Cheniere Energy, Inc. (LNG) FY 2021 MD&A

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 2019 items and variance drivers between the year ended December 31, 2020 as compared to December 31, 2019 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, 2020.

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 (respectively, the “Sabine Pass LNG Terminal” and “Corpus Christi LNG Terminal”) with a total of nine operational natural gas liquefaction Trains, regasification facilities at the Sabine Pass LNG Terminal and pipelines that interconnect our facilities to several interstate and intrastate natural gas pipelines (the SPL Project and CCL Project, respectively, and collectively, the “Liquefaction Projects”). We are also developing an expansion of the Corpus Christi LNG Terminal. 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. We have contracted approximately 95% of the total production capacity from the Liquefaction Projects, including those contracts executed to support the expansion of the Corpus Christi LNG terminal adjacent to the CCL Project (“Corpus Christi Stage 3”). Excluding contracts with terms less than 10 years, our SPAs and IPM agreements had approximately 17 years of weighted average remaining life. 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 and transportation and liquefaction fuel to produce LNG, thus limiting our exposure to fluctuations in U.S. natural gas prices. During 2021, we continued to grow our SPA portfolio, and we believe that continued global demand for natural gas and LNG, as further described in Items 1. and 2. Business and Properties—Market Factors and Competition, 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 long-term capital allocation plan announced in 2021, which includes strengthening of balance sheet, capital return and accretive growth priorities.

Overview of Significant Events

Our significant events since January 1, 2021 and through the filing date of this Form 10-K include the following:

Strategic

•In February 2022, CCL Stage III amended the IPM agreement previously entered into with EOG Resources, Inc. (“EOG”), increasing the volume and term of natural gas supply from 140,000 MMBtu per day for 10 years, to 420,000

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MMBtu per day for 15 years, with pricing continuing to be based on the Platts Japan Korea Marker (“JKM”). Under the amended IPM agreement, supply is targeted to commence upon completion of Trains 1, 4 and 5 of Corpus Christi Stage 3. In addition, the previously executed gas supply agreement (“GSA”), under which EOG sells 300,000 MMBtu per day to CCL Stage III at a price indexed to Henry Hub, has been extended by 5 years, resulting in a 15 year term that is expected to commence upon start-up of the amended IPM agreement.

•In September 2021, our board of directors (our “Board”) approved a long-term capital allocation plan which includes (1) the repurchase, repayment or retirement of approximately $1.0 billion of existing indebtedness of the Company each year through 2024 with the intent of achieving consolidated investment grade credit metrics, (2) initiation of a quarterly dividend for third quarter 2021 at $0.33 per share and (3) the authorization of a reset in the share repurchase program to $1.0 billion, inclusive of any amounts remaining under the previous authorization as of September 30, 2021, for a three-year term effective October 1, 2021.

•In July 2021, CCL Stage III entered into an IPM agreement with Tourmaline Oil Marketing Corp., a subsidiary of Tourmaline Oil Corp., to purchase 140,000 MMBtu per day of natural gas at a price based on JKM, for a term of approximately 15 years beginning in early 2023.

•In July 2021, the Board appointed Mses. Patricia K. Collawn and Lorraine Mitchelmore to serve as members of the Board. Ms. Collawn was appointed to the Audit Committee and the Compensation Committee of the Board, and Ms. Mitchelmore was appointed to the Audit Committee and the Governance and Nominating Committee of the Board.

•Our subsidiaries entered into SPAs with multiple counterparties for portfolio volumes aggregating approximately 67 million tonnes of LNG to be delivered between 2021 and 2042, inclusive of long-term SPAs entered into with ENN LNG (Singapore) Pte Ltd., a subsidiary of Glencore plc and Sinochem Group Co., Ltd.

Operational

•As of February 18, 2022, over 2,000 cumulative LNG cargoes totaling approximately 140 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

•On February 4, 2022, substantial completion of Train 6 of the SPL Project was achieved.

•On March 26, 2021, substantial completion of Train 3 of the CCL Project was achieved.

Financial

•We completed the following debt transactions:

◦In December 2021, we issued a notice of redemption for all $625 million aggregate principal amount outstanding of our 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”), which were redeemed on January 5, 2022.

◦In December 2021, SPL issued Senior Secured Notes due 2037 on a private placement basis for an aggregate principal amount of approximately $482 million (the “2037 SPL Private Placement Senior Secured Notes”). The 2037 SPL Private Placement Senior Secured Notes are fully amortizing, with a weighted average life of over 10 years and a weighted average interest rate of 3.07%.

◦In September 2021, CQP issued an aggregate principal amount of $1.2 billion of 3.25% Senior Notes due 2032 (the “2032 CQP Senior Notes”).

◦The proceeds, net of related fees, costs and expenses (“net proceeds”) of the 2032 CQP Senior Notes were used to redeem a portion of the outstanding $1.1 billion aggregate principal amount of the 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”). The remaining net proceeds of the 2032 CQP Senior Notes, along with the net proceeds of the 2037 SPL Private Placement Senior Secured Notes and cash on hand, were used to redeem the outstanding $1.0 billion aggregate principal amount of the 6.25% Senior Secured Notes due 2022 (the “2022 SPL Senior Notes”).

◦In October 2021, we amended and restated our $1.25 billion Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”) to, among other things, (1) extend the maturity through October 2026, (2) reduce the interest rate and commitment fees, which can be further reduced based on our credit ratings and may be positively or negatively adjusted up to five basis points on the interest rate and up to one basis point on the

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commitment fees based on the achievement of defined ESG milestones and (3) make certain other changes to the terms and conditions of the existing revolving credit facility.

◦In August 2021, CCH issued an aggregate principal amount of $750 million of fully amortizing 2.742% Senior Secured Notes due 2039 (the “2.742% CCH Senior Secured Notes”). The net proceeds of the 2.742% CCH Senior Secured Notes were used to prepay a portion of the principal amount outstanding under CCH’s amended and restated term loan credit facility (the “CCH Credit Facility”).

◦In March 2021, CQP issued an aggregate principal amount of approximately $1.5 billion of 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”). The net proceeds of the 2031 CQP Senior Notes, along with cash on hand, were used to redeem the 5.250% Senior Notes due 2025.

•In line with our capital allocation plan, during the year ended December 31, 2021, on a consolidated basis, we reduced our long-term indebtedness by $1.2 billion, extended the weighted-average maturity of our outstanding debt by over one year and lowered our weighted average borrowing rate.

•In April 2021, S&P Global Ratings (“S&P”) changed the outlook of Cheniere and CQP’s ratings to positive from negative, and in February 2022, upgraded its issuer credit ratings of Cheniere and CQP from BB to BB+.

•In February 2021, Fitch Ratings (“Fitch”) changed the outlook of SPL’s senior secured notes rating to positive from stable and the outlook of CQP’s long-term issuer default rating and senior unsecured notes rating to positive from stable.

•In July 2021, we recommenced share repurchase activities, with 101,944 shares repurchased during the year ended December 31, 2021 for $9 million.

•In January 2021, the term commenced on Cheniere Marketing International LLP’s 25 year SPA with CPC Corporation, Taiwan.

Market Environment

The LNG market in 2021 saw unprecedented price increases across all natural gas and LNG benchmarks. Colder than normal temperatures early in the year, concerns over low natural gas and LNG inventories, low additional LNG supply availability and forecasts of a cold 2021/2022 winter in Europe and Asia increased price volatility and supported a run-up in natural gas and LNG prices. These conditions were exacerbated by rising coal and carbon prices in Europe, persistent under-performance from some non-US LNG supply projects and reduced Russian pipe exports to Europe, precipitating the early stages of a price-based energy crisis in Europe.

High demand for LNG during the recovery from the initial stages of the COVID-19 pandemic resulted in intense competition for supplies between the Atlantic and Pacific basins. Global LNG demand grew by about approximately 5% from the comparable 2020 period, adding an additional 18 mtpa to the overall market. A robust economic recovery in China powered an 8% increase in Asia’s LNG demand of approximately 19.5 million tonnes from the comparable 2020 period. This led to competition for supplies between Asia, Europe and Latin America, exposing the supply constraints that the industry has had while emerging from the pandemic. In turn, this drove international natural gas and LNG prices higher and widened the price spreads between the U.S. and other parts of the world. As an example, the Dutch Title Transfer Facility (“TTF”) monthly settlement prices averaged $14.4/MMBtu in 2021, approximately 375% higher than the $3.0/MMBtu average in 2020, and the TTF monthly settlement prices averaged $28.9/MMBtu in the fourth quarter of 2021, approximately 512% higher than the $4.72/MMBtu average in the fourth quarter of 2020. Similarly, the 2021 average settlement price for the JKM increased 292% year-over-year to an average of $15.0/MMBtu in 2021, and the fourth quarter of 2021 average settlement price for the JKM increased over 412% year-over-year to an average of $27.9/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. The U.S. exported 70 million tonnes of LNG in 2021, a gain of approximately 49% from the comparable 2020 period, as the market continued to pull on supplies from our facilities and those of our competitors. Exports from our Liquefaction Projects reached 39 million tonnes in aggregate, representing over 55% of the gain in the U.S. total over the same period.

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Results of Operations

The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Projects (including both operational and commissioning volumes) during the years ended December 31, 2021 and 2020:

The following table summarizes the volumes of operational and commissioning LNG cargoes that were loaded from the Liquefaction Projects, which were recognized on our Consolidated Financial Statements during the year ended December 31, 2021:

Net loss attributable to common stockholders

Net loss attributable to common stockholders increased by $2.3 billion during the year ended December 31, 2021 from the comparable period in 2020, primarily due to the increase in derivative losses from changes in fair value and settlements of $5.8 billion (pre-tax and excluding the impact of non-controlling interest) between the periods as further described below and non-recurrence of $969 million in revenues recognized on LNG cargoes for which customers notified us that they would not take delivery. This impact was partially offset by increased margin on LNG delivered as a result of increases in both volume delivered and gross margin on LNG delivered per MMBtu during the year ended December 31, 2021 from the comparable period in 2020, as well as a tax benefit recorded during the year ended December 31, 2021.

Substantially all derivative losses relate to the use of commodity derivative instruments indexed to international LNG prices, primarily related to our IPM agreements. While operationally we utilize commodity derivatives to mitigate price volatility for commodities procured or sold over a period of time, as a result of significant appreciation in forward international LNG commodity curves during the year ended December 31, 2021, we recognized $4.5 billion of non-cash unfavorable changes in fair value attributed to positions indexed to such prices (pre-tax and excluding the impact of non-controlling interest).

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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 transactions being economically hedged are accounted for under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt 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, notwithstanding the operational intent to mitigate risk exposure over time.

Revenues

Total revenues increased during the year ended December 31, 2021 from the comparable period in 2020, primarily as a result of increased revenues per MMBtu and higher volume of LNG delivered between the periods. Revenues per MMBtu of LNG were higher due to improved market prices recognized by our integrated marketing function as a result of appreciation in international LNG prices and increases in Henry Hub prices, as well as variable fees that are received in addition to fixed fees when the customers take delivery of scheduled cargoes as opposed to exercising their contractual right to not take delivery. The volume of LNG delivered between the periods increased due to the non-recurrence of notification by our customers to not take delivery of scheduled LNG cargoes during the year ended December 31, 2021 and as a result of production from Train 3 of the CCL Project, which achieved substantial completion on March 26, 2021.

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, 2021 and 2020, we realized offsets to LNG terminal costs of $319 million and $19 million, corresponding to 42 TBtu and 3 TBtu respectively, that were related to the sale of commissioning cargoes from Train 3 of the CCL Project and Train 6 of the SPL Project.

Also included in LNG revenues are sales of certain unutilized natural gas procured for the liquefaction process and other revenues, which was $320 million and $466 million during the years ended December 31, 2021 and 2020, respectively. Additionally, LNG revenues include gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized offsets to revenues of $1.8 billion and $30 million during the years ended December 31, 2021 and 2020, respectively, related to the gains and losses from derivative instruments due to shifts in forward commodity curves.

We expect the volume of LNG produced and available for sale to increase in the future as Train 6 of the SPL Project achieved substantial completion on February 4, 2022.

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The following table presents the components of LNG revenues and the corresponding LNG volumes delivered:

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

(2)LNG revenues include revenues with no corresponding volumes due to revenues attributable to LNG cargoes for which customers notified us that they would not take delivery.

Operating costs and expenses

Our total operating costs and expenses increased during the year ended December 31, 2021 from the comparable period in 2020, primarily as a result of increased cost of sales. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Projects, to the extent those costs are not utilized for the commissioning process. Cost of sales increased during the year ended December 31, 2021 from the comparable 2020 period, primarily due to increased pricing of natural gas feedstock as a result of higher U.S. natural gas prices and increased volume of LNG delivered, as well as unfavorable changes in our commodity derivatives to secure natural gas feedstock for the Liquefaction Projects driven by unfavorable shifts in international forward commodity curves, as discussed above under Net loss attributable to common stockholders. Cost of sales also includes costs associated with the sale of certain unutilized natural gas procured for the liquefaction process and a portion of derivative instruments that settle through physical delivery, port and canal fees, variable transportation and storage costs, net of margins from the sale of natural gas procured for the liquefaction process and other costs to convert natural gas into LNG.

Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Projects. During the year ended December 31, 2021, operating and maintenance expense increased from the comparable period in 2020, primarily due to increased natural gas transportation and storage capacity demand charges and increased third party service, generally as a result of an additional Train that was in operation between the periods. Operating and maintenance expense also includes insurance and regulatory and other operating costs.

Depreciation and amortization expense increased during the year ended December 31, 2021 from the comparable period in 2020 as a result of commencing operations of Train 3 of the CCL Project in March 2021.

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We expect our operating costs and expenses to generally increase as Train 6 of the SPL Project achieved substantial completion on February 4, 2022, although we expect certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized.

Other expense

Interest expense, net of capitalized interest, decreased during the year ended December 31, 2021 from the comparable 2020 period as a result of lower interest costs as a result of refinancing higher cost debt and repayment of debt in accordance with our capital allocation plan, partially offset by the portion of total interest costs that was eligible for capitalization due to the completion of construction of Train 3 of the CCL Project in March 2021. During the years ended December 31, 2021 and 2020, we incurred $1.6 billion and $1.8 billion of total interest cost, respectively, of which we capitalized $166 million and $248 million, respectively, which was primarily related to interest costs incurred for the construction of the Liquefaction Projects.

Loss on modification or extinguishment of debt decreased during the year ended December 31, 2021 from the comparable period in 2020 due to a lower amount of debt that was paid down prior to their scheduled maturities between the periods, as further described in Liquidity and Capital Resources—Sources and Uses of Cash—Financing Cash Flows.

Interest rate derivative loss, net decreased during the year ended December 31, 2021 compared to the comparable 2020 period, primarily due to the settlement of certain outstanding derivatives in August 2020 that were in an unfavorable position and a favorable shift in the long-term forward LIBOR curve between the periods

Other expense, net decreased during the year ended December 31, 2021 from the comparable period in 2020 primarily due to lower other-than-temporary impairment losses related to our investment in Midship Holdings, LLC that were recognized between the periods. These impairment losses were partially offset by an increase in interest income earned on our cash and cash equivalents.

Income tax provision (benefit)

Our effective income tax rate for the year ended December 31, 2021 reflected a 31.3% tax benefit, compared to a 7.9% tax expense for the year ended December 31, 2020. The recorded tax benefit for 2021 was greater than the statutory income tax rate primarily due to income allocated to non-controlling interest that is not taxable to Cheniere and the partial release of the valuation allowance on our Louisiana net operating loss carryforwards. The prior year tax expense was lower than the statutory income tax rate primarily due to income allocated to non-controlling interest that is not taxable to Cheniere. See further discussion in Note 15 – Income Taxes of our Notes to Consolidated Financial Statements.

Our effective tax rate is subject to variation prospectively due to variability in our pre-tax and taxable earnings and the proportion of such earnings attributable to non-controlling interests.

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Net income attributable to non-controlling interest

Net income attributable to non-controlling interest increased during the year ended December 31, 2021 from the year ended December 31, 2020 primarily due to an increase in consolidated net income recognized by CQP, which increased from net income of $1.2 billion in the year ended December 31, 2020 to $1.6 billion in the year ended December 31, 2021.

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. 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 and equity offerings by us or our subsidiaries. The table below provides a summary of our available liquidity as of December 31, 2021 (in millions). Future material sources of liquidity are discussed below.

(1)Amounts presented include balances held by our consolidated variable interest entity, CQP, as discussed in Note 9—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of December 31, 2021, assets of CQP, which are included in our Consolidated Balance Sheets, included $0.9 billion of 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, 2021. 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, 2021 is driven by future sources of liquidity and future cash requirements. Future sources of liquidity are expected to be composed of (1) cash receipts from executed contracts, under which we are contractually entitled to future consideration, and (2) additional sources of liquidity, from which we expect to receive cash although the cash is not underpinned by executed contracts. Future cash requirements are expected to be composed of (1) cash payments under executed contracts, under which we are contractually obligated to make payments, and (2) additional cash requirements, under which we expect to make payments although we are not contractually obligated to make the payments under executed contracts. Future sources of liquidity and future cash requirements are estimates based on management’s assumptions and currently known market conditions and other factors as of December 31, 2021.

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Although material sources of liquidity and material cash requirements 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. The majority of the cash held by SPL and CCH that is restricted to Cheniere relates to advance funding 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. 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, CQP 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.

Notwithstanding 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 liquidity provided by Cheniere Marketing, is available to enable Cheniere to meet its cash requirements.

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 and TUAs 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, 2021. 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 contracts as of December 31, 2021 (in billions):

(1)Excludes contracts for which conditions precedent have not been met. Agreements in force as of December 31, 2021 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2021. 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, 2021. 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.

(2)LNG revenues 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) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2021. 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

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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.

(4)Financial derivatives include certain LNG Trading Derivatives that are recorded as LNG Revenues based on the nature and intent of the derivative instrument. Pricing of financial derivatives is based on estimated forward prices and basis spreads as of December 31, 2021.

LNG Revenues

We have contracted substantially all of the total production capacity from the Liquefaction Projects. 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 Trains 1 through 6 of the SPL Project and Trains 1 through 3 of the CCL Project. Substantially all of our contracted capacity is from contracts with terms exceeding 10 years. Excluding contracts with terms less than 10 years, our SPAs had approximately 17 years of weighted average remaining life as of December 31, 2021. 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 $2.9 billion for Trains 1 through 5 of the SPL Project. After giving effect to an SPA that Cheniere has committed to provide to SPL and upon the date of first commercial delivery of Train 6 of the SPL Project, the annual fixed fee portion to be paid by the third-party SPA customers is expected to increase to at least $3.3 billion. In aggregate, the minimum annual fixed fee portion to be paid by the third-party SPA customers is approximately $1.8 billion for Trains 1 through 3 of the CCL Project. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A-, A3 and A- by S&P, Moody’s Corporation and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 13—Revenues from Contracts with Customers of our Notes to Consolidated Financial Statements.

We market and sell LNG produced by the Liquefaction Projects that is not required for other customers 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.

As of December 31, 2021, Cheniere Marketing has sold or has options to sell approximately 7,974 TBtu of LNG to be delivered to third party customers between 2022 and 2045, including 7,791 TBtu from long-term executed contracts that are included in the Future Sources of Liquidity under Executed Contracts table above. The cargoes have been sold either on a FOB basis (delivered to the customer at the Sabine Pass LNG Terminal or the Corpus Christi LNG Terminal, as applicable) or a delivered at terminal (“DAT”) basis (delivered to the customer at their specified LNG receiving terminal).

Regasification Revenues

SPLNG has entered into two long-term, third party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the approximately 2 Bcf/d of the regasification capacity they have reserved at the Sabine Pass LNG Terminal. Total and Chevron U.S.A. Inc. (“Chevron”) are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually, prior to inflation adjustments, for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

SPLNG has also entered into a TUA with SPL to reserve the remaining capacity at the Sabine Pass LNG Terminal. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG that started in 2019. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. Payments made by SPL to Total under this partial TUA assignment agreement are included in other purchase obligations in the Future Cash Requirements for Operations and

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Capital Expenditures under Executed Contracts table below. Full discussion of SPLNG’s revenues under the TUA agreements and the partial TUA assignment can be found in Note 13—Revenues from Contracts with Customers of our Notes to Consolidated Financial Statements.

Financial Derivatives

Cheniere Marketing has entered into financial derivatives to minimize future cash flow variability associated with Cheniere Marketing’s LNG agreements. Full discussion of financial derivatives can be found in Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements.

Additional Future Sources of Liquidity

Available Commitments under Credit Facilities

As of December 31, 2021, we had $3.4 billion in available commitments under our credit facilities, subject to compliance with the applicable covenants, to potentially meet liquidity needs. Our credit facilities mature between 2023 and 2026.

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, 2021 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

We expect to reach FID on Corpus Christi Stage 3 in 2022 based on our progress in commercializing the project and the strong global LNG market. Corpus Christi Stage 3 is a shovel-ready, brownfield project with an incremental liquefaction capacity of approximately 10 mtpa. Beyond Corpus Christi Stage 3, our significant land positions at the Corpus Christi and Sabine Pass LNG terminals provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources.

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, 2021 (in billions):

(1)Excludes contracts for which conditions precedent have not been met. Agreements in force as of December 31, 2021 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2021. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. 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.

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(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. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly. We include contracts for which we have an early termination option if the option is not currently expected to be exercised.

(3)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2021. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Does not include incremental volumes of approximately 1,790 TBtu and 548 TBtu, respectively, pursuant to an amended IPM agreement and GSA with EOG that was executed subsequent to December 31, 2021, a portion of which is conditional on the in-service date of certain asset infrastructure and substantially all of which will be delivered after 2026. See Overview of Significant Events for additional discussion.

(4)Includes $0.4 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements.

(5)Capital expenditures primarily consist of costs incurred through our EPC contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Train 6 of the SPL Project, which achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction.

(6)Other purchase obligations include payments under SPL’s partial TUA assignment agreement with Total, as discussed in Note 13—Revenues from Contracts with Customers of our Notes to Consolidated Financial Statements.

(7)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, 2021 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 the payment of a fixed amount that is 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.

Natural Gas Supply, Transportation and Storage Service Agreements

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

As of December 31, 2021, we have secured approximately 86% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2022. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2022. 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, 2021 and those executed by CCL Stage III, we have secured up to 10,872 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 Consolidated Financial Statements.

To ensure that we are able to transport natural gas feedstock to the Corpus Christi and Sabine Pass LNG terminals, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity from 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 engineering, procurement and construction (“EPC”) of our Liquefaction Projects. The historical contracts have been executed with Bechtel, who has charged a lump sum for all work performed and generally bore project cost, schedule and performance risks unless certain specified events occurred,

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in which case Bechtel caused us to enter into a change order, or we agreed with Bechtel to a change order. The future capital expenditures included in the table above primarily consist of costs incurred under the Bechtel EPC contract for Train 6 of the SPL Project. The total contract price of the EPC contract for Train 6, which achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction is approximately $2.5 billion. We anticipate our future cash requirements for capital expenditures will increase in connection with the expected final investment decision (“FID”) of Corpus Christi Stage 3. See Financially Disciplined Growth section for further discussion.

Leases

Our obligations under our lease arrangements primarily consist of LNG vessel time charters with terms of up to 10 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 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, 2021, selling, general and administrative expense was $0.3 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. Our full-time employee headcount was 1,550 as of January 31, 2022.

Financially Disciplined Growth

We expect to reach FID of Corpus Christi Stage 3 in 2022, which will result in additional cash requirements to fund the construction and operations of Corpus Christi Stage 3 in excess of our current contractual obligations under executed contracts discussed above. However, in connection with reaching FID, we expect to secure financing to meet the cash needs that Corpus Christi Stage 3 will initially require, in support of commercializing the project.

Beyond Corpus Christi Stage 3, our significant land positions at the Corpus Christi and Sabine Pass LNG terminals 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 or Sabine Pass LNG terminals 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, 2021 (in billions):

(1)The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. 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.

(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, 2021, excluding debt and interest payments on the 2045 Cheniere Convertible Senior Notes which are based on the redemption payment made January 5, 2022. In December 2021, we issued a notice of redemption for all $0.6 billion aggregate principal amount outstanding of the 2045 Cheniere Convertible Senior Notes. The redemption payment of $0.5 billion is included in 2022 debt payments for consistency

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with expected cash flow presentation in our Consolidated Statements of Cash Flows when the instrument settles. Other than debt and interest payments on the 2045 Cheniere Convertible Senior Notes, 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 11—Debt of our Notes to Consolidated Financial Statements.

Debt

As of December 31, 2021, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $27.8 billion, credit facilities with an aggregate outstanding balance of $2.0 billion and convertible notes with an outstanding principal balance of $625 million. As of December 31, 2021, 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, 2021, our senior notes had a weighted average contractual interest rate of 4.84%, our credit facilities had weighted average interest rates on outstanding balances ranging from 1.85% to 3.50% and our convertible notes had an effective interest rate of 9.4%. Borrowings under our credit facilities are indexed to LIBOR, which is expected to be phased out by 2023. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We amended certain credit facilities in 2021 to establish a SOFR-indexed replacement rate for LIBOR. We intend to continue working with our lenders and counterparties to pursue amendments to our debt and interest rate swap agreements that are currently indexed to LIBOR. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.20% to 0.50%. Issued letters of credit under our credit facilities are subject to letter of credit fees ranging from 1.25% to 1.625%. We had $756 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2021.

Additional Future Cash Requirements for Financing

CQP Distribution

CQP is required by its partnership agreement to 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, 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, 2021, CQP paid $649 million in distributions to its non-controlling interest.

Capital Allocation Plan

Cheniere Dividend

In September 2021, Cheniere declared an inaugural quarterly dividend of $0.33 per common share. As of December 31, 2021, there were 253.6 million shares of our common stock outstanding. On January 25, 2022, we declared a quarterly dividend of $0.33 per common share that is payable on February 28, 2022 to shareholders of record as of February 7, 2022.

Share Repurchase Program

In 2019, our Board authorized a three-year, $1.0 billion share repurchase program. In 2021, our Board authorized a reset of the share repurchase program, which reset the available balance to $1.0 billion, inclusive of any amounts remaining under the previous authorization as of September 30, 2021, for an additional three years beginning on October 1, 2021. As of December 31, 2021, we had up to $998 million 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, 2021, we repurchased a total of 0.1 million shares of our common stock for $9 million at a weighted average price per share of $87.32. 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.

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Debt Repurchases, Repayments and Redemptions

We expect to repurchase, repay or redeem approximately $1.0 billion of existing indebtedness each year through 2024, with the intent of reaching investment grade consolidated credit metrics by the early-to-mid 2020s. Going forward, we expect to prioritize repayment of secured callable or maturing project debt to strengthen project credit metrics and lessen subordination of the corporate level credit profiles.

Financially Disciplined Growth

We expect to reach FID of Corpus Christi Stage 3 in 2022, which will increase cash requirements for financing the construction of Corpus Christi Stage 3. To the extent that liquefaction capacity at the Corpus Christi and Sabine Pass LNG terminals is expanded beyond the Liquefaction Projects and Corpus Christi Stage 3, 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 for the years ended December 31, 2021 and 2020 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.

Operating Cash Flows

Our operating cash net inflows during the years ended December 31, 2021 and 2020 were $2,469 million and $1,265 million, respectively. The $1,204 million increase in operating cash inflows in 2021 compared to 2020 was primarily related to increased cash receipts from the sale of LNG cargoes due to higher revenue per MMBtu and higher volume of LNG delivered, as well as from higher than normal contributions from LNG and natural gas portfolio optimization activities due to significant volatility in LNG and natural gas markets during the year ended December 31, 2021. Partially offsetting these operating cash inflows were higher operating cash outflows due to higher natural gas feedstock costs and payment of paid-in-kind interest on our convertible notes.

Investing Cash Flows

Our investing cash net outflows in both years primarily was for the construction costs for the Liquefaction Projects. The $1,035 million decrease in 2021 compared to 2020 was primarily due to the completion of Train 3 of the CCL Project in March 2021, which was under construction throughout 2020. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, we purchased land adjacent to the CCL Project for potential future expansion purposes and received proceeds from the sale of fixed assets from divestment of non-core land holdings.

Financing Cash Flows

During the year ended December 31, 2021, we had total debt issuances of $5,911 million, which was comprised of $3,932 million aggregate principal amount of senior notes and aggregate borrowings of $1,979 million under our credit facilities. The proceeds from these issuances and borrowings, together with cash on hand, were used to redeem or repay a total of $6,810 million in debt, comprised of $3,600 million aggregate principal amount of senior notes, $295 million of our 4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Notes”) and $2,915 million aggregate outstanding borrowings under our credit facilities.

During the year ended December 31, 2020, we had total debt issuances of $7,823 million, which was comprised of $4,764 million aggregate principal amount of senior notes and aggregate borrowings of $3,059 million under our credit

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facilities. The proceeds from these issuances and borrowings, together with cash on hand, were used to redeem or repay a total of $6,940 million in debt, comprised of $2.0 billion aggregate principal amount of SPL’s 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”) $1,513 million of our convertible notes and $3,427 million aggregate outstanding borrowings under our credit facilities. Additionally, during the year ended December 31, 2020, we entered into the 2020 SPL Working Capital Facility to replace the previous working capital facility.

Debt Issuances and Related Financing Costs

The following table shows the issuances of debt during the years ended December 31, 2021 and 2020, including intra-quarter borrowings (in millions):

During the years ended December 31, 2021 and 2020, we incurred debt issuance costs and other financing costs of $53 million and $125 million, respectively, related to the debt issuances above and closing of credit facilities during the respective periods.

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Debt Redemptions and Repayments and Related Modification or Extinguishment Costs

The following table shows the redemptions and repayments of debt during the years ended December 31, 2021 and 2020, including intra-quarter repayments (in millions):

During the years ended December 31, 2021 and 2020, we incurred debt modification or extinguishment costs of $82 million and $172 million, respectively, related to these redemptions and repayments, primarily for the payment of early redemption fees and write off of unamortized issuance costs.

Non-Controlling Interest Distributions

In addition to the above debt transactions, CQP paid distributions during the years ended December 31, 2021, 2020 and 2019 to non-controlling interests since we own 48.6% limited partner interest in CQP and the remaining non-controlling interest is held by Blackstone Inc., Brookfield Asset Management Inc. and the public. During the year ended December 31, 2021, CQP paid $649 million in distributions to its non-controlling interest. During the years ended December 31, 2021 and 2020, we also paid $9 million and $155 million, respectively, to repurchase approximately 0.1 million shares and 2.9 million shares, respectively, of our common stock under our share repurchase program.

Summary of Critical Accounting Estimates

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

Fair Value of Derivative Instruments

All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. 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. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation approaches. Such evaluations may involve significant judgment and the results are based on expected future events or conditions, particularly for those valuations using inputs unobservable in the market as discussed below.

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Our derivative instruments consist of interest rate swaps, financial commodity derivative contracts transacted in an over-the-counter market, physical commodity contracts and foreign currency exchange (“FX”) contracts. We value our interest rate swaps using observable inputs including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. Valuation of our financial commodity derivative contracts is determined using observable commodity price curves and other relevant data. We estimate the fair values of our FX derivative instruments using observable FX rates and other relevant data.

Valuation of our physical commodity derivative contracts, consisting primarily of natural gas supply contracts for the operation of our liquified natural gas facilities, is often developed through the use of internal models which incorporate significant observable and unobservable inputs. 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 volatility, 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.

The valuation of certain physical commodity derivatives requires the use of significant unobservable inputs and 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 is the change in unrealized valuation gain (loss) of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2021 and 2020 (in millions). The changes shown are limited to instruments still held at the end of each respective period.

The $4.3 billion unrealized valuation loss on instruments held during the year ended December 31, 2021 is primarily attributed to significant appreciation in estimated forward international LNG commodity curves on our IPM agreements from December 31, 2020 to December 31, 2021, relative to prior comparative period.

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.

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.