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Expected Credit Losses
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Depreciation
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(Policies)
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Expected Credit Losses (Tables)
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Depreciation (Tables)
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(Details)
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Assets and Liabilities (Details)
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Quantitative Information (Details)
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Activity (Details)
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(Details)
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Instruments by Balance Sheet Location (Details)
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Presentation on Balance Sheets (Details)
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Fair Values of Debt Instruments (Details)
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(Details)
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(Details)
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to Future Performance Obligations (Details)
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Variable Consideration (Details)
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Party Transactions (Details)
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(Details)
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(Details)
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(Details)
77: R67 Commitments and Contingencies - Purchase HTML 51K
Obligations Table (Details)
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Concentration (Details)
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External Customers by Country (Details)
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UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM i10-K
i☒ ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
(Exact
name of registrant as specified in its charter)
iDelaware
i27-3235920
(State
or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
i845 Texas Avenue, iSuite 1250
iHouston,
iTexasi77002
(Address of principal executive offices) (Zip Code)
(i713) i375-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol
Name
of each exchange on which registered
iNone
None
None
Securities registered pursuant to Section 12(g) of the Act: None
The registrant meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.
Indicate by check mark if the
registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐iNo☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐iNo☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. iYes☒ No ☐
Note:
The registrant was a voluntary filer until July 27, 2023. The registrant has filed all reports required pursuant to Sections 13 or 15(d) during the preceding 12 months as if the registrant was subject to such filing requirements.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit such files). iYes☒No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer,”“smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filer
☐
Accelerated filer
☐
iNon-accelerated filer
☒
Smaller reporting company
i☐
Emerging
growth company
i☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant
has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. i☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. i☐
Indicate
by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes i☐ No ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates: Not applicable
Indicate the number of shares outstanding of the issuer’s classes of common stock, as of the latest practicable date: Not applicable
As used in this annual report, the terms listed below have the following meanings:
Common Industry and Other Terms
ASU
Accounting Standards Update
Bcf
billion cubic feet
Bcf/d
billion
cubic feet per day
Bcf/yr
billion cubic feet per year
DOE
U.S. Department of Energy
EPC
engineering, procurement and construction
ESG
environmental, social and governance
FASB
Financial
Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FID
final investment decision
FOB
free-on-board
FTA countries
countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP
generally accepted
accounting principles in the United States
Henry Hub
the final settlement price (in U.S. dollars per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
IPM agreement
integrated production marketing agreement in which the gas producer sells to us gas on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs
LIBOR
London
Interbank Offered Rate
LNG
liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu
million British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
mtpa
million tonnes per annum
non-FTA countries
countries
with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC
U.S. Securities and Exchange Commission
SOFR
Secured Overnight Financing Rate
SPA
LNG sale and purchase agreement
TBtu
trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature
of one pound of water by one degree Fahrenheit
Train
an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements.” All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
•statements that we expect to commence or complete construction of our natural gas liquefaction project, or any expansions or portions thereof, by certain dates, or at all;
•statements regarding future levels of domestic and
international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
•statements regarding our future sources of liquidity and cash requirements;
•statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement
with any EPC or other contractor, and anticipated costs related thereto;
•statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
•statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
•statements
regarding our planned development and construction of additional Trains, including the financing of such Trains;
•statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
•statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
•any
other statements that relate to non-historical or future information; and
•other factors described in Item 1A. Risk Factors in this Annual Report on Form 10-K.
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,”“will,”“could,”“should,”“achieve,”“anticipate,”“believe,”“contemplate,”“continue,”“estimate,”“expect,”“intend,”“plan,”“potential,”“predict,”“project,”“pursue,”“target,” the
negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other
information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.
We are a Delaware limited liability company formed by CQP. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.
LNG
is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking, other industrial uses and back up for intermittent energy sources. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.
We
own six operational Trains, for a total production capacity of approximately i30 mtpa of LNG (the “Liquefaction Project”), at a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world. The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks and three marine berths owned and operated by SPLNG, a subsidiary of CQP, and a 94-mile natural gas supply pipeline owned
and operated by CTPL, a subsidiary of CQP.
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted most of our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under an IPM agreement, in which the gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these
contracts helps limit our exposure to fluctuations in U.S. natural gas prices. Through our SPAs and IPM agreement, we have contracted approximately 85% of the total anticipated production from the Liquefaction Project with approximately 14 years of weighted average remaining life as of December 31, 2023, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.
We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We
believe these factors provide a foundation for additional growth in our portfolio of customer contracts in the future. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. In May 2023, we and another subsidiary of CQP entered the pre-filing review process with the FERC under the National Environmental Policy Act (“NEPA”) for an expansion adjacent to the Liquefaction Project with a potential production capacity of up to approximately 20 mtpa of total LNG capacity, inclusive of estimated debottlenecking opportunities (the “Expansion Project”). This expansion may be developed and constructed by an affiliate of ours outside of the Liquefaction Project. The development of the Expansion
Project or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before a positive FID is made.
Our Business Strategy
Our primary business strategy is to develop, construct and operate assets to meet our long-term customers’ energy demands. We plan to implement our strategy by:
•safely, efficiently and reliably operating and maintaining our assets, including our Trains;
•procuring
natural gas and pipeline transport capacity to our facility;
•commencing commercial delivery for our long-term SPA customers, of which we have initiated for nine of eleven third party long-term SPA customers as of December 31, 2023;
•maximizing the production of LNG to serve our customers and generating steady and stable revenues and operating cash flows;
•optimizing the Liquefaction Project by leveraging existing infrastructure;
•maintaining a prudent and cost-effective capital structure; and
•strategically identifying actionable and economic environmental solutions.
Our Business
Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Liquefaction
Project and Expansion Project
The Liquefaction Project, as described above under the caption General, is one of the largest LNG production facilities in the world with six Trains. Additionally, in May 2023, we and another subsidiary of CQP entered the pre-filing review process with the FERC under the NEPA for the Expansion Project.
The following summarizes the volumes of natural gas for which we have received approvals from FERC to site, construct and operate the Trains at the Liquefaction Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December
31, 2050:
FERC Approved Volume
DOE Approved Volume
(in Bcf/yr)
(in mtpa)
(in Bcf/yr)
(in
mtpa)
FTA countries
1,661.94
33
1,661.94
33
Non-FTA countries
1,661.94
33
1,661.94
33
Natural Gas Supply, Transportation and Storage
We
have secured natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements, including an IPM agreement. Additionally, to ensure that we are able to transport natural gas feedstock to the Liquefaction Project and manage inventory levels, we have entered into firm pipeline transportation and storage contracts with third parties and CTPL.
Terminal Use Agreements
We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. Additionally, we have entered into a partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”),
another TUA customer, to provide us with additional berthing and storage capacity at the Sabine Pass LNG Terminal. Refer to Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of our TUA agreements.
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These rigorous regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.
Federal Energy Regulatory Commission
The design, construction, operation, maintenance
and expansion of the Liquefaction Project and the export of LNG are highly regulated activities subject to the jurisdiction of the FERC pursuant to the Natural Gas Act of 1938, as amended (the “NGA”). Under the NGA, the FERC’s jurisdiction generally extends to the sale for resale of natural gas in interstate commerce and to the construction, operation, maintenance and expansion of liquefaction facilities.
On February 18, 2022, the FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for the FERC’s decision-making process, modifying the standards that the FERC uses to evaluate applications to include, among other things, reasonably foreseeable greenhouse gas (“GHG”)
emissions that may be attributable to the project and the project’s impact on environmental justice communities. On March 24, 2022, the FERC rescinded the Policy Statement, re-issued it as a draft and it remains pending. At this time, we do not expect it to have a material adverse effect on our operations.
In May 2023, we and another subsidiary of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project.
All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction
under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other governmental and regulatory approvals and permits are required throughout the life of the Liquefaction Project. In addition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of the Liquefaction Project. For example, throughout the life of our liquefaction facility, we are subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”)
and applicable federal and state regulatory
agencies regarding the operation and maintenance of our facility. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations has not materially affected our construction or operations.
DOE Export Licenses
The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal as discussed in Liquefaction
Project and Expansion Projects. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.
Under Section 3 of the NGA, applications for exports of natural gas to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in
a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations. We do not believe such a pause will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity. We have no projects pending non-FTA export approval with the DOE at this time, although we would anticipate seeking non-FTA export authorization from the DOE on the SPL Expansion Project in the future, having entered the pre-filing review process with the FERC in May 2023. See Liquefaction Project and
Expansion Project section above for FERC and DOE approved volumes on our existing Liquefaction Project.
Other Governmental Permits, Approvals and Authorizations
Construction and operation of the Liquefaction Project requires additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including the DOT, U.S. Army Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the U.S. Environmental Protection Agency (the “EPA”), U.S. Department of Homeland Security and the Louisiana Department of Environmental Quality (the
“LDEQ”).
The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10). The EPA administers the Clean Air Act (“CAA”), and has delegated authority to the LDEQ to issue the Title V Operating Permit and the Prevention of Significant Deterioration Permit. These two permits are issued by the LDEQ for the Liquefaction Project.
Commodity Futures Trading Commission (“CFTC”)
The Dodd-Frank
Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in those markets. The CFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, including the speculative position limit rules. Given the enactment of the speculative position limit rules, as well as the impact of other rules and regulations under the Dodd-Frank Act, the impact of such rules and regulations on our business continues to be uncertain, but is not expected to be material.
As required by the Dodd-Frank Act, the CFTC and federal banking regulators also adopted rules requiring swap dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions,
to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We qualify as a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.
Pursuant to the Dodd-Frank Act, the
CFTC adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.
Environmental Regulation
The Liquefaction Project is subject to various federal, state and local laws and
regulations relating to the protection of the environment and natural resources. These environmental laws and regulations can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can
lead to substantial administrative, civil and criminal fines and penalties for non-compliance.
Clean Air Act
The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. However, we do not believe any such requirements will have a material adverse effect on our operations.
On February 28, 2022, the EPA removed a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants
(“NESHAP”) Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant (“HAP”) emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that the construction and operations of our Liquefaction Project will be materially and adversely affected by such regulatory actions.
We are supportive of regulations reducing GHG
emissions over time. Since 2009, the EPA has promulgated and finalized multiple GHG emissions regulations related to reporting and reductions of GHG emissions from our facilities. On December 2, 2023, the EPA issued final rules to reduce methane and volatile organic compounds (“VOC”) emissions from new, existing and modified emission sources in the oil and gas sector. These regulations will require monitoring of methane and VOC emissions at our compressor stations. We do not believe such regulations will have a material adverse effect on our operations, financial condition or results of operations.
From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. On August 16, 2022, President
Biden signed H.R. 5376(P.L. 117-169), the Inflation Reduction Act of 2022 (“IRA”) which includes a charge on methane emissions above a certain methane intensity threshold for facilities that report their GHG emissions under the EPA’s Greenhouse Gas Emissions Reporting Program Part 98 regulations. The charge starts at $900 per metric ton of methane in 2024, $1,200 per metric ton in 2025, and increasing to $1,500 per metric ton in 2026 and beyond. In January 2024, the EPA issued a proposed rule to impose and collect the methane emissions charge authorized under the IRA. We do not expect the methane charge to have a material adverse effect on our operations, financial condition or results of operations.
Coastal Zone Management Act (“CZMA”)
The
siting and construction of the Liquefaction Project within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.
The Liquefaction Project is subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on
the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.
Resource Conservation and Recovery Act (“RCRA”)
The federal RCRA and
comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.
Protection of Species, Habitats and Wetlands
Various federal and state statutes, such as the Endangered Species Act, the Migratory Bird Treaty Act, the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If the Liquefaction Project may adversely affect a protected species or its habitat, we may
be required to develop and follow a plan to avoid those impacts. In that case, siting, construction or operation may be delayed or restricted and cause us to incur increased costs.
It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe such regulatory actions will have a material adverse effect on our operations, or the operations.
Market Factors and Competition
Market Factors
Our ability to
enter into additional long-term SPAs to underpin the development of additional Trains or develop new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the extent of energy security needs in the European Union and elsewhere, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and other overarching factors such as global economic growth and the pace of any transition from fossil-based systems of energy production and consumption to alternative energy sources. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our ability to access capital markets.
We
expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Market participants around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure growth. Currently, significant amounts of money are being invested across Europe, Asia and Latin America in natural gas projects under construction, and more continues to be earmarked to planned projects globally. In Europe, there are various plans to install more than 85 mtpa of import capacity over the near-term to secure access to LNG and displace Russian gas imports. In India, there are more than 11,000 kilometers of gas pipelines under construction to expand the gas distribution network and increase access to natural gas. And in China, billions of U.S. dollars have already been invested and hundreds
of billions of U.S. dollars are expected to be further invested all along the natural gas value chain to enable growth and decrease harmful emissions. Furthermore, some of the existing integrated liquefaction facilities outside of the U.S. have been experiencing issues related to reduced feed gas as a result of depleting upstream resources. Global supply contributions from these plants have been decreasing and LNG supply growth is expected to help support these shortages.
As a result of these dynamics, we expect natural gas and LNG to continue to play an important role in satisfying
energy demand going forward. In its forecast published in the third quarter of 2023, Wood Mackenzie Limited (“WoodMac”) forecasted that global demand for LNG would increase by approximately 60%, from approximately 411 mtpa, or 19.7 Tcf, in 2022, to 657 mtpa, or 31.5 Tcf, in 2040 and to 709 mtpa or 34 Tcf in 2050. In its forecast published in the third quarter of 2023, WoodMac also forecasted LNG production from existing operational facilities and new facilities already under construction would be able to supply the market with approximately 544 mtpa in 2040, declining to 477 mtpa in 2050. This could result in a market need for construction of an additional approximately 113 mtpa of LNG production by 2040 and about 231 mtpa by 2050. As a cleaner burning fuel with lower emissions than coal or liquid fuels in power generation, we expect natural gas and LNG to play a central role in balancing grids, serving as back
up for intermittent energy sources and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of the Liquefaction Project, as well as the proposed expansion at Sabine Pass is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.
We have limited exposure to oil price movements as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements indexed to Henry Hub. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes. Through our SPAs and IPM agreement, we have contracted approximately 85% of the total anticipated production from the Liquefaction Project, with approximately 14 years of weighted average remaining
life as of December 31, 2023, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. Customers are required to pay a fixed fee with respect to the contracted volumes, irrespective of their election to cancel or suspend deliveries of LNG cargoes.
Competition
Despite the long term nature of our SPAs, when we need to replace or amend any existing SPA or enter into new SPAs, we will compete on the basis of price per contracted volume of LNG with other natural gas liquefaction projects throughout the world, including our affiliate Corpus Christi Liquefaction, LLC (“CCL”), which operates three Trains at a natural gas liquefaction facility near Corpus Christi,
Texas. Revenues associated with any incremental volumes of the Liquefaction Project, including those made available to Cheniere Marketing, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to LNG markets than us.
Corporate Responsibility
As described in Market Factors and Competition, we expect that global
demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Our vision is to provide clean, secure and affordable energy to the world. This vision underpins our focus on responding to the world’s shared energy challenges—expanding the global supply of clean, secure and affordable energy, improving air quality, reducing emissions and supporting the transition to a lower-carbon future. Our approach to corporate responsibility is guided by our Climate and Sustainability Principles: Transparency, Science, Supply Chain and Operational Excellence. In August 2023, Cheniere published The Power of Connection, its fourth Corporate Responsibility (“CR”) report, which details Cheniere’s approach and progress on ESG matters. Cheniere’s CR report is available at www.cheniere.com/our-responsibility/reporting-center. Information
on Cheniere’s website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K.
Cheniere’s climate strategy is to measure and mitigate emissions – to better position our LNG supplies to remain competitive in a lower carbon future, providing energy, economic and environmental security to our customers across the world. To maximize the environmental benefits of our LNG, we believe it is important to develop future climate goals and strategies based on an accurate and holistic assessment of the emissions profile of our LNG, accounting for all steps in the supply chain.
Consequently, Cheniere has
collaborated with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment (“LCA”) models, quantification, monitoring, reporting and verification (“QMRV”) of GHG emissions and other research and development projects. Cheniere also co-founded and sponsored the Energy Emissions Modeling and Data Lab (“EEMDL”), a multidisciplinary research and education initiative led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines. In addition,
Cheniere commenced providing Cargo Emissions Tags (“CE Tags”) to its long-term customers in June 2022, and in October 2022 joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative.
Our total incremental expenditures related to climate initiatives, including capital expenditures, were not material to our Financial Statements during the years ended December 31, 2023, 2022 and 2021. However, as governments consider and implement
actions to reduce GHG emissions and the transition to a lower-carbon economy continues to evolve, as described in Market Factors and Competition, we expect the scope and extent of our future climate and sustainability initiatives to evolve accordingly. While we have not incurred material direct expenditures related to climate change, we are proactive in our management of climate risks and opportunities, including compliance with existing and future government regulations. We face certain business and operational risks associated with physical impacts from climate change, such as exposure to severe weather events or changes in weather patterns, in addition to transition risks. Please see Item 1A. Risk Factors
for additional discussion.
Employees
We have no employees. We have contracts with CQP and other subsidiaries of Cheniere for operations, maintenance and management services. See Note 12—Related Party Transactions of our Notes to Financial Statements for a discussion of such services agreements with our affiliate entities. As of December
31, 2023, Cheniere and its subsidiaries had 1,605 full-time employees, including 501 employees who directly supported the Sabine Pass LNG Terminal operations.
Available Information
Our principal executive offices are located at 845 Texas Avenue, Suite 1250, Houston, Texas77002, and our telephone number is (713) 375-5000. Our
internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website
should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers.
ITEM 1A. RISK FACTORS
The following are some of the important risk factors that could adversely affect our financial performance or 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:
An inability to source capital to supplement our available cash resources and existing revolving credit facility could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
As of December 31, 2023, we had $56 million of restricted cash and cash equivalents, $720 million of available commitments under our $1.0 billion senior secured revolving credit facility (the “Revolving Credit Facility”) and $10.4 billion of total debt outstanding (before unamortized,
discount and debt issuance costs). We incur, and will incur, significant interest expense relating to financing the assets at the Liquefaction Project. Our ability to refinance our indebtedness will depend on
our ability to access the debt capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, lending institutions’ evolving policies on financing businesses linked to fossil
fuels and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.
Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant customer fails to perform its contractual obligations
for any reason.
Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2023, we had SPAs with initial terms of 10 or more years with a total of 11 different third party customers.
While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.
Additionally, our long-term SPAs
entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we fail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs upon the occurrence of certain events of force majeure.
Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially
and adversely affected.
Our efforts to manage commodity and financial risks through derivative instruments, including our IPM agreement, could adversely affect our earnings reported under GAAP and our liquidity.
We use derivative instruments to manage commodity, currency and financial market risks. The extent of our derivative position at any given time depends on our assessments of the markets for these commodities and related exposures. We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements. Such
valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile, which could have a significant adverse effect on our earnings reported under GAAP. For example, as described in Results of Operations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our net income for the year ended December 31, 2022 included $1.1 billion of losses resulting from changes in the fair values of our derivatives, of which substantially all of such losses 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 commodities exchanges or the failure of a counterparty to perform in accordance with a contract. As
of December 31, 2023 and 2022, we had collateral posted with counterparties by us of zero and $35 million, respectively, which are included in margin deposits in our Balance Sheets.
Catastrophic weather events or other disasters could result in an interruption of our operations,
a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us.
Weather events such as major hurricanes and winter storms have caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our facilities. In August 2020, we entered into an arrangement with our affiliate to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers from the other facility in the event operational conditions impact operations at the Sabine Pass LNG Terminal or at our affiliate’s terminal. During the year ended December 31, 2021, eight TBtu was loaded at affiliate facilities pursuant to this agreement. Our risk of loss related to weather events or other disasters
is limited by contractual provisions in our SPAs, which can provide under certain circumstances relief from operational events, and partially mitigated by insurance we maintain. Aggregate direct and indirect losses associated with the aforementioned weather events, net of insurance reimbursements, have not historically been material to our Financial Statements, and we believe our insurance coverages maintained, existence of certain protective clauses within our SPAs and other risk management strategies mitigate our exposure to material losses. However, future adverse weather events and collateral effects, or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or interruption of operations at our terminal or related infrastructure, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of our other facilities. Our
LNG terminal infrastructure and LNG facility located in or near Sabine Pass, Louisiana are designed in accordance with requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards, and all applicable industry codes and standards.
Disruptions to the third party supply of natural gas to our facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We depend upon third party pipelines and other facilities that provide gas delivery options to our Liquefaction Project. If any pipeline connection were to become unavailable
for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be adversely impacted. Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the risk factor Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result
of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified
times. The supply of natural gas to our Liquefaction Project to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including 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 facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in
part mitigated by the diversification of our natural gas supply and transportation across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the criticality of natural gas supply to our production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected could have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.
The operation of the Liquefaction Project is, and will be, subject to the inherent risks associated with this type of operation as discussed throughout our risk factors, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes
and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. Although losses incurred as a result of self- insured risk have not been material historically, the occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the
following factors:
•competitive liquefaction capacity in North America;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;
•reduced demand and lower prices for natural gas;
•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•decreased
oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
•cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding exported LNG, natural gas or alternative energy sources, which may reduce the demand for exported LNG and/or natural gas;
•political conditions in customer regions;
•sudden
decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;
•adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect our business and the performance of our customers, and could have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
Failure of exported LNG to be a long term competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the Liquefaction Project are dependent upon the
ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from the United States and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries
and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or from our competitors’ liquefaction facilities in the United States.
As described in Market Factors and Competition, 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 Market Factors and Competition, we have contracted through our SPAs and IPM agreement approximately 85% of the total
anticipated production from the Liquefaction Project with approximately 14 years of weighted average remaining life as of December 31, 2023, 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 party pipelines which supply the Liquefaction Project, could negatively impact our operations, result in data security breaches,
impede the processing of transactions, or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
The LNG industry is increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our liquefaction operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third
party pipelines which supply natural gas to our Liquefaction Project. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should multiple of the third party pipelines which supply our Liquefaction Project suffer similar concurrent attacks, the 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 party pipelines with which we do business, could negatively impact our operations, result in data security breaches, impede the processing of transactions, or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and
liquidity.
Outbreaks of infectious diseases, such as COVID-19, at our facilities could adversely affect our operations.
Our facilities at the Liquefaction Project are critical infrastructure and continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including subsequent variants, had no adverse impact on our on-going operations, the risk of future variants and other infectious diseases is unknown. While we believe we can continue to mitigate any significant adverse impact to our employees and operations at our critical facilities related to the virus in its current form, the outbreak of a more potent variant or another infectious
disease in the future at one or more of our facilities could adversely affect our operations.
We are entirely dependent on Cheniere and CQP for key personnel, and the unavailability of skilled workers or Cheniere or CQP’s failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our key personnel could affect our business results.
As of December 31, 2023, Cheniere and its subsidiaries had 1,605 full-time employees, including 501 employees who directly supported the Liquefaction Project and the remaining facilities at the Sabine Pass LNG Terminal. We have contracted with subsidiaries
of Cheniere and CQP to provide the personnel necessary for the operation, maintenance and management of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. 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 construct and operate our facilities and to provide our customers with the highest quality service. We also compete with any other projects Cheniere is operating, including its liquefaction project near Corpus Christi, Texas, for the time and expertise of Cheniere’s personnel. Further, Cheniere faces competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project
and more generally from the Gulf Coast hydrocarbon processing and construction industries.
Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our future success will depend in part on our ability to engage, and Cheniere’s ability to attract and retain, additional qualified personnel.
A shortage in the labor pool of skilled workers, remoteness of our
site locations, general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. In addition, we are also subject to increased competition for skilled workers from new entrants to the LNG market. Any increase in our
operating costs could materially and adversely affect our business, contracts, financial condition,
operating results, cash flow, liquidity and prospects.
We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.
We have agreements to compensate and to reimburse expenses of Cheniere’s affiliates. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently operating three Trains and constructing or developing expansion projects at a natural gas liquefaction facility near Corpus Christi, Texas through its subsidiaries, and CCL has entered into fixed price SPAs with third-parties for the sale of LNG from this natural
gas liquefaction facility, and may continue to enter into commercial arrangements with respect to this liquefaction facility that might otherwise have been entered into with respect to any of our future Trains.
We have or will have numerous contracts and commercial arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements, as well as servicing and other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest may be involved.
We
are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.
Risks Relating to Regulations
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of the Liquefaction Project and the export of LNG could impede operations and construction and could have
a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The design, construction and operation of the Liquefaction Project and the Expansion Project, as well as the export of LNG are highly regulated activities. Approvals of the FERC and DOE under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and export LNG. To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the Liquefaction Project. In May 2023, we and another subsidiary of CQP entered the pre-filing
review process with the FERC under the NEPA for the Expansion Project. To date, the DOE has also issued orders under Section 4 of the NGA authorizing us to export domestically produced LNG. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations. We do not believe such a pause will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity. We have no projects pending non-FTA export approval with the DOE at this time, although we would anticipate seeking non-FTA export authorization from the DOE on the SPL Expansion Project in the future, having entered the pre-filing review process with the FERC in May 2023.
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.
Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management,
natural resources, and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our terminal, including 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. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that will apply to our facilities beginning in calendar year 2024. In January 2024, the EPA issued a proposed rule to impose and collect methane emissions charges authorized under the IRA. In addition, other international, federal and state initiatives may be considered in the future to address GHG emissions through treaty commitments, direct regulation, market-based regulations such as a GHG emissions tax or cap-and-trade programs or clean energy or performance-based standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our Liquefaction Project, or could increase compliance costs for our operations.
Revised,
reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.
On February 28, 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 by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by such regulatory actions.
Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from the Sabine Pass LNG Terminal or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national climate change-related policies, could cause additional expenditures, restrictions
and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.
Total expenditures related to environmental and similar laws and governmental regulations, including capital expenditures, were immaterial to our Financial Statements for the years ended December 31, 2023, 2022 and 2021. 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.
Cyberattacks
represent a potentially significant risk to the Company and our industry. We rely on subsidiaries of Cheniere, through our service agreements with them, as further discussed in Note 12—Related Party Transactions of our Notes to Financial Statements, and the board of directors of CQP’s general partner (the “Board”), which has oversight of our operations, to implement policies and procedures that are intended to manage and reduce this risk.
Risk Management and Strategy
As
part of its broader approach to risk management, Cheniere’s cybersecurity program is designed to follow an “identify, protect, detect, respond and recover” approach to cybersecurity that is based off of the National Institute of Standards and Technology Cybersecurity Framework (“CSF”). Cheniere’s strategy also includes segmentation of corporate and operations networks, defense in depth and the least privileged access principle. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, Cheniere routinely evaluates opportunities to refine its cybersecurity program in order to mitigate operational network risks. Cheniere includes business continuity planning as a component of its strategy to help ensure critical systems are available to support the
Company in the instance of a disruptive event. Cheniere also participates in various industry organizations to stay abreast of recent trends and developments.
On an ongoing basis, Cheniere assesses its people, processes and technology and, when necessary, adjusts the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. Cheniere conducts regular assessments and audits, cross-functional risk mitigation exercises and risk strategy sessions to identify cybersecurity risks, applicable regulatory requirements and industry standards. These engagements are also designed to exercise, assess the maturity of and enhance Cheniere’s Cyber Incident Response Plan. To support these efforts, Cheniere has contracted with third parties to perform facility and system penetration tests, compromise assessments of IT systems, and security maturity assessments of its corporate and operational networks. Cheniere
maintains a training program to help its personnel identify and assist in mitigating cybersecurity and data security risks. Cheniere’s employees and the members of the Board participate in annual training, user awareness campaigns and additional issue-specific training as needed. Cheniere also provides annual training for certain contractors who have access to its information technology networks.
With respect to third party service providers, Cheniere’s information security program includes conducting risk-based due diligence of certain service providers’ information security programs prior to onboarding. Cheniere strives to contractually require third party service providers with access to its information technology systems, sensitive business data or personal information to maintain reasonable security controls and restrict their ability to use Cheniere’s data, including personal
information, for purposes other than to provide services to them, except as required by applicable law. Cheniere also strives to negotiate contractual requirements which compel its service providers to notify them of information security incidents occurring on their systems which may affect Cheniere’s systems or data, including personal information.
During the year ended December 31, 2023, 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 (“CISO”),
Vice President and Chief Information Officer and Senior Vice President of Shared Services. These individuals collectively provide the strategic oversight of Cheniere’s cybersecurity governance, cyber risk management and security operations and are responsible for maintaining Cheniere’s technology defense posture and program. 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. Cheniere’s CISO’s experience includes assessing risks, implementing governance programs, and responding to threats in oil and gas, electric and natural gas utilities and nuclear power generation companies. He maintains a Certified Information Security Manager certification from ISACA, secret clearance from
the Department of Homeland Security and has played an active role in the development of various cybersecurity standards including the CSF.
Risks that could affect us are an integral part of Board and Audit Committee deliberations throughout the year. The Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management’s plan for mitigating these risks, while the Audit Committee of the Board has been delegated the authority to oversee and periodically review the security of CQP’s information technology systems and controls, including programs and defenses against cybersecurity threats. The Audit Committee discusses with the management of CQP’s general partner its cybersecurity risk exposures and the steps management has
taken to mitigate such exposures, including risk assessment and risk management policies. On a quarterly basis, Cheniere’s cybersecurity leadership team updates the Audit Committee on the overall status of its cybersecurity program, key operational metrics, current assessments, cybersecurity issues or events and pertinent events related to cybersecurity.
For additional information about cybersecurity risks, see the risk A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Project, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting under Risks
Relating to Our Operations and Industry in Item 1A.Risk Factors.
ITEM 3. LEGAL PROCEEDINGS
We 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
We and another subsidiary of CQP are in discussions with the LDEQ to resolve alleged non-compliance with national emission standards for formaldehyde
from combustion turbines at the Sabine Pass LNG Terminal. The allegations are identified in a Consolidated Compliance Order and Notice of Potential Penalty, Tracking No. AE-CN-22-00833 (the “2023 Compliance Order”) issued by the LDEQ on April 12, 2023. In August 2004, the EPA stayed the application of the emission standard to combustion turbines such as those at the Sabine Pass LNG Terminal. In March 2022, the EPA lifted the stay, and in June 2022, we and the other subsidiary of CQP petitioned the EPA and LDEQ for approval of additional operating parameters to demonstrate compliance with the emission limitation. The petition remains pending. We and the other subsidiary of CQP continue to work with the LDEQ to resolve the matters identified in the 2023 Compliance Order, including the petition pending with the EPA. As of December 2023, we and the other subsidiary
of CQP have filed test results with the LDEQ indicating that all 44 turbines meet the relevant compliance standard. We do not expect that any ultimate penalty will have a material adverse impact on our financial results.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Not applicable.
ITEM 6. [Reserved]
ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Discussion of 2021 items and variance drivers between the year ended December 31, 2022 as compared to December 31, 2021 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, 2022.
Our discussion and analysis includes the following subjects:
We
are a limited liability company formed by CQP to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We own the natural gas liquefaction and export facility at Sabine Pass, Louisiana. For further discussion of our business, see Items 1. and 2. Business and Properties.
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Through our SPAs and IPM agreement, we have contracted approximately 85% of the total anticipated production from the Liquefaction Project with approximately 14 years of weighted average remaining life as of December 31,
2023. 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 portfolio of customer contracts in the future.
Our significant events since January 1, 2023 and through the filing date of this Form 10-K include the following:
Strategic
•In
May 2023, we and another subsidiary of CQP entered the pre-filing review process with the FERC under the NEPA for the Expansion Project, and in April 2023, the other CQP subsidiary executed a contract with Bechtel Energy Inc. to provide the front end engineering and design work on the project. This expansion is being developed and may be constructed by another subsidiary of CQP.
Operational
•As of February 16, 2024, approximately 2,410 cumulative LNG cargoes totaling approximately 165 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
Financial
•We
closed the following debt transactions:
◦In September and November 2023, we redeemed an aggregate of $100 million of our 5.750% Senior Secured Notes due 2024 (the “2024 Senior Notes”).
◦In July 2023, we redeemed $1.4 billion of aggregate principal amount outstanding of our 2024 Senior Notes using contributions received from CQP and cash on hand.
◦In June 2023, we entered into a $1.0 billion Senior Secured Revolving Credit and Guaranty Agreement (the “Revolving Credit Facility”). The Revolving Credit Facility refinanced and replaced our existing credit facility to, among other things, (1) extend the maturity date thereunder, (2) reduce the
rate of interest and commitment fees applicable thereunder and (3) make certain other changes to the terms and conditions of the prior credit facility.
•In August 2023, Fitch Ratings (“Fitch”) upgraded our senior secured debt and issuer credit ratings from BBB to BBB+ with a stable outlook.
•In February 2023, S&P Global Ratings (“S&P”) upgraded our issuer credit rating from BBB to BBB+ with a stable outlook.
Market Environment
In
2023, the LNG market continued to rebalance with robust LNG flows to Europe maintaining the region’s underground storage inventories at high levels, and weak demand in Japan and Korea largely offsetting a modest rebound in China and other emerging economies in Asia. Price levels started moving towards pre-Russia-Ukraine war levels in the second quarter of 2023 and have for the most part normalized versus pre-war levels, as concerns about physical market tightness dissipated. However, extensive upstream maintenance in Norway and concerns about tight supply capacity amid strike threats in Australia elevated prices during the third quarter of 2023 and brought some volatility back to the market, albeit not at much lower levels than those seen in 2022. These conditions were quickly resolved, and winter prices remained within a more normal level, despite the eruption of military conflict in the Middle East in October.
The
Dutch Title Transfer Facility (“TTF”) monthly settlement prices averaged $13.73/MMBtu in 2023, over 66% lower year-over-year and 4.6% lower than 2021. Similarly, the 2023 average settlement price for the Japan Korea Marker (“JKM”) decreased 53% year-over-year to an average of $16.13/MMBtu in 2023. Prices in the fourth quarter of 2023 also decreased, with TTF averaging $13.66/MMBtu and JKM $14.97/MMBtu - both significantly below levels seen in the previous two years. The Henry Hub benchmark also witnessed a similar year-over-year drop albeit from a much lower base. The Henry Hub average settlement price in 2023 was $2.74, down approximately 59% from $6.64/MMBtu in 2022 during the height of the energy crisis in Europe.
The U.S. played a significant role in balancing the global market in 2023, exporting approximately 86 million tonnes of LNG, a gain of approximately 13% from 2022, due in part to the return of Freeport LNG to operations. Exports from our Liquefaction Project reached approximately 30 million tonnes in aggregate, representing over 34% of total U.S. exports for the year, according to Kpler data.
Global LNG demand grew by approximately 3% from 2022, adding 10.5 million tonnes to the overall market. Although overall Asian demand has increased from 2022, weakness in Japan, mainly due to improved nuclear availability, along with continued gas demand destruction in Europe, especially in the residential sector, exerted downward pressure on the market and kept LNG and gas prices from increasing. Despite the decrease in Japanese
demand, which was down approximately 8% or 6 mtpa year-over-year, Asia’s LNG imports increased roughly 4% year-over-year in 2023 to approximately 263 mtpa. This uptick was largely due to an approximately 8.4 mtpa year-over-year growth in South and Southeast Asia’s demand and a modest rebound in China’s economy, which resulted in approximately 12% or 7.5 mtpa increase in LNG imports into the country. In Europe, despite continued declines in gas demand, LNG imports were flat year-over-year as pipeline flows from Russia to the EU remained low at 27 billion cubic meters (“Bcm”), down 36 Bcm or 57% year-over-year.
The market dynamics brought on by the need to displace and replace Russian gas into Europe in 2023 resulted in a notable uptick in long-term LNG contracting and a push for LNG project FIDs. Commercial activity in 2023 continued
to build on last year’s momentum with executed long-term SPAs in the U.S. reaching approximately 23 mtpa for the year, of which Cheniere’s SPAs and IPM agreements totaled approximately 6.5 mtpa. This contractual momentum over the past two years led to the positive FID of nearly 40 mtpa of U.S. LNG capacity in 2023, and we anticipate that a portion of these contracts will support our planned future growth.
Despite the global impacts of the Russia-Ukraine war, we do not believe we have significant exposure to adverse direct or indirect impacts of the war, as we do not conduct business in Russia and refrain from business dealings with Russian entities. Additionally, we are not aware of any specific adverse direct or indirect effects of the Russia-Ukraine war or the Israel-Hamas war on our supply
chain. Consequently, we believe we are well positioned to help meet the increased demand of our international LNG customers to overcome their supply shortages.
LNG
volumes loaded and recognized as revenues (in TBtu)
1,536
1,520
16
Net
income
The increase of $2.7 billion in net income between the years ended December 31, 2023 and 2022 was primarily attributable to the favorable variance of $3.2 billion from changes in fair value and settlements of derivatives. During the year ended December 31, 2023, we recognized a gain of $1.8 billion due to non-cash favorable changes in fair value of the IPM agreement with Tourmaline Oil Marketing Corp. (the “Tourmaline IPM Agreement”) as a result of lower volatility in international gas prices and declines in international forward commodity curves, as compared to a loss of $757 million in the year ended December 31, 2022 following
the assignment of the Tourmaline IPM Agreement to us from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”) in March 2022. The 2022 loss following the assignment was primarily attributed to our lower credit risk profile relative to that of CCL Stage III, resulting in a higher derivative liability given reduced risk of our own nonperformance and shifts in the international forward commodity curve. The increasewas partially offset by a reduction in LNG revenues, net of cost of sales and excluding the aforementioned effect of derivatives, of $499 million between the years ended December 31, 2023 and 2022, the majority of which was attributable to lower margins on LNG delivered.
The following is an additional discussion of the significant drivers of the variance in net income by line item:
Revenues
Substantially all of the $6.6 billion decrease between the years ended December 31, 2023 and 2022 was attributable to a $6.7 billion decrease from lower pricing per MMBtu as a result of decreased Henry Hub pricing.
Operating costs and expenses
The $9.2 billion decrease between the years ended December 31, 2023 and 2022
was attributable to:
•$6.1 billion decrease in cost of sales excluding the effect of derivative changes described below, primarily as a result of a $6.0 billion decrease in cost of natural gas feedstock largely due to lower U.S. natural gas prices; and
•$3.2 billion favorable variance from changes in fair value and settlements of derivatives included in cost of sales, from a loss of $1.2 billion in the year ended December 31, 2022 to a gain of $2.1 billion in the year ended December 31, 2023 primarily due to decreased international gas prices resulting in non-cash favorable changes in fair value of our commodity derivatives indexed to such prices, specifically associated with the Tourmaline IPM Agreement as discussed above under Net
income.
Significant factors affecting our results of operations
Below are significant factors that affect our results of operations.
Gains and losses on derivative instruments
Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risks and are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreement, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization
of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 7—Derivative Instruments of our Notes to Financial Statements, the fair value of our Liquefaction Supply Derivatives incorporates
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 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.
Commissioning cargoes
Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the year
ended December 31, 2022, we realized offsets to LNG terminal costs of $148 million corresponding to 13 TBtu attributable to the sale of commissioning cargoes from Train 6 of the Liquefaction Project. We did not have any commissioning cargoes during the year ended December 31, 2023.
The
following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facility. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
Restricted cash and cash equivalents designated for the Liquefaction Project
$
56
Revolving Credit Facility (1)
720
Total
available liquidity
$
776
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under the Revolving Credit Facility as of December 31, 2023. See Note 10—Debt
of our Notes to Financial Statements for additional information on the Revolving Credit Facility and other debt instruments.
Our liquidity position subsequent to December 31, 2023 will be driven by future sources of liquidity and future cash requirements as further discussed below.
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, 2023. 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 SPAs
As described in Items 1.and 2. Business and Properties, our long-term customer arrangements form the foundation of our business and provide
us with significant, stable, long-term cash flow. Substantially all of our future revenues are contracted under SPAs and because many of these contracts have long-term durations, we are contractually entitled to significant future consideration under these contracts which has not yet been recognized as revenue. This future consideration is, in most cases, not yet legally due to us and was not reflected on our Balance Sheets as of December 31, 2023. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources
of liquidity to be received from executed SPAs as of December 31, 2023 (in billions):
Estimated Revenues Under Executed SPAs by Period (1) (2)
2024
2025
- 2028
Thereafter
Total
LNG revenues (fixed fees)
$
3.9
$
14.1
$
31.0
$
49.0
LNG
revenues (variable fees) (3)
5.1
24.4
60.1
89.6
Total
$
9.0
$
38.5
$
91.1
$
138.6
(1)Agreements
in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the revenues above when the conditions are considered probable of being met.
(2)LNG
revenues (including $1.4 billion and $7.6 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises, in certain instances, their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.
(3)LNG
revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated forward prices and basis spreads as of December 31, 2023. The pricing structure of many of our SPA arrangements with our customers 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.
Through our SPAs and IPM agreement, we have contracted approximately 85% of the total anticipated production from the Liquefaction Project, with approximately 14 years of weighted average remaining life as
of December 31, 2023. The majority of the contracted capacity is comprised of fixed-price, long-term SPAs that we have executed with third parties to sell LNG from the Liquefaction Project. Under the SPAs, the 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. 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 variable fees under our SPAs were generally sized with the intention to cover the costs of gas
purchases, transportation and liquefaction fuel consumed to produce the LNG to be sold under each such SPA. In aggregate, the annual fixed fee portion to be paid by the third party SPA customers is approximately $3.4 billion. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A, A2 and A by S&P Global Ratings, Moody’s and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 11—Revenues of our Notes to Financial Statements.
In addition to the third party SPAs discussed above, we have executed agreements with Cheniere Marketing under SPAs and letter agreements at a price equal to 115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement
for which pricing is linked to international natural gas prices.
In August 2020, we entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event certain conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.
Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As
of December 31, 2023, we had $720 million in available commitments under the Revolving Credit Facility, subject to compliance with the applicable covenants, to potentially meet liquidity needs. The Revolving Credit Facility matures in 2028.
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, 2023 (in billions):
Estimated Payments Due Under Executed Contracts by Period (1)
2024
2025
- 2028
Thereafter
Total
Purchase obligations (2):
Natural gas supply agreements (3)
$
3.5
$
10.0
$
5.2
$
18.7
Natural
gas transportation and storage service agreements (4)
0.4
1.3
2.8
4.5
Other
purchase obligations (5)
0.5
1.9
3.0
5.4
Total
$
4.4
$
13.2
$
11.0
$
28.6
(1)Agreements
in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023.
(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)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of our IPM agreement is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Includes $0.8 billion under natural gas supply agreements with unsatisfied contractual conditions.
(4)Includes $1.0 billion of purchase obligations to affiliates and $0.2 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements.
(5)Includes
$3.4 billion of purchase obligations to affiliates under the TUA and $1.1 billion of purchase obligations to affiliates under services agreements, as well as payments under our partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), as discussed in Note 12—Related Party Transactions of our Notes to Financial Statements.
Natural Gas Supply, Transportation and Storage Service Agreements
We have secured natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements, including an IPM agreement. Under our IPM agreement, we pay for natural gas feedstock based on global
gas market prices less fixed liquefaction fees and certain costs incurred by us. While our IPM agreement is not a revenue contract for accounting purposes, the payment structure for the purchase of natural gas under the IPM agreement generates a take-or-pay style fixed liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global gas market price paid for the natural gas feedstock purchase.
As of December 31, 2023, we have secured approximately 77% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2024. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2024. Natural
gas supply is generally secured on an indexed pricing basis plus a fixed fee, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers 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. Inclusive of amounts under contracts with unsatisfied contractual conditions that are currently considered probable of being met and exclusive of extension options that were uncertain to be taken as of December 31, 2023, we have secured up to 5,169 TBtu of natural gas feedstock through agreements with remaining fixed terms of up to approximately
15 years. A discussion of our natural gas supply and IPM agreements can be found in Note 7—Derivative Instruments of our Notes to Financial Statements.
To ensure that we are able to transport natural gas feedstock to the Sabine Pass LNG Terminal, we have entered into firm pipeline transportation and other agreements to secure firm pipeline transportation capacity from CTPL, a wholly owned subsidiary of CQP, 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 Financially Disciplined Growth section for further discussion.
Terminal Use Agreements
We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for unloading, loading, storage and regasification of LNG. Full discussion of our TUA agreement can be found in Note
12—Related Party Transactions of our Notes to Financial Statements.
Additionally, we have entered into a partial TUA assignment agreement with TotalEnergies, another TUA customer, whereby upon substantial completion of Train 5 of the Liquefaction Project, we gained access to substantially all of
TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG Terminal that may be used to provide
increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG storage capacity. Full discussion of our partial TUA assignment with TotalEnergies can be found in Note 13—Commitments and Contingencies of our Notes to Financial Statements.
Additional Future Cash Requirements for Operations and Capital Expenditures
Operational Services
We do not have any employees, and thus have contracts with subsidiaries
of Cheniere and CQP for operations, maintenance and management services. As of December 31, 2023, Cheniere and its subsidiaries had 1,605 full-time employees, including 501 employees who directly supported the Liquefaction Project. Full discussion of our operations, maintenance and management agreements can be found in Note 12—Related Party Transactions of our Notes to Financial Statements.
Financially Disciplined Growth
Our significant land position at the Sabine Pass LNG Terminal provides potential development and investment
opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. We expect that any future expansion at the Sabine Pass LNG Terminal would increase cash requirements to support expanded operations, 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, 2023 (in billions):
Estimated Payments Due Under Executed Contracts by Period
(1)
2024
2025 - 2028
Thereafter
Total
Debt
$
0.3
$
6.7
$
3.4
$
10.4
Interest
payments
0.6
1.2
0.5
2.3
Total
$
0.9
$
7.9
$
3.9
$
12.7
(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, 2023. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity. See further discussion in Note 10—Debt of our Notes to Financial Statements.
Debt
As of December 31, 2023, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $10.4 billion and the Revolving Credit Facility with no outstanding
loan balances. As of December 31, 2023, we were in compliance with all covenants related to our debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10—Debt of our Notes to Financial Statements.
Interest
As of December 31, 2023, our senior notes had a weighted average contractual interest rate of 5.02%. Borrowings under the Revolving Credit Facility are indexed to SOFR. Undrawn commitments
under the Revolving Credit Facility are subject to commitment fees ranging from 0.075% to 0.30%, subject to change based on our credit rating. Issued letters of credit under the Revolving Credit Facility are subject to letter of credit fees ranging from 1.00% to 1.750%, subject to change based on our credit rating. We had $280 million aggregate amount of issued letters of credit under the Revolving Credit Facility as of December 31, 2023.
In September 2022, the board of directors of Cheniere approved a revised long-term capital allocation plan, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of debt, including our senior notes.
Sources and Uses of Cash
The following table summarizes the sources and uses of our restricted cash and cash equivalents (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion
of these items follows the table.
Net
decrease in restricted cash and cash equivalents
$
(36)
$
(6)
Operating Cash Flows
The $147 million decrease between
the periods was primarily related to lower cash receipts from the sale of LNG cargoes from lower pricing per MMBtu as a result of decreased Henry Hub pricing, which was partially offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.
Investing Cash Flows
Cash outflows for property, plant and equipment during the year ended December 31, 2023 were primarily related to optimization and other site improvement projects. Cash outflows for property, plant and equipment during the year ended December 31, 2022 were primarily related to the construction costs for Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022,
and the construction of the third marine berth at the Liquefaction Project, which achieved substantial completion on October 27, 2022 and which we immediately conveyed to SPLNG.
Financing Cash Flows
During the years ended December 31, 2023 and 2022, we made distributions to CQP of $2.2 billion and $1.8 billion, respectively. During the year ended December 31, 2023, we received $1.2 billion of contributions from CQP, which were used with cash on hand to redeem $1.4 billion of the 2024 Senior Notes. Additionally, during the
year ended December 31, 2023, we purchased $200 million of the 2024 SPL Senior Notes in the open market and redeemed an additional $100 million of the 2024 Senior Notes, which leaves only $300 million to be repaid for debt maturing in 2024. During the year ended December 31, 2022, we issued an aggregate principal amount of $430 million of 5.900% Senior Secured Amortizing Notes due 2037 and $70 million of 2037 SPL Private Placement Senior Secured Notes. The proceeds of these issuances, together with cash on hand, were used to redeem $1.5 billion in aggregate principal amount of 2023 Senior Notes. Additionally, during the year ended December 31, 2022, we had borrowings and repayments of $60 million on our previous working capital facility.
Summary
of Critical Accounting Estimates
The preparation of our Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.
Fair Value of Level 3 Physical Liquefaction Supply Derivatives
All of our derivative instruments are recorded at fair value, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements. We record changes in the fair value of our derivative positions through earnings based on the value for which the derivative instrument could be exchanged between willing parties. Valuation of our physical liquefaction supply derivative contracts is often developed through the use of internal models which includes significant unobservable inputs representing Level 3 fair value measurements
as further described in Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability.To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value.In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data.Changes in facts and circumstances or additional information
may result in revised estimates and judgments, and actual results may differ from these estimates and judgments.We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing.Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational
impacts to global energy infrastructure.Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.
Our fair value estimates incorporate market participant-based assumptions pertaining to applicable contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations
if and when such uncertainties are resolved.
Additionally, the valuation of certain physical 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, 2023 and 2022 (in millions), which entirely consisted of physical liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the end of each respective period.
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period
$
1,318
$
(1,032)
The
changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our Tourmaline IPM Agreement during the years ended December 31, 2023 and 2022.
The estimated fair value of level 3 derivatives recognized in our Balance Sheets as of December 31, 2023 and 2022 amounted to a liability of $1.7 billion and $3.7 billion, respectively, consisting entirely of physical liquefaction supply derivatives.
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 given the level of volatility in the current year. 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.
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
We
have commodity derivatives consisting of natural gas supply contracts for the operation of the Liquefaction Project (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):
MANAGEMENT’S REPORT TO THE MEMBER OF SABINE PASS LIQUEFACTION, LLC
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Sabine Pass Liquefaction, LLC (“Sabine Pass Liquefaction”). In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(“COSO”). Sabine Pass Liquefaction’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
Based on our assessment, we have concluded that Sabine Pass Liquefaction maintained effective internal control over financial reporting as of December 31, 2023, based on criteria in
Internal Control—Integrated Framework (2013) issued by the COSO.
This annual report does not include an attestation report of Sabine Pass Liquefaction’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Sabine Pass Liquefaction’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
Management’s Certifications
The certifications of Sabine Pass Liquefaction’s Principal Executive
Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Sabine Pass Liquefaction’s Form 10-K.
Report of Independent Registered Public Accounting Firm
To the Member of Sabine Pass Liquefaction, LLC and
Board of Directors of Cheniere Energy Partners GP, LLC
Sabine Pass Liquefaction, LLC:
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Sabine Pass Liquefaction, LLC (the Company) as of December 31, 2023 and 2022, the related statements of income, member’s equity (deficit), and cash flows for each of the years in the
three-year period ended December 31, 2023, and the related notes (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the
Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor
were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Fair value of the level 3 liquefaction
supply derivatives
As discussed in Notes 2 and 7 to the financial statements, the Company recorded fair value of level 3 liquefaction supply derivatives of $(1,676) million as of December 31, 2023, which included the fair value of the IPM agreement. The IPM agreement is a natural gas supply contract for the operation of the liquefied natural gas facilities. The fair value of the IPM agreement is developed using internal models, including option pricing models. The models incorporate significant unobservable inputs, including future prices of energy units in unobservable periods and volatility.
We identified the evaluation of the fair value of the level
3 liquefaction supply derivatives for the IPM agreement as a critical audit matter. Specifically, complex auditor judgment and specialized skills and knowledge were required to evaluate the appropriateness and application of the option pricing model as well as the assumptions for future prices of energy units in unobservable periods and volatility.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the valuation of liquefaction supply derivatives, including those under the IPM agreement. This included controls related to the appropriateness and application of the
option pricing model and the evaluation of assumptions for future prices of energy units in unobservable periods and volatility. We involved valuation professionals with specialized skills and knowledge who assisted in testing management’s process for developing the fair value of the IPM agreement by:
•evaluating the design and testing the operating effectiveness of certain internal controls related to the appropriateness and application of the option pricing model
•evaluating the appropriateness and application of the option pricing model by inspecting the contractual agreements and model documentation to determine whether the model is suitable for its intended use
•evaluating the reasonableness of
management’s assumptions for future prices of energy units in unobservable periods and volatility by comparing to market data.
We are a Delaware limited liability company formed by CQP and based in Houston with ione member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of CQP. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of CQP, a publicly traded limited partnership (NYSE MKT: CQP). CQP is a i48.6%
owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses. Cheniere also owns i100% of the general partner interest in CQP through ownership in Cheniere Energy Partners GP, LLC.
The natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”)
has isix operational Trains, for a total production capacity of approximately i30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities owned by SPLNG.
Another
subsidiary of CQP is pursuing a certain expansion project to provide additional liquefaction capacity at the Sabine Pass LNG Terminal, and it has commenced commercialization to support the additional liquefaction capacity associated with this expansion project.
We do not have employees and thus we have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. See Note 12—Related Party Transactions for additional
details of the activity under these services agreements during the years ended December 31, 2023, 2022 and 2021.
We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss included in the federal income tax return of CQP, a publicly traded partnership which indirectly owns us. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP taxable income. Accordingly, iiino//
provision or liability for federal or state income taxes is included in the accompanying Financial Statements. At December 31, 2023, the tax basis of our assets and liabilities was $i7.8 billion less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our tax sharing agreement.
NOTE 2—iSUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
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Basis of Presentation
Our Financial Statements have been prepared in accordance with GAAP.
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Estimates
The
preparation of our Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment and certain valuations including asset retirement obligations (“AROs”), each as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
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Fair
Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific
details that, in management’s judgment, market
participants would take into account in measuring fair value. We attempt to maximize our use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for derivative instruments, as disclosed in Note
7—Derivative Instruments.
The carrying amount of restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, contract assets, margin deposits, accounts payable and accrued liabilities reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Refer to Note 10—Debt for our debt fair value estimates, including our estimation
methods.
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Revenue Recognition
We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 11—Revenues for further discussion of our revenue streams and accounting policies related to revenue recognition.
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Restricted
Cash and Cash Equivalents
Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
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Inventory
LNG and natural gas inventory are recorded at the
lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.
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Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major
renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.
Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with preliminary review and selection of equipment alternatives, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train.
Generally,
costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets.
We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.
We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives. Refer to Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation for
additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in other operating costs and expenses.
Management tests property, plant and equipment for impairment
whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.
We did iiinot//
record any material impairments related to property, plant and equipment during the years ended December 31, 2023, 2022 and 2021.
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Advances of Cash and Conveyed Assets to Service Providers
We may convey cash or physical assets to service providers in support of infrastructure maintained by them, which is necessary to support our own operations. Such conveyances
are recognized within other non-current assets on our Balance Sheets and amortized within depreciation and amortization expense on our Statements of Income over the shorter of the contractual term of the arrangement with the service provider or the useful life of the physical asset. The weighted average amortization period of these assets was approximately ii30/
years as of both December 31, 2023 and 2022.
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Interest Capitalization
We capitalize interest costs mainly during the construction period of our LNG terminal and related assets. Upon placing the underlying asset in service, these costs are depreciated over the estimated useful life of the corresponding assets which interest costs were incurred, except for capitalized interest associated with land, which
is not depreciated.
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Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis.
Changes
in the fair value of our derivative instruments are recorded in earnings. We did iiinot//
have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2023, 2022 and 2021. See Note 7—Derivative Instruments for additional details about our derivative instruments.
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Concentration of Credit Risk
Financial
instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable and contract assets related to our long-term SPAs, as discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have inot incurred credit losses related to these cash balances to date.
The
use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within margin deposits on our Balance Sheets. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties
not perform, we may not realize the benefit of some of our derivative instruments.
As of December 31, 2023, we had SPAs with initial terms of i10
or more years with a total of i11 different third party customers and had agreements with Cheniere Marketing. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.
Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with
certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.
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Debt
Our
debt consists of current and long-term secured and unsecured debt securities and a credit facility with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.
Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded
in interest expense, net of capitalized interest using the effective interest method.
We classify debt on our Balance Sheets based on contractual maturity, with the following exceptions:
•We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.
•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.
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Asset
Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
We have inot
recorded an ARO associated with the Sabine Pass LNG Terminal. Based on the real property lease agreements at the Sabine Pass LNG Terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG Terminal have terms of up to i90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG Terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.
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Business
Segment
We have determined that we operate as a single operating and reportable segment. Substantially all of our long-lived assets are located in the United States. Our chief operating decision maker is regularly provided with our financial information to makes resource allocation decisions and assesses performance in the delivery of an integrated source of LNG to our
customers. The
financial measures regularly provided to the chief operating decision maker that are most consistent with GAAP are net income (loss) and total assets, as presented in our Financial Statements.
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Recent Accounting Standards
ASU 2020-04
In March 2020, the FASB issued ASU No. 2020-04, Reference
Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.
As further detailed in Note 10—Debt,
our existing credit facility includes a variable interest rate indexed to SOFR, incorporated through a replacement of the previous credit facility subsequent to the effective date of ASU 2020-04. We elected to apply the optional expedients as applicable; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.
ASU 2023-07
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280). This guidance requires a public entity, including entities with single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit
or loss and assets that are currently required annually. We plan to adopt this guidance and conform with the applicable disclosures retrospectively when it becomes mandatorily effective for our annual report for the year ending December 31, 2024.
NOTE 3—iRESTRICTED CASH AND CASH EQUIVALENTS
As
of December 31, 2023 and 2022, we had $i56 million and $i92 million
of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is contractually or legally restricted to the payment of liabilities related to the Liquefaction Project as required under certain debt arrangements.
NOTE 4—iTRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES
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Trade
and other receivables, net of current expected credit losses, consisted of the following (in millions):
(1)We
recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.
LNG Terminal Costs
LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. iThe
identifiable components of the Liquefaction Project have depreciable lives between i6 and i50 years, as follows:/
Components
Useful
life (years)
Water pipelines
i30
Liquefaction processing equipment
i6-i50
Other
i10-i30
Fixed
Assets
Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.
NOTE 7—iDERIVATIVE INSTRUMENTS
We have commodity derivatives consisting of natural gas supply
contracts, including those under our IPM agreements, for the operation of the Liquefaction Project and expansion project, as well as the associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. iNone of our derivative
instruments are designated as cash flow, fair value or net investment hedging instruments, and changes in fair value are recorded within our Statements of Income to the extent not utilized for the commissioning process, in which case such changes are capitalized.
The
following table shows the fair value of our derivative instruments, which are required to be measured at fair value on a recurring basis, by the fair value hierarchy levels prescribed by GAAP (in millions):
We
value our Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, which incorporates observable commodity price curves, when available, and other relevant data.
We include a significant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk
related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.
In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly
mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility includes the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control. Our fair value estimates incorporate market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of 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.
The
Level 3 fair value measurements of our natural gas positions within our Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. iThe following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of December 31, 2023:
Net
Fair Value Liability
(in millions)
Valuation Approach
Significant Unobservable Input
Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives
$(i1,676)
Market
approach incorporating present value techniques
Henry Hub basis spread
$(i0.483) - $i0.423 / $i0.014
Option
pricing model
International LNG pricing spread, relative to Henry Hub (2)
i113% - i379% / i226%
(1)Unobservable
inputs were weighted by the relative fair value of the instruments.
(2)Spread contemplates U.S. dollar-denominated pricing.
Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of our Liquefaction Supply Derivatives.
Realized
and change in fair value gains (losses) included in net income (1):
Included in cost of sales, existing deals (2)
i1,302
(i228)
i74
Included
in cost of sales, new deals (3)
i16
(i804)
i—
Purchases
and settlements:
Purchases (4)
i—
(i2,712)
(i10)
Settlements
(5)
i724
(i13)
(i5)
Transfers
out of level 3 (6)
i1
i—
i—
Balance,
end of period
$
(i1,676)
$
(i3,719)
$
i38
Favorable
(unfavorable) changes in fair value relating to instruments still held at the end of the period
$
i1,318
$
(i1,032)
$
i74
(1)Does
not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.
(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.
(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts
acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. For further discussion of the IPM agreement that was novated to us in 2022, see Note 15—Supplemental Cash Flow Information.
(5)Roll-off in the current period of amounts recognized in our Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.
(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.
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All
counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value
measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.
Liquefaction Supply Derivatives
We hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of December 31, 2023, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately i14
years, some of which commence upon the satisfaction of certain events or states of affairs.
The forward notional amount for our Liquefaction Supply Derivatives was approximately i5,478 TBtu and i5,972
TBtu as of December 31, 2023 and 2022, respectively, inclusive of amounts under contracts with unsatisfied contractual conditions, and exclusive of extension options that were uncertain to be taken as of December 31, 2023.
(1)Does
not include the realized value associated with Liquefaction Supply Derivatives that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
Fair Value and Location of Derivative Assets and Liabilities on the Balance Sheets
iThe
following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions):
(1)Does
not include collateral posted by counterparties to us of $i4 million as of December 31, 2023, which is included in other current liabilities on our Balance Sheets, and collateral posted with counterparties by us of $i35 million
as of December 31, 2022, which is included in margin deposits on our Balance Sheets.
Balance Sheets Presentation
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The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions) for our derivative instruments that are presented on a net basis on our Balance Sheets:
Working
capital revolving credit and letter of credit reimbursement agreement (the “Working Capital Facility”)
i—
i—
Revolving
credit and guaranty agreement (the “Revolving Credit Facility”)
i—
i—
Total
debt
i10,432
i12,132
Current
debt, net of discount and debt issuance costs
(i300)
i—
Long-term
portion of unamortized discount and debt issuance costs, net
(i69)
(i92)
Total
long-term debt, net of discount and debt issuance costs
$
i10,063
$
i12,040
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Senior
Secured Notes
The Senior Secured Notes are our senior secured obligations, ranking equally in right of payment with our other existing and future senior debt that is secured by the same collateral and senior in right of payment to any of its future subordinated debt. Subject to permitted liens, the Senior Secured Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in us and substantially all of our assets. We may, at any time, redeem all or part of the Senior Secured Notes at specified prices set forth in the respective indentures governing the Senior Secured Notes, plus accrued and
unpaid interest, if any, to the date of redemption. The series of Senior Secured Notes due in 2037 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.
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Below is a schedule of future principal
payments that we are obligated to make on our outstanding debt at December 31, 2023 (in millions):
Years Ending December 31,
Principal Payments
2024
$
i300
2025
i2,052
2026
i1,607
2027
i1,612
2028
i1,468
Thereafter
i3,393
Total
$
i10,432
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Revolving
Credit Facility
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Below is a summary of our Revolving Credit Facility as of December 31, 2023 (in millions):
Revolving Credit Facility (1)(2)
Total
facility size
$
i1,000
Less:
Outstanding balance
i—
Letters
of credit issued
i280
Available commitment
$
i720
Priority
ranking
Senior secured
Interest rate on available balance (3)
SOFR plus credit spread adjustment of i0.1%, plus margin of i1.0%
- i1.75% or base rate plus i0.0% - i0.75%
(1)In June 2023, we refinanced and replaced the Working Capital Facility with the Revolving Credit Facility, resulting in an extended maturity date, revised borrowing capacity, reduced rate of interest and commitment fees applicable thereunder
and certain other changes to terms and conditions.
(2)The obligations of SPL under the SPL Revolving Credit Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on a pari passu basis by a first priority lien with the SPL Senior Secured Notes. The SPL Revolving Credit Facility contains customary contractual conditions for extensions of credit.
(3)The margin on the interest rate and the commitment fees is subject to change based on our credit rating.
/
Restrictive
Debt Covenants
The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit our ability to make certain investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least i1.25:1.00
is satisfied.
As of December 31, 2023, we were in compliance with all covenants related to our debt agreements.
(1)As
of both December 31, 2023 and 2022, $ii1.3/ billion
of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.
/
The estimated fair value of our Working Capital Facility as of December 31, 2022 and our Revolving Credit Facility as of December 31, 2023 approximated the principal amount outstanding because the interest rates are variable and reflective
of market rates and the debt may be repaid, in full or in part, at any time without penalty.
NOTE 11—iREVENUES
i
The
following table represents a disaggregation of revenue earned (in millions):
We have entered into numerous SPAs with third party customers for the sale of LNG on an FOB basis (delivered to the customer at the Sabine Pass LNG Terminal). Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus
a variable fee per MMBtu of LNG generally equal to i115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere
Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 12—Related Party Transactions for additional information regarding these agreements.
Revenues from the sale of LNG are recognized at a point in
time when the LNG is delivered to the customer, at the Sabine Pass LNG Terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts
is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price.
Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.
Sales of natural gas where, in the delivery of the natural gas to the end customer, we have concluded that we acted as a principal
are presented within revenues in our Statements of Income, and where we have concluded that we acted as an agent are netted within cost of sales in our Statements of Income.
The following table shows our contract
assets, net of current expected credit losses, which are classified as other current assets, net and other non-current assets, net on our Balance Sheets (in millions):
Contract
assets, net of current expected credit losses
$
i1
$
i1
/
Contract
assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due.
i
The following table reflects the changes in our contract liabilities, which we classify as deferred revenue and other non-current liabilities on our Balance Sheets (in millions):
The
following table reflects the changes in our contract liabilities to affiliate, which we classify as other non-current liabilities—affiliate on our Balance Sheets (in millions):
We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes
in deferred revenue during the years ended December 31, 2023 and 2022 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.
Transaction Price Allocated to Future Performance Obligations
Because
many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. iThe following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied:
(1)The
weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
(2)We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met and consideration
is not otherwise constrained from ultimate pricing and receipt.
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation
when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of the underlying variable index, primarily Henry Hub, throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Additionally, we have excluded variable consideration related to volumes that contractually
are subject to additional liquefaction capacity beyond what is currently in construction or operation. iThe following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:
Below
is a summary of our transactions with our affiliates and other related parties, all in the ordinary course of business, as reported on our Statements of Income (in millions):
SPAs and Letter Agreements with Cheniere Marketing (1)
$
i2,472
$
i4,565
$
i1,453
Contracts
for Sale and Purchase of Natural Gas and LNG with other affiliates (2)
i3
i3
i19
Total
LNG revenues—affiliate
i2,475
i4,568
i1,472
LNG
revenues—related party
Natural Gas Transportation and Storage Agreements (3)
i—
i—
i1
Cost
of sales—affiliate
Cheniere Marketing Agreements (1)
i—
i—
i34
Cargo
loading fees under TUA (4)
i51
i51
i43
Contracts
for Sale and Purchase of Natural Gas and LNG (2)
i25
i211
i51
Total
cost of sales—affiliate
i76
i262
i128
Cost
of sales—related party
Natural Gas Transportation and Storage Agreements (3)
i—
i—
i1
Natural
Gas Supply Agreements (5)
i—
i—
i16
Total
cost of sales—related party
i—
i—
i17
Operating
and maintenance expense—affiliate
TUA (4)
i275
i269
i266
Natural
Gas Transportation Agreement (6)
i82
i81
i81
Services
Agreements (7)
i130
i131
i109
LNG
Site Sublease Agreement (8)
i1
i1
i1
Total
operating and maintenance expense—affiliate
i488
i482
i457
Operating
and maintenance expense—related party
Natural Gas Transportation and Storage Agreements (3)
i62
i72
i46
General
and administrative expense—affiliate
Services Agreements (7)
i61
i66
i61
(1)We
primarily sell LNG to Cheniere Marketing under SPAs and letter agreements at a price equal to i115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement for which pricing is linked to international natural gas prices. We also have a master SPA agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. As of December 31, 2023 and 2022, we had $i272 million
and $i551 million of trade receivables—affiliate, respectively, under these agreements with Cheniere Marketing. In addition, we have an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be the greater of: (a) i115%
of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price.
(2)We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. As of December 31, 2023 and 2022, we had $i4 million
and $i2 million of trade receivables—affiliate, respectively, under these agreements.
(3)We are party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. This related party is partially owned by the investment management company that indirectly owns a portion of CQP’s limited partner interests. We recorded accrued liabilities—related party of $i5 million and $i6 million
as of December 31, 2023 and 2022, respectively, with this related party.
(4)We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately i2 Bcf/d of regasification capacity, and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $i250 million
per year (a portion of which is indexed for inflation), continuing until at least May 2036. Additionally, we are required to reimburse SPLNG for our proportionate share of ad valorem taxes incurred based on our contracted share of SPLNG’s regasification capacity. CQP has guaranteed our obligations under our TUA. As of December 31, 2023 and 2022, we had $i22 million and $i21 million
of other current assets—affiliate, respectively, under this agreement.
(5)We were a party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. This related party was partially owned by Blackstone, who also partially owns CQP’s limited partner interests. However, this entity was acquired by a non-related party on December 31, 2021; therefore, as of such date, this agreement ceased to be considered a related party agreement.
(6)To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG Terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of CQP,
and third party pipeline companies.
(7)We do not have employees and thus we have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements were primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2023 and 2022, we had $i75 million
and $i151 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.
(8)We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG Terminal site for the Liquefaction Project. The aggregate annual sublease payment is $i1 million,
with renewal options and adjustment for inflation every ifive years. As of December 31, 2023 and 2022, we recorded other non-current liabilities—affiliate of $i15 millionand
$i15 million, respectively, related to this agreement.
We had $i64 million and $i80 million
due to affiliates as of December 31, 2023 and 2022, respectively, under agreements with affiliates as described above.
Disclosure of future consideration under revenue contracts with affiliates is included in Note 11—Revenues. Additionally, disclosure of future contractual obligations with affiliates and related parties is included in Note 13—Commitments
and Contingencies.
Other Agreements
Cooperation Agreement
We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We conveyed $i4 million,
$i576 million and izero in assets to SPLNG under this agreement during the years ended December 31, 2023, 2022 and 2021, respectively. The
amount conveyed in 2022 related to the property, plant and equipment associated with the third marine berth at the Liquefaction Project, which was conveyed to SPLNG upon completion in October 2022.
We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare
and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. To date, there have been ino state and local tax payments demanded by Cheniere under the tax sharing agreement. The agreement is effective for tax returns due on or after August 2012.
NOTE 13—iCOMMITMENTS
AND CONTINGENCIES
Commitments
We have various future commitments under executed contracts that include unconditional purchase obligations and other commitments which do not meet the definition of a liability as of December 31, 2023 and thus are not recognized as liabilities in our Financial Statements.
Natural Gas Supply, Transportation and Storage Service Agreements
We have physical natural gas supply contracts
to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2023, the remaining fixed terms of these contracts ranged up to i14 years, with renewal options for certain contracts and some of which commence upon the satisfaction of certain events or states of affairs.
Additionally, we have natural gas transportation and storage service agreements
for the Liquefaction Project. The initial fixed terms of the natural gas transportation agreements range up to i20 years, with renewal options for certain contracts and some of which commence upon the satisfaction of certain events or states of affairs. The initial fixed terms of our natural gas storage service agreements range up to i10
years.
i
As of December 31, 2023, our obligations under natural gas supply, transportation and storage service agreements for contracts in which contractual conditions were met or are currently expected to be met were as follows (in billions):
Years
Ending December 31,
Payments Due to Third Parties (1) (2)
Payments Due to Affiliates (1)
Payments Due to Related Parties (1)
2024
$
i3.7
$
i0.1
$
i0.1
2025
i3.5
i0.1
i0.1
2026
i2.8
i0.1
i—
2027
i2.4
i0.1
i—
2028
i2.1
i0.1
i—
Thereafter
i7.5
i0.5
i—
Total
$
i22.0
$
i1.0
$
i0.2
(1)Pricing
of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of IPM agreement is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Global gas market prices are based on estimates as of December 31, 2023 to the extent forward prices are not available and assume the highest price in cases of price optionality available under the agreement. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.
(2)Includes $i0.8 billion
under natural gas supply agreements with unsatisfied contractual conditions.
/
Services Agreements
We have certain fixed commitments under services and other agreements of $i0.9 billion with third parties and $i4.5 billion
with affiliates.
Substantially all of our commitments to affiliates consist of a TUA with SPLNG pursuant to which we have reserved approximately i2 Bcf/d
of regasification capacity. See Note 12—Related Party Transactions for additional information regarding this TUA.
Additionally, we have a partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), another TUA customer, whereby upon substantial completion of Train 5, we gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG Terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG
storage capacity.
Environmental and Regulatory Matters
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.
Legal Proceedings
We
may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In the opinion of management, as of December 31, 2023, there were ino pending legal matters that would reasonably be expected to have a material impact on our operating results, financial
position or cash flows.
NOTE 14—iCUSTOMER CONCENTRATION
i
The
concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:
Percentage
of Total Revenues from External Customers
Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
The
following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.
Cash paid during the period for interest on debt, net of amounts capitalized
$
i580
$
i613
$
i615
Non-cash
investing and financing activities:
Distribution to affiliate resulting from the conveyance of property, plant and equipment
i4
i576
i—
Non-cash
contributions from affiliates related to extinguishment of debt
i2
i—
i—
Unpaid
purchases of property, plant and equipment, net
i17
i95
i66
/
Novation
of IPM Agreement from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)
In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, we and CCL Stage III, formerly a wholly owned direct subsidiary of Cheniere that merged with and into CCL, entered into an agreement to assign to us an IPM agreement to purchase i140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately
i15 years beginning in early 2023. The transaction was accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $i2.7
billion in distributions to Cheniere’s common unitholder interest within our Statements of Member’s Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $i142 million and $i2.6 billion, respectively,
which represented a non-cash financing activity.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.CONTROLS AND
PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December
31, 2023, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s
Report on Internal Control Over Financial Reporting
ITEM 10. MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE
Omitted
pursuant to Instruction I of Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to Instruction I of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS
Omitted pursuant to Instruction I of Form 10-K.
ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE
Omitted pursuant to Instruction I of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is iKPMG LLP, iHouston,
Texas, Auditor Firm ID i185. The following table sets forth the fees billed by KPMG LLP for professional services rendered for 2023 and 2022 (in millions):
Fiscal 2023
Fiscal
2022
Audit Fees
$
2
$
2
Audit Fees—Audit fees for 2023 and 2022 include fees associated with the audit of our annual Financial Statements, reviews of our interim Financial Statements and services performed in connection with registration statements and debt offerings, including comfort letters and consents.
Audit-Related Fees—There were no audit-related fees in 2023 and 2022.
Tax
Fees—There were no tax fees in 2023 and 2022.
Other Fees—There were no other fees in 2023 and 2022.
Auditor Pre-Approval Policy and Procedures
We are not a public company and we are not listed on any stock exchange. As a result, we are not required to, and do not, have an independent audit committee, a financial expert or a majority of independent directors. The audit committee of the general partner of CQP has approved all audit and non-audit services to be provided by the independent accountants and the fees for such services during the fiscal years ended December 31, 2023 and 2022.
All financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.
(3)Exhibits:
Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that
have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:
•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
•may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;
•may apply standards of materiality that differ from those of a reasonable investor; and
•were
made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
