Filed Pursuant to Rule 424(b)(3)
Registration No. 333-273238

PROSPECTUS

SABINE PASS LIQUEFACTION, LLC

Offer to exchange up to

$430,000,000 of 5.900% Senior Secured Amortizing Notes due 2037

(CUSIP No. 785592AZ9)

that have been registered under the Securities Act of 1933

for

$430,000,000 of 5.900% Senior Secured Amortizing Notes due 2037

(CUSIP NOS. 785592AY2 AND U77888AN2)

that have not been registered under the Securities Act of 1933

THE EXCHANGE OFFER EXPIRES AT 5:00 P.M., NEW YORK CITY TIME,

ON AUGUST 24, 2023, UNLESS WE EXTEND IT.

 

 

Terms of the Exchange Offer:

 

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We are offering to exchange up to $430,000,000 aggregate principal amount of registered 5.900% Senior Secured Amortizing Notes due 2037 (CUSIP No. 785592AZ9) (the “New Notes”) for any and all of our $430,000,000 aggregate principal amount of unregistered 5.900% Senior Secured Amortizing Notes due 2037 (CUSIP Nos. 785592AY2 and U77888AN2) (the “Old Notes” and together with the New Notes, the “notes”) that were issued on November 29, 2022.

 

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We will exchange all outstanding Old Notes that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer for an equal principal amount of New Notes.

 

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The terms of the New Notes will be substantially identical to those of the outstanding Old Notes except that the New Notes will be registered under the Securities Act of 1933, as amended (the “Securities Act”), and will not contain restrictions on transfer, registration rights or provisions for additional interest.

 

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You may withdraw tenders of Old Notes at any time prior to the expiration of the exchange offer.

 

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The exchange of Old Notes for New Notes will not be a taxable event for U.S. federal income tax purposes.

 

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We will not receive any cash proceeds from the exchange offer.

 

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The Old Notes are, and the New Notes will be, secured by first-priority liens on substantially all right, title and interest in or to substantially all of our assets and the assets of any future guarantors along with certain other items listed under “Description of Notes” (the “collateral”).

 

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The Old Notes are, and the New Notes will be, guaranteed on a senior basis by all of our future domestic subsidiaries. There is no established trading market for the New Notes or the Old Notes.

 

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We do not intend to apply for listing of the New Notes on any national securities exchange or for quotation through any quotation system.

 

 

Please read “Risk Factors” beginning on page 13 for a discussion of certain risks that you should consider prior to tendering your outstanding Old Notes in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 

 

Each broker-dealer that receives New Notes for its own account pursuant to the exchange offer must acknowledge by way of letter of transmittal that it will deliver a prospectus in connection with any resale of such New Notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, such broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of New Notes received in exchange for Old Notes where such Old Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. Please read “Plan of Distribution.”

The date of this prospectus is July 27, 2023.

TABLE OF CONTENTS

 

ABOUT THIS PROSPECTUS			ii
WHERE YOU CAN FIND MORE INFORMATION			ii
PRESENTATION OF INFORMATION			iii
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS			iv
PROSPECTUS SUMMARY			1
RISK FACTORS			13
USE OF PROCEEDS			31
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			32
BUSINESS			48
MANAGEMENT			58
EXECUTIVE COMPENSATION			60
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			61
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			62
DESCRIPTION OF OTHER INDEBTEDNESS			65
THE EXCHANGE OFFER			68
DESCRIPTION OF NOTES			78
SUMMARY DESCRIPTIONS OF PRINCIPAL FINANCE DOCUMENTS			108
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS			176
PLAN OF DISTRIBUTION			177
LEGAL MATTERS			178
EXPERTS			178
INDEX TO FINANCIAL STATEMENTS			F-1

 

 

This prospectus incorporates important business and financial information about us that is not included or delivered with this prospectus. We will provide this information to you at no charge upon written or oral request directed to Corporate Secretary, Sabine Pass Liquefaction, LLC, 700 Milam Street, Suite 1900, Houston, Texas 77002 (telephone number (713) 375-5000).

In order to ensure timely delivery of this information, any request should be made by August 17, 2023, five business days prior to the expiration date of the exchange offer.

 

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ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission (the “SEC”). No person has been authorized to give any information or any representation concerning us or the exchange offer (other than as contained in this prospectus or the related letter of transmittal) and we take no responsibility for, nor can we provide any assurance as to the reliability of, any other information that others may give you. We are not making an offer to sell these securities in any state or jurisdiction where the offer is not permitted. You should not assume that the information contained in or incorporated by reference into this prospectus is accurate as of any date other than the date on the front cover of this prospectus or the date of such incorporated documents, as the case may be.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly, current and other reports with the SEC under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Our SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov. We will provide you upon request, without charge, a copy of the notes and the indenture governing the notes. You may request copies of these documents by contacting us at:

Sabine Pass Liquefaction, LLC

Attention: Corporate Secretary

700 Milam Street, Suite 1900

Houston, Texas, 77002

(713) 375-5000

We also make all periodic and other information filed or furnished with the SEC available, free of charge, on our website at www.cheniere.com as soon as reasonably practicable after such information is electronically filed with or furnished to the SEC. Except as otherwise set forth herein, information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

 

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PRESENTATION OF INFORMATION

In this prospectus, we rely on and refer to information and statistics regarding our industry. We obtained this market data from independent industry publications or other publicly available information. Although we believe that these sources are reliable, we have not independently verified and do not guarantee the accuracy or completeness of this information.

In this prospectus, unless the context otherwise requires:

 

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Bcf means billion cubic feet;

 

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Bcf/d means billion cubic feet per day;

 

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Bcf/yr means billion cubic feet per year;

 

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DOE means the U.S. Department of Energy;

 

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EPC means engineering, procurement and construction;

 

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FERC means the Federal Energy Regulatory Commission;

 

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FOB means free on board;

 

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FTA countries means countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas;

 

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GAAP means generally accepted accounting principles in the United States;

 

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Henry Hub means the final settlement price (in USD 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;

 

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

 

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LIBOR means the London Interbank Offered Rate;

 

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LNG means 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;

 

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MMBtu means million British thermal units, an energy unit;

 

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mtpa means million tonnes per annum;

 

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non-FTA countries means 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;

 

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SEC means the U.S. Securities and Exchange Commission;

 

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SPA means an LNG sale and purchase agreement;

 

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TBtu means trillion British thermal units, an energy unit;

 

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Tcf means trillion cubic feet;

 

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Train means an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG; and

 

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TUA means terminal use agreement.

 

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

 

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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;

 

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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;

 

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

 

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statements regarding our future sources of liquidity and cash requirements;

 

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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;

 

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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;

 

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

 

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

 

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

 

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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;

 

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

 

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

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this prospectus or incorporated by reference herein 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

 

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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 prospectus 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 “Risk Factors” and elsewhere in this prospectus. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

 

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RISK FACTORS

Before deciding to participate in the exchange offer, you should carefully consider the risks and uncertainties described below together with all other information contained in this prospectus. The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. If any of the risks described this prospectus actually materialize, such risks could have a material adverse effect on our business, contracts, financial condition, operating results cash flow, liquidity and prospect. In such event, our ability to make payments of interest, principal or premium, if any, on the New Notes may be materially and adversely affected. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results cash flow, liquidity and prospects.

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

 

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Risks Relating to Our Financial Matters;

 

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Risks Relating to Our Operations and Industry;

 

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Risks Relating to Regulations; and

 

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Risks Relating to the Exchange Offer and the New Notes.

Risks Relating to Our Financial Matters

Our existing level of cash resources and significant debt 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 March 31, 2023, we had no cash and cash equivalents, $160 million of restricted cash and cash equivalents, $871 million of available commitments under the Working Capital Facility and $12.1 billion of total debt outstanding (before unamortized premium, 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 additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations 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. We also rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

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

Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of March 31, 2023, we had SPAs with 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.

 

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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 affect 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, other than certain derivatives for which we have elected to apply accrual accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements for the year ended December 31, 2022 included elsewhere in this prospectus. Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile. As described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations,” our net income for the year ended December 31, 2022 includes $1.1 billion of losses resulting from changes in 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, 2022 and 2021, we had collateral posted with counterparties by us of $35 million and $7 million, respectively, which are included in margin deposits in our Balance Sheets.

Risks Relating to Our Operations and Industry

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

As 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

 

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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 pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in part mitigated by the diversification of our natural gas supply and transport 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.

 

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

The construction and operation of the 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:

 

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competitive liquefaction capacity in North America;

 

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

 

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insufficient LNG tanker capacity;

 

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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;

 

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reduced demand and lower prices for natural gas;

 

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

 

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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;

 

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

 

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

 

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

 

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political conditions in customer regions;

 

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

 

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

 

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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 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 North America 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 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 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 agreements approximately 85% of the total production capacity from the Liquefaction Project with approximately 15 years of weighted average remaining life as of December 31, 2022. 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 in the United States or 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

 

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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:

 

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

 

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

 

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

 

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

 

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

 

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

 

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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 and shipping 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 the outbreak of 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 the Delta and Omicron variants, has had no adverse impact on our on-going operations during this time, the risk of future variants 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.

 

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We are entirely dependent on Cheniere and CQP, including employees of Cheniere and its subsidiaries, for key personnel, and the unavailability of skilled workers or 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, 2022, Cheniere and its subsidiaries had 1,551 full-time employees, including 517 employees who directly supported the Liquefaction Project. 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 project Cheniere is developing, including its liquefaction project at 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, or other 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. 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 affiliates of Cheniere. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently operating three Trains at a natural gas liquefaction facility near Corpus Christi, Texas and CCL has entered into fixed price SPAs with third-parties for the sale of LNG from this natural gas liquefaction facility, and may continue to enter into with respect to any future expansion of the Liquefaction Project.

We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements with one or more Cheniere-affiliated entities as well as 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 will 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.

 

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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 us.

The design, construction and operation of the Liquefaction Project and 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. To date, the DOE has also issued orders under Section 4 of the NGA authorizing us to export domestically produced LNG.

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. We are currently in compliance with such conditions; however, failure to comply or our inability to obtain and maintain existing or newly imposed approvals and permits, filings, which 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 the siting of LNG facilities due to safety, environmental or security concerns, 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 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 to 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. 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 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 terminals, or could increase compliance costs for our operations.

 

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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 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. 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, 2022 and 2021. Revised, reinterpreted or additional laws and regulations 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.

Risks Relating to the Exchange Offer and the New Notes

If you do not properly tender your Old Notes, you will continue to hold unregistered outstanding notes and your ability to transfer outstanding notes will be adversely affected.

We will only issue New Notes in exchange for Old Notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the Old Notes, and you should carefully follow the instructions on how to tender your Old Notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of Old Notes. Please read “The Exchange Offer—Procedures for Tendering Old Notes” and “Description of Notes.”

If you do not exchange your Old Notes for New Notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your Old Notes described in the legend on the certificates for your Old Notes. In general, you may only offer or sell the Old Notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. Except in connection with this exchange offer or as required by the registration rights agreement, we do not intend to register resales of the Old Notes under the Securities Act. For further information regarding the consequences of not tendering your Old Notes in the exchange offer, please read “The Exchange Offer—Consequences of Failure to Exchange Old Notes.”

We will still be able to incur substantially more indebtedness in the future. This could further exacerbate the risks associated with our substantial leverage.

Subject to the covenant described under the heading “Description of Notes—Covenants Applicable to the Notes—Restrictions on Indebtedness”, the indenture governing the New Notes does not prohibit us from

 

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incurring additional indebtedness, including additional senior or secured indebtedness, and other liabilities, or from pledging assets to secure such indebtedness and liabilities. As of March 31, 2023, we had $12.1 billion of total debt outstanding (before unamortized premium, discount and debt issuance costs), excluding $329 million of outstanding letters of credit. As of March 31, 2023, we had $871 million of available commitments and $329 million aggregate amount of issued letters of credit under the Working Capital Facility. We had no other material indebtedness outstanding as of March 31, 2023. In June 2023, we entered into the 2023 Revolving Credit Facility, which refinanced and replaced the Working Capital Facility. The 2023 Revolving Credit Facility reduced the interest rate and commitment fees, extended the maturity date and made certain other changes to the terms and conditions contained in the Working Capital Facility. We will have the ability to draw 100% of the aggregate amount of commitments under the 2023 Revolving Credit Facility for the account or benefit of SPL for general corporate purposes. See “Description of Other Indebtedness” for additional information regarding the 2023 Revolving Credit Facility. The incurrence of additional indebtedness and, in particular, the granting of a security interest in the collateral to secure the indebtedness could adversely affect our ability to pay our obligations on the New Notes.

Our substantial indebtedness could adversely affect our ability to operate our business and prevent us from fulfilling our obligations under the New Notes.

Our substantial indebtedness could have important consequences to you, including:

 

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making it more difficult for us to satisfy our obligations with respect to the New Notes;

 

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limiting our ability to obtain additional financing to fund our capital expenditures, working capital, acquisitions, debt service requirements or liquidity needs for general business or other purposes;

 

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limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt, including indebtedness that we may incur in the future;

 

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limiting our ability to compete with other companies that are not as highly leveraged;

 

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limiting our ability to react to changing market conditions in our industry and in our customers’ industries and to economic downturns;

 

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limiting our flexibility in planning for, or reacting to, changes in our business and future business opportunities;

 

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making us more vulnerable than a less leveraged company to a downturn in our business or in the economy; and

 

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resulting in a material adverse effect on our business, operating results and financial condition if we are unable to service our indebtedness or obtain additional financing, as needed.

Our ability to satisfy our obligations, including the New Notes, will depend upon our future operating performance. Prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control, will affect our ability to make payments on our debt obligations. If we cannot generate sufficient cash from operations to meet our other obligations, we may need to refinance or sell assets. Our business may not generate sufficient cash flow, or we may not be able to obtain sufficient funding, to make the payments required by all of our debt, including the New Notes.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness, including the New Notes, and to fund planned capital expenditures and other strategic investments depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other

 

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factors that are beyond our control. We may not generate sufficient cash flow from operations and we cannot assure you that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness, including the New Notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the New Notes, on or before maturity. If any of the counterparties to our SPAs fails to perform its obligations under its respective SPA or if any of our SPAs are terminated, it could adversely affect our ability to make payments on or refinance the New Notes. We may not be able to refinance any of our indebtedness, including the New Notes, on commercially reasonable terms or at all.

The indenture governing the New Notes contains restrictions that limit our flexibility in operating our business.

The indenture governing the New Notes contains several significant covenants that, among other things, restrict our ability to:

 

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incur additional indebtedness;

 

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engage in certain asset sales;

 

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make certain investments or loans;

 

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enter into certain hedging arrangements;

 

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engage in certain transactions with our affiliates;

 

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create liens on our assets; and

 

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engage in mergers or acquisitions and to make equity investments.

Under some circumstances, these restrictive covenants may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business. However, certain of these covenants are also subject to significant exceptions, which provide flexibility to us but may provide greater risk to holders of the New Notes.

If we fail to comply with the restrictions in the indenture governing the New Notes, the Common Terms Agreement (as described under the heading “Description of Notes—Summary Description of Principal Finance Documents—Common Terms Agreement, Intercreditor Agreement and Security Agency Agreement”) or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies.

We may not be able to repurchase New Notes upon a change of control or upon the exercise of the holders’ options to require repurchase of notes if certain asset sales or loss events occur.

Upon the occurrence of a change of control, as defined under the caption “Description of Notes—Certain Definitions,” you will have the right to require us to repurchase your notes at a purchase price in cash equal to 101% of the remaining principal amount of your New Notes plus accrued and unpaid interest, if any. A change of control shall not be deemed to have occurred if we receive rating reaffirmations from two rating agencies (or one rating agency, if only one rating agency currently rates the New Notes) reaffirming the then current rating of the New Notes as of the date of such change of control. Any future credit agreement or other agreements relating to indebtedness to which we become a party may contain similar provisions. In the event that we experience a change of control as defined in the indenture governing the New Notes that results in us having to repurchase the New Notes or upon the exercise of the holders’ options to require repurchase of the New Notes in the event of certain asset sales or loss events, we may not have sufficient financial resources to satisfy all of our obligations under the New Notes and our other debt instruments.

 

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Our failure to make the change of control offer or to pay the change of control purchase price when due or to make payments upon the exercise of the holders’ options to require repurchase of the New Notes in the event of certain asset sales or loss events would result in a default under the indenture governing the New Notes. In addition, the change of control feature of the New Notes does not cover all corporate reorganizations, mergers or similar transactions and may not provide you with protection in a highly leveraged transaction. See “Description of Notes—Repurchase at the Option of Holders—Change of Control.”

Holders of the New Notes may not be able to determine when a change of control giving rise to their right to have the New Notes repurchased has occurred following a sale of “substantially all” of our assets.

The definition of change of control in the indenture governing the New Notes includes a phrase relating to the sale of “all or substantially all” of our assets. There is no precise established definition of the phrase “substantially all” under applicable law. Accordingly, the ability of a holder of New Notes to require us to repurchase its notes as a result of a sale of less than all our assets to another person may be uncertain.

Federal and state statutes allow courts, under specific circumstances, to void the New Notes and require note holders to return payments received from us.

Under the federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, the New Notes could be voided, or claims in respect of the New Notes could be subordinated to all other debts of ours if, among other things, we, at the time the indebtedness evidenced by the New Notes was incurred:

 

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received less than reasonably equivalent value or fair consideration for the incurrence of the indebtedness; and

 

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were insolvent or rendered insolvent by reason of the incurrence of the indebtedness; or

 

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were engaged, or about to engage, in a business or transaction for which our remaining assets constituted unreasonably small capital; or

 

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intended to incur, or believed that we would incur, debts beyond our ability to pay such debts as they matured.

In addition, any payment by us could be voided and required to be returned to us, or to a fund for the benefit of our creditors. In any such case, your right to receive payments in respect of the New Notes from us would be effectively subordinated to all of our indebtedness and other liabilities.

The rights of the Common Security Trustee to foreclose upon collateral may be impaired by bankruptcy law.

The rights of the Common Security Trustee (as defined under the caption “Description of Notes—Certain Definitions”), under the security documents to foreclose upon and sell collateral, including assets in any accounts, upon the occurrence of an event of default under the Common Terms Agreement or the indenture governing the New Notes is likely to be significantly impaired by applicable bankruptcy law if a bankruptcy or reorganization case were to be commenced by or against us. Under applicable bankruptcy law, secured creditors such as the holders of the New Notes would be prohibited from foreclosing upon or disposing of a debtor’s property without prior bankruptcy court approval.

Your ability to resell the New Notes may be limited by a number of factors; prices for the New Notes may be volatile.

There currently is no established market, and no active or liquid trading market may develop for the New Notes. We do not intend to apply for listing of the New Notes on any securities exchange or on any automated

 

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dealer quotation system. If a market for the New Notes were to develop, the New Notes could trade at prices that may be higher or lower than reflected by their initial offering price, depending on many factors, including among other things:

 

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changes in the overall market for debt securities;

 

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changes in our financial performance or prospects;

 

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the prospects for companies in our industry generally;

 

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the number of holders of the New Notes;

 

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the interest of securities dealers in making a market for the New Notes; and

 

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prevailing interest rates.

The transactions with affiliates covenant contained in the indenture will be suspended if Cheniere Partners receives a rating from all acceptable rating agencies that rate both Cheniere Partners and us that is equivalent to or better than our rating from all acceptable rating agencies that rate Cheniere Partners and us.

The transactions with affiliates covenant contained in the indenture will be suspended if (1) Cheniere Partners (or any successor entity thereto) receives a rating from all acceptable rating agencies that rate both Cheniere Partners (or any successor entity thereto) and us that is equivalent to or better than our rating from all acceptable rating agencies that rate Cheniere Partners (or any successor entity thereto) and us and (2) our notes continue to be rated investment grade by at least two of Moody’s, Fitch or S&P and no default or event of default has occurred and is continuing. There can be no assurance that Cheniere Partners will receive ratings equivalent to or better than our ratings. However, the inapplicability of the transactions with affiliates covenant would allow us to engage in certain transactions with affiliates that would not be permitted while this covenant is in force.

There may not be sufficient collateral to pay all or any amounts due on the New Notes.

We own no significant assets other than those related to the ownership and operation of the Liquefaction Project. If we default under the indenture governing the New Notes, the Common Security Trustee’s remedies under the security documents, including foreclosure on the collateral, may not provide sufficient funds to pay our obligations under the indenture governing the New Notes. Moreover, our direct and indirect owners and their affiliates do not have any liability for the payment or performance of the New Notes.

The New Notes are secured by a first priority lien on the collateral, equal in right of security with the holders of the Senior Notes, lenders under the 2023 Revolving Credit Facility and any of our other debt permitted to be secured by the collateral. To the extent third parties enjoy prior liens, such third parties may have rights and remedies with respect to the property subject to such liens that, if exercised, could adversely affect the value of the collateral. See “Description of Notes—Security.” Any additional Permitted Liens or the incurrence of additional secured debt may have the effect of significantly diluting your ability to recover payment in full on the New Notes from the then existing pool of collateral and will adversely affect your relative position with respect to the collateral.

The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral. The value of the assets that are pledged or charged, as applicable, as collateral could be impaired in the future as a result of changing economic conditions, competition or other future trends. In the event of a foreclosure, liquidation, bankruptcy or similar proceeding, no assurance can be given that the proceeds from any sale or liquidation of the collateral will be sufficient to pay our obligations under the New Notes, in full or at all. Accordingly, there may not be sufficient collateral to pay all or any of the amounts due on the New Notes. Any claim for the difference between the amount, if any, realized by you from the sale of any portion of the collateral and the amount of our obligations owed to you under the New Notes will rank equally in right of payment with all of our other unsecured debt and other obligations that are not subordinated, including trade payables.

 

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In addition, releases of collateral from the liens securing the New Notes will be permitted under certain circumstances. On June 30, 2015, we entered into a second amended and restated intercreditor agreement (which amended and restated the intercreditor agreement entered into on May 28, 2013), with representatives of holders of our secured debt and Société Générale, as the Common Security Trustee and Intercreditor Agent (the “Intercreditor Agreement”), which governs the relationship between the Secured Parties and regulates the claims of the Secured Parties against us and the enforcement by the Secured Parties of the liens upon any collateral, including the method of voting and decision making, and the appointment of the Intercreditor Agent.

The actual provisions relating to such releases are contained in the Intercreditor Agreement and the indenture governing the New Notes. See “Description of Notes—Security.” If the Common Security Trustee were to foreclose upon our assets, there are certain assets, such as permits and certain contracts, which the Common Security Trustee may not be able to effectively foreclose upon without the consent of third parties, such as a governmental authority. We cannot assure you that if the Common Security Trustee forecloses on our assets, the Common Security Trustee will be able to obtain all of the third-party approvals necessary to obtain or transfer ownership of all assets necessary to operate the Liquefaction Project.

Furthermore, if the Common Security Trustee forecloses on the collateral, then, in connection therewith, transferring required permits to a purchaser or new operator of the Liquefaction Project may require additional governmental approvals or proceedings, which could result in delays. Accordingly, we cannot assure you that, if we default on the payments due on the New Notes and the Common Security Trustee forecloses on and sells the collateral, you will receive sufficient proceeds to pay all amounts that we owe on the New Notes.

The Intercreditor Agreement contains provisions that may limit the remedies that could be exercised in respect of an event of default, unless and until the required parties have directed the Intercreditor Agent who, in turn, directs the Common Security Trustee to do so. The holders of the New Notes are also deemed to vote in conformity with Secured Bank Debt Holders in numerous instances.

The Intercreditor Agreement requires the affirmative vote of Secured Parties representing a certain percentage of our outstanding secured debt obligations to direct specific actions of the Intercreditor Agent and Common Security Trustee, including the exercise of remedies with respect to the collateral following an event of default under the indenture governing the New Notes or the documents governing such other secured debt (including the indenture governing the 2037 Senior Notes (the “2037 Senior Notes Indenture”) and the 2023 Revolving Credit Facility). Because the affirmative vote of these required Secured Parties will be required before the Common Security Trustee will be able to exercise remedies, if an event of default under the indenture governing the New Notes were to occur, no remedies could be exercised in respect of the collateral unless and until the required Secured Parties have directed the Intercreditor Agent who, in turn, directs the Common Security Trustee to do so. If the holders of the New Notes do not constitute holders of at least the applicable percentage of the outstanding indebtedness secured by the collateral, the Indenture Trustee and the holders of the New Notes may not be able to direct the Intercreditor Agent or the Common Security Trustee to exercise remedies in respect of the collateral upon the occurrence of an event of default under the indenture governing the New Notes without the affirmative vote of other Secured Parties. In certain cases under the Intercreditor Agreement, the holders of the New Notes do not have the right to vote and decisions will be determined by other holders of our secured debt. See “Description of Notes—Summary Description of Principal Finance Documents—Common Terms Agreement, Intercreditor Agreement and Security Agency Agreement—Voting and Decision-Making” and “—Enforcement of Security Interests.”

The indenture also provides that in numerous instances the holders of the New Notes are deemed to vote in conformity with the Secured Bank Debt Holders, without the requirement of a vote or consent by the holders of the New Notes. See “Description of Notes—Summary Description of Principal Finance Documents—Common Terms Agreement, Intercreditor Agreement and Security Agency Agreement—Modifications—Majority Decisions” and “—Unanimous Decisions.” Please see “Description of Notes—Certain Definitions” for definitions of capitalized terms in this Risk Factor.

 

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The remedies available to the holders of the New Notes and the Common Security Trustee may be limited in bankruptcy.

If we seek the protection of bankruptcy or insolvency laws, or if one or more of our creditors commences an involuntary bankruptcy proceeding against us, the Common Security Trustee’s rights to foreclose on the collateral and our ability to make payments in respect of the New Notes are likely to be significantly impaired. Upon the commencement of a case for relief under the Bankruptcy Code, a secured creditor such as the Common Security Trustee is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from such debtor, without bankruptcy court approval. Moreover, the Bankruptcy Code permits the debtor to continue to remain and use collateral although the debtor is in default under the applicable debt instrument, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to the circumstances, but it is intended to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security if and at such times as the court in its discretion determines that the value of the secured creditor’s interest in the collateral is declining during the pendency of the bankruptcy case. A bankruptcy court may determine that a secured creditor is “adequately protected” and therefore not entitled to prevent diminution in the value of its collateral if the value of the collateral sufficiently exceeds the debt it secures.

In view of the lack of a precise definition of the term “adequate protection” and the broad discretionary and equitable powers of a bankruptcy court, it is impossible to predict:

 

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how long payments under the New Notes could be delayed following commencement of a bankruptcy case;

 

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whether or when the Common Security Trustee could repossess or dispose of the collateral; or

 

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whether or to what extent holders of the New Notes would be compensated for any delay in payment or loss of value of the collateral through the requirement of “adequate protection.”

Furthermore, in the event a bankruptcy court determines that the value of the collateral is not sufficient to repay all amounts due on the New Notes, the holders of the New Notes would hold a secured claim to the extent of the value of the collateral to which the holders of the New Notes are entitled and would hold unsecured claims with respect to such shortfall. The Bankruptcy Code permits the payment and accrual of post-petition interest, costs and attorney’s fees to a secured creditor during a debtor’s court proceeding to exceed the aggregate outstanding principal amount of the obligations secured by the collateral up to the value of the collateral. In addition, if we or any counterparty to any one of our contracts were the subject of bankruptcy proceedings, then we or such counterparty, as the case may be, or a trustee appointed in the applicable bankruptcy case, could choose to reject the contract. If that occurred, the contract would be treated as terminated and the Common Security Trustee could not specifically enforce the rejected contract.

In addition, bankruptcy law and bankruptcy-related court orders generally prohibit the payment of pre- bankruptcy debt by a company that has commenced a bankruptcy case while the case is pending. If we become a debtor in a bankruptcy case, so long as the case was pending, you would likely not receive timely installment payments under the New Notes.

Your rights in the collateral may be adversely affected by the failure to perfect security interests in such collateral and other issues generally associated with the realization of security interests in such collateral.

Generally, a security interest in tangible and intangible assets can only be properly perfected, a valid lien created on such assets can only be granted and the priority of such lien can only be retained, if certain actions are undertaken by the applicable Secured Party. The liens in all collateral from time to time owned by us may not be perfected or validly created with respect to the New Notes if the Common Security Trustee has not taken the actions necessary to perfect or validly create any of those liens upon or prior to the issuance of the New Notes. The inability or failure of the Common Security Trustee to take all actions necessary to create properly perfected

 

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security interests or validly created liens on the collateral may result in the loss of the priority of the security interest for your benefit to which you would have been entitled had such perfection or valid creation of such liens been effectuated by the Common Security Trustee. In addition, applicable law provides that certain property and rights acquired after the grant of a general security interest can only be perfected and a lien on such property and rights validly created at the time such property and rights are acquired and identified. We will have limited obligations to perfect your security interest in, or create valid liens with respect to, specified collateral. We cannot assure you that the Common Security Trustee will monitor, or that we will inform the Common Security Trustee of, the future acquisition of property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in, or create a valid lien with respect to, such after-acquired collateral. Our failure to meet our obligations to inform the Common Security Trustee of the future acquisition of property or rights that constitute collateral may constitute a breach under the security document, which may result in the acceleration of our indebtedness. However, acceleration of such obligations in such situation may not provide an adequate remedy to you if the value of the collateral is impaired by the failure to perfect the security interest in, or create a valid lien with respect to, such after-acquired collateral. The Common Security Trustee has no obligation to monitor the acquisition of additional property or rights that constitute collateral or the perfection of any security interest or the creation of a valid lien with respect thereto. Such failure may result in the loss of the security interest in the collateral or the priority of the security interest granted to secure the New Notes as against third parties.

The collateral is subject to casualty risks, which may limit your ability to recover as a secured creditor for losses to the collateral, and which may have an adverse impact on our operations and results.

The indenture governing the New Notes and the security documents will require us to maintain insurance with responsible and financially sound insurance carriers, in such form and amounts as is necessary to insure the projected probable maximum loss for the Liquefaction Project. However, there are certain losses, including losses resulting from terrorist acts, which may be either uninsurable or not economical to insure, in whole or in part. As a result, we cannot assure you that the insurance proceeds will compensate us fully for our losses. If there is a total or partial loss of any of the collateral, we cannot assure you that any insurance proceeds received by us will be sufficient to satisfy all of our obligations, including the New Notes.

In the event of a total or partial loss affecting any of the collateral securing the New Notes, certain items of equipment and inventory may not be easily replaced. Accordingly, although there may be insurance coverage, the extended period needed to obtain replacement units or inventory may cause significant delays, which may have an adverse impact on our operations and results.

The indenture governing the New Notes does not contain the covenants or events of default contained in the Common Terms Agreement or the 2023 Revolving Credit Facility Agreement.

On July 26, 2021, we entered into a first amendment to the third amended and restated common terms agreement, with representatives of holders of our secured debt and Société Générale, as the Common Security Trustee and Intercreditor Agent in order to set out certain provisions regarding, among other things: (a) common covenants; and (b) common events of default under the secured debt instruments. In connection with the Bank of New York Mellon (the “Indenture Trustee”) becoming party to the Common Terms Agreement and the Intercreditor Agreement, the Indenture Trustee has opted out of the covenants (save for the separateness provisions incorporated by reference in the indenture) and most events of default under the Common Terms Agreement, and the covenants and events of default applicable to the New Notes are as set forth in the indenture, as described under “Description of Notes.” As a holder of the New Notes, you will not have the benefit of the covenants (save for the separateness provisions incorporated by reference in the indenture) or many of the events of default pursuant to the Common Terms Agreement.

 

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Any future pledge of collateral might be avoidable in bankruptcy.

Any future pledge of collateral in favor of the collateral trustee, including pursuant to security documents delivered after the date of the indenture governing the New Notes, might be avoidable by the pledgor (as the debtor in possession in a bankruptcy proceeding) or by the trustee in bankruptcy if certain events or circumstances exist or occur, including, among others, if the pledgor is insolvent at the time of the pledge, the pledge permits the holders of the New Notes to receive greater recovery than if the pledge had not been given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge or, in certain circumstances, a longer period.

A future subsidiary’s guarantee of the New Notes may be reduced, avoided or released under certain circumstances and you may not receive any payments from some or all of those guarantors.

Our future domestic subsidiaries will be required to guarantee the New Notes under certain circumstances. There is legal uncertainty regarding whether those guarantees would be legally enforceable in any bankruptcy proceedings involving those guarantors. If a subsidiary’s guarantee is unenforceable, any security interest in the subsidiary’s assets granted to secure that guarantee also could be set aside and the property made available to other creditors of the bankrupt subsidiary. Among other things, there is a risk that the guarantee, and any related security interest, could be considered a fraudulent conveyance, that can be set aside in bankruptcy proceedings. The indenture governing the New Notes contains a “savings clause,” which limits the liability of each subsidiary’s note guarantee to the maximum amount that such guarantor can incur without risk that its note guarantee will be subject to avoidance as a fraudulent transfer. As a result, a guarantor’s liability under its note guarantee could be reduced in amount or reduced to zero, depending upon the amount of other obligations of such guarantor. We cannot assure you that this limitation of liability will protect such note guarantees from fraudulent transfer challenges or, if it does, that the remaining amount due and collectible under the note guarantees would be sufficient to pay the New Notes in full when due.

The New Notes will be structurally subordinated in right of payment to the indebtedness and other liabilities of our future subsidiaries that do not guarantee the New Notes.

The New Notes, and guarantees of our future subsidiaries, will be structurally subordinated to all of the liabilities of any of our future subsidiaries that do not guarantee the New Notes and these liabilities would be required to be paid before the holders of the New Notes have a claim, if any, against those subsidiaries and their assets. Therefore, if there was a dissolution, bankruptcy, liquidation or reorganization of any such subsidiary, the holders of the New Notes would not receive any amounts with respect to the New Notes from the assets of such non-guarantor subsidiary until after the payment in full of the claims of creditors of such subsidiary. As of the date of this prospectus, we do not have any subsidiaries.

Your right to receive payments under the New Notes are effectively subordinated to indebtedness secured by other assets.

The New Notes will be effectively subordinated to any secured debt we may incur that is secured by assets that are not part of the collateral securing the New Notes to the extent of the assets securing such debt. In the event of a liquidation, dissolution, reorganization, bankruptcy or similar proceeding involving us, such assets which serve as collateral for such other secured debt that are not part of the collateral securing the New Notes will be available to satisfy the obligations under such secured debt before any payments are made on the New Notes.

The ratings of the New Notes may be lowered or withdrawn.

The ratings address the likelihood of timely payment of the scheduled interest and principal on each scheduled payment date. The ratings do not address the likelihood of payment of any overdue interest, premiums

 

29

or any other amounts payable in respect of the New Notes or the timeliness of any accelerated principal payments coming due as the result of the occurrence of an event of default. A rating is not a recommendation to buy, sell or hold a note (or beneficial interests therein) and is subject to revision or withdrawal in the future by each rating agency.

Changes in our credit rating could adversely affect the market price or liquidity of the New Notes.

Credit rating agencies continually revise their ratings for the companies that they follow. Credit rating agencies also evaluate our industry as a whole and may change their credit ratings for us based on their overall view of our industry. We cannot be sure that credit rating agencies will maintain their initial ratings on the New Notes. A negative change in our ratings could have an adverse effect on the trading price or liquidity of the New Notes.

 

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USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement we entered into in connection with the private offering of the Old Notes. We will not receive any proceeds from the issuance of the New Notes in the exchange offer. In consideration for issuing the New Notes as contemplated in this prospectus, we will receive, in exchange, outstanding Old Notes in like principal amount. We will cancel all of the Old Notes surrendered in exchange for New Notes in the exchange offer. As a result, the issuance of the New Notes will not result in any increase or decrease in our indebtedness.

 

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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 historical financial statements included elsewhere in this prospectus. The following discussion contains, in addition to historical information, forward-looking statements that are subject to significant risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including those factors set forth under the captions “Forward-Looking Statements” and “Risk Factors” and elsewhere in this prospectus. Our discussion and analysis includes the following subjects:

 

•

Overview

 

•

Overview of Significant Events

 

•

Market Environment

 

•

Results of Operations

 

•

Liquidity and Capital Resources

 

•

Summary of Critical Accounting Estimates

 

•

Recent Accounting Standards

Overview

We are a 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 and other industrial uses. 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 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, which has six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities owned and operated by SPLNG.

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

 

32

costs. Through our SPAs and IPM agreement, we have contracted approximately 85% of the total production capacity from the Liquefaction Project with approximately 15 years of weighted average remaining life as of March 31, 2023.

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 hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. In February 2023, we and another subsidiary of CQP initiated the pre-filing review process with the FERC under the NEPA for an expansion adjacent to the Liquefaction Project consisting of up to three Trains with an expected total production capacity of approximately 20 mtpa of LNG (the “SPL Expansion Project”). This expansion may be developed and constructed by an affiliate of ours outside of the Liquefaction Project. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive final investment decision.

Overview of Significant Events

Our significant events since January 1, 2022 and through the filing date of this prospectus include the following:

Strategic

 

•

In May 2023, we and our affiliate entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project. This expansion may be developed and constructed by an affiliate of ours outside of the Liquefaction Project.

 

•

In November 2022, we entered into an SPA with Cheniere Marketing for approximately 0.85 mtpa of LNG associated with the IPM agreement between us and Tourmaline Oil Marketing Corp., a subsidiary of Tourmaline Oil Corp (as supplier) (“Tourmaline”), discussed below.

 

•

In June 2022, we entered into an SPA with Chevron U.S.A. Inc. (“Chevron”) to sell Chevron approximately 1.0 mtpa of LNG between 2026 and 2042.

 

•

In February 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project:

 

•

Cheniere Marketing entered into agreements to novate to us certain SPAs entered into with ENN LNG (Singapore) Pte Ltd. and a subsidiary of Glencore plc, with effective dates of January 1, 2023 and February 17, 2022, respectively, aggregating approximately 21 million tonnes of LNG to be delivered between 2023 and 2035.

 

•

The board of directors of CQP approved our entry into (1) an agreement to novate to us an IPM agreement between Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”), formerly a wholly owned direct subsidiary of Cheniere (as purchaser) that merged with and into Corpus Christi Liquefaction, LLC, and Tourmaline to purchase 140,000 MMBtu per day of natural gas at a price based on Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023 (the “Tourmaline IPM”) and (2) a FOB SPA with Cheniere Marketing International LLP to sell LNG associated with the natural gas to be supplied under the IPM agreement. The agreement to assign the Tourmaline IPM agreement from CCL Stage III to us was executed and the assignment was effective on March 15, 2022.

 

33

Operational

 

•

As of April 26, 2023, approximately 2,070 cumulative LNG cargoes totaling approximately 142 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

 

•

On February 4, 2022, substantial completion of Train 6 of the Liquefaction Project was achieved (the “Train 6 Completion”).

Financial

 

•

In June 2023, we issued a notice of partial redemption for $1.4 billion in aggregate principal amount of the 2024 Senior Notes in accordance with the terms of the indenture governing the 2024 Senior Notes. We funded the partial redemption of the 2024 Senior Notes from the proceeds of CQP’s offering of senior notes due 2033, which it contributed to us, and from cash on hand.

 

•

In June 2023, we entered into a $1.0 billion Senior Revolving Credit and Guaranty Agreement (the “2023 Revolving Credit Facility”). The 2023 Revolving Credit Facility refinanced and replaced our previous revolving credit facility (the “Working Capital Facility”), reduced the interest rate and commitment fees, extended the maturity date and made certain other changes to the terms and conditions contained in the previous facility.

 

•

In December and November 2022, we issued an aggregate principal amount of $70 million of 6.293% Senior Secured Notes due 2037 (the “6.293% Senior Notes”) and $430 million of the Old Notes, respectively, with a weighted average life of approximately 9.6 years and 9.5 years, respectively. The proceeds from the 6.293% Senior Notes and the Old Notes, together with cash on hand, were used to redeem the remaining outstanding amount of SPL’s $1.5 billion aggregate principal amount of Senior Secured Notes due 2023 (the “2023 Senior Notes”), subsequent to the $300 million redemption in October 2022.

Market Environment

The LNG market in 2022 saw unprecedented price volatility across all natural gas and LNG benchmarks. Gas market fundamentals across the globe were tight and exacerbated by the Russia / Ukraine war risks, and later by the drastic reduction in Russian natural gas flows to the European Union (“EU”). Concerns over low natural gas and LNG inventories and low additional LNG supply availability early in the year were intensified by the war dynamics in Europe and by further constraints on natural gas and LNG supplies caused by the outage at the Freeport LNG facility in June and the explosion on the Nordstream 1 and Nordstream 2 Pipelines in September. Several EU policy initiatives were passed to ensure underground gas storage in the region was filled before winter. Europe had to compete for LNG cargoes resulting in unprecedented price spikes. These conditions were worsened by high coal prices, low nuclear generation output and low hydro levels in Europe, which limited optionality for power generators and deepened the energy crisis in Europe.

Despite the generally tight supply conditions, according to Kpler, global LNG demand grew by approximately 5% from 2021, adding an additional 19.5 million tonnes to the overall market. LNG imports into Europe and Turkey, increased by 45.9 million tonnes, or 61% year-over-year in 2022. This growth was primarily accompanied by a pronounced slowdown in economic activity in China, which contributed to a 7% decrease in Asia’s LNG demand of 19.1 million tonnes from 2021. These sizeable EU LNG requirements resulting from the war fallout and the increase in global demand, especially demand for increased imports to Europe and Turkey, exposed the vulnerability of the LNG industry in terms of supply constraints and under-investments. This was manifested in the price levels and the magnitude of the price spreads between the benchmarks. As an example, the Dutch Title Transfer Facility (“TTF”) monthly settlement prices averaged $40.9/MMBtu in 2022, approximately 184% higher than the $14.4/MMBtu average in 2021, and the TTF monthly settlement prices averaged $42.3/MMBtu in the fourth quarter of 2022, approximately 46% higher than the $28.9/MMBtu average in the fourth quarter of 2021. Similarly, the 2022 average settlement price for the JKM increased 128% year-over-year to an average of $34.2/MMBtu in 2022, and the fourth quarter of 2022 average settlement price

 

34

for the JKM increased 38% year-over-year to an average of $38.5/MMBtu. This extreme price increase triggered a strong supply response from the U.S., which played a significant role in balancing the global LNG market. Despite the outage at Freeport LNG, the U.S. exported approximately 77 million tonnes of LNG in 2022, a gain of approximately 9% from 2021, as the market continued to pull on supplies from our facilities and those of our competitors. Exports from our Liquefaction Project reached 29.1 million tonnes, representing over 70% of the gain in the U.S. total for the year.

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 war on our supply chain. Consequently, we believe we are well positioned to help meet the needs of our international LNG customers to overcome their supply shortages.

Results of Operations

Three Months Ended March 31, 2023 vs. Three Months Ended March 31, 2022

 

		Three Months Ended March 31,
(in millions)		2023				2022				Variance
Revenues
LNG revenues		$	2,106			$	2,488			$	(382	)
LNG revenues-affiliate			761				757				4
Total revenues			2,867				3,245				(378	)
Operating costs and expenses
Cost of sales (excluding items shown separately below)			313				2,561				(2,248	)
Cost of sales-affiliate			33				18				15
Operating and maintenance expense			176				148				28
Operating and maintenance expense-affiliate			124				117				7
Operating and maintenance expense-related party			16				12				4
General and administrative expense			1				1				—
General and administrative expense-affiliate			16				17				(1	)
Depreciation and amortization expense			138				130				8
Total operating costs and expenses			817				3,004				(2,187	)
Income from operations			2,050				241				1,809
Other income (expense)
Interest expense, net of capitalized interest			(161	)			(156	)			(5	)
Other income, net			4				—				4
Total other expense			(157	)			(156	)			(1	)
Net income		$	1,893			$	85			$	1,808

Operational volumes loaded and recognized from the Liquefaction Project

 

		Three Months Ended March 31,
		2023				2022				Variance
LNG volumes loaded and recognized as revenues (in TBtu)			403				372				31

 

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Net income

Substantially all of the favorable variance of $1.8 billion for the three months ended March 31, 2023 as compared to the same period of 2022 was attributable to the favorable variance of $1.8 billion from changes in fair value and settlements of derivatives in the three months ended March 31, 2023 as compared to the same period of 2022. During the three months ended March 31, 2023 we incurred a gain of $1.0 billion due to non-cash favorable changes in fair value of the Tourmaline IPM agreement as a result of favorable shifts in international forward commodity curves, as compared to a loss of $431 million in the three months ended March 31, 2022 following the assignment to us from CCL Stage III in March 2022. The 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 unfavorable shifts in the international forward commodity curve.

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

Revenues

$378 million decrease between comparable periods primarily attributable to:

 

•

$604 million decrease due to lower pricing per MMBtu from decreased Henry Hub pricing; which was offset by

 

•

$267 million increase due to higher volumes of LNG delivered between the periods, which increased 29 TBtu or 8%, primarily due to the Train 6 Completion in February 2022.

Operating costs and expenses

$2.2 billion decrease between comparable periods primarily attributable to:

 

•

$1.8 billion favorable variance from changes in fair value of derivatives included in cost of sales, from losses of $516 million in the three months ended March 31, 2022 to gains of $1.3 billion in the three months ended March 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; and

 

•

$449 million decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of $425 million in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices, which was partially offset by increased volume of LNG delivered, as discussed above under the caption Revenues.

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 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. Because 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, use of

 

36

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, notwithstanding the operational intent to mitigate risk exposure over time.

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 three months ended March 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 three months ended March 31, 2023.

Year Ended December 31, 2022 vs. Year Ended December 31, 2021

 

		Year Ended December 31,
(in millions)		2022				2021				Variance
Revenues
LNG revenues		$	11,507			$	7,639			$	3,868
LNG revenues-affiliate			4,568				1,472				3,096
LNG revenues-related party			—				1				(1	)
Total revenues			16,075				9,112				6,963
Operating costs and expenses
Cost of sales (excluding items shown separately below)			11,885				5,289				6,596
Cost of sales-affiliate			262				128				134
Cost of sales-related party			—				17				(17	)
Operating and maintenance expense			652				548				104
Operating and maintenance expense-affiliate			482				457				25
Operating and maintenance expense-related party			72				46				26
General and administrative expense			—				4				(4	)
General and administrative expense-affiliate			66				61				5
Depreciation and amortization expense			539				468				71
Other			—				6				(6	)
Total operating costs and expenses			13,958				7,024				6,934
Income from operations			2,117				2,088				29
Other income (expense)
Interest expense, net of capitalized interest			(667	)			(622	)			(45	)
Loss on modification or extinguishment of debt			(2	)			(5	)			3
Other income, net			7				—				7
Total other expense			(662	)			(627	)			(35	)
Net income		$	1,455			$	1,461			$	(6	)

Operational volumes loaded and recognized from the Liquefaction Project

 

		Year Ended December 31,
		2022				2021				Variance
LNG volumes loaded and recognized as revenues (in TBtu) (1)			1,520				1,288				232

 

(1)	The year ended December 31, 2021 includes eight TBtu that were loaded at our affiliate’s facility.

 

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Net Income

Our net income was $1.5 billion for both of the years ended December 31, 2022 and 2021.

There was an unfavorable variance of $1.2 billion in derivative losses from changes in fair value in the year ended December 31, 2022 as compared to the same period of 2021. During the year ended December 31, 2022 we incurred losses of $757 million on the derivative liability associated with the Tourmaline IPM agreement following its assignment to us from CCL Stage III in March 2022. See Overview of Significant Events for further discussion of the assignment. The associated losses following the assignment were 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 unfavorable shifts in the international forward commodity curve. The losses on the Tourmaline IPM agreement, along with losses on our other derivative instruments, were offset by an increase in LNG revenues, net of cost of sales and excluding the effect of derivative losses, of $1.4 billion, approximately half of which was attributable to higher margins on sales indexed to Henry Hub, with variable consideration on our long-term SPAs generally priced at 115% of Henry Hub, and half of which was attributable to increased volume delivered between the comparable periods, in part due to the Train 6 Completion.

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

Revenues

$7.0 billion increase between comparable periods primarily attributable to:

 

•

$5.2 billion increase due to higher pricing per MMBtu, from increased Henry Hub pricing; and

 

•

$1.8 billion increase due to higher volumes of LNG delivered between the periods, which increased 38 TBtu or 5%, as result of the additional production capacity of approximately 5 mtpa arising from the Train 6 Completion.

Operating costs and expenses

$6.9 billion increase between comparable periods primarily attributable to:

 

•

$5.5 billion increase in cost of sales excluding the effect of derivative losses described below, primarily as a result of $5.4 billion in increased cost of natural gas feedstock largely due to higher U.S. natural gas prices and, to a lesser extent, from increased volume of natural gas liquified and delivered as LNG, as discussed above under the caption Revenues; and

 

•

$1.2 billion unfavorable variance in derivative losses from changes in fair value and settlements included in cost of sales, from $32 million derivative gain in the year ended December 31, 2021 to $1.2 billion derivative loss in the year ended December 31, 2022, primarily due to non-cash unfavorable changes in fair value of our commodity derivatives that are attributed to positions indexed to international gas prices, specifically associated with the Tourmaline IPM agreement that was assigned to us as discussed in Net income above.

Significant factors affecting our results of operations

In addition to sources and uses of liquidity as discussed in Liquidity and Capital Resources, below are additional 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 Financial Statements. For commodity derivative instruments related to our

 

38

IPM agreement assigned to us during the year ended December 31, 2022 as described further in Overview of Significant Events, 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. Because 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, 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 our control, notwithstanding the operational intent to mitigate risk exposure over time.

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 years ended December 31, 2022 and 2021, we realized offsets to LNG terminal costs of $148 million and $105 million, respectively, corresponding to 13 TBtu and 12 TBtu, respectively, that were related to the sale of commissioning cargoes from Train 6 of the Liquefaction Project.

Liquidity and Capital Resources

The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements 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.

 

		March 31, 2023				December 31, 2022
Restricted cash and cash equivalents designated for the Liquefaction Project		$	160			$	92
Available commitments under the Working Capital Facility (1)			871				872
Total available liquidity		$	1,031			$	964

 

(1)

Available commitments represent total commitments less loans outstanding and letters of credit issued under the Working Capital Facility as of March 31, 2023 and December 31, 2022. See Note 8—Debt of our Notes to Financial Statements for the three months ended March 31, 2023 and Note 10—Debt of our Notes to Financial Statements for the year ended December 31, 2022 included elsewhere in this prospectus for additional information on the Working Capital Facility and other debt instruments.

Our liquidity position subsequent to March 31, 2023 will be driven by future sources of liquidity and future cash requirements as further discussed below under the caption Future Sources and Uses of Liquidity.

Future Sources and Uses of Liquidity

Future Sources of Liquidity under Executed Contracts

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration under our SPAs 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, 2022. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically

 

39

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 contracts as of December 31, 2022 (in billions):

 

		Estimated Revenues Under Executed Contracts by Period (1)
		2023				2024 - 2027				Thereafter				Total
LNG revenues (fixed fees) (2)		$	3.7			$	14.7			$	34.4			$	52.8
LNG revenues (variable fees) (2) (3)			8.1				30.6				69.9				108.6
Total		$	11.8			$	45.3			$	104.3			$	161.4

 

(1)

Agreements in force as of December 31, 2022 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2022. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this prospectus.

(2)

LNG revenues (including $2.0 billion and $12.9 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 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, 2022. The pricing structure 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. 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 to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt.

LNG Revenues

Through our SPAs and IPM agreement, we have contracted approximately 85% of the total production capacity from the Liquefaction Project, with approximately 15 years of weighted average remaining life as of December 31, 2022. 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 a free on board (“FOB”) basis 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 and variable transportation and liquefaction fuel 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 for the Liquefaction Project. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A, A2 and A by S&P, 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 for the year ended December 31, 2022 included elsewhere in this prospectus.

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.

 

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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 March 31, 2023 and December 31, 2022, we had $871 million and $872 million, respectively, in available commitments under the Working Capital Facility, subject to compliance with the applicable covenants, to potentially meet liquidity needs. In June 2023, we entered into a $1.0 billion Senior Revolving Credit and Guaranty Agreement (the “2023 Revolving Credit Facility”). The 2023 Revolving Credit Facility refinanced and replaced the Working Capital Facility, reduced the interest rate and commitment fees, extended the maturity date and made certain other changes to the terms and conditions contained in the Working Capital Facility. The 2023 Revolving Credit Facility matures in 2028. 100% of the aggregate amount of commitments under the 2023 Revolving Credit Facility are available for the account or benefit of SPL for general corporate purposes.

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 and capital expenditures under executed contracts as of December 31, 2022 (in billions):

 

		Estimated Payments Due Under Executed Contracts by Period (1)
		2023				2024 - 2027				Thereafter				Total
Purchase obligations (2):
Natural gas supply agreements (3)		$	6.4			$	12.7			$	7.3			$	26.4
Natural gas transportation and storage service agreements (4)			0.4				1.4				3.0				4.8
Other purchase obligations (5)			0.6				1.9				3.2				5.7
Total		$	7.4			$	16.0			$	13.5			$	36.9

 

(1)

Agreements in force as of December 31, 2022 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2022. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this prospectus.

(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 conditions precedent 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, 2022. Pricing of our IPM agreement is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Includes $0.4 billion under natural gas supply agreements with unsatisfied conditions precedent.

(4)	Includes $1.1 billion of purchase obligations to affiliates and $0.3 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements.

(5)	Other purchase obligations include $3.6 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

 

41

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 for the year ended December 31, 2022 included elsewhere in this prospectus.

Natural Gas Supply, Transportation and Storage Service Agreements

We have secured natural gas feedstock for the Sabine Pass LNG Terminal through long-term natural gas supply and 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 LNG market price paid for the natural gas feedstock purchase.

As of December 31, 2022, we have secured approximately 84% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2023. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2023. Natural gas supply is generally secured on an indexed pricing basis, 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 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 conditions precedent as of December 31, 2022, we have secured up to 5,785 TBtu of natural gas feedstock through agreements with remaining terms that range up to 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 for the year ended December 31, 2022 included elsewhere in this prospectus.

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 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 for the year ended December 31, 2022 included elsewhere in this prospectus.

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

 

42

TotalEnergies can be found in Note 13—Commitments and Contingencies of our Notes to Financial Statements for the year ended December 31, 2022 included elsewhere in this prospectus.

Additional Future Cash Requirements for Operations and Capital Expenditures

Corporate Activities

We have contracts with subsidiaries of Cheniere and CQP for operations, maintenance and management services. Cheniere and its subsidiaries’ full-time employee headcount was 1,551, including 517 employees who directly supported the Liquefaction Project operations, as of December 31, 2022. Full discussion of our operations, maintenance and management agreements can be found in Note 12—Related Party Transactions of our Notes to Financial Statements for the year ended December 31, 2022 included elsewhere in this prospectus.

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 potential future expansion at the Sabine Pass LNG Terminal would increase cash requirements to support expanded operations, although expansion could 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, 2022 (in billions):

 

		Estimated Payments Due Under Executed Contracts by Period (1)
		2023				2024 - 2027				Thereafter				Total
Debt (2)		$	—			$	7.2			$	4.9			$	12.1
Interest payments (2)			0.6				1.7				0.7				3.0
Total		$	0.6			$	8.9			$	5.6			$	15.1

 

(1)	The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this prospectus.

(2)

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, 2022. Debt and interest payments do not contemplate repurchases, repayments and retirements that we expect to make prior to contractual maturity. See further discussion in Note 10—Debt of our Notes to Financial Statements for the year ended December 31, 2022 included elsewhere in this prospectus.

Debt

As of December 31, 2022, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $12.1 billion and the Working Capital Facility with no outstanding balances. As of December 31, 2022, 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 for the year ended December 31, 2022 included elsewhere in this prospectus.

 

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Interest

As of December 31, 2022, our senior notes had a weighted average contractual interest rate of 5.13%. Borrowings under the Working Capital Facility were indexed to LIBOR, which is expected to be phased out in 2023. There were $328 million aggregate amount of issued letters of credit under the Working Capital Facility as of December 31, 2022.

In June 2023, we entered into the 2023 Revolving Credit Facility, which refinanced and replaced the Working Capital Facility. Loans under the 2023 Revolving Credit Facility bear interest at a variable rate per annum equal to SOFR or the base rate (the highest of (a) the rate of interest per annum publicly announced from time to time by the Senior Facility Agent as its primate rate in effect at its principal office, (b) the federal funds rate plus 0.50%, and (c) Term SOFR for an interest period of one month plus 1.00%), plus the applicable margin. The applicable margin for SOFR loans ranges from 1.00% to 1.75% per annum, and the applicable margin for base rate loans ranges from 0.00% to 0.75% per annum, in each case, based on the credit ratings then in effect assigned to loans under the 2023 Revolving Credit Facility. Interest on SOFR loans is due and payable at the end of each SOFR period, and interest on base rate loans is due and payable at the end of each calendar quarter.

We pay a commitment fee on the average daily amount of undrawn commitments at an annual rate that ranges from 0.075% to 0.30% based on the credit ratings then in effect assigned to loans under the 2023 Revolving Credit Facility. We also pay (i) a letter of credit fee at an annual rate equal to the applicable margin for SOFR loans on the undrawn portion of all letters of credit issued under the 2023 Revolving Credit Facility, and (ii) a fronting fee to each issuing bank that issues a letter of credit in an amount equal to 0.15% per annum of the average daily amount available to be drawn under such letter of credit issued by such issuing bank.

Additional Future Cash Requirements for Financing

Revised Capital Allocation Plan

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. During the year ended December 31, 2022, $1.5 billion of 2023 SPL Senior Notes were redeemed pursuant to the capital allocation plan.

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.

 

		Three Months Ended March 31,								Year Ended December 31,
		2023				2022				2022				2021
Net cash provided by operating activities		$	777			$	686			$	2,973			$	1,937
Net cash used in investing activities			(87	)			(85	)			(434	)			(612	)
Net cash used in financing activities			(622	)			(563	)			(2,545	)			(1,324	)
Net increase (decrease) in restricted cash and cash equivalents		$	68			$	38			$	(6	)		$	1

Operating Cash Flows

Our operating cash net inflows during the three months ended March 31, 2023 and 2022 were $777 million and $686 million, respectively. The $91 million favorable variance between the periods was primarily related to

 

44

higher volume of LNG delivered, which contributed to increased cash receipts from the sale of LNG cargoes, which was partially offset by unfavorable variances due to increased cash outflows for natural gas feedstock as a result of higher volumes purchased as well as timing of cash receipts and payments.

Our operating cash net inflows during the years ended December 31, 2022 and 2021 were $2,973 million and $1,937 million, respectively. The $1,036 million increase was primarily related to increased cash receipts from the sale of LNG cargoes due to higher revenue per MMBtu and volume of LNG delivered. Partially offsetting these operating cash inflows were higher operating cash outflows primarily due to higher natural gas feedstock costs.

Investing Cash Flows

Cash outflows for property, plant and equipment during the three months ended March 31, 2023 were primarily related to optimization and other site improvement projects. Cash outflows for property, plant and equipment during the three months ended March 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.

Cash outflows for property, plant and equipment were primarily for 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 three months ended March 31, 2023 and 2022, we made distributions to CQP of $622 million and $563 million, respectively. We did not have any debt activity during the three months ended March 31, 2023 or 2022.

During the year ended December 31, 2022, we issued an aggregate principal amount of $430 million of the Old Notes and $70 million of 6.293% Senior Notes. We incurred $7 million of debt issuance costs related to these issuances. 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. We paid $1 million of debt extinguishment costs related to premiums associated with this redemption. Additionally, during the year ended December 31, 2022, we had borrowings and repayments of $60 million on our Working Capital Facility.

During the year ended December 31, 2021, we issued $482 million of Senior Secured Notes due 2037 on a private placement basis (the “2037 Private Placement Senior Secured Notes”). We incurred $5 million of debt issuance and other financing costs related to this issuance. The proceeds of the 2037 Private Placement Senior Secured Notes, along with capital contributions and cash on hand, were used to redeem $1.0 billion of our 6.25% Senior Secured Notes due 2022. We paid $3 million of debt extinguishment costs related to premiums associated with this redemption.

During the years ended December 31, 2022 and 2021, we made distributions to CQP of $1.8 billion and $1.6 billion, respectively, and received contributions from CQP of $225 million and $821 million, respectively

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

 

45

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 derivative instruments are recorded at fair value, other than certain derivatives for which we have elected to apply accrual accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements for the year ended December 31, 2022 included elsewhere in this prospectus. 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 for the year ended December 31, 2022 included elsewhere in this prospectus. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and adjustments for transportation prices, and associated events deriving fair value including, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.

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, 2022 and 2021 (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.

 

		Year Ended December 31,
		2022				2021
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period		$	(1,032	)		$	74

The unfavorable change in unrealized loss on instruments held at December 31, 2022 is primarily attributed to the assignment of an IPM agreement to us in March 2022, which is valued based on estimated forward international LNG commodity curves. For additional discussion of the assignment of the IPM agreement, see Note 15—Supplemental Cash Flow Information of our Notes to Financial Statements for the year ended December 31, 2022 for additional information that have been included elsewhere in this prospectus.

The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2022 and 2021 amounted to an asset (liability) of $(3.7) billion and $38 million, 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 “Quantitative and Qualitative Disclosures About Market Risk” below for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices.

 

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Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation of our Notes to Financial Statements for the three months ended March 31, 2023 that have been included elsewhere in this prospectus.

Quantitative and Qualitative Disclosures About Market Risk

Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas supply contracts for the operation of the Liquefaction Project (“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):

 

		March 31, 2023								December 31, 2022								December 31, 2021
		Fair Value				Change in Fair Value				Fair Value				Change in Fair Value				Fair Value				Change in Fair Value
Liquefaction Supply Derivatives		$	(2,470	)		$	447			$	(3,741	)		$	565			$	27			$	1

See Note 6—Derivative Instruments of our Notes to Financial Statements for the three months ended March 31, 2023 that have been included elsewhere in this prospectus and Note 7—Derivative Instruments of our Notes to Financial Statements for the year ended December 31, 2022 that have been included elsewhere in this prospectus for additional details about our derivative instruments.

 

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BUSINESS

General

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

LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, 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 and other industrial uses. 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 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, which has six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities owned and operated by SPLNG.

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 IPM agreements, in which the gas producer sells natural gas to us on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Through our SPAs and IPM agreement, we have contracted approximately 85% of the total production capacity from the Liquefaction Project with approximately 15 years of weighted average remaining life as of March 31, 2023.

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 hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. In February 2023, we and another subsidiary of CQP initiated the pre-filing review process with the FERC under the NEPA for an expansion adjacent to the Liquefaction Project consisting of up to three Trains with an expected total production capacity of approximately 20 mtpa of LNG (the “SPL Expansion Project”). This expansion may be developed and constructed by an affiliate of ours outside of the Liquefaction Project. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive final investment decision.

Our Business Strategy

Our primary business strategy is to develop, construct and operate assets supported by long-term, fixed fee contracts. We plan to implement our strategy by:

 

•

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

 

•

procuring natural gas to our facility;

 

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•

commencing commercial delivery for our long-term SPA customers, of which we have initiated for eight of eleven third party long-term SPA customers as of March 31, 2022;

 

•

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 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Liquefaction Facilities

The Liquefaction Project, as described above under the caption “—General,” is one of the largest LNG production facilities in the world with six Trains and three marine berths.

The following summarizes the volumes of natural gas for which we have received approvals from FERC to site, construct and operate 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 Sabine Pass LNG Terminal 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 Sabine Pass LNG Terminal and manage inventory levels, we have entered into firm pipeline transportation and storage contracts with third parties.

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 another TUA customer, to provide us with additional berthing and storage capacity at the Sabine Pass LNG Terminal. Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional discussion of our TUA agreements.

Customers

Information regarding our customer contracts can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources”.

 

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The following table shows customers with revenues of 10% or greater of total revenues from external customers:

 

		Percentage of Total Revenues from External Customers
		Year Ended December 31,
		2022				2021				2020
BG Gulf Coast LNG, LLC and affiliates			24	%			25	%			25	%
GAIL (India) Limited			17	%			18	%			19	%
Korea Gas Corporation			17	%			17	%			18	%
Naturgy LNG GOM, Limited			16	%			16	%			16	%
TotalEnergies			*				10	%			*

 

*	Less than 10%

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

Governmental Regulation

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

Federal Energy Regulatory Commission

The design, construction, operation, maintenance and expansion of the Liquefaction Project 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.

The FERC issued its final Order Granting Section 3 Authority (“Order”) in April 2012 approving our application for an order under Section 3 of the NGA authorizing the siting, construction and operation of Trains 1 through 4 of the Liquefaction Project (and related facilities). Subsequently, in May 2012, the FERC issued written approval to commence site preparation work for Trains 1 through 4. In October 2012, we applied to amend the FERC approval to reflect certain modifications to the Liquefaction Project, and in August 2013, the FERC issued an Order approving the modifications. In October 2013, we applied to further amend the FERC approval, requesting authorization to increase the total permitted LNG production capacity of Trains 1 through 4 from the then authorized 803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity of Trains 1 through 4. In February 2014, the FERC issued an order approving the October 2013 application (the “February 2014 Order”). A party to the proceeding requested a rehearing of the February 2014 Order, and in September 2014, the FERC issued an order denying the rehearing request (the “FERC Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) to review the February 2014 Order and the FERC Order Denying Rehearing. The court denied the petition in June 2016. In September 2013, we filed an application with the FERC for authorization to add Trains 5 and 6 to the Liquefaction Project, which was granted by the FERC in an Order issued in April 2015 and an Order denying rehearing issued in June 2015. These Orders are not subject to appellate court review. In October of 2018, we applied to the FERC for authorization to add a third marine berth to the Liquefaction Project, which FERC approved in February of 2020. FERC issued written approval to commence site preparation work for the third berth in June 2020.

 

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On September 27, 2019, we filed a request with the FERC pursuant to Section 3 of the NGA, requesting authorization to increase the total LNG production capacity of the terminal from currently authorized levels to an amount which reflects more accurately the capacity of the facility based on enhancements during the engineering, design and construction process, as well as operational experience to date. The requested authorizations do not involve construction of new facilities. Corresponding applications for authorization to export the incremental volumes were also submitted to the DOE. The DOE issued Orders granting authorization to export LNG to FTA countries in April 2020 and to non-FTA countries in March 2022. In October 2021, the FERC issued its Orders Amending Authorization under Section 3 of the NGA. In March 2022, the DOE authorized the export of an additional 152.64 Bcf/yr of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050 to non-FTA countries, that were previously authorized for FTA countries only.

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, which would now include, among other things, reasonably foreseeable greenhouse gas emissions that may be attributable to the project and the project’s impact on environmental justice communities. These FERC changes are the first revision in more than 20 years to the FERC’s policy for the certification of new interstate natural gas pipeline projects under Section 7 of the NGA. The updated Policy Statement has more limited applicability to LNG projects regulated under Section 3 of the Natural Gas Act. While the impact on our future projects and expansions is not known at this time, we do not expect it to have a material adverse effect on our operations.

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 material 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 have not materially affected our construction or operations.

DOE Export License

The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal as discussed in Liquefaction Facilities. 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.

 

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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 (“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 (the “Title V Permit”) and the Prevention of Significant Deterioration Permit (the “PSD 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 recent 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 under the caption “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.

 

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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. We do not believe, however, that our operations, or the construction and operations of the Liquefaction Project, will be materially and adversely affected by any such requirements.

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. 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.

We are supportive of regulations reducing greenhouse gas (“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. The EPA has proposed additional new regulations to reduce methane emissions from both new and existing sources within the Crude Oil and Natural Gas source category that impact our assets and our supply chain.

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 threshold for facilities that report their GHG emissions under the EPA’s Greenhouse Gas Emissions Reporting Program (“GHGRP”) Part 98 (“Subpart W”) 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. At this time, we do not expect it 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, and in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act

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

Resource Conservation and Recovery Act (“RCRA”)

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

 

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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 that our operations, or the construction and operations of our Liquefaction Project, will be materially and adversely affected by such regulatory actions.

Market Factors and Competition

Market Factors

Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sale of LNG by Cheniere Marketing or development of 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 renewable 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 80 mtpa of import capacity over the near-term to secure access to LNG and displace Russian gas imports. In India, there are nearly 12,000 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 decrease harmful emissions.

As a result of these dynamics, we expect gas and LNG to continue to play an important role in satisfying energy demand going forward. In its fourth quarter 2022 forecast, Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 53%, from 388.5 mtpa, or 18.6 Tcf, in 2021, to 595.7 mtpa, or 28.6 Tcf, in 2030 and to 677.8 mtpa or 32.5 Tcf in 2040. In its fourth quarter 2022 forecast, WoodMac also forecasts LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 537 mtpa in 2030, declining to 490 mtpa in 2040. This could result in a market need for construction of an additional approximately 59 mtpa of LNG production by 2030 and about 187 mtpa by 2040. As a cleaner burning fuel with lower emissions than coal or liquid fuels in power generation, we expect gas and LNG to play a central role in balancing grids and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Project is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

 

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Our LNG business has 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. 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 production capacity from the Liquefaction Project, with approximately 15 years of weighted average remaining life as of December 31, 2022, which includes volumes contracted under SPAs in which the 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

When we need to replace 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 under the Cheniere Marketing SPA, 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 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 2022, Cheniere published Acting Today, Securing Tomorrow, its third Corporate Responsibility (“CR”) report, which outlines Cheniere’s focus on sustainability and its performance on key environmental, social and governance (“ESG”) metrics. Cheniere’s CR report is available at www.cheniere.com/our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this prospectus.

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, we are collaborating with natural gas midstream companies, methane detection technology providers and/or leading academic institutions on quantification, monitoring, reporting and verification (“QMRV”) of GHG research and development projects, co-founding and sponsoring multidisciplinary research and education initiatives led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines.

Cheniere also 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 in October 2022.

Our total expenditures related to the climate initiatives, including capital expenditures, were not material to our Financial Statements during the years ended December 31, 2022, 2021 and 2020. However, as the transition

 

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to a lower-carbon economy continues to evolve, as described in Market Factors and Competition, we expect the scope and extent of our future initiatives to evolve accordingly. While we have not incurred material direct capital expenditures related to climate change, we aspire to conduct our business in a safe and responsible manner and are proactive in our management of environmental impacts, risks and opportunities. We face certain business and operational risks associated with physical impacts from climate change, such as potential increases in severe weather events or changes in weather patterns, in addition to transition risks. Please see “Risk Factors” for additional discussion.

Employees

We have no employees. We have contracts with subsidiaries of Cheniere and CQP for operations, maintenance and management services. As of December 31, 2022, Cheniere and its subsidiaries had 1,551 full-time employees, including 517 employees who directly supported the Liquefaction Project. See Note 12—Related Party Transactions of our Notes to Financial Statements for the year ended December 31, 2022 included elsewhere in this prospectus for a discussion of the services agreements pursuant to which general and administrative services are provided to us.

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

Certain of Cheniere’s subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG Terminal and the commissioning of the Liquefaction Project and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of Cheniere’s subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of Cheniere’s subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.

We and another subsidiary of CQP are in discussions with the LDEQ to resolve alleged non-compliance with national emission standards for formaldehyde from combustion turbines at the Sabine Pass LNG Terminal. The allegations are identified in a Consolidated Compliance Order and Notice of Potential Penalty, Tracking No. AE-CN-22-00833 (the “2023 Compliance Order”) issued by the LDEQ on April 12, 2023. In August 2004, the U.S. Environmental Protection Agency (the “EPA”) had 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 Compliance Order, including the petition pending with the EPA. As of March 2023, we and the other subsidiary of CQP have filed test results with the LDEQ indicating that 41 of 44 turbines meet the relevant compliance standard, including through retesting. We do not expect that any ultimate penalty will have a material adverse impact on our financial results.

 

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PHMSA Matter

In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to us in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG Terminal (the “2018 tank incident”). These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, we and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to us returning the tanks to service. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to us alleging violations of federal pipeline safety regulations relating to the 2018 tank incident and proposing civil penalties totaling $2,214,900. On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200. On October 12, 2021, we responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty. PHMSA notified us in a letter dated November 9, 2021 that the case was considered “closed.” We continue to coordinate with PHMSA and FERC to address the matters relating to the 2018 tank incident, including repair approach and related analysis. One tank has been placed back into operational service. We do not expect that the Consent Order and related analysis, repair and remediation or resolution of the NOPV will have a material adverse impact on our financial results or operations.

 

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MANAGEMENT

We are a Delaware limited liability company managed by our “managers” (as defined in our first amended and restated limited liability company agreement, dated July 31, 2012), who currently are Zach Davis, Corey Grindal, Michelle A. Dreyer and Scott Peak. Messrs. Davis, Grindal and Peak each serve as an executive officer and/or director of other affiliated entities, including Cheniere and Cheniere Partners and direct or indirect subsidiaries of Cheniere and Cheniere Partners.

The following sets forth information, as of July 1, 2023, regarding these managers and our executive officers.

 

Name		Age		Position
Jack A. Fusco		60		Chief Executive Officer
Zach Davis		39		Manager, Chief Financial Officer
Corey Grindal		52		Manager, President
Michelle A. Dreyer		52		Manager
Scott Peak		42		Manager

Jack A. Fusco is our Chief Executive Officer and has held that position since May 2016. Mr. Fusco also serves as a director and President and Chief Executive Officer of Cheniere and as Chairman, President and Chief Executive Officer of the General Partner. Mr. Fusco served as Chairman, President and Chief Executive Officer of Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) from June 2016 to September 2018. Mr. Fusco served as the Executive Chairman of Calpine Corporation (“Calpine”) from May 2014 through May 2016, Chief Executive Officer of Calpine from August 2008 to May 2014, President of Calpine from August 2008 to December 2012 and director of Calpine from August 2008 to March 2018. From July 2004 to February 2006, Mr. Fusco served as the Chairman and Chief Executive Officer of Texas Genco LLC. From 2002 through July 2004, Mr. Fusco was an exclusive energy investment advisor for Texas Pacific Group. From November 1998 until February 2002, he served as founder, President and Chief Executive Officer of Orion Power Holdings, Inc. Prior to his founding of Orion Power Holdings, Inc., Mr. Fusco was a Vice President at Goldman Sachs Power, an affiliate of Goldman, Sachs & Co. Prior to joining Goldman, Sachs & Co., Mr. Fusco was employed by Pacific Gas & Electric Company or its affiliates in various engineering and management roles for approximately 13 years. Mr. Fusco obtained a Bachelor of Science degree in Mechanical Engineering from California State University, Sacramento.

Zach Davis is our Chief Financial Officer and a Manager and has held these positions since August 2020. Mr. Davis has served as Executive Vice President and Chief Financial Officer of Cheniere and the General Partner since February 2022, and previously served as Senior Vice President and Chief Financial Officer from August 2020 to February 2022. Mr. Davis also serves as a director of the Cheniere Foundation. Institutional Investor recognized Mr. Davis as the 2023 All-America Executive Team Best CFO in Energy - Natural Gas & Master Limited Partnerships. Mr. Davis joined Cheniere in November 2013. He previously served as Senior Vice President, Finance from February 2020 to August 2020 and as Vice President, Finance and Planning from October 2016 to February 2020. Mr. Davis has over 15 years of energy finance experience, focusing on strategic advisory assignments and financings for companies, projects and assets in the LNG, power, renewable energy, midstream and infrastructure sectors. Prior to joining Cheniere, Mr. Davis held energy investment banking and project finance roles at Credit Suisse, Marathon Capital and HSH Nordbank. Mr. Davis received a B.S. in Economics from Duke University.

Michelle A. Dreyer is our “independent manager” (as defined in our first amended and restated limited liability company agreement, dated July 31, 2012), whose role is limited to approve, unanimously with our managers, any action that would constitute a bankruptcy. At any time that the Common Security Trustee or its designee acquires at least 50.1% of our membership interests having voting rights, the independent manager will be removed and no successor will be designated.

 

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Corey Grindal is our President and a Manager and has held these positions since February 2023. Mr. Grindal also serves as Executive Vice President and Chief Operating Officer of Cheniere. Mr. Grindal previously served as Cheniere’s Executive Vice President, Worldwide Trading from September 2020 to January 2023. Mr. Grindal has also served as a director and Executive Vice President and Chief Operating Officer of Cheniere Partners GP since September 2022 and January 2023, respectively. Mr. Grindal previously served as Senior Vice President, Gas Supply from September 2016 to September 2020, after joining Cheniere in June of 2013 as Vice President of Supply. Mr. Grindal has over 30 years of experience in pipeline construction and operations, project management, and natural gas and power trading. Prior to joining Cheniere, Mr. Grindal was with Deutsche Bank and was responsible for physical and financial trading. Prior to Deutsche Bank, Mr. Grindal held positions with Louis Dreyfus and the Tenneco/El Paso companies. Mr. Grindal holds a B.S. degree in Mechanical Engineering with Honors from the University of Texas at Austin.

Scott Peak is a Manager and has held that position since May 2023. Mr. Peak also serves as a director of Cheniere Partners GP. Mr. Peak is a Managing Partner in Brookfield’s Infrastructure Group and Chief Investment Officer for North America, where he is responsible for infrastructure investments and is head of the Houston office. Prior to joining Brookfield in January 2016, Mr. Peak spent almost a decade at Macquarie Group Ltd. based in New York and Houston focused on the infrastructure sector. Previously, Mr. Peak worked in the mergers and acquisitions group at Dresdner Kleinwort Wasserstein in New York. Mr. Peak previously served as a director of Cheniere from April 2022 to April 2023 and the general partner of Cheniere Partners from September 2020 to April 2022. Mr. Peak holds a Master of Finance with distinction from INSEAD and a B.A. in Economics from Bates College.

 

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We have not paid any compensation to our executive officers since inception and have no plans to do so in the future. All of our executive officers are also employees of Cheniere. In addition to providing services to us, each of our officers and directors, with the exception of Ms. Dreyer, devotes a significant portion of his or her time to work for Cheniere and its affiliates.

Cheniere compensates our officers for the performance of their duties as employees of Cheniere, which includes managing our business. Cheniere does not allocate this compensation between services for us and services for Cheniere and its affiliates. Our officers may participate in employee benefit plans and arrangements sponsored by Cheniere and its affiliates, including plans that may be established by Cheniere and its affiliates in the future. Our board of managers does not review any of the compensation decisions made by Cheniere with regard to compensation of our executive officers.

Manager Compensation

We have paid no compensation to our managers since inception and have no plans to do so in the future. The company that employs Ms. Dreyer is compensated $2,500 per year for her services as an independent manager.

 

		Fees Earned or Paid in Cash				Stock Awards				Option Awards				Non-equity Incentive Plan Compensation				All Other Compensation				Total
Zach Davis		$	—			$	—			$	—			$	—			$	—			$	—
Michelle A. Dreyer			2,500				—				—				—				—				2,500
Corey Grindal			—				—				—				—				—				—
Scott Peak			—				—				—				—				—				—

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The limited liability company interest represented by units in our limited liability company is wholly owned by Cheniere Partners. The following table sets forth the beneficial ownership of our limited liability company interests owned of record and beneficially as of July 1, 2023 by:

 

•

each person who beneficially owns more than 5% of our limited liability company interests;

 

•

each of our managers;

 

•

each of our executive officers; and

 

•

all of our managers and executive officers as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Cheniere, as our indirect parent, has sole voting and investment power with respect to all of our limited liability company interests. The address for the beneficial owners listed below is 700 Milam Street, Suite 1900, Houston, Texas 77002.

 

Name of Beneficial Owner		Units Beneficially Owned				Percentage of Limited Liability Company Interests Beneficially Owned
Cheniere Partners			100				100	%
Jack A. Fusco			—				—
Zach Davis			—				—
Michelle A. Dreyer			—				—
Corey Grindal			—				—
Scott Peak			—				—
All executive officers and managers as a group (5 persons)			—				—

 

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Below is a summary of our related party transactions as reported on our Statements of Income (in millions):

 

		Three Months Ended March 31,								Year Ended December 31,
		2023				2022				2022				2021				2020
LNG revenues-affiliate
Cheniere Marketing Agreements (1)		$	761			$	745			$	4,565			$	1,453			$	632
Contracts for Sale and Purchase of Natural Gas and LNG (2)			—				12				3				19				30
Total LNG revenues-affiliate			761				757				4,568				1,472				662
LNG revenues-related party
Natural Gas Transportation and Storage Agreements (3)			—				—				—				1				—
Cost of sales-affiliate
Cheniere Marketing Agreements (1)			—				—				—				34				61
Cargo loading fees under TUA (4)			14				13				51				43				33
Contracts for Sale and Purchase of Natural Gas and LNG (2)			19				5				211				51				16
Total cost of sales-affiliate			33				18				262				128				110
Cost of sales-related party
Natural Gas Transportation and Storage Agreements (3)			—				—				—				1				—
Natural Gas Supply Agreements (5)			—				—				—				16				—
Total cost of sales-related party			—				—				—				17				—
Operating and maintenance expense-affiliate
TUA (4)			68				66				269				266				265
Natural Gas Transportation Agreement (6)			21				20				81				81				82
Services Agreements (7)			35				31				131				109				118
LNG Site Sublease Agreement (8)			—				—				1				1				1
Total operating and maintenance expense-affiliate			124				117				482				457				466
Operating and maintenance expense-related party
Natural Gas Transportation and Storage Agreements (3)			16				12				72				46				13
General and administrative expense-affiliate
Services Agreements (7)			16				17				66				61				71

 

(1)

We primarily sell LNG to Cheniere Marketing under SPAs and letter agreements at a price equal to 115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement for which pricing is linked to international natural gas prices, which will commence in January 2023. 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 March 31, 2023 and December 31, 2022, we had $263 million and $551 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) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price.

(2)	We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is

 

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