)		(18)
Net assets	$	182	$	70

Gross liabilities	$	(1,464)	$	(1,746)
Offsetting amounts	1		19
Net liabilities	$	(1,463)	$	(1,727)

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

We had a collateral balance of $13 million that was recorded within other current assets, net, and not netted on our Balance Sheets, as of December 31, 2024. We did not have a collateral balance as of December 31, 2023.

NOTE 7—OTHER NON-CURRENT ASSETS, NET

Other non-current assets, net consisted of the following (in millions):


	December 31,

	2024		2023
Advances to service providers	$	113	$	119

Operating lease assets	22		22



Other	35		34
Total other non-current assets, net	$	170	$	175

NOTE 8—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):



	December 31,
	2024		2023
Natural gas purchases	$	558	$	464
Interest costs and related debt fees	81		159
Liquefaction Project costs	79		58
Other accrued liabilities	7		5
Total accrued liabilities	$	725	$	686

NOTE 9—DEBT

Debt consisted of the following (in millions):



	December 31,
	2024		2023
Senior Secured Notes:


5.750% due 2024	$	—	$	300
5.625% due 2025	300		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.746% weighted average rate due 2037 (1)	1,782		1,782
Total Senior Secured Notes	8,432		10,432

Revolving credit and guaranty agreement (the “Revolving Credit Facility”)	—		—
Total debt	8,432		10,432

Current debt, net of unamortized discount and debt issuance costs (1)	(351)		(300)

Unamortized discount and debt issuance costs	(51)		(69)
Total long-term debt, net of unamortized discount and debt issuance costs	$	8,030	$	10,063

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

Senior Secured Notes

The Senior Secured Notes are our senior secured obligations, ranking equally in right of payment with our other existing and future senior debt that is secured by the same collateral and senior in right of payment to any of its future subordinated debt. Subject to permitted liens, the Senior Secured Notes are secured on a pari passu first-priority basis by a security interest in all

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of the membership interests in us and substantially all of our assets. We may, at any time, redeem all or part of the Senior Secured Notes at specified prices set forth in the respective indentures governing the Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption. The series of Senior Secured Notes due in 2037 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2024 (in millions):


Years Ending December 31,	Principal Payments
2025	$	352
2026	1,607
2027	1,612
2028	1,468
2029	124
Thereafter	3,269
Total	$	8,432

Revolving Credit Facility

Below is a summary of our Revolving Credit Facility as of December 31, 2024 (in millions):

Revolving Credit Facility (1)

Total facility size

1,000

Less:

Outstanding balance

—

Letters of credit issued

224

Available commitment

776

Priority ranking

Senior secured

Interest rate on available balance (2)

SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%

Commitment fees on undrawn balance (2)

0.075% - 0.30%

Letter of credit fees (2)

1.0% - 1.75%

Maturity date

June 23, 2028

(1)The obligations of SPL under the SPL Revolving Credit Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on a pari passu basis by a first priority lien with the SPL Senior Secured Notes. The SPL Revolving Credit Facility contains customary contractual conditions for extensions of credit.

(2)The margin on the interest rate, the commitment fees and the letter of credit fees are subject to change based on our credit rating.

Restrictive Debt Covenants

The agreements governing our indebtedness contain customary terms and events of default and certain covenants that, among other things, may limit our ability to make certain investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our 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 December 31, 2024, we were in compliance with all covenants related to our debt agreements.

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Interest Expense

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


	Year Ended December 31,
		2024		2023		2022
Total interest cost		$	493	$	600	$	706
Capitalized interest		(4)		(5)		(39)
Total interest expense, net of capitalized interest		$	489	$	595	$	667

Fair Value Disclosures

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


	December 31, 2024				December 31, 2023
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior Secured Notes	$	8,432	$	8,282	$	10,432	$	10,375

(1)As of both December 31, 2024 and 2023, $1.3 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of the fair value of our senior notes was classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

The estimated fair value of our Revolving Credit Facility as of December 31, 2024 approximated the principal amount outstanding because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

NOTE 10—REVENUES

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


	Year Ended December 31,
		2024		2023		2022
Revenues from contracts with customers
LNG revenues (excluding net derivative gain below)		$	6,550	$	6,991	$	11,506
LNG revenues—affiliate		1,954		2,475		4,568

Total revenues from contracts with customers		$	8,504	$	9,466	$	16,074
Net derivative gain (See Note 6)		—		—		1
Total revenues		$	8,504	$	9,466	$	16,075

LNG Revenues

We have numerous SPAs with third party customers for the sale of LNG on an FOB basis (delivered to the customer at the Sabine Pass LNG Terminal). Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 11—Related Party Transactions for additional information regarding these agreements.

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Contract Liabilities

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



	Year Ended December 31, 2024
Deferred revenue, beginning of period	$	178
Cash received but not yet recognized in revenue	139
Revenue recognized from prior period deferral	(101)
Deferred revenue, end of period	$	216

The following table reflects the changes in our contract liabilities to affiliate, which we classify as other non-current liabilities—affiliate on our Balance Sheets (in millions):



	Year Ended December 31, 2024
Deferred revenue—affiliate, beginning of period	$	5
Cash received but not yet recognized in revenue	1
Revenue recognized from prior period deferral	—
Deferred revenue—affiliate, end of period	$	6

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2024 and 2023 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

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:


	December 31, 2024			December 31, 2023
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues (2)	$	44.4	7	$	47.6	8
LNG revenues—affiliate	0.7		1	1.4		2
Total revenues	$	45.1		$	49.0

(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.

(2)We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the transaction price above when the conditions have been met and consideration is not otherwise constrained from ultimate pricing and receipt.

The following potential future sources of revenue are omitted from the table above under exemptions we have elected: (1) all performance obligations that are part of a contract that has an original expected duration of one year or less and (2) substantially all variable consideration under our SPAs 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 will vary based on 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, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt.

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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


	Year Ended December 31,
		2024		2023
LNG revenues		51	%	56	%
LNG revenues—affiliate		64	%	69	%

NOTE 11—RELATED PARTY TRANSACTIONS

Below is a summary of our transactions with our affiliates and other related parties, all in the ordinary course of business, as reported on our Statements of Operations (in millions):


	Year Ended December 31,
		2024		2023		2022
LNG revenues—affiliate
SPAs and Letter Agreements with Cheniere Marketing (1)		$	1,954	$	2,472	$	4,565
Contracts for Sale and Purchase of Natural Gas and LNG with other affiliates (2)		—		3		3
Total LNG revenues—affiliate		1,954		2,475		4,568




Cost of sales—affiliate
Cheniere Marketing Agreements (1)		4		—		—
Cargo loading fees under TUA (3)		51		51		51
Contracts for Sale and Purchase of Natural Gas and LNG (2)		—		25		211


Total cost of sales—affiliate		55		76		262






Operating and maintenance expense—affiliate
TUA (3)		275		275		269
Natural Gas Transportation Agreement (4)		82		82		81
Services Agreements (see Note 1) (5)		135		130		131
LNG Site Sublease Agreement (6)		1		1		1
Total operating and maintenance expense—affiliate		493		488		482

Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements (7)		58		62		72






General and administrative expense—affiliate
Services Agreements (see Note 1) (5)		62		61		66

(1)We primarily sell LNG to Cheniere Marketing under SPAs and letter agreements at a price equal to 115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement for which pricing is linked to international natural gas prices. We also have a master SPA agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. As of December 31, 2024 and 2023, we had $161 million and $272 million of trade receivables—affiliate, respectively, under these agreements with Cheniere Marketing. In addition, we have an arrangement with Cheniere Marketing to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be the greater of: (a) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price.

(2)We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. As of December 31, 2024 and 2023, the amount of trade receivables—affiliate associated with these agreements was immaterial.

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(3)We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity, and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (a portion of which is indexed for inflation), continuing until at least May 2036. Additionally, we are required to reimburse SPLNG for our proportionate share of ad valorem taxes incurred based on our contracted share of SPLNG’s regasification capacity. CQP has guaranteed our obligations under our TUA. As of both December 31, 2024 and 2023, we had $22 million of other current assets—affiliate under this agreement.

(4)To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG Terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of CQP, and third party pipeline companies.

(5)We do not have employees and thus we 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. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements were primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2024 and 2023, we had $98 million and $75 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

(6)We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG Terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million, with renewal options and adjustment for inflation every five years. As of both December 31, 2024 and 2023, we recorded other non-current liabilities—affiliate of $15 million related to this agreement.

(7)We are party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. This related party is partially owned by the investment management company that indirectly owns a portion of CQP’s limited partner interests. We recorded accrued liabilities—related party of $5 million as of both December 31, 2024 and 2023 with this related party.

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 Balance Sheets.

Disclosures relating to future consideration under revenue contracts with affiliates is included in Note 10—Revenues.

Other Agreements

Cooperation Agreement

We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We conveyed $3 million, $4 million and $576 million in assets to SPLNG under this agreement during the years ended December 31, 2024, 2023 and 2022, respectively. The amount conveyed in 2022 related to the property, plant and equipment associated with the third marine berth at the Liquefaction Project, which was conveyed to SPLNG upon completion in October 2022.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing agreement. The agreement is effective for tax returns due on or after August 2012.

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 12—COMMITMENTS AND CONTINGENCIES

Commitments

We have various future contractual commitments which do not meet the definition of a liability as of December 31, 2024 and thus are not recognized as liabilities in our Financial Statements. Executed contracts containing such future commitments include agreements for capital expenditures, natural gas transportation and storage services, goods and services necessary to operate our Liquefaction Project and letters of credit.

Environmental and Regulatory Matters

The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.

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. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In the opinion of management, as of December 31, 2024, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

NOTE 13—SEGMENT INFORMATION AND CUSTOMER CONCENTRATION

We have determined that we operate as a single operating and reportable segment. We have contracts with CQP and other subsidiaries of Cheniere for operations, maintenance and management services, and the executive team of our affiliates that oversees us is organized by function, rather than legal entity or discrete financial data oversight, with no business component managers reporting to the chief operating decision maker (“CODM”), who is our chief executive officer. The CODM regularly analyzes financial and operational data on a single basis of segmentation, consistent with our integrated service offering, in order to allocate resources and assess performance.

The measure of profit and loss regularly provided to the CODM that is most consistent with GAAP is net income, as presented in our 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 Statements of Operations. Included in the measure of profit and loss is a significant noncash item of changes in the fair value of our derivative instruments, which was $388 million of gains, $2.1 billion of gains and $1.1 billion in losses for the years ended December 31, 2024, 2023 and 2022, respectively. Interest income was $11 million, $12 million and $2 million for the years ended December 31, 2024, 2023 and 2022, respectively, which is included in interest and dividend income on our Statements of Operations.

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

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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


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

	Year Ended December 31,			December 31,
		2024	2023	2022	2024	2023
Customer A		23%	24%	24%	19%	22%
Customer B		16%	17%	17%	*	16%
Customer C		15%	16%	17%	20%	12%
Customer D		14%	15%	16%	18%	15%
Customer E		*	*	*	*	12%

* Less than 10%

The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.


	Revenues from External Customers
	Year Ended December 31,
	2024		2023		2022
United States	$	2,129	$	2,403	$	4,147
South Korea	1,024		1,169		1,932
India	1,015		1,119		1,951
United Kingdom	976		717		1,026
Ireland	947		1,058		1,858
Other countries	459		525		593
Total	$	6,550	$	6,991	$	11,507

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION

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


	Year Ended December 31,
	2024		2023		2022
Cash paid during the period for interest on debt, net of amounts capitalized	$	549	$	580	$	613


Non-cash investing and financing activities:




Non-cash contributions from affiliates related to extinguishment of debt	—		2		—
Unpaid purchases of property, plant and equipment (1)	20		17		95
Distribution resulting from the conveyance of property, plant and equipment (see Note 11)	3		4		576

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

Novation of IPM Agreement from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)

In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, we and CCL Stage III, formerly a wholly owned direct subsidiary of Cheniere that merged with and into CCL, entered into an agreement to assign to us an IPM agreement to purchase 140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023. The transaction was accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $2.7 billion in distributions to Cheniere’s common unitholder interest within our Statements of Member’s Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $142 million and $2.6 billion, respectively, which represented a non-cash financing activity.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on their evaluation as of the end of the fiscal year ended December 31, 2024, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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.

Management’s Report on Internal Control Over Financial Reporting

Our Management’s Report on Internal Control Over Financial Reporting is included in our Financial Statements and is incorporated herein by reference.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III

ITEM 10. MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE

Omitted pursuant to Instruction I of Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

Omitted pursuant to Instruction I of Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS

Omitted pursuant to Instruction I of Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE

Omitted pursuant to Instruction I of Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent registered public accounting firm is KPMG LLP, Houston, Texas, Auditor Firm ID 185. The following table sets forth the fees billed by KPMG LLP for professional services rendered for 2024 and 2023 (in millions):


	Fiscal 2024		Fiscal 2023
Audit Fees	$	2	$	2

Audit Fees—Audit fees for 2024 and 2023 include fees associated with the audit of our annual Financial Statements, reviews of our interim Financial Statements and services performed in connection with registration statements and debt offerings, including comfort letters and consents.

Audit-Related Fees—There were no audit-related fees in 2024 and 2023.

Tax Fees—There were no tax fees in 2024 and 2023.

Other Fees—There were no other fees in 2024 and 2023.

Auditor Pre-Approval Policy and Procedures

We are not a public company and we are not listed on any stock exchange. As a result, we are not required to, and do not, have an independent audit committee, a financial expert or a majority of independent directors. The audit committee of the general partner of CQP has approved all audit and non-audit services to be provided by the independent accountants and the fees for such services during the fiscal years ended December 31, 2024 and 2023.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)Financial Statements and Exhibits

(1)Financial Statements—Sabine Pass Liquefaction, LLC:


Management’s Report to the Member of Sabine Pass Liquefaction, LLC			32
Report of Independent Registered Public Accounting Firm			33
Statements of Income			35
Balance Sheets			36
Statements of Member’s Equity (Deficit)			37
Statements of Cash Flows			38
Notes to Financial Statements			39

(2)Financial Statement Schedules:

All financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.

(3)Exhibits:

Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:

•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;

•may apply standards of materiality that differ from those of a reasonable investor; and

•were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.

Exhibit No.

Incorporated by Reference (1)

Description

Entity

Form

Exhibit

Filing Date

3.1

Certificate of Formation of the Company

SPL

S-4

3.1

11/15/2013

3.2

First Amended and Restated Limited Liability Company Agreement of the Company

SPL

S-4

3.2

11/15/2013

4.1

Indenture, dated as of February 1, 2013, by and among the Company, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee

CQP

8-K

4.1

2/4/2013

4.2

First Supplemental Indenture, dated as of April 16, 2013, between the Company and The Bank of New York Mellon, as Trustee

CQP

8-K

4.1.1

4/16/2013

Table of Contents

Exhibit No.

Incorporated by Reference (1)

Description

Entity

Form

Exhibit

Filing Date

4.3

Second Supplemental Indenture, dated as of April 16, 2013, between the Company and The Bank of New York Mellon, as Trustee

CQP

8-K

4.1.2

4/16/2013

4.4

Third Supplemental Indenture, dated as of November 25, 2013, between the Company and The Bank of New York Mellon, as Trustee

CQP

8-K

4.1

11/25/2013

4.5

Fourth Supplemental Indenture, dated as of May 20, 2014, between the Company and The Bank of New York Mellon, as Trustee

CQP

8-K

4.1

5/22/2014

4.6

Fifth Supplemental Indenture, dated as of May 20, 2014, between the Company and The Bank of New York Mellon, as Trustee

CQP

8-K

4.2

5/22/2014

4.7

Sixth Supplemental Indenture, dated as of March 3, 2015, between the Company and The Bank of New York Mellon, as Trustee

CQP

8-K

4.1

3/3/2015

4.8

Form of 5.625% Senior Secured Note due 2025 (Included as Exhibit A-1 to Exhibit 4.7 above)

CQP

8-K

4.1

3/3/2015

4.9

Seventh Supplemental Indenture, dated as of June 14, 2016, between the Company and The Bank of New York Mellon, as Trustee under the Indenture

CQP

8-K

4.1

6/14/2016

4.10

Form of 5.875% Senior Secured Note due 2026 (Included as Exhibit A-1 to Exhibit 4.9 above)

CQP

8-K

4.1

6/14/2016

4.11

Eighth Supplemental Indenture, dated as of September 19, 2016, between the Company and The Bank of New York Mellon, as Trustee under the Indenture

CQP

8-K

4.1

9/23/2016

4.12

Ninth Supplemental Indenture, dated as of September 23, 2016, between the Company and The Bank of New York Mellon, as Trustee under the Indenture

CQP

8-K

4.2

9/23/2016

4.13

Form of 5.00% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.12 above)

CQP

8-K

4.2

9/23/2016

4.14

Tenth Supplemental Indenture, dated as of March 6, 2017, between the Company and The Bank of New York Mellon, as Trustee under the Indenture

CQP

8-K

4.1

3/6/2017

4.15

Form of 4.200% Senior Secured Note due 2028 (Included as Exhibit A-1 to Exhibit 4.14 above)

CQP

8-K

4.1

3/6/2017

4.16

Eleventh Supplemental Indenture, dated as of May 8, 2020, between the Company and The Bank of New York Mellon, as Trustee under the Indenture

SPL

8-K

4.1

5/8/2020

4.17

Form of 4.500% Senior Secured Note due 2030 (Included as Exhibit A-1 to Exhibit 4.16 above)

SPL

8-K

4.1

5/8/2020

4.18

Twelfth Supplemental Indenture, dated as of November 29, 2022, between the Company and The Bank of New York Mellon, as Trustee under the Indenture

SPL

8-K

4.1

11/29/2022

4.19

Form of 5.900% Senior Secured Amortizing Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.18 above)

SPL

8-K

4.1

11/29/2022

4.20

Indenture, dated as of February 24, 2017, between the Company, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as Trustee under the Indenture

CQP

8-K

4.1

2/27/2017

4.21

Form of 5.00% Senior Secured Note due 2037 (Included as Exhibit A-1 to Exhibit 4.20 above)

CQP

8-K

4.1

2/27/2017

4.22

Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee

SPL

10-K

4.23

2/24/2022

4.23

Form of 2.95% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.22 above)

SPL

10-K

4.23

2/24/2022

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Exhibit No.

Incorporated by Reference (1)

Description

Entity

Form

Exhibit

Filing Date

4.24

Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee

SPL

10-K

4.25

2/24/2022

4.25

Form of 3.17% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.24 above)

SPL

10-K

4.25

2/24/2022

4.26

First Supplemental Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee

SPL

10-K

4.27

2/24/2022

4.27

Form of 3.19% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.26 above)

SPL

10-K

4.27

2/24/2022

4.28

Second Supplemental Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee

SPL

10-K

4.29

2/24/2022

4.29

Form of 3.08% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.28 above)

SPL

10-K

4.29

2/24/2022

4.30

Third Supplemental Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee

SPL

10-K

4.31

2/24/2022

4.31

Form of 3.10% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.30 above)

SPL

10-K

4.31

2/24/2022

10.1

LNG Sale and Purchase Agreement (FOB), dated November 21, 2011, between the Company (Seller) and Gas Natural Aprovisionamientos SDG S.A. (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)

CQP

8-K

10.1

11/21/2011

10.2

Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated April 3, 2013, between the Company (Seller) and Gas Natural Aprovisionamientos SDG S.A. (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)

CQP

10-Q

10.1

5/3/2013

10.3

Amendment of LNG Sale and Purchase Agreement (FOB), dated January 12, 2017, between the Company (Seller) and Gas Natural Fenosa LNG GOM, Limited (assignee of Gas Natural Aprovisionamientos SDG S.A.) (Buyer)

SPL

(SEC File No. 333-215882)

S-4

10.3

2/3/2017

10.4

Letter agreement regarding change from LIBOR to SOFR, dated June 8, 2023, to LNG Sale and Purchase Agreement, dated November 21, 2011, between the Company and Naturgy LNG GOM, Limited (assignee of Gas Natural Aprovisionamientos SDG S.A.), as amended

SPL

10-Q

10.6

8/3/2023

10.5

LNG Sale and Purchase Agreement (FOB), dated December 11, 2011, between the Company (Seller) and GAIL (India) Limited (Buyer)

CQP

8-K

10.1

12/12/2011

10.6

Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between the Company (Seller) and GAIL (India) Limited (Buyer)

CQP

10-K

10.18

2/22/2013

10.7

Letter agreement regarding change from LIBOR to SOFR, dated June 16, 2023, to LNG Sale and Purchase Agreement, dated December 11, 2011, between the Company and GAIL (India) Limited, as amended

SPL

10-Q

10.4

8/3/2023

10.8

Amended and Restated LNG Sale and Purchase Agreement (FOB), dated January 25, 2012, between the Company (Seller) and BG Gulf Coast LNG, LLC (Buyer)

CQP

8-K

10.1

1/26/2012

10.9

Letter agreement regarding change from LIBOR to SOFR, dated May 18, 2023, to LNG Sale and Purchase Agreement, dated January 25, 2012, between the Company and BG Gulf Coast LNG, LLC, as amended

SPL

10-Q

10.3

8/3/2023

10.10

LNG Sale and Purchase Agreement (FOB), dated January 30, 2012, between the Company (Seller) and Korea Gas Corporation (Buyer)

CQP

8-K

10.1

1/30/2012

Table of Contents

Exhibit No.

Incorporated by Reference (1)

Description

Entity

Form

Exhibit

Filing Date

10.11

Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between the Company (Seller) and Korea Gas Corporation (Buyer)

CQP

10-K

10.19

2/22/2013

10.12

Letter agreement regarding change from LIBOR to SOFR, dated June 30, 2023, to LNG Sale and Purchase Agreement, dated January 30, 2012, between the Company and Korea Gas Corporation, as amended

SPL

10-Q

10.5

8/3/2023

10.13

Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company (Seller) and Cheniere Marketing, LLC (Buyer)

SPL

8-K

10.1

8/11/2014

10.14

Letter agreement, dated December 8, 2016, amending the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)

SPL

10-K

10.14

2/24/2017

10.15

Amendment No. 1 of Amended and Restated LNG Sale and Purchase Agreement, dated May 3, 2019, by and between the Company and Cheniere Marketing International LLP

SPL

10-Q

10.1

5/9/2019

10.16

Letter Agreement, dated August 4, 2021, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)

SPL

10-Q

10.2

8/5/2021

10.17

Letter agreement regarding change from LIBOR to SOFR, dated June 26, 2023, to Amended and Restated LNG Sale and Purchase Agreement (FOB) between the Company and Cheniere Marketing International LLP, dated August 5, 2014, as amended

SPL

10-Q

10.7

8/3/2023

10.18

Letter Agreement, dated November 24, 2021, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)

SPL

8-K

10.1

11/26/2021

10.19

LNG Sale and Purchase Agreement (Tourmaline Oil Marketing Corp), dated June 15, 2022, between the Company and Cheniere Marketing International LLP

SPL

10-Q

10.2

11/3/2022

10.20

Management Services Agreement, dated May 14, 2012, by and between Cheniere Terminals and the Company

CQP

8-K

10.6

5/15/2012

10.21

Amendment to Management Services Agreement, dated September 28, 2015, between Cheniere Terminals and the Company

SPL

10-Q/A

10.8

11/9/2015

10.22

Operation and Maintenance Agreement (Sabine Pass Liquefaction Facilities), dated May 14, 2012, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and the Company

CQP

8-K

10.5

5/15/2012

10.23

Assignment and Assumption Agreement (Sabine Pass Liquefaction O&M Agreement), dated as of November 20, 2013, by and between Cheniere Energy Partners GP, LLC and Cheniere Investments

Cheniere Holdings

S-1/A

10.76

12/2/2013

10.24

Amendment to Operation and Maintenance Agreement (Sabine Pass Liquefaction Facilities), dated September 28, 2015, by and among Cheniere LNG O&M Services, LLC, Cheniere Investments and the Company

SPL

10-Q/A

10.7

11/9/2015

10.25

Second Amended and Restated LNG Terminal Use Agreement, dated as of July 31, 2012, between the Company and SPLNG

SPLNG

8-K

10.1

8/6/2012

10.26

Letter Agreement, dated May 28, 2013, by and between the Company and SPLNG

SPLNG

10-Q

10.1

8/2/2013

Table of Contents

Exhibit No.

Incorporated by Reference (1)

Description

Entity

Form

Exhibit

Filing Date

10.27

Senior Revolving Credit and Guaranty Agreement, among the Company, as borrower, certain subsidiaries of the Company, The Bank of Nova Scotia, as Senior Facility Agent, Société Générale, as the Common Security Trustee, the issuing banks and lenders from time to time party thereto and other participants

SPL

(SEC No. 333-273238)

S-4

10.46

7/13/2023

10.28

Fourth Amended and Restated Common Terms Agreement, among the Company, as borrower, the Secured Debt Holder Group Representatives party thereto, the Secured Hedge Representatives party thereto, the Secured Gas Hedge Representatives party thereto and Société Générale, as the Common Security Trustee and the Intercreditor Agent

SPL

(SEC No. 333-273238)

S-4

10.44

7/13/2023

10.29

Third Amended and Restated Accounts Agreement, among SPL, certain subsidiaries of SPL, Société Générale, as the Common Security Trustee, and Citibank, N.A. as the Accounts Bank

SPL

8-K

10.3

3/23/2020

10.30

Tax Sharing Agreement, dated as of August 9, 2012, by and between Cheniere and the Company

SPL

S-4

10.30

11/15/2013

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)


(1)			Exhibits are incorporated by reference to reports of Cheniere (SEC File No. 001-16383), CQP (SEC File No. 001-33366), Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) (SEC File No. 333-191298), SPL (SEC File No. 333-192373) and SPLNG (SEC File No. 333-138916), as applicable, unless otherwise indicated.
*			Filed herewith.
**			Furnished herewith.

ITEM 16. FORM 10-K SUMMARY

None.

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.














						SABINE PASS LIQUEFACTION, LLC

						By:			/s/ Jack A. Fusco
									Jack A. Fusco
									Chief Executive Officer (Principal Executive Officer)
						Date:			February 19, 2025

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date




/s/ Zach Davis	Manager and Chief Financial Officer (Principal Financial Officer)	February 19, 2025
Zach Davis

/s/ David Slack	Chief Accounting Officer (Principal Accounting Officer)	February 19, 2025
David Slack




/s/ Matthew Runkle	Manager	February 19, 2025
Matthew Runkle

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. junior Avg

Sabine Pass Liquefaction 10-K2024 FY Annual report

Content analysis