Cheniere Energy Partners, L.P.: Form 10-K for the period ended Dec 31, 2024

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The following are some of the important factors that should be considered when investing in us, as such risk factors 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;
• Risks Relating to Regulations;
• Risks Relating to Our Relationship with Our General Partner;
• Risks Relating to an Investment in Us and Our Common Units; and
• Risks Relating to Tax Matters.

Risks Relating to Our Financial Matters

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

As of December 31, 2024, we had, on a consolidated basis, $270 million of cash and cash equivalents, $109 million of restricted cash and cash equivalents, a total of $1.8 billion of available commitments under our credit facilities and $15.2 billion of total debt outstanding (before unamortized discount and debt issuance costs). SPL and CQP operate with independent capital structures as further detailed in Note 10—Debt of our Notes to Consolidated Financial Statements. We incur, and will incur, significant interest expense relating to financing the assets at the Sabine Pass LNG Terminal, and we anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of the SPL Expansion Project if a positive FID is made. Our ability to fund our capital expenditures and refinance our indebtedness may depend on our ability to access additional project financing as well as the debt and equity 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 or equity offerings 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. We also may rely on borrowings under our credit facilities to fund our capital expenditures. 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.

We and our subsidiaries may be restricted under the terms of our and their indebtedness from making distributions under certain circumstances, which could materially and adversely affect our liquidity.

The agreements governing our and our subsidiaries’ indebtedness contain customary terms and events of default and certain covenants that, among other things, may limit our and our subsidiaries’ ability to make certain investments or pay distributions. For example, SPL is restricted from making distributions under agreements governing its indebtedness generally unless, 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 1.25:1.00 is satisfied.

Any inability to pay distributions by us or our subsidiaries as a result of the foregoing restrictions could have a material adverse effect on our liquidity.

Our use of derivative instruments, including our IPM agreements, 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 3—Summary of Significant Accounting Policies of our Notes to Consolidated 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 $388 million 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 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 Consolidated Balance Sheets.

Restrictions in agreements governing us and our subsidiaries’ indebtedness may prevent us and our subsidiaries from engaging in certain beneficial transactions, which could materially and adversely affect us.

In addition to restrictions on the ability of us and SPL to make distributions or incur additional indebtedness, the agreements governing SPL’s indebtedness also contain various other covenants that may prevent them from engaging in beneficial transactions, including limitations on their ability to:

• make certain investments;
• purchase, redeem or retire equity interests;
• issue preferred stock;
• sell or transfer assets;
• incur liens;
• enter into transactions with affiliates;
• consolidate, merge, sell or lease all or substantially all of its assets; and
• enter into sale and leaseback transactions.

Any restrictions on the ability to engage in beneficial transactions could materially and adversely affect us.

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, SPL entered into an arrangement with its 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 its 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 Consolidated 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 pipeline and 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 and to and from the Creole Trail Pipeline. 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 natural gas to our pipeline and 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 construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The construction and operation of the Sabine Pass LNG Terminal and the operation of the Creole Trail Pipeline are, and will be, subject to the inherent risks associated with these types of operations 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;
• 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 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.

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, or direct their LNG to, non-U.S. markets or from or to 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 the IPM agreement currently in effect 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 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 pipeline and LNG industries are 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 pipeline and 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 or business.

Our facilities at the Sabine Pass LNG Terminal 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 or business.

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 our facilities, the development and operation of our pipeline 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 interstate natural gas pipelines, our LNG terminal, including the Liquefaction Project, the SPL Expansion Project and other facilities, as well as the export of LNG and the purchase and transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 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 an interstate natural gas pipeline 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, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline. In February 2024, certain of our subsidiaries submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project. To date, the DOE has also issued orders under Section 4 of the NGA authorizing SPL to export domestically produced LNG. We currently have the SPL 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. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipeline on land owned by third parties. If we were to lose these rights or be required to relocate our pipeline, our business could be materially and adversely affected.

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, 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.

Our Creole Trail Pipeline and its FERC gas tariff are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.

The Creole Trail Pipeline is subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA”). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by our Creole Trail Pipeline must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any potential shipper with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our Creole Trail Pipeline could be subject to substantial penalties and fines.

In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.5 million per day for each violation.

Although the FERC has not imposed fines or penalties on us to date, we are exposed to substantial penalties and fines if we fail to comply with such regulations.

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 LNG terminal, marine berths and pipeline, including the 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. These regulations require monitoring of methane and VOC emissions at our compressor stations. 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 the Sabine Pass LNG Terminal, 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 imported to or 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 Consolidated 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 restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.

The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:

• perform ongoing assessments of pipeline safety and compliance;
• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
• improve data collection, integration and analysis;
• repair and remediate the pipeline as necessary; and
• implement preventative and mitigating actions.

We are required to utilize pipeline integrity management programs that are intended to maintain pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines, which for certain violations can aggregate up to as high as $2.7 million.

Risks Relating to Our Relationship with Our General Partner

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

As of December 31, 2024, Cheniere had 1,714 full-time employees, including 501 employees who directly supported our operations. We have contracted with subsidiaries of Cheniere to provide the personnel necessary for the construction, operation, maintenance and management of the Liquefaction Project and the Creole Trail Pipeline, and administrative services. We depend on Cheniere’s 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 projects near Corpus Christi, Texas, for the time and expertise of Cheniere’s personnel. Further, we and Cheniere face competition for these highly skilled employees in the vicinity of our operations and more generally from the Gulf Coast hydrocarbon processing and construction industries.

The executive officers of our general partner are officers and employees of Cheniere. We do not maintain key person life insurance policies on any personnel, and our general partner does 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 general partner’s 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 Cheniere offers. In addition, Cheniere is also subject to increased competition for skilled workers from new entrants to the LNG market. Currently, our payments to Cheniere for labor consist of reimbursement of cost plus a fixed monthly fee (indexed for inflation) per mtpa, therefore any increases in Cheniere’s costs will increase our operating costs, which could materially and adversely affect our business results.

Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of us and our unitholders.

Cheniere owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Some of our general partner’s directors are also directors of Cheniere, and certain of our general partner’s officers are officers of Cheniere. Therefore, conflicts of interest may arise between Cheniere and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of us and our unitholders. These conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires Cheniere to pursue a business strategy that favors us. Cheniere’s directors and officers have a fiduciary duty to make these decisions in favor of the owners of Cheniere, which may be contrary to our interests:
• our general partner controls the interpretation and enforcement of contractual obligations between us, on the one hand, and Cheniere, on the other hand, including provisions governing administrative services and acquisitions;
• our general partner is allowed to take into account the interests of parties other than us, such as Cheniere and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us and our unitholders;
• our general partner has limited its liability and reduced its fiduciary duties under the partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty;
• Cheniere is not limited in its ability to compete with us. Cheniere is not restricted from competing with us and is free to develop, operate and dispose of, and is currently developing, LNG facilities, pipelines and other assets without any obligation to offer us the opportunity to develop or acquire those assets;
• our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities, and the establishment, increase or decrease in the amounts of reserves, each of which can affect the amount of cash that is distributed to our unitholders;
• our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;
• our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;
• our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
• our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and
• our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

We also have agreements to compensate and to reimburse expenses of affiliates of Cheniere. 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, through CCL, is currently operating three Trains at a natural gas liquefaction facility near Corpus Christi, Texas 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 in 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.

In the event Cheniere favors its interests over our interests, we may have less available cash to make distributions on our units than we otherwise would have if Cheniere had favored our interests.

Risks Relating to an Investment in Us and Our Common Units

Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

• permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;
• provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner, as long as it acted in good faith, meaning that it believed the decision was in the best interests of our partnership, including in resolution of conflicts of interest;
• generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us;
• provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was criminal; and
• provides that in resolving conflicts of interest, it will be presumed that in making its decision the conflicts committee or the general partner acted in good faith, and in any proceedings brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units trade.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by affiliates of Cheniere. As a result, the price at which the common units trade could be diminished because of the absence or reduction of a control premium in the trading price.

The vote of the holders of at least 66 2/3% of all outstanding common units (including any units owned by our general partner and its affiliates), voting together as a single class is required to remove our general partner. Cheniere owns 48.6% of our outstanding common units, but it is contractually prohibited from voting our units that it holds in favor of the removal of our general partner.

Additionally, our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Any change of our general partner or the replacement of the board of directors or officers of our partnership, which can occur without the consent of our unitholders, can impact our future operations and have an adverse impact on the trading price of our common units.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers. Any change in our general partner or the replacement of the board of directors or officers of our partnership can impact our future operations and have an adverse impact on the trading price of our common units.

Our partnership agreement prohibits a unitholder (other than our general partner and its affiliates) who acquires 15% or more of our limited partner units without the approval of our general partner from engaging in a business combination with us for three years unless certain approvals are obtained. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our common units.

Our partnership agreement effectively adopts Section 203 of the General Corporation Law of the State of Delaware (“DGCL”). Section 203 of the DGCL as it applies to us prevents an interested unitholder defined as a person (other than our general partner and its affiliates) who owns 15% or more of our outstanding limited partner units from engaging in business combinations with us for three years following the time such person becomes an interested unitholder unless certain approvals are obtained. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our partnership agreement could have an anti-takeover effect with respect to transactions not approved in advance by our general partner, including discouraging takeover attempts that might result in a premium over the market price for our common units.

Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for contractual obligations of the partnership that are expressly made without recourse to the general partner. We are organized under Delaware law, and we conduct business in other states. As a limited partner in a partnership organized under Delaware law, holders of our common units could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other action under our partnership agreement constituted participation in the “control” of our business. In addition, limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions.

Our unitholders may have liability to repay distributions wrongfully made.

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, partners who received such a distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partner interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Affiliates of our general partner or affiliates of Blackstone Inc. (“Blackstone”) or Brookfield Asset Management Inc. (“Brookfield”) may sell limited partner units, which sales could have an adverse impact on the trading price of our common units.

Sales by us or any of our affiliated unitholders or affiliates of Blackstone of a substantial number of our common units, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. As of December 31, 2024, Cheniere owned approximately 239.9 million of our common units. We also filed a registration statement for the resale of 202,450,687 common units owned by Blackstone and its affiliates in 2017. Any sales of these units could have an adverse impact on the price of our common units.

Risks Relating to Tax Matters

Our tax treatment depends on our status as a partnership for federal income tax purposes, and our not being subject to a material amount of entity-level taxation by individual states. If we were treated as a corporation for federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would likely pay state and local income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distributions to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such taxes on us in jurisdictions in which we operate, or to which we may expand our operations, may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the initial quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The Internal Revenue Service (“IRS”) may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. Although final Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, such tax items must be prorated on a daily basis and these regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A successful IRS contest of the federal income tax positions that we take, may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.

The IRS may adopt positions that differ from the positions that we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions that we take. A court may not agree with some or all of the positions that we take. Any contest with the IRS may adversely impact the taxable income or loss reported to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under applicable rules, we may pay such amounts directly to the IRS or, if we are eligible, elect to issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. No assurances can be made that such election will be practical, permissible, or effective in all circumstances. As a result, our current unitholders may bear some or all of the economic burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

Our unitholders may be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.

Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income irrespective of whether they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability attributable to their share of our taxable income.

Tax gain or loss on the disposition of our common units could be different than expected.

If our unitholders sell any of their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of the unitholders’ allocable share of our net taxable income decrease the unitholders’ tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price received is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income due to the potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investments in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our common units will generally be considered to be “effectively connected” with a U.S. trade or business and subject to U.S. federal income tax. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.

Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, withholding at a rate of 10% may be required on the amount realized unless the disposing unitholder certifies that it is not a foreign person. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the unitholder. Quarterly distributions made to our non-U.S. unitholders will also be subject to withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. We intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to the additional 10% withholding tax. For transfers of, or distributions on, interests in a publicly traded partnership, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

Our unitholders will likely be subject to state and local taxes and return filing requirements as a result of an investment in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the unitholder does not live in any of those jurisdictions. Our unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Furthermore, our unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own property or conduct business in additional states or foreign countries that impose a personal tax or an entity level tax. Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of our unitholders to file all United States federal, state and local tax returns.

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates ourselves using a methodology based on the market value of our common units as a means to determine the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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.

Cyberattacks represent a potentially significant risk to the Partnership and our industry. We have implemented policies and procedures that are intended to manage and reduce this risk, including those managed by affiliates of Cheniere through our service agreements with them, as further discussed in Note 13—Related Party Transactions of our Notes to Consolidated Financial Statements.

Risk Management and Strategy

As part of our broader approach to risk management, our 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”). Our 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, we routinely evaluate opportunities to refine our cybersecurity program in order to mitigate operational network risks. We include business continuity planning as a component of our strategy to help ensure critical systems are available to support the Partnership in the instance of a disruptive event. We also participate in various industry organizations to stay abreast of recent trends and developments.

On an ongoing basis, we and Cheniere assess our people, processes and technology and, when necessary, adjust the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. We conduct 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 our Cyber Incident Response Plan. To support these efforts, Cheniere has contracted with third parties to perform facility and system penetration tests, compromise assessments of information technology systems and security maturity assessments of our 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 board of directors of our general partner 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 seeks to contractually require third party service providers with access to our 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 us, except as required by applicable law. Cheniere also seeks to negotiate contractual requirements which compel our service providers to notify us 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.

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 our cybersecurity governance, cyber risk management and security operations and are responsible for maintaining our 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 the board of directors of our general partner and Audit Committee deliberations throughout the year. The board of directors of our general partner 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 has been delegated the authority to oversee and periodically review the security of Cheniere’s information technology systems and controls, including programs and defenses against cybersecurity threats. The Audit Committee discusses with management our cybersecurity risk exposures and the steps management has taken to mitigate such exposures, including our risk assessment and risk management policies. On a quarterly basis, Cheniere’s cybersecurity leadership team updates the Audit Committee on the overall status of our 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.

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.

LDEQ Matter

Certain of our subsidiaries 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 our subsidiaries petitioned the EPA and LDEQ for approval of additional operating parameters to demonstrate compliance with the emission limitation. The petition remains pending. Our subsidiaries 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, our subsidiaries 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.

Introduction

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

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, certain of our subsidiaries submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL 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 SPL 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

• We declared aggregate distributions of $3.465 per common unit for the year ended December 31, 2024. On January 29, 2025, with respect to the fourth quarter of 2024, we declared a cash distribution of $0.820 per common unit to unitholders of record as of February 10, 2025, and the related general partner distribution, that was paid on February 14, 2025. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.045 per unit.
• In May 2024, we issued $1.2 billion aggregate principal amount of 5.750% Senior Notes due 2034 (the “2034 CQP Senior Notes”). In June 2024, the net proceeds, together with cash on hand, were used to redeem $1.2 billion of the outstanding aggregate principal amount of SPL’s 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes”).
• Excluding amounts refinanced, SPL redeemed $800 million of outstanding aggregate principal amount of its senior secured notes during the year ended December 31, 2024.
• In May 2024, in connection with the 2034 CQP Senior Notes issuance, Moody’s Ratings (“Moody’s”) upgraded our issuer credit rating to Baa2 from Ba1 and revised our outlook to stable from positive. Moody’s also upgraded SPL’s issuer credit rating to Baa1 from Baa2 and revised SPL’s outlook to stable from positive.

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.

Results of Operations

(in millions, except per unit data)

Volumes loaded and recognized from the Liquefaction Project

Net income

Net income declined by $1.7 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 majority of the decrease was attributable 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.

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

Revenues

The $960 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 maintenance activities compared to the same period of 2023 and cooler weather.

Operating costs and expenses

The increase in operating costs and expenses of $796 million 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.

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 Consolidated Financial Statements. For commodity derivative instruments, including those related to our IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

Liquidity and Capital Resources

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

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

(1) Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2024. See Note 10—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities 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.

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

• SPL is required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments. In addition, SPL’s operating costs are managed by subsidiaries of Cheniere under affiliate agreements, which may require SPL to advance cash to the respective affiliates; and
• SPL is restricted by affirmative and negative covenants included in certain of its debt agreements in its ability to make certain payments, including distributions, unless specific requirements are satisfied.

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

Supplemental Guarantor Information

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

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

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

Obligations also include events of default that are customary for the respective debt instrument, which are subject to customary grace periods and materiality standards.

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

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

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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):

(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 in effect, 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 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. We do not have an SPA as of December 31, 2024 for the approximately 665 TBtu associated with an IPM agreement that is subject to unsatisfied contractual conditions precedent.

Additional Future Sources of Liquidity

Available Commitments under Credit Facilities

As of December 31, 2024, we had $1.8 billion in available commitments under our credit facilities, as detailed earlier in the table summarizing our available liquidity, subject to compliance with the applicable covenants, to potentially meet liquidity needs. Our credit facilities mature 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, certain of our subsidiaries submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL 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):

(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.

(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 $0.2 billion in obligations to related parties.

(6) Other purchase obligations include $1.2 billion of purchase obligations to affiliates under service agreements.

(7) Leases include payments under operating leases and finance leases. Payments during future renewal option periods that are exercisable at our sole discretion are included only to the extent that the option is believed to be reasonably certain to be exercised.

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 in effect. 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.

Leases

Our obligations under our lease arrangements primarily consist of leases for the use of tug vessels and land sites.

Additional Future Cash Requirements for Operations and Capital Expenditures

Operational Services

We rely on our general partner to manage all aspects of the development, construction, operation and maintenance of the Sabine Pass LNG Terminal and to conduct our business. Because our general partner has no employees, it relies on subsidiaries of Cheniere to provide the personnel necessary to allow it to meet its management obligations to us and our subsidiaries. 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.

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):

(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 $15.2 billion and credit facilities with no outstanding loan balances. As of December 31, 2024, we and SPL were in compliance with all covenants related to their respective debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10—Debt of our Notes to Consolidated Financial Statements.

Interest

As of December 31, 2024, our senior notes had a weighted average contractual interest rate of 4.79%. Borrowings under our credit facilities are indexed to SOFR. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.075% to 0.30%, subject to change based on the applicable entity’s credit rating. Issued letters of credit under our credit facilities are subject to letter of credit fees ranging from 1.0% to 2.0%, subject to change based on the applicable entity’s credit rating. We had $224 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2024.

Additional Future Cash Requirements for Financing

CQP Distribution

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

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 senior notes of CQP and SPL.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash and cash equivalents (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.

Operating Cash Flows

The $143 million decrease between the periods was primarily related to cash flows attributed to working capital, mainly due to differences in timing of payments to suppliers and cash collections from the sale of LNG cargoes.

Investing Cash Flows

Cash outflows for property, plant and equipment during the 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):

Debt Activity

The following table shows our debt activity (in millions):

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Cash Distributions to Unitholders

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

The following provides a summary of distributions paid by us during the years ended December 31, 2024 and 2023:

In addition, Tug Services distributed $13 million during both the years ended December 31, 2024 and 2023, respectively, to Cheniere Terminals in accordance with their terminal marine service agreement, which is recognized as part of the distributions to the holder of our general partner interest. Refer to Note 13—Related Party Transactions of our Notes to Consolidated Financial Statements for further discussion of this agreement.

On January 29, 2025, with respect to the fourth quarter of 2024, we declared a cash distribution of $0.820 per common unit to unitholders of record as of February 10, 2025, and the related general partner distribution, that was paid on February 14, 2025. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.045 per unit.

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. 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.

Fair Value of Level 3 Liquefaction Supply Derivatives

All of our derivative instruments are recorded at fair value, as described in Note 3—Summary of Significant Accounting Policies of our Notes to Consolidated 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 3—Summary of Significant Accounting Policies of our Notes to Consolidated 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.

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 IPM agreement in effect during the years ended December 31, 2024 and 2023.

The estimated fair value of level 3 derivatives recognized in our Consolidated 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.

Recent Accounting Standards

For a summary of recently issued accounting standards, see Note 3—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.

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):

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See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.

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 general partner’s 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 general partner’s 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 Consolidated Financial Statements and is incorporated herein by reference.