# Cheniere Energy, Inc. (LNG) FY 2023 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Cheniere Energy, Inc.'s 10-K for fiscal year 2023.

SEC filing source: https://www.sec.gov/Archives/edgar/data/3570/000000357024000040/lng-20231231.htm
Accession: 0000003570-24-000040
Filing date: 2024-02-22
Report date: 2023-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture.
Confidence: high

Company profile: /company/LNG/
All MD&A years: /company/LNG/mda/
Previous year: /company/LNG/mda/fy2022/ (FY 2022)
Next year: /company/LNG/mda/fy2024/ (FY 2024)

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

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Discussion of 2021 items and variance drivers between the year ended December 31, 2022 as compared to December 31, 2021 are not included herein and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the fiscal year ended December 31, 2022.

Our discussion and analysis includes the following subjects: 

•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 an energy infrastructure company primarily engaged in LNG-related businesses. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We operate two natural gas liquefaction and export facilities at Sabine Pass, Louisiana and near Corpus Christi, Texas. For further discussion of our business, see Items 1. and 2. Business and Properties.

Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Through our SPAs and IPM agreements, we have contracted approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s with approximately 16 years of weighted average remaining life as of December 31, 2023, excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. During 2023, we continued to grow our portfolio of SPA and IPM agreements, and we believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, will provide a foundation for additional growth in our portfolio of customer contracts in the future. The continued strength and stability of our long-term cash flows served as the foundation of our revised comprehensive, long-term capital allocation plan announced in 2022, which includes an increased share repurchase authorization, decreased consolidated long-term leverage target, increased dividends and continued investment in accretive organic growth.

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Overview of Significant Events

Our significant events since January 1, 2023 and through the filing date of this Form 10-K include the following:

Strategic

•In November 2023, we announced that SPL Stage V entered into an IPM agreement with ARC Resources U.S. Corp., a subsidiary of ARC Resources Ltd., to purchase 140,000 MMBtu per day of natural gas at a price based on the Dutch Title Transfer Facility (“TTF”), less a fixed regasification fee, fixed LNG shipping costs and a fixed liquefaction fee, for a term of approximately 15 years commencing with commercial operations of the first train of the SPL Expansion Project. This agreement is subject to CQP making a positive FID on the first train of the SPL Expansion Project or CQP unilaterally waiving that requirement.

•Cheniere Marketing entered into long-term SPAs with Foran Energy Group Co. Ltd., BASF, ENN LNG (Singapore) Pte. Ltd., Equinor ASA and Korea Southern Power Co. Ltd. with estimated volumes totaling approximately 106 million tonnes of LNG and expected deliveries between 2026 and 2050. Approximately 65 million tonnes is subject to CQP making a positive FID on the first or second trains of the SPL Expansion Project, as applicable, or us unilaterally waiving that requirement. Each of these SPAs permit Cheniere Marketing to assign or novate the agreement to certain affiliates at a later date.

•In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project, and in April 2023, one of our subsidiaries executed a contract with Bechtel to provide the front end engineering and design work on the project.

•In April 2023, certain of our subsidiaries filed an application with the DOE with respect to the CCL Midscale Trains 8 & 9 Project, requesting authorization to export LNG to FTA countries and non-FTA countries. In July 2023, we received authorization from the DOE to export LNG to FTA countries.

•In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project.

•On January 2, 2023, Corey Grindal, formerly Executive Vice President, Worldwide Trading, was promoted to Executive Vice President and Chief Operating Officer of the Company.

Operational

•As of February 16, 2024, approximately 3,280 cumulative LNG cargoes totaling over 225 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

Financial

•We closed the following debt transactions:

◦In June 2023, CQP issued $1.4 billion aggregate principal amount of 5.950% Senior Notes due 2033 (the “2033 CQP Senior Notes”). Using contributed proceeds from the 2033 CQP Senior Notes together with cash on hand, SPL redeemed $1.4 billion of its 5.750% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) in July 2023.

◦In June 2023, CQP entered into a $1.0 billion Senior Unsecured Revolving Credit and Guaranty Agreement (the “CQP Revolving Credit Facility”), and SPL entered into a $1.0 billion Senior Secured Revolving Credit and Guaranty Agreement (the “SPL Revolving Credit Facility”). The CQP Revolving Credit Facility and SPL Revolving Credit Facility each refinanced and replaced the respective existing credit facilities to, among other things, (1) extend the maturity date thereunder, (2) reduce the rate of interest and commitment fees applicable thereunder and (3) make certain other changes to the terms and conditions of the prior credit facilities.

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•We received the following upgrades from credit rating agencies, including S&P Global Ratings (“S&P”), Moody’s Investor Service (“Moody’s”) and Fitch Ratings (“Fitch”), each with a stable outlook:

[[GREPCENT_TABLE]]
[["","Date","","Entity","","Previous Rating","","Upgraded Rating","","Rating Agency"],["","October 2023","","CCH","","BBB-","","BBB","","S&P"],["","August 2023","","Cheniere","","Ba1","","Baa3","","Moody\u2019s"],["","August 2023","","CCH","","Baa3","","Baa2","","Moody\u2019s"],["","August 2023","","SPL","","BBB","","BBB+","","Fitch"],["","July 2023","","CCH","","BBB-","","BBB","","Fitch"],["","February 2023","","SPL","","BBB","","BBB+","","S&P"],["","January 2023","","Cheniere","","\u2014","","BBB-","","Fitch"]]
[[/GREPCENT_TABLE]]

•During the year ended December 31, 2023, we accomplished the following pursuant to our capital allocation priorities:

◦We prepaid $1.2 billion of consolidated long-term indebtedness, which excludes prepayments associated with debt refinancing and includes $600 million of debt repurchases in the open market.

◦We repurchased approximately 9.5 million shares of our common stock as part of our share repurchase program for $1.5 billion.

◦We paid dividends of $1.620 per share of common stock during the year ended December 31, 2023.

◦We continued to invest in accretive organic growth, including our investment in the Corpus Christi Stage 3 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

Market Environment

In 2023, the LNG market continued to rebalance with robust LNG flows to Europe maintaining the region’s underground storage inventories at high levels, and weak demand in Japan and Korea largely offsetting a modest rebound in China and other emerging economies in Asia. Price levels started moving towards pre-Russia-Ukraine war levels in the second quarter of 2023 and have for the most part normalized versus pre-war levels, as concerns about physical market tightness dissipated. However, extensive upstream maintenance in Norway and concerns about tight supply capacity amid strike threats in Australia elevated prices during the third quarter of 2023 and brought some volatility back to the market, albeit not at much lower levels than those seen in 2022. These conditions were quickly resolved, and winter prices remained within a more normal level, despite the eruption of military conflict in the Middle East in October.

The TTF monthly settlement prices averaged $13.73/MMBtu in 2023, over 66% lower year-over-year and 4.6% lower than 2021. Similarly, the 2023 average settlement price for the Japan Korea Marker (“JKM”) decreased 53% year-over-year to an average of $16.13/MMBtu in 2023. Prices in the fourth quarter of 2023 also decreased, with TTF averaging $13.66/MMBtu and JKM $14.97/MMBtu - both significantly below levels seen in the previous two years. The Henry Hub benchmark also witnessed a similar year-over-year drop albeit from a much lower base. The Henry Hub average settlement price in 2023 was $2.74, down approximately 59% from $6.64/MMBtu in 2022 during the height of the energy crisis in Europe.

The U.S. played a significant role in balancing the global market in 2023, exporting approximately 86 million tonnes of LNG, a gain of approximately 13% from 2022, due in part to the return of Freeport LNG to operations. Exports from our Liquefaction Projects reached 44 million tonnes in aggregate, representing over 50% of total U.S. exports for the year, according to Kpler data.

Global LNG demand grew by approximately 3% from 2022, adding 10.5 million tonnes to the overall market. Although overall Asian demand has increased from 2022, weakness in Japan, mainly due to improved nuclear availability, along with continued gas demand destruction in Europe, especially in the residential sector, exerted downward pressure on the market and kept LNG and gas prices from increasing. Despite the decrease in Japanese demand, which was down approximately 8% or 6 mtpa year-over-year, Asia’s LNG imports increased roughly 4% year-over-year in 2023 to approximately 263 mtpa. This uptick was largely due to an approximately 8.4 mtpa year-over-year growth in South and Southeast Asia’s demand and a modest rebound in China’s economy, which resulted in approximately 12% or 7.5 mtpa increase in LNG imports into the

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country. In Europe, despite continued declines in gas demand, LNG imports were flat year-over-year as pipeline flows from Russia to the EU remained low at 27 billion cubic meters (“Bcm”), down 36 Bcm or 57% year-over-year.

The market dynamics brought on by the need to displace and replace Russian gas into Europe in 2023 resulted in a notable uptick in long-term LNG contracting and a push for LNG project FIDs. Commercial activity in 2023 continued to build on last year’s momentum with executed long-term SPAs in the U.S. reaching approximately 23 mtpa for the year, of which our SPAs and IPM agreements totaled approximately 6.5 mtpa. This contractual momentum over the past two years led to the positive FID of nearly 40 mtpa of U.S. LNG capacity in 2023, and we anticipate that a portion of these contracts will support our future growth.

Despite the global impacts of the Russia-Ukraine war, we do not believe we have significant exposure to adverse direct or indirect impacts of the war, as we do not conduct business in Russia and refrain from business dealings with Russian entities. Additionally, we are not aware of any specific adverse direct or indirect effects of the Russia-Ukraine war or the Israel-Hamas war on our supply chain. Consequently, we believe we are well positioned to help meet the increased demand of our international LNG customers to overcome their supply shortages.

Results of Operations

Consolidated results of operations

[[GREPCENT_TABLE]]
[["","","","Year Ended December 31,"],["(in millions, except per share data)","","","","","","","2023","","2022","","Variance"],["Revenues"],["LNG revenues","","","","","","","$","19,569","","","$","31,804","","","$","(12,235)"],["Regasification revenues","","","","","","","135","","","1,068","","","(933)"],["Other revenues","","","","","","","690","","","556","","","134"],["Total revenues","","","","","","","20,394","","","33,428","","","(13,034)"],["Operating costs and expenses"],["Cost of sales (excluding items shown separately below)","","","","","","","1,356","","","25,632","","","(24,276)"],["Operating and maintenance expense","","","","","","","1,835","","","1,681","","","154"],["Selling, general and administrative expense","","","","","","","474","","","416","","","58"],["Depreciation and amortization expense","","","","","","","1,196","","","1,119","","","77"],["Other","","","","","","","44","","","21","","","23"],["Total operating costs and expenses","","","","","","","4,905","","","28,869","","","(23,964)"],["Income from operations","","","","","","","15,489","","","4,559","","","10,930"],["Other income (expense)"],["Interest expense, net of capitalized interest","","","","","","","(1,141)","","","(1,406)","","","265"],["Gain (loss) on modification or extinguishment of debt","","","","","","","15","","","(66)","","","81"],["Interest and dividend income","","","","","","","211","","","57","","","154"],["Other income (expense), net","","","","","","","4","","","(50)","","","54"],["Total other expense","","","","","","","(911)","","","(1,465)","","","554"],["Income before income taxes and non-controlling interest","","","","","","","14,578","","","3,094","","","11,484"],["Less: income tax provision","","","","","","","2,519","","","459","","","2,060"],["Net income","","","","","","","12,059","","","2,635","","","9,424"],["Less: net income attributable to non-controlling interest","","","","","","","2,178","","","1,207","","","971"],["Net income attributable to common stockholders","","","","","","","$","9,881","","","$","1,428","","","$","8,453"],["Net income per share attributable to common stockholders\u2014basic","","","","","","","$","40.99","","","$","5.69","","","$","35.30"],["Net income per share attributable to common stockholders\u2014diluted","","","","","","","$","40.72","","","$","5.64","","","$","35.08"]]
[[/GREPCENT_TABLE]]

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Volumes loaded and recognized from the Liquefaction Projects

[[GREPCENT_TABLE]]
[["","","","","Year Ended December 31,"],["(in TBtu)","","","","","","","","2023","","2022","","Variance"],["Volumes loaded during the current period","","","","","","","","2,299","","","2,295","","","4"],["Volumes loaded during the prior period but recognized during the current period","","","","","","","","56","","","49","","","7"],["Less: volumes loaded during the current period and in transit at the end of the period","","","","","","","","(37)","","","(56)","","","19"],["Total volumes recognized in the current period","","","","","","","","2,318","","","2,288","","","30"]]
[[/GREPCENT_TABLE]]

Components of LNG revenues and corresponding LNG volumes delivered

[[GREPCENT_TABLE]]
[["","","","Year Ended December 31,"],["","","","","","","","2023","","2022","","Variance"],["LNG revenues (in millions):"],["LNG from the Liquefaction Projects sold under third party long-term agreements (1)","","","","","","","$","12,820","","","$","20,702","","","$","(7,882)"],["LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements","","","","","","","6,028","","","10,169","","","(4,141)"],["LNG procured from third parties","","","","","","","359","","","760","","","(401)"],["Net derivative gains (losses)","","","","","","","110","","","(328)","","","438"],["Other revenues","","","","","","","252","","","501","","","(249)"],["Total LNG revenues","","","","","","","$","19,569","","","$","31,804","","","$","(12,235)"],["Volumes delivered as LNG revenues (in TBtu):"],["LNG from the Liquefaction Projects sold under third party long-term agreements (1)","","","","","","","2,034","","","1,926","","","108"],["LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements","","","","","","","284","","","362","","","(78)"],["LNG procured from third parties","","","","","","","35","","","29","","","6"],["Total volumes delivered as LNG revenues","","","","","","","2,353","","","2,317","","","36"]]
[[/GREPCENT_TABLE]]

(1)Long-term agreements include agreements with an initial tenor of 12 months or more.

Net income attributable to common stockholders

The favorable variance of $8.5 billion for the year ended December 31, 2023 as compared to the same period of 2022 was primarily attributable to a favorable variance of $14.4 billion (before tax and the impact of non-controlling interest), from changes in fair value and settlement of derivatives between the periods. The majority of the variance related to derivatives was due to non-cash favorable changes in fair value of our IPM agreements as a result of lower volatility in international gas prices and declines in international forward commodity curves, which changed from a loss of $5.0 billion in the year ended December 31, 2022 to a gain of $7.0 billion in the year ended December 31, 2023.

The favorable variance was partially offset by:

•decrease in LNG revenues, net of cost of sales and excluding the effect of derivatives (as further described above), of $2.4 billion, the majority of which was attributable to lower margins on LNG delivered;

•unfavorable variance of $2.1 billion in income tax provision due to higher taxable earnings; and

•unfavorable variance of $971 million in net income attributable to non-controlling interest due to an increase in CQP’s consolidated net income between the comparable periods.

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

Revenues

The decrease of $13.0 billion between the years ended December 31, 2023 and 2022 was primarily attributable to:

•$9.1 billion decrease in Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed;

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•decrease in revenues generated by our marketing function of $2.5 billion due to declining international prices and a reduction of volumes sold under short-term agreements; and

•decrease in regasification revenues of $933 million due to the accelerated recognition of revenues associated with the termination of one of our TUA agreements in December 2022. See Note 13—Revenues of our Notes to Consolidated Financial Statements for additional information on the termination agreement.

Operating costs and expenses (recoveries)

The $24.0 billion favorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to:

•$14.0 billion favorable variance from changes in fair value and settlements of derivatives included in cost of sales, from $6.2 billion of loss in the year ended December 31, 2022 to $7.8 billion of gain in the year ended December 31, 2023, primarily related to non-cash favorable changes in fair value of our IPM agreements as described above under the caption Net income attributable to common stockholders; and

•$10.3 billion decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of $9.6 billion in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices.

The favorable variance was partially offset by an increase in operating and maintenance expense of $154 million between the comparable periods, which was due to the completion of planned large-scale maintenance activities on two trains at the SPL Project during June 2023, other third party service and maintenance contract costs and natural gas transportation and storage capacity demand charges.

Other income (expense)

The $554 million favorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to:

•$265 million decrease in interest expense, net of capitalized interest, primarily as a result of lower debt balances due to $1.2 billion of repayment of debt in 2023, which excludes prepayments associated with debt refinancing;

•$154 million increase in interest and dividend income as a result of higher interest income earned on cash and cash equivalents from higher interest rates in 2023; and

•$81 million favorable variance in gain (loss) on modification or extinguishment of debt, primarily due to higher losses recognized from the amendment and restatement of CCH’s term loan facility agreement (the “CCH Credit Facility”) and CCH’s working capital facility agreement (the “CCH Working Capital Facility”) during the second quarter of 2022 and the redemption of our 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) during the first quarter of 2022. Further contributing to the favorable variance during the year ended December 31, 2023 was a reduction in premiums paid for the early redemption or repayment of debt principal, as a result of near-maturity debt being redeemed or repaid or repurchased in the open market resulting in lower make-whole payments, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

Income tax provision

The $2.1 billion unfavorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to an increase in pre-tax income.

Our effective tax rate was 17.3% and 14.8% for the years ended December 31, 2023 and 2022, respectively. The effective tax rate for both the years ended December 31, 2023 and 2022 was lower than the statutory rate of 21% primarily due to CQP’s income that is not taxable to us.

In December 2021, the OECD released a framework for Pillar Two model rules, which introduced a global minimum corporate tax rate of 15% for large multinational groups. We are a large multinational group with substantial operations in the U.S. and U.K. The U.K. enacted legislation implementing Pillar Two on July 18, 2023, effective beginning January 1, 2024. The U.S. has not enacted legislation implementing Pillar Two. We are continuing to evaluate the Pillar Two rules and their potential impact on future periods, but we do not expect the rules to have a material impact on our effective tax rate.

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Net income attributable to non-controlling interest

The $971 million increase between the years ended December 31, 2023 and 2022 was primarily attributable to $1.8 billion increase in CQP’s consolidated net income between the years ended December 31, 2023 and 2022.

Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

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

Commissioning cargoes

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the year ended December 31, 2022, we realized offsets to LNG terminal costs of $204 million corresponding to 15 TBtu attributable to the sale of commissioning cargoes from Train 6 of the SPL Project. We did not have any commissioning cargoes during the year ended December 31, 2023.

Liquidity and Capital Resources

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

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[[GREPCENT_TABLE]]
[["","December 31, 2023"],["Cash and cash equivalents (1)","$","4,066"],["Restricted cash and cash equivalents (1)","459"],["Available commitments under our credit facilities (2):"],["SPL Revolving Credit Facility","720"],["CQP Revolving Credit Facility","1,000"],["CCH Credit Facility","3,260"],["CCH Working Capital Facility","1,345"],["Cheniere\u2019s revolving credit agreement (the \u201cCheniere Revolving Credit Facility\u201d)","1,250"],["Total available commitments under our credit facilities","7,575"],["Total available liquidity","$","12,100"]]
[[/GREPCENT_TABLE]]

(1)Amounts presented include balances held by our consolidated variable interest entity, CQP, and its subsidiaries, as discussed in Note 9—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of December 31, 2023, assets of CQP and its subsidiaries, which are included in our Consolidated Balance Sheets, included $575 million of cash and cash equivalents and $56 million of restricted cash and cash equivalents.

(2)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2023. See Note 11—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

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

Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures. Certain restrictions under debt and equity instruments executed by our subsidiaries limit each entity’s ability to distribute cash, including the following:

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

•CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner. Beginning with the distribution paid in the second quarter of 2022, quarterly distributions by CQP are currently comprised of a base amount plus a variable amount equal to the remaining available cash per unit, which takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of CQP’s business;

•Our 48.6% limited partner interest, 100% general partner interest and incentive distribution rights in CQP limit our right to receive cash held by CQP to the amounts specified by the provisions of CQP’s partnership agreement; and

•SPL and CCH are restricted by affirmative and negative covenants included in certain of their debt agreements in their ability to make certain payments, including distributions, unless specific requirements are satisfied.

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

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Future Sources and Uses of Liquidity

The following discussion of our future sources and uses of liquidity includes estimates that reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2023. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.

Future Sources of Liquidity under Executed SPAs

As described in Items 1. and 2. Business and Properties, our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Substantially all of our future revenues are contracted under SPAs and because many of these contracts have long-term durations, we are contractually entitled to significant future consideration under these contracts which has not yet been recognized as revenue. This future consideration is, in most cases, not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2023. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed SPAs as of December 31, 2023 (in billions):

[[GREPCENT_TABLE]]
[["","","Estimated Revenues Under Executed SPAs by Period (1) (2)"],["","","2024","","2025 - 2028","","Thereafter","","Total"],["LNG revenues (fixed fees)","","$","6.3","","","$","27.1","","","$","77.6","","","$","111.0"],["LNG revenues (variable fees) (3)","","7.0","","","40.8","","","140.5","","","188.3"],["Total","","$","13.3","","","$","67.9","","","$","218.1","","","$","299.3"]]
[[/GREPCENT_TABLE]]

(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the revenues above when the conditions are considered probable of being met.

(2)LNG revenues exclude revenues from contracts with original expected durations of one year or less. As of December 31, 2023, Cheniere Marketing had short term delivery commitments of approximately 88 TBtu of LNG to be delivered to third party customers in 2024. Fixed fees are fees that are due to us regardless of whether a customer exercises, in certain instances, their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.

(3)LNG revenues (variable fees) reflect the assumption of delivery of all contractual volumes, irrespective of any contractual right of non-delivery. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2023. The pricing structure of many of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices.

Through our SPAs and IPM agreements, we have contracted substantially all of the total anticipated production from the Liquefaction Projects through the mid-2030s. The majority of the contracted capacity is comprised of fixed-price, long-term SPAs that SPL and CCL have executed with third parties to sell LNG from the Liquefaction Projects. In addition, we market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL through our integrated marketing function, Cheniere Marketing. Cheniere Marketing has a portfolio of long-, medium- and short-term SPAs to deliver commercial LNG cargoes to locations worldwide. These volumes are expected to be primarily sourced by LNG produced by the Liquefaction Projects but supplemented by volumes procured from other locations worldwide, as needed.

Substantially all of our contracted capacity is from contracts with terms exceeding 10 years. Excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation, our SPAs and IPM agreements had approximately 16 years of weighted average remaining life as of December 31, 2023. Under the SPAs, the customers purchase LNG on either an FOB basis (delivered to the customer at the Sabine Pass LNG Terminal or the Corpus Christi LNG Terminal, as applicable) or a DAT basis (delivered to the customer at their specified LNG receiving terminal) generally for a price consisting of a fixed fee per MMBtu of LNG (a

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portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. The variable fees under our SPAs were generally sized with the intention to cover the costs of gas purchases, transportation and liquefaction fuel consumed to produce the LNG to be sold under each such SPA. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A-, A3 and A- by S&P, Moody’s and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements.

Additional Future Sources of Liquidity

Regasification Revenues

SPLNG has a long-term, third party TUA with TotalEnergies, under which TotalEnergies is required to pay fixed fees of approximately $125 million annually, whether or not it uses the regasification capacity it has reserved. SPL has a partial TUA assignment agreement with TotalEnergies, whereby SPL gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. Notwithstanding any arrangements between TotalEnergies and SPL, payments required to be made by TotalEnergies to SPLNG will continue to be made by TotalEnergies to SPLNG in accordance with its TUA and we continue to recognize the payments received from TotalEnergies as revenue. Costs incurred by SPL to TotalEnergies under this partial TUA assignment agreement are recognized in operating and maintenance expense. Full discussion of the partial TUA assignment and SPLNG’s revenues under the TUA agreements can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements.

Available Commitments under Credit Facilities

As of December 31, 2023, we had $7.6 billion in available commitments under our credit facilities, as detailed earlier in the table summarizing our available liquidity, subject to compliance with the applicable covenants, to potentially meet liquidity needs. Our credit facilities mature between 2026 and 2029.

Uncontracted Liquefaction Supply

We expect a portion of total production capacity from the Liquefaction Projects that has not yet been contracted under executed agreements as of December 31, 2023 to be available for Cheniere Marketing to market to additional LNG customers. Debottlenecking opportunities and other optimization projects have led to increased run-rate production levels which has increased the production capacity available for Cheniere Marketing to the extent it has not already been contracted to other customers.

Financially Disciplined Growth

Our significant land positions at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project. In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

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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 related to our core operations under executed contracts as of December 31, 2023 (in billions):

[[GREPCENT_TABLE]]
[["","","Estimated Payments Due Under Executed Contracts by Period (1)"],["","","2024","","2025 - 2028","","Thereafter","","Total"],["Purchase obligations (2):"],["Natural gas supply agreements (3)","","$","5.8","","","$","20.2","","","$","25.4","","","$","51.4"],["Natural gas transportation and storage service agreements (4)","","0.5","","","2.0","","","4.9","","","7.4"],["Capital expenditures","","1.2","","","1.7","","","\u2014","","","2.9"],["Leases (5)","","0.9","","","3.0","","","3.7","","","7.6"],["Total","","$","8.4","","","$","26.9","","","$","34.0","","","$","69.3"]]
[[/GREPCENT_TABLE]]

(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023.

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

(3)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Global gas market prices are based on estimates as of December 31, 2023 to the extent forward prices are not available and assume the highest price in cases of price optionality available under the agreement. Includes $0.8 billion under natural gas supply agreements with unsatisfied contractual conditions.

(4)Includes $1.3 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements, of which $1.0 billion had unsatisfied contractual conditions.

(5)Leases include payments under (1) operating leases, (2) finance leases, (3) short-term leases and (4) vessel time charters that were executed as of December 31, 2023 but will commence in the future. Certain of our leases also contain variable payments, such as inflation, which are not included above unless the contract terms require in-substance fixed payments that are, in effect, unavoidable. Payments during renewal options that are exercisable at our sole discretion are included only to the extent that the option is believed to be reasonably certain to be exercised. We subcharter certain LNG vessels while retaining our existing obligation under the original charter. Future income associated with our subcharters was $510 million, inclusive of, as described in Note 12—Leases of our Notes to Consolidated Financial Statements, $163 million qualifying as subleases.

Natural Gas Supply, Transportation and Storage Service Agreements

We have secured natural gas feedstock for the CCL Project and the SPL Project through long-term natural gas supply agreements, including IPM agreements. Under our IPM agreements, we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. While IPM agreements are not revenue contracts for accounting purposes, the payment structure for the purchase of natural gas under the IPM agreements generates a take-or-pay style fixed liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global gas market price paid for the natural gas feedstock purchase.

As of December 31, 2023, we have secured approximately 82% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2024. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2024. Natural gas supply is generally secured on an indexed pricing basis plus a fixed fee, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under contracts with unsatisfied contractual conditions that are currently considered probable of being met and exclusive of extension options that were uncertain to be taken as of December 31, 2023, we have secured up

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to 12,794 TBtu of natural gas feedstock through agreements with remaining fixed terms of up to approximately 15 years. A discussion of our natural gas supply and IPM agreements can be found in Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements.

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

Capital Expenditures

We enter into lump sum turnkey contracts with third party contractors for the EPC of our Liquefaction Projects. The future capital expenditures included in the table above primarily consist of fixed costs under the Bechtel EPC contract for the Corpus Christi Stage 3 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occurred, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order. In addition to amounts presented in the table above, 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.

Corpus Christi Stage 3 Project

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:

[[GREPCENT_TABLE]]
[["Overall project completion percentage","","51.4%"],["Completion percentage of:"],["Engineering","","83.7%"],["Procurement","","72.2%"],["Subcontract work","","66.9%"],["Construction","","11.1%"],["Date of expected substantial completion","","2Q/3Q 2025 - 2H 2026"]]
[[/GREPCENT_TABLE]]

Leases

Our obligations under our lease arrangements primarily consist of LNG vessel time charters with terms of up to 15 years to ensure delivery of cargoes sold on a DAT basis. We have also entered into leases for the use of tug vessels, office space, marine equipment and facilities and land sites. A discussion of our lease obligations can be found in Note 12—Leases of our Notes to Consolidated Financial Statements.

Additional Future Cash Requirements for Operations and Capital Expenditures

Corporate Activities

We are required to maintain corporate and general and administrative functions to serve our business activities. During the year ended December 31, 2023, selling, general and administrative expense was $0.5 billion, a portion of which was related to leases for office space, which is included in the table of cash requirements for operations and capital expenditures under executed contracts above.

Income Tax

Because the currently enacted CAMT may accelerate or cause volatility in our cash tax payments attributable to variability in AFSI, our cash tax payments may fluctuate over time, influenced by both AFSI variability and the resulting impact of the CAMT on other tax benefits, including potential near-term deferral of the realization of our existing NOL carryforwards. This could result in higher cash tax payments in the near-term relative to the year ended December 31, 2023. Additionally, our cash tax payments may be substantially lower in the periods that the Corpus Christi Stage 3 Project is placed into service due to anticipated tax depreciation allowances from the project. Thus, the ongoing interplay between the CAMT,

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the utilization of our existing NOLs and bonus depreciation eligibility of our Corpus Christi Stage 3 Project is expected to cause volatility in our cash tax payments. See the risk Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity under Risks Relating to Our Financial Matters in Item 1A. Risk Factors.

Financially Disciplined Growth

The FID of any expansion projects will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above. However, in connection with reaching FID, we may be required to secure financing to meet the cash needs that such project will initially require, in support of commercializing the project.

Beyond the Corpus Christi Stage 3 Project, our significant land positions at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal provide 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 Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal would increase cash requirements to support expanded operations, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.

Future Cash Requirements for Financing under Executed Contracts

We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2023 (in billions):

[[GREPCENT_TABLE]]
[["","","Estimated Payments Due Under Executed Contracts by Period (1)"],["","","2024","","2025 - 2028","","Thereafter","","Total"],["Debt","","$","0.3","","","$","11.1","","","$","12.5","","","$","23.9"],["Interest payments","","1.3","","","3.3","","","1.8","","","6.4"],["Total","","$","1.6","","","$","14.4","","","$","14.3","","","$","30.3"]]
[[/GREPCENT_TABLE]]

(1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2023. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.

Debt

As of December 31, 2023, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $23.9 billion and credit facilities with no outstanding loan balances. As of December 31, 2023, each of our issuers was in compliance with all covenants related to their respective debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 11—Debt of our Notes to Consolidated Financial Statements.

Interest

As of December 31, 2023, our senior notes had a weighted average contractual interest rate of 4.73%. All of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.075% to 0.525%, subject to change based on the applicable entity’s credit rating. Issued letters of credit under our credit facilities are subject to letter of credit fees ranging from 1.000% to 2.200%, subject to change based on the applicable entity’s credit rating. We had $435 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2023.

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Additional Future Cash Requirements for Financing

CQP Distributions

CQP is required by its partnership agreement to, within 45 days after the end of each quarter, distribute to unitholders all available cash at the end of a quarter less the amount of any reserves established by its general partner. We own a 48.6% limited partner interest in CQP in the form of 239.9 million common units, 100% of the general partner interest and 100% of the incentive distribution rights, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. During the year ended December 31, 2023, $1.0 billion in distributions were paid to our non-controlling interests.

Capital Allocation Plan

In September 2022, our Board approved a revised comprehensive long-term capital allocation plan. Pursuant to the revised capital allocation plan, on September 12, 2022 our Board authorized an increase in the existing share repurchase program by $4.0 billion for an additional three years, beginning on October 1, 2022. As of December 31, 2023, we had up to $2.1 billion available under the share repurchase program. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by management based on market conditions and other factors. During the year ended December 31, 2023, we repurchased a total of 9.5 million shares of our common stock for $1.5 billion at a weighted average price per share of $155.50. A discussion of our share repurchase program can be found in Item 5. Market for Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchase of Equity Securities.

A further aspect of our capital allocation plan is to lower our long-term leverage target through debt paydown to approximately 4x, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of our indebtedness, including senior notes of SPL, CQP, CCH and Cheniere. The timing and amount of any paydown of our indebtedness will be determined by management based on market conditions and other factors. During the year ended December 31, 2023, we used $1.2 billion of available cash to reduce our outstanding indebtedness, all of which was pursuant to our capital allocation plan.

The capital allocation plan also includes a targeted annual dividend growth rate of approximately 10% through Corpus Christi Stage 3 Project construction. On January 26, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on February 23, 2024 to stockholders of record as of the close of business on February 6, 2024.

Financially Disciplined Growth

To the extent that liquefaction capacity at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal is expanded beyond the Liquefaction Projects, such as the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, we expect that additional financing would be used to fund construction of the expansion.

Sources and Uses of Cash

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","2022"],["Net cash provided by operating activities","$","8,418","","","$","10,523"],["Net cash used in investing activities","(2,202)","","","(1,844)"],["Net cash used in financing activities","(4,180)","","","(8,014)"],["Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents","2","","","5"],["Net increase in cash, cash equivalents and restricted cash and cash equivalents","$","2,038","","","$","670"]]
[[/GREPCENT_TABLE]]

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Operating Cash Flows

The $2.1 billion decrease between the periods was primarily related to lower cash receipts from the sale of LNG cargoes due to lower pricing per MMBtu as a result of decreased pricing and a reduction of volumes sold under short-term agreements, as well as a decrease in regasification revenues. A discussion of our revenues, including LNG and regasification revenues, can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements. The decrease was partially offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.

As described in Future Sources and Uses of Liquidity, our future operating cash flows will be impacted by CAMT, which may result in greater volatility in our cash tax payments, including potentially higher cash payments in the near-term relative to the year ended December 31, 2023. See Future Sources and Uses of Liquidity for additional discussion.

Investing Cash Flows

Our investing net cash outflows in both years primarily were for the construction costs for the Liquefaction Projects. The $358 million increase in 2023 compared to 2022 was primarily due to $1.5 billion of cash outflows during the year ended December 31, 2023 related to construction of the Corpus Christi Stage 3 Project following our issuance of full notice to proceed to Bechtel in June 2022 compared to $880 million in the comparable period of 2022, partially offset by a decrease in spend due to the completion of Train 6 of the SPL Project in February 2022. We expect to incur a similar level of capital expenditures in the upcoming year as construction work progresses on the Corpus Christi Stage 3 Project. During the year ended December 31, 2023, we also made investments in infrastructure expected to support the development, construction and operations of the Corpus Christi Stage 3 Project, including an investment in pipeline capacity for natural gas feedstock. Also during the year ended December 31, 2023, we acquired an existing power generation facility located near Corpus Christi, Texas to mitigate power price risk associated with our anticipated increased power load at the Corpus Christi LNG Terminal.

Financing Cash Flows

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

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2023","","2022"],["Proceeds from issuances of debt","","$","1,397","","","$","1,575"],["Redemptions, repayments and repurchases of debt","","(2,598)","","","(6,771)"],["Distributions to non-controlling interest","","(1,016)","","","(947)"],["Repurchase of common stock","","(1,473)","","","(1,373)"],["Dividends to stockholders","","(393)","","","(349)"],["Other, net","","(97)","","","(149)"],["Net cash used in financing activities","","$","(4,180)","","","$","(8,014)"]]
[[/GREPCENT_TABLE]]

Debt Issuances

During the year ended December 31, 2023, CQP issued an aggregate principal amount of $1.4 billion of 2033 CQP Senior Notes, the proceeds of which were used, together with cash on hand, to redeem $1.4 billion of the 2024 SPL Senior Notes. Additionally, during the year ended December 31, 2023, SPL purchased $200 million of the 2024 SPL Senior Notes in the open market and redeemed an additional $100 million of the 2024 SPL Senior Notes. As of December 31, 2023, the only bonds maturing in 2024 are the remaining $300 million outstanding of the 2024 SPL Senior Notes. During the year ended December 31, 2022, SPL issued $430 million of 5.900% Senior Secured Amortizing Notes due 2037 and $70 million of 2037 SPL Private Placement Senior Secured Notes, and we had total borrowings of $1.1 billion under our credit facilities. The proceeds from the borrowings during the year ended December 31, 2022, together with cash on hand, were used to redeem or repurchase $6.8 billion of outstanding indebtedness, entirely associated with redemptions of our outstanding notes or repayment of amounts outstanding under our credit facilities.

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Debt Redemptions, Repayments and Repurchases

The following table shows the redemptions, repayments and repurchases of debt, including intra-year repayments (in millions):

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2023","","2022"],["Redemptions, repayments and repurchases of debt"],["SPL:"],["2024 SPL Senior Notes","","$","(1,700)","","","$","\u2014"],["2023 SPL Senior Notes","","\u2014","","","(1,500)"],["SPL Working Capital Facility","","\u2014","","","(60)"],["CCH:"],["CCH Credit Facility","","\u2014","","","(2,169)"],["CCH Working Capital Facility","","\u2014","","","(250)"],["7.000% Senior Notes due 2024","","(498)","","","(752)"],["5.625% Senior Notes due 2025","","\u2014","","","(9)"],["5.125% Senior Notes due 2027","","(69)","","","(230)"],["3.700% Senior Notes due 2029","","(237)","","","(138)"],["2.742% Senior Notes due 2039","","(94)","","","\u2014"],["3.788% weighted average Senior Notes rate due 2039","","\u2014","","","(88)"],["Cheniere:"],["2045 Cheniere Convertible Senior Notes","","\u2014","","","(500)"],["Cheniere Revolving Credit Facility","","\u2014","","","(575)"],["4.625% Senior Notes due 2028","","\u2014","","","(500)"],["Total redemptions, repayments and repurchases of debt","","$","(2,598)","","","$","(6,771)"]]
[[/GREPCENT_TABLE]]

Non-Controlling Interest Distributions

We own a 48.6% limited partner interest in CQP with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. Distributions of $1.0 billion and $947 million were paid during the years ended December 31, 2023 and 2022, respectively, to non-controlling interests.

Repurchase of Common Stock

During the years ended December 31, 2023 and 2022, we paid $1.5 billion and $1.4 billion to repurchase 9.5 million and 9.4 million shares of our common stock, respectively, under our share repurchase program. As of December 31, 2023, we had approximately $2.1 billion remaining under our share repurchase program.

Cash Dividends to Stockholders

During the year ended December 31, 2023, we paid aggregate dividends of $1.62 per share of common stock, for a total of $393 million. We paid aggregate dividends of $1.385 per share of common stock, for a total of $349 million during the year ended December 31, 2022.

On January 26, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on February 23, 2024 to stockholders of record as of the close of business on February 6, 2024.

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised

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estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.

Fair Value of Level 3 Physical Liquefaction Supply Derivatives

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

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

Additionally, the valuation of certain physical liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2023 and 2022 (in millions), which entirely consisted of physical liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the end of each respective period.

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2023","","2022"],["Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period","","$","5,700","","","$","(6,493)"]]
[[/GREPCENT_TABLE]]

The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our IPM agreements during the years ended December 31, 2023 and 2022.

The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2023 and 2022 amounted to a liability of $2.2 billion and $9.9 billion, respectively, consisting entirely of physical liquefaction supply derivatives.

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

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Recent Accounting Standards

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