Washington, D.C. 20549
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $17.5$21.8 billion as of June 28, 2019.30, 2021.
As used in this annual report, the terms listed below have the following meanings:
The following diagram depicts our abbreviated legal entity structure as of December 31, 2019,2021, including our ownership of certain subsidiaries, and the references to these entities used in this annual report:
Unless the context requires otherwise, references to “Cheniere,” the “Company,” “we,” “us” and “our” refer to Cheniere Energy, Inc. and its consolidated subsidiaries, including our publicly traded subsidiary, Cheniere Partners.CQP.
Unless the context requires otherwise, references to the “CCH Group” refer to CCH, HoldCo II, CCH HoldCo I, CCH, CCL and CCP, collectively.
This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the
forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.
Cheniere Energy, Inc. (“Cheniere”), a Delaware corporation, was organized in 1983 and is a Houston-based 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 aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.
We own and operate the Sabine Pass LNG terminal in Louisiana, one of the largest LNG production facilities in the world, through our ownership interest in and management agreements with Cheniere Energy Partners, L.P. (“Cheniere Partners”CQP”), which is a publicly traded limited partnership that we created in 2007. As of December 31, 2019,2021, we owned 100% of the general partner interest and 48.6% of the limited partner interest in Cheniere Partners. We also own and operateCQP.
Additionally, separate from the CCH Group, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project (“Corpus Christi Stage 3”) through our subsidiary Cheniere Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”) for up to seven midscale Trains with an expected total production capacity of approximatelyover 10 mtpa of LNG. We received approval from FERC in November 2019 to site, construct and operate the expansion project.
We remain focused on operational excellence and customer satisfaction. Increasing demand offor LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Projects as a result of debottlenecking and other optimization projects. We hold significant land positions at both the Sabine Pass LNG terminal and the Corpus Christi LNG terminal, which provide opportunity for further liquefaction capacity expansion. 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 can make a final investment decision (“FID”).
Our primary business strategy is to be a full service LNG provider to worldwide end-use customers. We accomplish this objective by owning, constructing and operating LNG and natural gas infrastructure facilities to meet our long-term customers’ energy demands and:
maintaining a flexible capital structure to finance the acquisition, development, construction and operation of the energy assets needed to supply our customers.customers;
LNG Terminals and Marketing
Our Business
We shipped our first LNG cargo in February 2016 and we shipped our 1,000th cargo in January 2020.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. Cheniere’s LNG has been shipped to over 3037 countries and regions around the world.
Sabine Pass LNG Terminal
Liquefaction Facilities
The SPL Project is one of the largest LNG production facilities in the world. Through Cheniere Partners,CQP we are currently operating fiveoperate six Trains, including Train 6 which achieved substantial completion on February 4, 2022, and two marine berths at the SPL Project, and are constructing one additional Train. We have received authorization froma third marine berth. The SPL Project has a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the FERC to site, construct and operate Trains 1 through 6. We have achieved substantial completionEPC of the first five TrainsTrain 6 of the SPL Project and commenced commercial operating activities for each Train at various times starting in May 2016.Project. The following table summarizes the project completion and construction status of Train 6 of the SPL Project as of December 31, 2019:
|
| | | | | | | | | | |
| | SPL Train 6 |
Overall project completion percentage | | 43.7%99.5% |
Completion percentage of: | |
|
Engineering | | 91.5%100.0% |
Procurement | | 60.9%100.0% |
Subcontract work | | 37.4%99.6% |
Construction | | 9.7%98.8% |
Date of expected substantial completion | | 1H 2023February 4, 2022 |
The following summarizes the volumes of natural gas for which we have received approvals from FERC to site, construct and operate the SPL Project and the orders we have been issued byreceived from the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:terminal through December 31, 2050:
Trains 1 through 4—FTA countries | | | | | | | | | | | | | | | | | | | | | | | |
| FERC Approved Volume | | DOE Approved Volume |
| (in Bcf/yr) | | (in mtpa) | | (in Bcf/yr) | | (in mtpa) |
FTA countries | 1,661.94 | | 33 | | 1,661.94 | | 33 |
Non-FTA countries | 1,661.94 | | 33 | | 1,509.3 (1) | | 30 |
(1)The authorization for a 30-year term, which commenced in May 2016, and non-FTA countries for a 20-year term, which commenced in June 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803additional 152.64 Bcf/yr of natural gas).
Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term, both of which commenced in December 2018, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr(approximately 3 mtpa) of natural gas (approximately 4 mtpa).is currently pending.
Trains 5
Natural Gas Supply, Transportation and 6—FTA countries and non-FTA countries for a 20-year term, which partially commenced in June 2019 and the remainder commenced in September 2019, in an amount up to a combined total of 503.3 Bcf/yr ofStorage
SPL has secured natural gas (approximately 10 mtpa).
In each case, the terms of these authorizations began on the earlier of the date of first export thereunder or the date specified in the particular order. In addition, SPL received an order providingfeedstock for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes SPL was authorized but unable to export during any portion of the initial 20-year export period of such order.
The DOE issued orders authorizing SPL to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing January 2020, in an aggregate amount up to the equivalent of 600 Bcf ofthrough long-term natural gas (however, exports under this order, when combined with exports under the orders above, may not exceed 1,509 Bcf/yr).
An application was filed in September 2019supply agreements. Additionally, to authorize additional exports from the SPL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 153 Bcf/yr of natural gas, for a total SPL Project export of approximately 1,662 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the SPL Project of the volumes contemplated in the application. The application is currently pending before DOE.
Customers
SPL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) with eight third parties for Trains 1 through 6 of the SPL Project. Under these SPAs, the customers will purchase LNG from SPL 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 equal to approximately 115% of Henry Hub. The 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 volumesensure that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.
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. After giving effect to an SPA that Cheniere has committed to provide to SPL by the end of 2020, the annual fixed fee portion to be paid by the third-party SPA customers would increase to at least $3.3 billion, which is expected to occur upon the date of first commercial delivery of Train 6.
In addition, Cheniere Marketing has agreements with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers. See Marketing section for additional information regarding agreements entered into by Cheniere Marketing.
The annual contracted cash flows from fixed fees of each buyer of LNG under SPL’s third-party SPAs that constitute more than 10% of SPL’s aggregate fixed fees under all its SPAs are:
approximately $720 million from BG Gulf Coast LNG, LLC (“BG”), which is guaranteed by BG Energy Holdings Limited;
approximately $550 million from Korea Gas Corporation (“KOGAS”);
approximately $550 million from GAIL;
approximately $450 million from Naturgy LNG GOM, Limited (formerly known as Gas Natural Fenosa LNG GOM, Limited) (“Naturgy”), which is guaranteed by Naturgy Energy Group, S.A. (formerly known as Gas Natural SDG S.A.); and
approximately $310 million from Total Gas & Power North America, Inc. (“Total”), which is guaranteed by Total S.A.
The annual aggregate fixed fees for all of SPL’s other SPAs with third-parties is approximately $490 million, prior to giving effect to an SPA that Cheniere has committed to provide to SPL by the end of 2020.
Natural Gas Transportation, Storage and Supply
To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal and manage inventory levels, it has entered into transportation precedent and other agreements to secure firm pipeline transportation and storage capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements withfrom third parties to assist in managing variability in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of December 31, 2019, SPL had secured up to approximately 3,850 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.parties.
Construction
SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the SPL Project, under which Bechtel charges a lump sum for all work
performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.
The total contract price of the EPC contract for Train 6 of the SPL Project is approximately $2.5 billion, including estimated costs for an optional third marine berth. As of December 31, 2019, we have incurred $1.1 billion under this contract.
Regasification Facilities
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. ApproximatelySPLNG has entered into two long-term, third party TUAs for an aggregate of 2 Bcf/d, of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the regasification capacity they have reserved at the Sabine Pass LNG terminal. Each of Total and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1 Bcf/d of regasification capacity and is 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.
The remaining approximately 2 Bcf/d of capacity has been reserved under a TUA by SPL. 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 upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6. 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. During the years ended December 31, 2019, 2018 and 2017, SPL recorded $104 million, $30 million and $23 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.
Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.
Corpus Christi LNG Terminal
Liquefaction Facilities
We are currently operating twooperate three Trains and onetwo marine berthberths at the CCL Project and are constructing one additional Train and marine berth. We have received authorization from the FERC to site, construct and operate Trains 1 through 3 of the CCL Project. We completed construction of Trains 1 and 2 of the CCL Project and commenced commercial operating activities in February 2019of Trains 1, 2 and August 2019, respectively. The following table summarizes the project completion and construction status of Train 3 of the CCL Project including the related infrastructure, as of December 31, 2019:
|
| | | |
| | CCL Train 3 |
Overall project completion percentage | | 74.8% |
Completion percentage of: | | |
Engineering | | 98.7% |
Procurement | | 99.5% |
Subcontract work | | 28.3% |
Construction | | 49.5% |
Expected date of substantial completion | | 1H 2021 |
in February 2019, August 2019 and March 2021, respectively. Separate from the CCH Group, we are also developing Corpus Christi Stage 3 with up to seven midscale Trains through our subsidiary CCL Stage III, adjacent to the CCL Project. We
The following summarizes the volumes of natural gas for which we have received approvalapprovals from FERC in November 2019 to site, construct and operate seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG.
The followingthe CCL Project and Corpus Christi Stage 3 and the orders we have been issued byreceived from the DOE authorizing the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal:terminal through December 31, 2050:
CCL Project—FTA countries for a 25-year term and to non-FTA countries for a 20-year term, both of which commenced in June 2019, up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas. | | | | | | | | | | | | | | | | | | | | | | | |
| FERC Approved Volume | | DOE Approved Volume |
| (in Bcf/yr) | | (in mtpa) | | (in Bcf/yr) | | (in mtpa) |
CCL Project: | | | | | | | |
FTA countries | 875.16 | | 17 | | 875.16 | | 17 |
Non-FTA countries | 875.16 | | 17 | | 767 (1) | | 15 |
Corpus Christi Stage 3: | | | | | | | |
FTA countries | 582.14 | | 11.45 | | 582.14 | | 11.45 |
Non-FTA countries | 582.14 | | 11.45 | | 582.14 | | 11.45 |
Corpus Christi Stage 3—FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount equivalent to 582.14 Bcf/yr (approximately 11 mtpa) of natural gas.
In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from seven to 10 years from the date the order was issued.
An application was filed in September 2019 to authorize additional exports from the CCL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 108 Bcf/yr of natural gas, for a total CCL Project export of 875.16 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the CCL Project of the volumes contemplated in the application. The application is currently pending before DOE.
Customers
CCL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) with nine third parties for Trains 1 through 3 of the CCL Project. Under these SPAs, the customers will purchase LNG from CCL on a 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 equal to approximately 115% of Henry Hub. The 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. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the CCL Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for the applicable Train, as specified in each SPA.
In aggregate, the minimum fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to approximately $1.4 billion upon the date of first commercial delivery for Train 2 and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the CCL Project.
The annual contracted cash flows from fixed fees of each buyer of LNG under CCL’s third-party SPAs that constitute more than 10% of CCL’s aggregate fixed fees under all its SPAs for Trains 1 through 3 of the CCL Project are:
approximately $410 million from Endesa S.A.;
approximately $280 million from PT Pertamina (Persero); and
| | |
• | approximately $270 million from Naturgy, which is guaranteed by Naturgy Energy Group, S.A.
|
The average annual contracted cash flow from fixed fees for all of CCL’s other SPAs with third-parties is approximately $790 million.
In addition, Cheniere Marketing has agreements with CCL to purchase: (1) 15 TBtu per annum of LNG withThe authorization for an approximate term of 23 years, (2) any LNG produced by CCL in excess of that required for other customers at Cheniere Marketing’s option and (3) 0.85 mtpa of LNG with a term of up to seven years associated with an IPM gas supply agreement, as described below. See Marketing section for additional information regarding agreements entered into by Cheniere Marketing.
Natural Gas Transportation, Storage and Supply
To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline
companies. CCL has entered into a firm storage services agreement with a third party to assist in managing variability in natural gas needs for the CCL Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the CCL Project. As of December 31, 2019, CCL had secured up to approximately 2,999 TBtu108.16 Bcf/yr (approximately 2 mtpa) of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to eight years, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.
CCL Stage III has also entered into long-term natural gas supply contracts with third parties, and anticipates continuing to enter into such agreements, in order to secure natural gas feedstock for Corpus Christi Stage 3. As of December 31, 2019, CCL Stage III had secured up to approximately 2,361 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to approximately 15 years, which is subject to the achievement of certain project milestones and other conditions precedent.
A portion of the natural gas feedstock transactions for CCL and CCL Stage III are IPM transactions, in which the natural gas producers are paid based on a global gas market price less a fixed liquefaction fee and certain costs incurred by us.
Construction
CCL entered into separate lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 3 of the CCL Project under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause CCL to enter into a change order, or CCL agrees with Bechtel to a change order.
The total contract price of the EPC contract for Train 3, which is currently under construction, is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2019. As of December 31, 2019, we have incurred $2.0 billion under this contract.pending.
Final Investment Decision for Corpus Christi Stage 3
FID for Corpus Christi Stage 3 will be subject to, among other things, entering into an EPC contract, obtaining additional commercial support for the project and securing the necessary financing arrangements.
Pipeline Facilities
In December 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the Natural Gas Act of 1938, as amended (the “NGA”), authorizing CCP to construct and operate the Corpus Christi Pipeline. The Corpus Christi Pipeline is designed to transport 2.25 Bcf/d of natural gas feedstock required by the CCL Project from the existing regional natural gas pipeline grid. The construction of the Corpus Christi Pipeline was completed in the second quarter of 2018.
In November 2019, the FERC authorized CCP to construct and operate the pipeline for Corpus Christi Stage 3. The pipeline will be designed to transport 1.5 Bcf/d of natural gas feedstock required by Corpus Christi Stage 3 from the existing regional natural gas pipeline grid.
Natural Gas Supply, Transportation and Storage
CCL has secured natural gas feedstock for the Corpus Christi LNG terminal through traditional long-term natural gas supply and IPM agreements. CCL Stage III has also entered into long-term natural gas supply contracts with third parties, including IPM agreements, and anticipates continuing to enter into such agreements, in order to secure natural gas feedstock for Corpus Christi Stage 3. Additionally, to ensure that CCL is able to transport and manage the natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation and storage capacity from third parties.
Final Investment Decision for Corpus Christi Stage 3
FID for Corpus Christi Stage 3 will be subject to, among other things, entering into an EPC contract for the project and securing the necessary financing arrangements.
Marketing
We market and sell LNG produced by the Liquefaction Projects that is not required for other customers through Cheniere Marketing, our integrated marketing function. We have, and continue to develop, a portfolio of long-, medium- and short-term SPAs to transport and unload commercial LNG cargoes to locations worldwide. These volumes are expected to
Customers
Significant Customers
The following table shows customers with revenues of 10% or greater of total revenues from external customers:
|
| | | | | |
| Percentage of Total Revenues from External Customers |
| Year Ended December 31, |
| 2019 | | 2018 | | 2017 |
BG and its affiliates | 16% | | 18% | | 24% |
Naturgy | 10% | | 14% | | 14% |
KOGAS | 11% | | 19% | | 14% |
GAIL | 11% | | 13% | | * |
JERA Co., Inc. | * | | * | | 17% |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Percentage of Total Revenues from External Customers |
| | | | Year Ended December 31, |
| | | | | | 2021 | | 2020 | | 2019 |
BG Gulf Coast LNG, LLC and affiliates | | | | | | 12% | | 14% | | 16% |
Naturgy LNG GOM, Limited | | | | | | 12% | | 12% | | 10% |
Korea Gas Corporation | | | | | | 10% | | 10% | | 11% |
GAIL (India) Limited | | | | | | * | | 10% | | 11% |
| | | | | | | | | | |
* Less than 10%
Competition
If and when SPL, CCL or our integrated marketing function need to replace any existing SPA or enter into new SPAs, they will compete on the basis of price per contracted volume of LNG with each other and other natural gas liquefaction projects throughout the world. Revenues associated with any incremental volumes, including those sold by our integrated marketing function discussed above, will also be subject to market-based price competition. ManyAll of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to markets than us. We have proximityabove customers contribute to our customers, with offices located in Houston, London, Singapore, Beijing and Tokyo.LNG revenues through SPA contracts.
SPLNG currently does not experience competition for its terminal capacity because the entire approximately 4 Bcf/d of regasification capacity that is available at the Sabine Pass LNG terminal has been fully contracted. If and when SPLNG has to replace any TUAs, it will compete with other then-existing LNG terminals for customers.
Governmental Regulation
Our LNG terminals and pipelines are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These rigorous regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.
Federal Energy Regulatory Commission
The design, construction, operation, maintenance and expansion of our liquefaction facilities, the import or export of LNG and the purchase and transportation of natural gas in interstate commerce through our pipelines (including our Creole Trail Pipeline and Corpus Christi Pipeline) are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA.Natural Gas Act of 1938, as amended (the “NGA”). Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale for resale of natural gas in interstate commerce, to natural gas companies engaged in such transportation or sale and to the construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.
The FERC’s authority to regulate interstate natural gas pipelines and the services that they provide generally includes regulation of:
•rates and charges, and terms and conditions for natural gas transportation, storage and related services;
•the certification and construction of new facilities and modification of existing facilities;
•the extension and abandonment of services and facilities;
•the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;
•the acquisition and disposition of facilities;
•the initiation and discontinuation of services; and
•various other matters.
Under the NGA, our pipelines are not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including its own marketing affiliate. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates. Although the provisions that codified FERC’s policy in this area expired on January 1, 2015, we see no indication that the FERC intends to change its policy in this area. On February 18, 2022,
FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for FERC’s decision-making process, which would now include, among other things, reasonably foreseeable greenhouse gas emissions that may be attributable to the project and the project’s impact on environmental justice communities. These FERC changes are the first revision in more than 20 years to FERC’s policy for the certification of new interstate natural gas pipeline projects under Section 7 of the NGA. The updated Policy Statement has more limited applicability to LNG projects regulated under Section 3 of the Natural Gas Act. While the impact on our future projects and expansions is not known at this time, we do not expect it to have a material adverse effect on our operations.
We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate automatically granted by the FERC with the issuance of our Certificate of Public Convenience and Necessity to our marketing affiliates. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.
In order to site, construct and operate our LNG terminals, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct, amendments to the NGA. For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law.
The FERC issued its final ordersOrder Granting Section 3 Authority (“Order”) in April and July 2012 approving our application for an order under Section 3 of the NGA authorizing the siting, construction and operation of Trains 1 through 4 of the SPL Project (and related facilities). Subsequently, in May 2012, the FERC issued written approval to commence site preparation work for Trains 1 through 4. In October 2012, we applied to amend the FERC approval to reflect certain modifications to the SPL Project, and in August 2013, the FERC issued an orderOrder approving the modifications. In October 2013, we applied to further amend the FERC approval, requesting authorization to increase the total permitted LNG production capacity of Trains 1 through 4 from the then authorized 803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity of Trains 1 through 4. In February 2014, the FERC issued an order approving the October 2013 application (the “February 2014 Order”). A party to the proceeding requested a rehearing of the February 2014 Order, and in September 2014, the FERC issued an order denying the rehearing request (the “FERC Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) to review the February 2014 Order and the FERC Order Denying Rehearing. The court denied the petition in June 2016. In September 2013, we filed an application with the FERC for authorization to add Trains 5 and 6 to the SPL Project, which was granted by the FERC in an orderOrder issued in April 2015 and an orderOrder denying rehearing issued in June 2015. These ordersOrders are not subject to appellate court review. In October of 2018, SPL applied to the FERC for authorization to add a third marine berth to the Sabine Pass LNG terminal facilities.facilities, which FERC approved in February of 2020. FERC issued written approval to commence site preparation work for the third berth in June 2020.
The Creole Trail Pipeline, which interconnects with the Sabine Pass LNG terminal, holds a certificate of public convenience and necessity from the FERC under Section 7 of the NGA. The FERC’s approval under Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, may beis required prior to making any modifications to the Creole Trail Pipeline as it is a regulated, interstate natural gas pipeline. In February 2013, the FERC approved CTPL’s application for authorization to construct, own, operate and maintain certain new facilities in order to enable bi-directional natural gas flow on the Creole Trail Pipeline system to allow for the delivery of up to 1,530,000 Dekatherms per day of feed gas to the Sabine Pass LNG terminal. In November 2013, CTPL received approval from the Louisiana Department of Environmental Quality (“LDEQ”) for the proposed modifications and with subsequent final FERC clearance, construction was completed in 2015. In September 2013, as part of the Application for Trains 5 and 6, we filed an application with the FERC for authorization to construct and operate an extension and expansion of Creole Trail Pipeline and related facilities in order to deliver additional domestic natural gas supplies to the Sabine Pass LNG terminal, which was granted by the FERC in an order issued in April 2015 and an order denying rehearing issued in June 2015. These orders are not subject to appellate court review.
In December 2014, the FERC issued an order granting CCL authorization under Section 3 of the NGA to site, construct and operate Trains 1 through 3 of the CCL Project and issued a certificate of public convenience and necessity under Section 7(c) of the NGA authorizing construction and operation of the Corpus Christi Pipeline (the “December 2014 Order”). A party to the proceeding requested a rehearing of the December 2014 Order, and in May 2015, the FERC denied rehearing (the “Order
Denying Rehearing”). The party petitioned the relevant Court of Appeals to review the December 2014 Order and the Order Denying
Rehearing; that petition was denied on November 4, 2016. In June of 2018, CCL Stage III, CCL and CCPCorpus Christi Pipeline filed an application with the FERC for authorization under sectionSection 3 of the NGA to site, construct and operate additional facilities for the liquefaction and export of domestically-produced natural gas (“Corpus Christi Stage 3”)3 at the existing CCL Project.Project and pipeline locations. In November 2019, the FERC authorized CCP to construct and operate the pipeline for Corpus Christi Stage 3. Corpus Christi Stage 3 consists of the addition of seven midscale Trains and related facilities. The order is not subject to appellate court review. In 2020, FERC authorized Corpus Christi Pipeline to construct and operate a portion of Corpus Christi Stage 3 (Sinton Compressor Station Unit No. 1) on an interim basis independently from the remaining Corpus Christi Stage 3 facilities, which received FERC approval for in-service in December 2020.
On September 27, 2019, CCL and SPL filed a request with the FERC pursuant to sectionSection 3 of the NGA, requesting authorization to increase the total LNG production capacity of each terminal from currently authorized levels to an amount which reflects more accurately the capacity of each facility based on enhancements during the engineering, design and construction process, as well as operational experience to date. The requested authorizations do not involve construction of new facilities. Corresponding applications for authorization to export the incremental volumes were also submitted to the DOE. The DOE issued Orders granting authorization to export LNG to FTA countries in April 2020. The DOE authorization for export to non-FTA countries is still pending. In October 2021, the FERC issued its Orders Amending Authorization under Section 3 of the NGA.
The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in natural gas marketing functions. The general principles of the FERC Standards of Conduct are: (1) independent functioning, which requires transmission function employees to function independently of marketing function employees; (2) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (3) transparency, which imposes posting requirements to detect undue preference due to the improper disclosure of non-public transmission function information. We have established the required policies, procedures and training to comply with the FERC’s Standards of Conduct.
All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other material governmental and regulatory approvals and permits will be required throughout the life of our LNG terminals and our pipelines. In addition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of our facilities. For example, throughout the life of our LNG terminals and our pipelines, we are subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations have not materially affected our construction or operations.
DOE Export LicenseLicenses
The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal as discussed in Sabine Pass LNG Terminal—Liquefaction Facilities and the Corpus Christi LNG terminal as discussed in Corpus Christi LNG Terminal—Liquefaction Facilities. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.
Under Section 3 of the NGA applications for exports of natural gas to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest.
Pipeline and Hazardous Materials Safety Administration
Our LNG terminals as well as the Creole Trail Pipeline and the Corpus Christi Pipeline are subject to regulation by PHMSA. PHMSA is authorized by the applicable pipeline safety laws to establish minimum safety standards for certain pipelines and LNG facilities. The regulatory standards PHMSA has established are applicable to the design, installation, testing, construction, operation, maintenance and management of natural gas and hazardous liquid pipeline facilities and LNG facilities that affect interstate or foreign commerce. PHMSA has also established training, worker qualification and reporting requirements.
In October 2019, PHMSA published final rules revising its regulations governing the safety of certain gas transmission pipelines (effective July 1, 2020) and established new enforcement procedures for the issuance of temporary emergency orders (effective December 2, 2019).
PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $218,000$225,000 per day per violation, with a maximum administrative civil penalty of approximately $2$2.25 million for any related series of violations.
Other Governmental Permits, Approvals and Authorizations
Construction and operation of the Sabine Pass LNG terminal and the CCL Project require additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including the DOT, U.S. Army Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Services,Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the U.S. Environmental Protection Agency (the “EPA”), U.S. Department of Homeland Security, the LDEQ, the Texas Commission on Environmental Quality (“TCEQ”) and the Railroad Commission of Texas (“RRC”).
The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10) (the “Section 10/404 Permit”). The EPA administers the Clean Air Act (“CAA”), and has delegated authority to the TCEQ and LDEQ to issue the Title V Operating Permit (the “Title V Permit”) and the Prevention of Significant Deterioration Permit (the “PSD Permit”). These two permits are issued by the LDEQ for the Sabine Pass LNG terminal and CTPL and by the TCEQ for the CCL Project.
Commodity Futures Trading Commission (“CFTC”)
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.those markets. The regulatory regime created byCFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, is designed primarily to (1) regulate certain participants inincluding the swaps markets, including entities falling withinspeculative position limit rules which became effective on March 15, 2021 and have a phased-in compliance date that began on January 1, 2022. Given the categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of standardized swaps of certain classes as designated by the CFTC, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, (5) provide the CFTC with expanded authority to establish position limits on certain physical commodity futures and options contracts and their economically equivalent swaps as it finds necessary and appropriate and (6) otherwise enhance the rulemaking and enforcement authorityrecent enactment of the CFTC andspeculative position limit rules, as well as the SEC regarding the derivatives markets. Mostimpact of the regulations are already in effect, while other rules and regulations includingunder the proposed margin rules, position limits and commodity clearing requirements, remain to be finalized or effectuated. Therefore,Dodd-Frank Act, the impact of thosesuch rules and regulations on our business continues to be uncertain.
A provision of the Dodd-Frank Act requires the CFTC, in order to diminish or prevent excessive speculation in commodity markets, to adopt rules, as it finds necessary and appropriate, imposing new position limits on certain physical commodity futures contracts and options thereon, as well as economically equivalent swaps traded on registered swap trading platforms and on over-the-counter swaps that perform a significant price discovery function with respect to certain markets. In that regard, the CFTC has re-proposed position limits rules that would modify and expand the applicability of limits on speculative positions in certain physical commodity futures contracts and economically equivalent futures, options and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona fide hedging and other types of transactions. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.
Pursuant to rules adopted by the CFTC, certain interest rate swaps and index credit default swaps must be cleared through a derivatives clearing organization and executed on an exchange or swap execution facility. The CFTC has not yet proposed to designate swaps in any other asset classes, including swaps relating to physical commodities, for mandatory clearing and trade execution, but could do so in the future. Although we expect to qualify for the end-user exception from the mandatory clearing and exchange-trading requirements applicable to any swaps that we enter into to hedge our commercial risks, the mandatory clearing and exchange-trading requirements may apply to other market participants, including our counterparties (who may be registered as Swap Dealers), with respect to other swaps, and the application of such rules may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.
As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators havealso adopted rules to requirerequiring Swap Dealers and Major Swap Participants,(as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We expect to qualify as such a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.
Any new rules or changes to existing rules promulgated under the Dodd-Frank Act could (1) impair the availability of derivatives, (2) materially increase the cost of, or decrease the liquidity of, the derivatives we use to hedge, (3) significantly alter the terms and conditions of derivatives and (4) potentially increase our exposure to less creditworthy counterparties. Further, any resulting reduction in the use of derivatives could make cash flow more volatile and less predictable, which in turn could adversely affect our ability to plan for and fund capital expenditures.
Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.
United Kingdom /European Regulations
Our European Union (“EU”) trading activities, which are primarily established in and operated out of the United Kingdom (“UK”), are subject to a number of EU-wideEuropean Union (“EU”) and UK specific laws and regulations. These are described further below:regulations, including but not limited to:
•the European Market Infrastructure Regulation (“EMIR”)
EMIR is an EU regulation (with text that is relevant across the European Economic Area (“EEA”)), which was designed to increase the transparency and stability of the EEAEuropean Economic Area (“EEA”) derivatives markets, including by: (1) imposing requirements on market participants trading derivatives, including relating to reporting, clearing and risk mitigation; and (2) imposing rules and standards that apply to central counterparties (i.e. clearing houses) and trade repositories. The precise impact of these rules will depend on a number of factors, including markets;
•the regulatory status of the counterparty that is trading derivative instruments, as well as the volume and types of instruments it is trading. We currently are categorized under EMIR as a non-financial counterparty below the clearing threshold, which is a type of market participant subject to a lower regulatory burden. However, were we to engage in activities that resulted in a change to our status, we could be subject to more onerous regulations (including clearing and margining) which could significantly increase the cost of our derivatives trading activity, and materially alter the terms of the derivatives contracts we enter into.
Regulation on Wholesale Energy Market Integrity and Transparency (“REMIT”)
REMIT is an EU regulation (with EEA relevance) that, which prohibits market manipulation and insider trading in EuropeanEEA wholesale energy markets and imposes various transparency and other obligations on participants active in these markets. Market participants, such as us, cannot use inside information (i.e., non-public information that would likely have a significant effect on markets;
•the price of wholesale energy products if it were made public) to (1) buy or sell wholesale energy products for their own account or on behalf of a third party, directly or indirectly; (2) induce others to buy or sell wholesale energy products based on inside information; or (3) disclose such inside information to any other person except in the normal course of employment. A market participant is also prohibited from manipulating or attempting to manipulate any wholesale energy market, and is required to publicly disclose inside information which it possesses in respect of business or facilities which it or its affiliates either owns or controls, or for whose operational matters it or they are responsible, either in whole or in part.
Markets in Financial Instruments Directive and Regulation (“MiFID II”)
MiFID II consists of an EU directive, a regulation and a number of delegated acts, rules and guidance, that replaced the original 2004 Markets in Financial Instruments Directive (“MiFID”). MiFID II (with relevance throughout the EEA), which sets forth
an EEA-wide a financial services framework across the EEA, including rules for firms engaging in investment services and activities in connection with certain financial instruments, in including a range of commodity derivatives; and
•the EEA. Firms engaging in such activities must be authorized unless an exemption applies.
We are eligible to trade on our own account in commodity derivatives as a result of the “ancillary activity” exemption under MiFID II. To avail ourselves of this exemption, amongst other things, we must be able to demonstrate, on the basis of a methodology set out in certain delegated MiFID II text, that our activities in commodity derivatives are ancillary to the main business of our group. Provided we meet the requirements, we must notify the UK regulator that we are availing ourselves of this exemption on an annual basis. If, in the future, we are no longer able to meet the requirements of the “ancillary activity” exemption, and no other exemption is available to us, we would be required to become authorized as an investment firm under MiFID II. This may result in us being subject to the regulatory capital requirements under the EU’s Capital Requirements Directive IV.
Market Abuse Regulation (“MAR”)
MAR is intended, which was implemented to update and strengthen the existing EUcreate an enhanced market abuse framework, and which applies to all financial instruments listed or traded on EUEEA trading venues as well as other over-the-counter (“OTC”) financial instruments priced on, or impacting, the trading venue contract. Generally, MAR
Following the UK's departure from the EU (“Brexit”), the EU-wide rules that applied to the UK while it was a member of the EU (and during the transition period) have been replicated, subject to certain amendments, to create a parallel set of rules applicable only in the UK. As a result, we are subject to two sets of substantively similar rules based on the same underlying legislation: (i) one set of rules that apply in the EEA (i.e. not including the UK) (the “EEA Rules”); and (ii) one set of rules that apply only in the UK (the “UK Onshored Rules”).
To the extent our trading activities have a nexus with the EEA, we comply with the EEA Rules. However, as our trading activities are primarily operated out of the UK, the main rules that impact and apply to us on a day-to-day basis are the UK Onshored Rules.
In particular, under the UK Onshored Rules, firms engaging in investment services and activities under UK MiFID II must be authorized unless an exemption applies, and we qualify for an exemption and therefore do not need to entities trading on, or in a manner that impacts EU markets. MAR contains a number of “insider dealing” and “market manipulation” (including “attempted manipulation”) based offences. Under MAR, any person professionally arranging or executing transactions in financial instruments is required to establish and maintain effective arrangements, systems and procedures to detect and report suspicious orders and transactions.be authorized under UK MiFID II.
UK-Specific Rules
In addition to the variousUK Onshored Rules, we are also subject to a separate, UK-specific regime that is not based on prior EU/EEA rules described above, other UK-specific laws, such aslegislation. This is primarily set out in the UK’s Financial Services and Markets Act of 2002000 (“FSMA”) and Financial Services and Markets Act 2000 (Regulated Activities) Order 2001 (“RAO”), also applywhich, among other things, governs the regulation of financial services and markets in the UK, and contains a definitive list of the specified kinds of activities and products that are regulated. Under these UK-specific rules, a firm engaging in regulated activities must be authorized unless an exclusion applies. We qualify under applicable exclusions and therefore are not required to our trading activities.be authorized under the UK FSMA/RAO regime.
Any violation of the foregoing laws and regulations could result in investigations, and possible finefines and penalties, and in some scenarios, criminal offenses.offenses, as well as reputational damage.
Brexit and Equivalence
The UK withdrew from the EU (“Brexit”) on January 31, 2020, and the withdrawal may have an impact on the applicability of the current EU Regulations and Directives that govern our various trading activities. The precise impacts will depend on the negotiations that will occur duringwith the transition period ending as of January 1, 2021. A trade deal (the “Deal”) was agreed and ratified by both the UK and the EU, avoiding a “no deal” Brexit.
One area notably absent from the Deal was financial services. The UK and EU are working towards formally agreeing a memorandum of understanding (the “MoU”) on access to financial services, the text of which is currently scheduledwas agreed in principle in March 2021. This was expected to end on December 31, 2020,be formally ratified and published in 2021, but so far this has not occurred. In any event, an MoU would be less far-reaching than a legal text such as well as other factorsan international treaty.
The issue of whether the UK's financial system will be granted “equivalence” by the EU (the scenario that may or may not be addressed during the negotiations. We anticipate that impacts could include a possible requirement to registerwould result in the least disruption and would treat compliance with UK rules as being equivalent to compliance with the corresponding EU for certain activities,rules) has not been resolved, and at present seems unlikely to be agreed. The UK also has the possible reclassification of products traded onright to declare whether EU
financial services rules are “equivalent” to its own rules. Each side's equivalence decision will be made unilaterally, and could be withdrawn unilaterally as well.
Additionally, there is no guarantee that any equivalence decision, if granted, will be comprehensive across all financial services. In the meantime, UK exchanges for EU purposes and products traded on EU exchanges for UK purposes and possible impacts on our treatment related to various regulatory statuses (e.g., clearing threshold classifications and other safe harbors and exemptions). During this transition period,firms must comply with the UK will continue to be subject to EU Regulations and Rules, with the objective being to provide as smooth a transition as possible for businesses. Until additional clarity surrounding Brexit is obtained, other impacts pertaining to our trading activities could occur.Onshored Rules.
Environmental Regulation
Our LNG terminals are subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations require significant expenditures for compliance, can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.
Clean Air Act (“CAA”)
Our LNG terminals are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by any such requirements.
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of greenhouse gas (“GHG”) emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules havewere largely been stayed or repealed during the Trump Administration including by amendments adopted by the EPA on February 23, 2018 and additional proposed amendments to new source performance standards for the oil and gas industry on September 24, 2019,14 and 15, 2020. On November 15, 2021, the EPA’s June 19, 2019 adoptionEPA proposed new regulations to reduce methane emissions from both new and existing sources within the Crude Oil and Natural Gas source category. The proposed regulations if finalized, would result in more stringent requirements for new sources, expand the types of new sources covered, and for the Affordable Clean Energy rulefirst time, establish emissions guidelines for power generation.existing sources in the Crude Oil and Natural Gas source category. We are supportive of regulations reducing GHG emissions over time.
From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. In addition, many states have already taken regulatory action to monitor and/or reduce emissions of GHGs, primarily through the development of GHG emission inventories or regional GHG cap and trade programs. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs, the imposition of taxes or fees related to GHG emissions or additional operating restrictions and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Coastal Zone Management Act (“CZMA”)
The siting and construction of our LNG terminals within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, and in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.
Clean Water Act (“CWA”)
Our LNG terminals are subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants
into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ, and in Texas, by the TCEQ). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.
Resource Conservation and Recovery Act (“RCRA”)
The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.
Protection of Species, Habitats and Wetlands
Various federal and state statutes, such as the Endangered Species Act, (the “ESA”), the Migratory Bird Treaty Act, (“MBTA”), the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If one of our LNG terminals or pipelines adversely affects a protected species or its habitat, we may be required to develop and follow a plan to avoid those impacts. In that case, siting, construction or operation may be delayed or restricted and cause us to incur increased costs.
In August 2019, the U.S. Fish
It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and Wildlife Service (the “FWS”) announced a series of changes to the rules implementing the ESA, including revisions to the regulations governing interagency cooperation, listing specieswetlands and delisting critical habitat, and prohibitions related to threatened wildlife and plants. The revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions.
In addition, in December 2017, the Department of Interior’s (“DOI’s”) Solicitor’s Office issued an official opinion that the MBTA’s broad prohibition on “taking” migratory birds applies only to affirmative actions and does prohibit incidental harm. In April 2018, the FWS issued guidance consistent with the DOI’s opinion and on January 30, 2020, the FWS issued a proposed rule defining the scope of the MBTA to cover only actions directed at migratory birds, their nests or their eggs.
Weimpact our business. However, we do not believe that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by these recentsuch regulatory actions.
Market Factors and Competition
Market Factors
Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sale of LNG by Cheniere Marketing, or development of new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas, and economic growth in developing countries.countries and other related factors such as the effects of the COVID-19 pandemic. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our ability to access capital markets.
We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. GlobalPlayers around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure growth. Currently, significant amounts of money are being invested across Europe and Asia in natural gas projects under construction, and more continues to be earmarked to planned projects globally. Some examples include India’s commitment to invest over $60 billion to usher a gas-based economy, around $100 billion earmarked for Europe’s gas infrastructure buildout, and China’s hundreds of billions all along the natural gas value chain. We highlight regasification capacity, which will not only expand existing import capacities in rapidly growing markets like China and India, but also add new import markets all over the globe, raising the total number of import markets to approximately 60 by 2030 from 43 in 2020 and just 15 markets as recently as 2005.
As a result of these dynamics, global demand for natural gas is projected by the International Energy Agency to grow by approximately 2720 trillion cubic feet (“Tcf”) between 20182020 and 2030 and 3933 Tcf between 20182020 and 2035.2040. LNG’s share is seen growing from about 11% in 20182020 to about 16%12% of the global gas market in 2030 and 18%14% in 2035.2040. Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 79%57%, from approximately 316366.6 mtpa, or 15.217.6 Tcf, in 2018,2020, to approximately 566576.5 mtpa, or 27.227.7 Tcf, in 2030 and to 678734.5 mtpa or 32.635.3 Tcf in 2035.2040. WoodMac also forecasts LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 469517 mtpa in 2030, declining to 430456 mtpa in 2035.2040. This willcould result in a market need for construction of an additional approximately 9760 mtpa of LNG production by 2030 and about 248279 mtpa by 2035.2040. As a cleaner burning fuel with far lower emissions than coal or liquid fuels in power generation, we expect gas and LNG to play a central role in balancing grids
and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Projects and Corpus Christi Stage 3 are competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.
We have limited exposure to the decline in oil pricesprice movements as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes. We have contracted approximately 85%95% of the total production capacity from the Liquefaction Projects, including those contracts executed to support Corpus Christi Stage 3. Substantially all of our contracted capacity is from contracts with terms exceeding 10 years. Excluding contracts with terms less than 10 years, our SPAs and IPM agreements had approximately 17 years of weighted average remaining life as of December 31, 2021.
Competition
Despite the long term nature of our SPAs, when SPL, CCL or our integrated marketing function need to replace or amend any existing SPA or enter into new SPAs, they will compete with each other and other natural gas liquefaction projects throughout the world on a termthe basis which includes volumesof price per contracted under SPAs in which the customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveriesvolume of LNG cargoes, as well asat that time. Revenues associated with any incremental volumes, contracted under IPM gas supply agreements. Asincluding those sold by our integrated marketing function, will also be subject to market-based price competition. Many of January 31, 2020, U.S. natural gas prices indicatethe companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to LNG markets than us.
SPLNG currently does not experience competition for its terminal capacity because the entire approximately 4 Bcf/d of regasification capacity that is available at the Sabine Pass LNG exported from the U.S. continuesterminal has been fully contracted. If and when SPLNG has to be competitively priced, supporting the opportunityreplace any TUAs, it will compete with other then-existing LNG terminals for U.S. LNG to fill uncontracted future demand through the execution of long-term and medium-term contracting of LNG from our terminals.customers.
Subsidiaries
Our assets are generally held by our subsidiaries. We conduct most of our business through these subsidiaries, including the development, construction and operation of our LNG terminal business and the development and operation of our LNG and natural gas marketing business.
EmployeesHuman Capital Resources
We are in a unique position as the first U.S. LNG company in the lower 48. As the first mover, ensuring that we attract, retain and develop skilled employees has been a crucial part of our ability to grow and succeed.
WeAs of January 31, 2022, we had 1,5301,550 full-time employees with 1,456 located in the U.S. and 94 located outside of the U.S. (primarily in the UK).
Our strength comes from the collective expertise of our diverse workforce and through our core values of teamwork, respect, accountability, integrity, nimble and safety (“TRAINS”). Our employees help drive our success, build our reputation, establish our legacy and deliver on our commitments to our customers. Through fulfilling career opportunities, training, development and a competitive compensation program, we aim to keep our employees engaged. Our voluntary turnover was 5.4% for 2021.
Our Chief Human Resources Officer, along with senior leadership, are tasked with managing employment-related matters and initiatives including talent attraction and retention, rewards and remuneration, employee relations, employee engagement, diversity and inclusion, and training and development. We communicate progress on our human capital programs to our board of directors (our “Board”) quarterly.
Talent Attraction, Engagement and Retention
Through our recruitment efforts, we seek diverse talent to drive our corporate strategies and goals. We actively recruit at Januarycolleges and conduct information sessions at select universities, including Historically Black Colleges and Universities (“HBCUs”) and Hispanic-Serving Institutions. Internally and externally, we post openings to attract individuals with a range of backgrounds, skills and experience, offering employee bonuses for referring highly qualified candidates.
We manage and measure organizational health with a view to gaining insight into employees’ experiences, levels of workplace satisfaction and feelings of engagement and inclusion with the company through biennial engagement surveys. Insights from the biennial survey are used to develop both company-wide and business unit level organizational and talent development plans and training programs.
Compensation and Benefits
We provide robust compensation and benefits programs to our employees. In addition to salaries, all employees are eligible for annual bonuses and stock awards. Benefit plans, which vary by country, include a 401(k) Plan, healthcare and insurance benefits, health savings and flexible spending accounts, paid time off, family leave, family care resources, employee assistance programs and tuition assistance. This year we have enhanced ESG-related performance criteria linked to annual incentive compensation, adding targets for actions on diversity, equity and inclusion (“DEI”) and climate change to our Health & Safety performance goals.
Diversity, Equity and Inclusion
We are committed to providing a diverse culture where all employees can thrive and feel welcomed and valued. To create this environment, we are committed to equal employment opportunity and to compliance with all federal, state and local laws that prohibit workplace discrimination, harassment and unlawful retaliation. Our Code of Business Conduct and Ethics, Cheniere’s TRAINS values and both our discrimination and harassment and equal employment opportunity policies demonstrate our commitment to building an inclusive workplace, regardless of race, beliefs, nationality, gender and sexual orientation or any other status protected by our policy. We have provided executives and senior management with DEI training and have begun providing Unconscious Bias training to all employees.
Through our targeted recruitment efforts, we attract a variety of candidates with a diversity of backgrounds, skills, experience and expertise. Since 2016, we have had a 20% increase in racially or ethnically diverse employees and a 24% increase in racially or ethnically diverse management. In the past five years, the percentage of female employees has remained generally consistent at approximately 27% and we have had a 22% increase in women in management positions. In 2021, we announced our multiyear commitment to the Thurgood Marshall College Fund of $500,000 in scholarships to students attending selected HBCUs. We also committed to other scholarships and community efforts throughout 2021 furthering our commitment to DEI.
We encourage our employees to leverage their unique backgrounds through involvement in various employee resource groups and employee networks. Groups such as WILS (Women Inspiring Leadership Success), EPN (Emerging Professional Network) and Cultural Champions Teams help build a culture of inclusion.
Development and Training
As the first exporter of LNG in the lower 48 of the US, we faced the unique challenge of developing our own LNG talent. Our apprenticeship program prepares local students for careers in LNG. This program combines classroom education with training and on-site learning experiences at our facilities.
We strive to provide our people with all of the tools and support necessary for them to succeed. We actively encourage our employees to take ownership of their careers and offer a number of resources to do so. Employees undergo annual performance reviews to encourage the ongoing development of their skills and expertise. To ensure safe, reliable and efficient operations in a highly regulated environment, we offer online and site-specific learning opportunities. We also provide employees, leaders and executives with targeted development programming to solidify internal talent pipelines and succession plans.
Employee Safety, Health and Wellness
The safety of our employees, contractors and communities is one of our core values. Our Cheniere Integrated Management System defines our required safety programs and details safety and health related procedures. Safety efforts are led by our Executive Safety Committee, which includes the Chief Executive Officer, senior leaders from across the company, and representatives from each of our operating assets. We focus our efforts on continuously improving our performance. For the year ended December 31, 2020. 2021, we had one employee recordable injury and seven contractor recordable injuries. Our total recordable incident rate (employees and contractors combined) was 0.10, placing us in the top quartile of industry benchmarks based on Bureau of Labor safety statistics.
To support the well-being of our employees, we provide a wellness program that offers employees incentives to maintain an active lifestyle and set personal wellness goals. Incentives include online education related to health, nutrition, emotional health and COVID-19 vaccinations, as well as subsidies for fitness devices and gym memberships. We also offer mammography screenings, rooms for nursing mothers and biometric screenings on site.
In our continuing response to the COVID-19 pandemic, we have implemented workplace controls and risk reduction measures that have enabled us to work through several periods of elevated regional impacts from COVID-19, including the Delta and Omicron variants. We took certain measures that allow the company to maintain our operations, keep our employees safe and react quickly to any new COVID-19 risks. We also provided the same level of resources, aid and support for weather-related disasters.
Available Information
Our common stock has been publicly traded since March 24, 2003 and is traded on the NYSE American under the symbol “LNG.” Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.
We will also make available to any stockholder, without charge, copies of our annual report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Cheniere Energy, Inc., Investor Relations Department, 700 Milam Street Suite 1900, Houston, Texas 77002 or call (713) 375-5000. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers.
Additionally, we encourage you to review our Corporate Responsibility Report (located on our internet site at www.cheniere.com), for more detailed information regarding our Human Capital programs and initiatives, as well as our response to ESG issues. Nothing on our website, including our Corporate Responsibility Report or sections thereof, shall be deemed incorporated by reference into this Annual Report.
ITEM 1A. RISK FACTORS
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
Risks Relating to Our Business in General.
Risks Relating to Our Financial Matters
Our existing level of cash resources and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
As of December 31, 2019,2021, we had $2.5$1.4 billion of cash and cash equivalents, $520$413 million of current restricted cash and $31.5cash equivalents, a total of $3.4 billion of available commitments under our credit facilities and $30.4 billion of total debt outstanding on a consolidated basis (before unamortized premium, discount and debt issuance costs), excluding $1.5 billion aggregate outstanding letters. SPL, CQP, CCH and Cheniere operate with independent capital structures as further detailed in Note 11—Debt of credit.our Notes to Consolidated Financial Statements. We incur, and will incur, significant interest expense relating to the assets at the Sabine Pass and Corpus Christi LNG terminals, and we anticipate needing to incurincurring additional debt to finance the construction of Corpus Christi Stage 3. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.
We have not always been profitable historically. We may not achieve profitability or generate positive operating cash flow in the future.
We had net loss attributable to common stockholders of $393 million for the year ended December 31, 2017 and had losses in prior years.
In the future, we may incur operating losses and experience negative operating cash flow. We may not be able to reduce costs, increase revenues or reduce our debt service obligations sufficiently to maintain our cash resources, which could cause us to have inadequate liquidity to continue our business.
We will continue to incur significant capital and operating expenditures while we develop and construct the Liquefaction Projects, Corpus Christi Stage 3 and other projects. Any delays beyond the expected development period for these projects could cause operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under third-party agreements in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate any significant positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timely complete and operate the applicable project.
We may sell equity or equity-related securities or assets, including equity interests in Cheniere Partners. Such sales could dilute our stockholders’ proportionate indirect interests in our assets, business operations and proposed liquefaction and other projects of Cheniere Partners or other subsidiaries, and could adversely affect the market price of our common stock.
We have historically pursued a number of alternatives in order to finance the construction of our Trains, including potential issuances and sales of additional equity or equity-related securities by us or Cheniere Partners. Such sales, in one or more transactions, could dilute our stockholders’ proportionate indirect interests in our assets, business operations and proposed projects of Cheniere Partners, including the SPL Project, or in other subsidiaries or projects, including the CCL Project. In addition, such sales, or the anticipation of such sales, could adversely affect the market price of our common stock.
Our stockholders may experience dilution upon the conversion of our convertible notes.
In November 2014, we issued an aggregate principal amount of $1.0 billion Convertible Unsecured Notes due 2021 (the “2021 Cheniere Convertible Unsecured Notes”) to RRJ Capital II Ltd, Baytree Investments (Mauritius) Pte Ltd and Seatown Lionfish Pte. Ltd. In March 2015, we issued $625 million aggregate principal amount of 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) to certain investors through a registered direct offering. In May 2015, CCH HoldCo II issued $1.0 billion aggregate principal amount of 11.0% Convertible Senior Secured Notes due 2025 (the “2025 CCH HoldCo II Convertible Senior Notes” and together with the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes, the “Convertible Notes”) to EIG Management Company, LLC.
We have the option to satisfy the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes conversion obligations with cash, common stock or a combination thereof. The 2025 CCH HoldCo II Convertible Senior Notes conversion obligations must be satisfied with common stock. The 2021 Cheniere Convertible Unsecured Notes are convertible at an initial conversion price of $93.64. Prior to December 15, 2044, the 2045 Cheniere Convertible Senior Notes will be convertible upon the occurrence of certain conditions, and on and after such date they will become freely convertible. The 2045 Cheniere Convertible Senior Notes will become convertible into the common stock of Cheniere at an initial conversion price of $138.38 per share. Provided the total market capitalization of Cheniere at that time is not less than $10.0 billion and certain other conditions are satisfied, the 2025 CCH HoldCo II Convertible Senior Notes will be convertible at CCH HoldCo II’s option on or after March 1, 2020 (the “Eligible Conversion Date”). The conversion price for 2025 CCH HoldCo II Convertible Senior Notes converted at CCH HoldCo II’s option is the lower of (1) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date on which notice of conversion is provided. At the option of the holders, the 2025 CCH HoldCo II Convertible Senior Notes are convertible on or after the six-month anniversary of the Eligible Conversion Date, provided the total market capitalization of Cheniere at that time is not less than $10.0 billion and certain other conditions are satisfied, at a conversion price equal to the average of the daily VWAP of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided.
The conversion of some or all of the Convertible Notes into shares of our common stock will dilute the ownership percentages and voting power of our existing stockholders. Based on the initial conversion price, if we elect to satisfy the entire conversion obligations of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes with common stock, an aggregate of approximately 19.1 million shares of our common stock would be issued upon the conversion, assuming the notes are converted at maturity and all interest on the notes is paid in kind for the 2021 Cheniere Convertible Unsecured Notes. Because the conversion rate for the 2025 CCH HoldCo II Convertible Senior Notes will depend on the price of our common stock at the time of conversion, we cannot meaningfully estimate the number of shares of our common stock, if any, that would be issued upon the conversion of such notes; however, under these convertible notes, a maximum of 47,108,466 shares of our common stock (subject to adjustment in the event of a stock split) may be issued in the aggregate upon the conversion of all of the 2025 CCH HoldCo II Convertible Senior Notes. Any sales in the public market of the shares issuable upon conversion of the Convertible Notes could adversely affect the prevailing market prices of our common stock. In addition, the existence of the Convertible Notes may encourage short selling by market participants because the conversion of the Convertible Notes could be used to satisfy short positions, or the anticipated conversion of the Convertible Notes into shares of our common stock could depress the price of our common stock.
Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant customer fails to perform its contractual obligations for any reason.
Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2019, SPL2021, we had SPAs with eight third-party customers, CCL had SPAsterms of 10 or more years with nine third-party customers and our integrated marketing function had a limited numbertotal of SPAs with third-party24 different third party customers. In addition, SPLNG had TUAs with two third-partythird party customers. We
While substantially all of our long-term third party customer arrangements are dependent on each customer’s continued willingness and ability to perform its obligations under its SPAexecuted with a creditworthy parent company or TUA. Wesecured by a parent company guarantee or other form of collateral, we are nonetheless exposed to the credit risk of any guarantor of these customers’ obligations under their respective agreements in the event of a customer default that requires us to seek recourse.
Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events, which include, but are not limited to: (1) if we must seek recoursefail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs, upon the occurrence of certain events of force majeure. Under each of SPLNG’s long-term TUAs, such termination events include, but are not limited to: if the Sabine Pass LNG terminal (1) experiences a guaranty. If any customerforce majeure delay for longer than 18 months; (2) fails to perform its obligations under its SPAredeliver a specified amount of natural gas in accordance with the customer’s redelivery nominations; or TUA,(3) fails to accept and unload a specified number of the customer’s proposed LNG cargoes.
Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the agreement.affected.
Each of our customer contracts is subject to termination under certain circumstances.
Each of the SPAs contains various termination rights allowing our customers to terminate their SPAs, including, without limitation: (1) upon the occurrence of certain events of force majeure; (2) if we fail to make available specified scheduled cargo quantities; and (3) delays in the commencement of commercial operations. We may not be able to replace these SPAs on desirable terms, or at all, if they are terminated.
Each of SPLNG’s long-term TUAs contains various termination rights. For example, each customer may terminate its TUA if the Sabine Pass LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount of natural gas in accordance with the customer’s redelivery nominations or fails to accept and unload a specified number of the customer’s proposed LNG cargoes. SPLNG may not be able to replace these TUAs on desirable terms, or at all, if they are terminated.
Our subsidiaries may be restricted under the terms of their indebtedness from making distributions under certain circumstances, which may limit Cheniere Partners’CQP’s ability to pay or increase distributions to us or inhibit our access to cash flows from the CCL Project and could materially and adversely affect us.
The agreements governing our subsidiaries’ indebtedness restrict payments that our subsidiaries can make to Cheniere PartnersCQP or us in certain events and limit the indebtedness that our subsidiaries can incur. For example, SPL is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, deposits are made into debt service reserve accounts and a debt service coverage ratio of 1.25:1.00 is satisfied.
CCH is generally restricted from making distributions under agreements governing its indebtedness until, among other requirements, the completion of the construction of Trains 1 through 3 of the CCL Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.
CCH HoldCo II is restricted from making distributions to Cheniere under agreements governing its indebtedness generally until, among other requirements, a historical debt service coverage ratio and a projected fixed debt services coverage ratio of 1.20:1.00 are achieved.
Our subsidiaries’ inability to pay distributions to Cheniere PartnersCQP or us or to incur additional indebtedness as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit Cheniere Partners’CQP’s ability to pay or increase distributions to us and its other unitholders or inhibit our access to cash flows from the CCL Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our efforts to manage commodity and financial risks through derivative instruments, including our IPM agreements, could adversely affect our results of operations and financial condition.
We use derivative instruments to manage commodity, currency and financial market risks. The extent of our derivative position at any given time depends on our assessments of the markets for these commodities and related exposures. We currently account for all derivatives at fair value, with immediate recognition of changes in the fair value in earnings. As described in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations, our net loss attributable to common stockholders of $2.3 billion and $85 millionfor the years ended December 31, 2021 and 2020, respectively, was primarily due to derivative losses, with substantially all of such losses relating to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreements. These transactions and other derivative transactions have and may continue to result in substantial volatility in reported results of operations, particularly in periods of significant commodity, currency or financial market variability, or as a result of ineffectiveness of these contracts. For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
In addition, our liquidity may be adversely impacted by the cash margin requirements of the commodities exchanges or the failure of a counterparty to perform in accordance with a contract.
Restrictions in agreements governing us and our subsidiaries’ indebtedness may prevent us and our subsidiaries from engaging in certain beneficial transactions.transactions, which could materially and adversely affect us.
In addition to restrictions on the ability of us, Cheniere Partners,CQP, SPL CCH and CCH HoldCo II to make distributions or incur additional indebtedness, the agreements governing our indebtedness also contain various other covenants that may prevent us from engaging in beneficial transactions, including limitations on our ability to:
•make certain investments;
•purchase, redeem or retire equity interests;
•issue preferred stock;
•sell or transfer assets;
•incur liens;
•enter into transactions with affiliates;
•consolidate, merge, sell or lease all or substantially all of our assets; and
•enter into sale and leaseback transactions.
Our use of hedging arrangements may
Any restrictions on the ability to engage in beneficial transactions could materially and adversely affect us.
The market price of our future operating results or liquidity.
To reduce our exposurecommon stock has fluctuated significantly in the past and is susceptible to fluctuations in the price, volumefuture due to market volatility and timing risk associated with the purchaseother factors. Our stockholders could lose all or part of natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements could expose us to risk of financial loss in some circumstances, including when:their investment.
expected supply is less than the amount hedged;
the counterparty to the hedging contract defaults on its contractual obligations; or
there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.
The regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations, including EMIR and REMIT, could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.
The provisions of the Dodd-Frank Act and the rules adopted and to be adopted by the CFTC, the SEC and other federal regulators establishing federal regulation of the OTC derivatives market and entities like us that participate in that market may adversely affect our ability to manage certainprice of our risks on a cost effective basis. Such lawscommon stock has historically experienced and regulations may also adversely affect our abilitycontinue to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable toexperience volatility. For example, during the future salethree-year period ended December 31, 2021, the market price of our LNG inventorycommon stock ranged between $27.06 and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminals and to secure natural gas feedstock for our liquefaction facilities.
The CFTC has re-proposed position limits rules that would modify and expand the applicability of position limits on the amounts of certain speculative futures contracts, as well as economically equivalent options, futures and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants$113.40. Such fluctuations may hold, subject to limited exemptions for certain bona fide hedging positions and other types of transactions. To the extent the revised CFTC position limits proposal becomes final, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.
Under the Dodd-Frank Act and the rules adopted thereunder, certain swaps may be required to be cleared through a derivatives clearing organization. While the CFTC has designated certain interest rate swaps and index credit default swaps for mandatory clearing, it has not yet finalized rules designating any physical commodity swaps, for mandatory clearing or mandatory exchange trading. Further, we qualify for the end-user exception from the mandatory clearing and trade execution requirements for our
swaps entered into to hedge our commercial risks. If we fail to qualify for that exception as to any swap we enter into and have to clear that swap through a derivatives clearing organization, we could be required to post margin (or post higher margin than if we entered into an uncleared OTC swap) with respect to such swap, our cost of entering into and maintaining such swap could increase and we would not enjoy the same flexibility with the cleared swaps that we enjoy with the uncleared OTC swaps we enter into. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.
As required by the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require certain market participants to collect and post initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users and certain registered swap dealers and major swap participants. Although we believe we will not be required to post margin with respect to any uncleared swaps we enter into in the future, were we required to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be increased. Our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, contractually require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.
The Dodd-Frank Act also imposes other regulatory requirements on swaps market participants, including end users of swaps, such as regulations relating to swap documentation, reporting and recordkeeping, and certain business conduct rules applicable to swap dealers and major swap participants. Together with the Basel III capital requirements on certain swaps market participants, the regulatory requirements of the Dodd-Frank Act and the rules thereunder relating to swaps and derivatives market participants could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter and reduce our ability to monetize or restructure our existing derivative contracts and to execute our hedging strategies. If,continue as a result of a variety of factors, some of which are beyond our control, including:
•domestic and worldwide supply of and demand for natural gas and corresponding fluctuations in the swaps regulatory regime discussed above,price of natural gas;
•sales of a high volume of shares of our common stock by our stockholders;
•operating and stock price performance of companies that investors deem comparable to us;
•events affecting other companies that the market deems comparable to us;
•changes in government regulation or proposals applicable to us;
•actual or potential non-performance by any customer or a counterparty under any agreement;
•announcements made by us or our competitors of significant contracts;
•changes in accounting standards, policies, guidance, interpretations or principles;
•general conditions in the industries in which we operate;
•general economic conditions;
•the failure of securities analysts to cover our common stock or changes in financial or other estimates by analysts;
•changes in investor sentiment regarding the energy industry and fossil fuels;
•other factors described in these “Risk Factors.”
In addition, the United States securities markets have experienced significant price and volume fluctuations. These fluctuations have often been unrelated to the operating performance of companies in these markets. Market fluctuations and broad market, economic and industry factors may negatively affect the price of our common stock, regardless of our operating performance. If we were to be the object of securities class litigation as a result of volatility in our common stock price or for other reasons, it could result in substantial diversion of our management’s attention and resources, which could negatively affect our financial results.
Our ability to declare and pay dividends and repurchase shares is subject to certain considerations.
Dividends are authorized and determined by our Board in its sole discretion and depend upon a number of factors, including:
•Cash available for distribution;
•Our results of operations and anticipated future results of operations;
•Our financial condition, especially in relation to the anticipated future capital needs of any expansion of our Liquefaction Facilities;
•The level of distributions paid by comparable companies;
•Our operating expenses; and
•Other factors our Board deems relevant.
We expect to continue to pay quarterly dividends to our stockholders; however, our Board may reduce our usedividend or cease declaring dividends at any time, including if it determines that our net cash provided by operating activities, after deducting capital expenditures and investments, are not sufficient to pay our desired levels of swapsdividends to hedge our risks, suchstockholders or to pay dividends to our stockholders at all.
Additionally as commodity price risks that we encounter inof December 31, 2021, $998 million of repurchase authority remained of the $1 billion share repurchase program our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.
The Federal Reserve Board also has proposed rules that would limit certain physical commodity activitieshad authorized. Our share repurchase program does not obligate us to acquire a specific number of financial holding companies. Such rules, if adopted, may adversely affect our ability to execute our strategies by restricting our available counterparties for certain types of transactions, limiting our ability to obtain certain services, and reducing liquidity in physical and financial markets. It is uncertain at this time whether, when and in what form the Federal Reserve’s proposed rules regarding financial holding companies may become final and effective.
European and UK-specific regulations, including but not limited to EMIR, MiFID II, REMIT, MAR, FSMA and RAO, govern our trading activitiesshares during any period, and our compliance with such lawsdecision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board may resultconsider when declaring dividends, among others.
Any downward revision in increased costs and risksthe amount of dividends we pay to stockholders or the business similar to the impacts stated above with respect to the Dodd-Frank Act. The increased costs may alsonumber of shares we purchase under our share repurchase program could have an adverse impacteffect on the market price of our common stock.
We may sell equity or equity-related securities or assets, including equity interests in CQP. Such sales could dilute our proportionate interests in our assets, business contracts, financial condition, operating results, cash flow, liquidityoperations and prospects. Further, any violationproposed projects of CQP or other subsidiaries, and could adversely affect the foregoing lawsmarket price of our common stock.
We have historically pursued a number of alternatives in order to finance the construction of our Trains, including potential issuances and regulationssales of additional equity or equity-related securities by our subsidiaries. Such sales, in one or more transactions, could resultdilute our proportionate indirect interests in investigations,our assets, business operations and possible fines and penalties, and in some scenarios, criminal offenses.
Further, given the current lackproposed projects of clarity relating to how UK and EU financial and commodity market regulatory regimes will interact following the UK’s withdrawal from the EU on January 31, 2020,CQP, including the impactSPL Project, or in other subsidiaries or projects, including the CCL Project. In addition, such withdrawal will have on parties subject tosales, or the referenced regulations, additional regulatory risks may result. However, until negotiations betweenanticipation of such sales, could adversely affect the UK and EU are completed during the transition period, which is currently scheduled to expire on December 31, 2020, it is impossible at this point to address with certainty the impactmarket price of Brexit on our operations.
common stock.
We expect that our hedging activities will remain subject to significant and developing regulations and regulatory oversight. However, the full impact of the various U.S. (and non-U.S.) regulatory developments in connection with these activities will not be known with certainty until such derivatives market regulations are fully implemented and related market practices and structures are fully developed.
Risks Relating to Our LNG Terminal Operations and CommercializationIndustry
Operation of the Sabine Pass LNG terminal, the Liquefaction Projects, our pipelines and other facilities that we may construct involves significant risks.
As more fully discussed in these Risk Factors, the Sabine Pass LNG terminal, the Liquefaction Projects, our pipelines and our other existing and proposed LNG facilities face operational risks, including the following:
the facilities’ performing below expected levels of efficiency;
breakdown or failures of equipment;
operational errors by vessel or tug operators;
operational errors by us or any contracted facility operator;
labor disputes; and
weather-related interruptions of operations.
Cost overruns and delays in the completion of one or more Trains, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The actual construction costs of the Trains may be significantly higher than our current estimates as a result of many factors, including change orders under existing or future EPC contracts resulting from the occurrence of certain specifiedCatastrophic weather events that may give Bechtel the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. We have already experienced increased costs due to change orders. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations.
Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to the EPC contracts with Bechtel or any future EPC contract related to additional Trains, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays). Our ability to obtain financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our ability to complete development of additional Trains will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our business strategy.
We will require significant additional funding to be able to commence construction of additional Trains, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development of additional Trains, and we may not be able to complete our business plan. Even if we are able to obtain funding, the funding may be inadequate to cover any increases in costs or delays in completion of additional Trains, which may cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more future customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Hurricanes or other disasters could result in an interruption of our operations, a delay in the completion of our liquefaction projects,Liquefaction Projects, damage to our liquefaction projectsLiquefaction Projects and increased insurance costs, all of which could adversely affect us.
Hurricanes Katrina and Rita in 2005, Hurricane Ike in 2008, and Hurricane Harvey in 2017, Hurricanes Laura and Delta in 2020 and Winter Storm Uri in 2021 caused interruptions or temporary suspension in construction ofor operations at our liquefaction projectsfacilities or caused minor damage to our liquefaction projects.facilities. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal, the Corpus Christi LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Liquefaction Projects, Corpus Christi Stage 3 or our other facilities
and increase our insurance premiums. The U.S. Global Change Research Program has reported that the U.S.’s energy and transportation systems are expected to be increasingly disrupted by climate change and extreme weather events. An increase in frequency and severity of extreme weather events such as storms, floods, fires and rising sea levels could have an adverse effect on our operations.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipelines and the export of LNG could impede operations and construction and could have a material adverse effect on us.
The design, construction and operationOur ability to complete development of interstate natural gas pipelines, LNG terminals,additional Trains, including the Liquefaction Projects, Corpus Christi Stage 3, and other facilities, and the import and export of LNG and the purchase and transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG. Although the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the SPL Project, the three Trains and related facilities of the CCL Project and the seven midscale Trains and related facilities for Corpus Christi Stage 3, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline, the Corpus Christi Pipeline and the pipeline for Corpus Christi Stage 3, the FERC orders require us to comply with certain ongoing conditions and obtain certain additional approvals in conjunction with ongoing construction and operations of our liquefaction and pipeline facilities. We will be required to obtain similar approvals and permits with respect to any expansion or modification of our liquefaction and pipeline facilities. We cannot control the outcome of the regulatory review and approval processes. Certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We do not know whether or when any such approvals or permits can be obtained, or whether any existing or potential interventions or other actions by third parties will interfere withcontingent on our ability to obtain and maintain such permits or approvals.additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our business strategy.
We continuously pursue liquefaction expansion opportunities and maintainother projects along the necessary approvalsLNG value chain. As described further in Items 1. and permits, including as2. Business and Properties, we are currently developing the Corpus Christi Stage 3 project, which includes an expansion adjacent to the CCL Project for up to seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. The commercial development of an LNG facility takes a resultnumber of untimely notices or filings,years and requires a substantial capital investment that is dependent on sufficient funding and commercial interest, among other factors.
We will require significant additional funding to be able to commence construction of Corpus Christi Stage 3, and any additional expansion projects, which we may not be able to recover our investmentobtain at a cost that results in our projects. Additionally, government disruptions, such as a U.S. government shutdown,positive economics, or at all. The inability to achieve acceptable funding may delay or halt our ability to obtain and maintain necessary approvals and permits. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Delays in the completion of one or more Trains could lead to reduced revenues or termination of one or more of the SPAs by our customers.
Any delay in completion of a Train could cause a delay in the receiptdevelopment of revenues projected therefromCorpus Christi Stage 3, or cause a loss of one or more customers in the event of significant delays. In particular, each of our SPAs provides that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidityadditional expansion projects, and prospects.
We are dependent on Bechtel and other contractors for the successful completion of the Liquefaction Projects.
Timely and cost-effective completion of the Liquefaction Projects in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of Bechtel and our other contractors under their agreements. The ability of Bechtel and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:
design and engineer each Train to operate in accordance with specifications;
engage and retain third-party subcontractors and procure equipment and supplies;
respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
attract, develop and retain skilled personnel, including engineers;
post required construction bonds and comply with the terms thereof;
manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
maintain their own financial condition, including adequate working capital.
Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Liquefaction Projects, and any liquidated damages that we receive may not be sufficientable to cover the damages that we suffer as a result of any such delay or impairment. The obligations of Bechtel andcomplete our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.
Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Liquefaction Projects or result in a contractor’s unwillingness to perform further work on the Liquefaction Projects. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs,business plan, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Cost overruns and other facilities interconnecteddelays in the completion of our expansion projects, including Corpus Christi Stage 3, as well as difficulties in obtaining sufficient financing to our pipelinespay for such costs and facilities are or become unavailable to transport natural gas, thisdelays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
While we expect to reach FID on Corpus Christi Stage 3, our investment decision on the project and any potential future LNG facilities relies on cost estimates developed initially through front end engineering and design studies. However, due to the size and duration of construction of an LNG facility, the actual construction costs may be significantly higher than our current estimates as a result of many factors, including but not limited to changes in scope, the ability of Bechtel and our other contractors to execute successfully under their agreements, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules or comply with existing or future environmental or other regulations. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations. Additionally, our SPAs generally provide that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Significant increases in the cost of a liquefaction project beyond the amounts that we estimate could impact the commercial viability of the project as well as require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays), thereby negatively impacting our business and limiting our growth prospects. While historically we have not experienced cost overruns or construction delays that have had a significant adverse impact on our operations, factors giving rise to such events in the future may be outside of our control and could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Disruptions to the third party supply of natural gas to our pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We depend upon third-partythird party pipelines and other facilities that provide gas delivery options to our liquefaction facilities and pipelines. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to meet our SPA obligations andreceive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be restricted, thereby reducingadversely impacted. Any significant disruption to our natural gas supply could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. However, we may not be able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our interstate natural gas pipelines and their FERC gas tariffsWe are subject to FERC regulation.significant construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.
Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA”). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the construction and operation of our LNG terminals and our pipelines the rates, termsare, and conditions of service and abandonment of facilities. Under the NGA, the rates charged by our interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our interstate pipelines couldwill be, subject to substantial penaltiesthe inherent risks associated with these types of operations, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and fines.
adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGAour operations and the NGPA to impose penalties for current violationsfacilities and vessels of up to $1.3 million per day for each violation.
Pipeline safety integrity programs and repairs may impose significant costs and liabilitiesthird parties on us.
The PHMSA requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a “high consequence area”;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventative and mitigating actions.
We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines.
Any reduction in the capacity of, or the allocations to, interconnecting, third-party pipelines could cause a reduction of volumes transported inwhich our pipelines, which would adversely affect our revenues and cash flow.
Weoperations are dependent upon third-party pipelines and other facilities to provide delivery options to and from our pipelines. If any pipeline connection were to become unavailable for volumesface possible risks associated with acts of natural gas due to repairs, damage to the facility, lack of capacityaggression or any other reason, our ability to continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any permanent interruption at any key pipeline interconnect which causes a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.terrorism.
Our business could be materially and adversely affected if we lose the right to situate our pipelines on property owned by third parties.
We do not, own the land on which our pipelines are situated, and we are subject to the possibility of increased costs to retain necessary land use rights. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.
We are relying on estimates for the future capacity ratings and performance capabilities of the Liquefaction Projects, and these estimates may prove to be inaccurate.
We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of the Liquefaction Projects. If any Train, when actually constructed, fails to have the capacity ratings and performance capabilities thatnor do we intend our estimatesto, maintain insurance against all of these risks and losses. We may not be accurate. Failureable to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of any of our Trains to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our SPAs anda significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
AnyWe are dependent on our EPC partners and other contractors for the successful completion of the Liquefaction Projects and any potential expansion projects, including Corpus Christi Stage 3.
Timely and cost-effective completion of the Liquefaction Projects and any potential expansion projects in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our EPC partners, including Bechtel, and our other contractors under their agreements. The ability of our EPC partners and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:
•design and engineer each Train to operate in accordance with specifications;
•engage and retain third party subcontractors and procure equipment and supplies;
•respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by our counterparties undersubcontractors, some of which are beyond their control;
•attract, develop and retain skilled personnel, including engineers;
•post required construction bonds and comply with the terms thereof;
•manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
•maintain their own financial condition, including adequate working capital.
Although some agreements may adversely affect our operating results, liquidity and access to financing.
Our integrated marketing function involves our entering into various purchase and sale, hedging and other transactions with numerous third parties (commonly referred to as “counterparties”). In such arrangements, we are exposed toprovide for liquidated damages if the performance and credit risks of our counterparties, including the risk that one or more counterpartiescontractor fails to perform in the manner required with respect to certain of its obligationobligations, the events that trigger a requirement to make deliveriespay liquidated damages may delay or impair the operation of commodities and/the Liquefaction Projects or to make payments. These risks may increase during periods of commodity price volatility. Defaults by suppliersany expansion projects, and other counterparties may adversely affect our operating results, liquidity and access to financing.
Weany liquidated damages that we receive may not be ablesufficient to contractcover the damages that we suffer as a result of any such delay or impairment. The obligations of EPC partners and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.
Furthermore, we may have disagreements with customers to sell LNG produced in excessour contractors about different elements of the aggregate annual contract quantitiescommittedconstruction process, which could lead to SPL’sthe assertion of rights and CCL’s third-party SPAs.
We expect to sell any LNG produced in excessremedies under their contracts and increase the cost of the aggregate annual contract quantity committed to SPL’s and CCL’s third-party SPAs through our integrated marketing function. We are developing a portfolio of long-, medium- and short-term SPAs to transport and unload commercial LNG cargoes to locations worldwide, which is primarily sourced by LNG produced by the Liquefaction Projects in excess of the contract quantities committed to SPL’s and CCL’s third party SPAs, supplemented by volume procured from other locations worldwide, as needed. Excess LNG from the Liquefaction Projects competes with other sources of LNG that are priced to indices other than Henry Hub, and any collapsepotential expansion project or result in the spread between global LNG prices and the Henry Hub index could impact the ability of our integrated marketing functiona contractor’s unwillingness to profitably sellperform further work. If any such excess LNG. Failure to secure buyers for a sufficient amount of LNG could materially and adversely affect our operating results, cash flows and liquidity.
Risks Relating to Our LNG Businesses in General
We may not construct or operate all of our proposed LNG facilities or Trains or any additional LNG facilities or Trains beyond those currently planned, which could limit our growth prospects.
We may not construct some of our proposed LNG facilities or Trains, whether due to lack of commercial interest or inability to obtain financing or otherwise. Our ability to develop additional liquefaction facilities will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world. Competitors may have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to sources of natural gas and LNG than we do. If we arecontractor is unable or unwilling to constructperform according to the negotiated terms and operate additional LNG facilities, our prospectstimetable of its respective agreement for growth willany reason or terminates its agreement, we would be limited.
Our cost estimates for Trains are subjectrequired to change asengage a result of cost overruns, change orders under existing or future construction contracts, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules. In the event we experience cost overruns, delays or both, the amount of funding needed to complete a Train could exceed our available funds andsubstitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our failurebusiness, contracts, financial condition, operating results, cash flow, liquidity and prospects.
There may be impediments to completethe transport of LNG, such Trainas shortages of LNG vessels worldwide or operational impacts on LNG shipping, including maritime transportation routes, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and thereby negatively impactprospects.
The construction and delivery of LNG vessels require significant capital and long construction lead times. Additionally, the availability of LNG vessels and transportation costs could be impacted to the detriment of our business and limit our growth prospects.customers because of:
•an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
•shortages of or delays in the receipt of necessary construction materials;
•political or economic disturbances;
•acts of war or piracy;
•changes in governmental regulations or maritime self-regulatory organizations;
•work stoppages or other labor disturbances;
•bankruptcy or other financial crisis of shipbuilders or shipowners;
•quality or engineering problems;
•disruptions to maritime transportation routes; and
•weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows,flow, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG, and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from the Sabine Pass LNG terminal and the Corpus Christi LNG terminal;
•competitive liquefaction capacity in North America;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions, including extreme weather events and temperature volatility resulting from climate change;change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand. For example, LNG procurement in Japan rose dramatically in 2011 and several years thereafter following a tsunami that caused extensive destruction to its nuclear power infrastructure;
•reduced demand and lower prices for natural gas;
•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
•cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
•political conditions in natural gas producing regions;
•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;
•adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows,flow, liquidity and prospects.
Failure of imported or exported LNG to be a competitive source of energy for the United States or international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the Liquefaction Projects are dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered
outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Although SPL has entered into arrangements to utilize up to approximately three-quarters of the regasification capacity at the Sabine Pass LNG terminal in connection with operations of the SPL Project, operations at the Sabine Pass LNG terminal are dependent, in part, upon the ability of our TUA customers to import LNG supplies into the United States, which is primarily dependent upon LNG being a competitive source of energy in North America. In North America, due mainly to a historically abundant supply of natural gas and discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the regasification services component of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to North America at a lower cost than the cost to produce some domestic supplies of natural gas, or other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas have recently been and may continue to be discovered in North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than imported LNG.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import or export LNG from or to the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction or regasification facilities in the United States.
In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. LNG from the Liquefaction Projects also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Projects in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Projects, may also be impacted by an increase in natural gas prices in the United States.
As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or to the
United States on a commercial basis. Any significant impediment to the ability to deliver LNG to or from the United States generally, or to the Sabine Pass LNG terminal or the Corpus Christi LNG terminal or from the Liquefaction Projects specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Various economic and political factors could negatively affect the development, construction and operation of LNG facilities, including the Liquefaction Projects and expansion projects, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Commercial development of an LNG facility takes a number of years, requires a substantial capital investment and may be delayed by factors such as:
increased construction costs;
economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;
the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;
political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and
any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.
There may be shortages of LNG vessels worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability of the vessels could be delayed to the detriment of our business and our customers because of:
an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
political or economic disturbances in the countries where the vessels are being constructed;
changes in governmental regulations or maritime self-regulatory organizations;
work stoppages or other labor disturbances at the shipyards;
bankruptcy or other financial crisis of shipbuilders;
quality or engineering problems;
weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
shortages of or delays in the receipt of necessary construction materials.
We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation requirements, which could have a material adverse effect on us.
We have contracted for firm capacity for our natural gas feedstock transportation requirements for the Liquefaction Projects and for Corpus Christi Stage 3. If and when we need to replace one or more of our existing agreements with these interconnecting pipelines, we may not be able to do so on commercially reasonable terms or at all, which could impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We face competition based upon the international market price for LNG.
Our liquefaction projectsLiquefaction Projects are subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and
prospects. Factors which may negatively affect potential demand for LNG from our liquefaction projectsLiquefaction Projects are diverse and include, among others:
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to our liquefaction projects;Liquefaction Projects;
•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
•increases in capacity and utilization of nuclear power and related facilities; and
•displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
Terrorist attacks,
A cyber incidentsattack involving our business, operational control systems or military campaigns may adverselyrelated infrastructure, or that of third party pipelines which supply the Liquefaction Facilities, could negatively impact our business.operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our trading, marketing, pipeline, liquefaction and shipping operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Facilities. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should a multiple of the third party pipelines which supply our Liquefaction Facilities suffer similar concurrent attacks, the Liquefaction Facilities may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A terroristcyber attack cyber incidentinvolving our business or military incident involving an LNG facility, ouroperational control systems or related infrastructure, or an LNG vessel maythat of third party pipelines with which we do business, could negatively impact our operations, result in delaysdata security breaches, impede the processing of transactions, or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our senior management or cancellationother key personnel could affect our business results.
We are dependent upon the available labor pool of constructionskilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of new LNG facilities, includingskilled workers, remoteness of our site locations or other general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel other than our employment agreement with our President and Chief Executive Officer binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business.
Outbreaks of infectious diseases, such as the outbreak of COVID-19, at one or more of the Trains, which would increase our costs and decrease our cash flows. A terrorist incident or cyber incident may also result in temporary or permanent closure of our existing facilities which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our businessoperations.
Our facilities at the Sabine Pass LNG terminal and Corpus Christi LNG terminal are critical infrastructure and have continued to operate during the COVID-19 pandemic through our customers,implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including their abilitythe Delta and Omicron variants, has had no adverse impact on our on-going operations during this time, the risk of future variants is unknown. While we believe we can continue to satisfy their obligationsmitigate any significant adverse impact to us under our commercial agreements. Instabilityemployees and operations at our critical facilities related to the virus in its current form, the outbreak of a more potent variant in the financial markets as a resultfuture at one or more of terrorism, cyber incidents or warour facilities could also materially adversely affect our abilityoperations.
Risks Relating to raise capital. The continuation of these developments may subject ourRegulations
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipelines and the export of LNG could impede operations to increased risks,and construction and could have a material adverse effect on us.
The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Liquefaction Projects, Corpus Christi Stage 3 and other facilities, as well as increased costs,the import and dependingexport of LNG and the purchase and transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG.
To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the SPL Project, the three Trains and related facilities of the CCL Project and the seven midscale Trains and related facilities for Corpus Christi Stage 3, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline, the Corpus Christi Pipeline and the pipeline for Corpus Christi Stage 3. To date, the DOE has also issued orders under Section 4 of the NGA authorizing SPL, CCL and Corpus Christi Stage 3 to export domestically produced LNG. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipelines on their ultimate magnitude,land owned by third parties. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with such conditions, or our inability to obtain and maintain existing or newly imposed approvals and permits, filings, which may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns, could impede the operation and construction of our infrastructure. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Risks Relating to Our Business in General
Weinterstate natural gas pipelines and their FERC gas tariffs are subject to significant constructionFERC regulation. If we fail to comply with such regulations, we could be subject to substantial penalties and operating hazardsfines.
Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and uninsured risks, one or morethe Natural Gas Policy Act of which may create significant liabilities1978 (the “NGPA”). The FERC regulates the purchase and losses for us.
Thetransportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by our LNG terminalsinterstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our interstate pipelines are, and willcould be subject to the inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanessubstantial penalties and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. fines.
In addition, our operationsas a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the facilities and vesselsNGPA to impose penalties for current violations of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.up to $1.3 million per day for each violation.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our
compliance. In addition,
certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our LNG terminals and pipelines, including FERC and PHMSA, to issue compliance orders, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties or to capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of GHG emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules havewere largely been stayed or repealed during the Trump Administration including by amendments adopted by the EPA on February 23, 2018 and additional proposed amendments to new source performance standards for the oil and gas industry on September 24, 201914 and 15, 2020. On November 15, 2021, the EPA’s June 19, 2019 adoptionEPA proposed new regulations to reduce methane emissions from both new and existing sources within the Crude Oil and Natural Gas source category. The proposed regulations, if finalized, would result in more stringent requirements for new sources, expand the types of new sources covered, and for the Affordable Clean Energy rulefirst time, establish emissions guidelines for power generation. However, Congress or a future Administration may reverse these decisions. Otherexisting sources in the Crude Oil and Natural Gas source category. In addition, other federal and state initiatives may be considered in the future to address GHG emissions through, for example, United States treaty commitments, direct regulation, market-based regulations such as a carbon emissions tax or cap-and-trade programs or clean energy standards.Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.We are supportive of regulations reducing GHG emissions over time.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
A major healthPipeline safety and safety incident relating to our business could be costly in terms of potential liabilitiescompliance programs and reputational damages.
Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performancerepairs may result in personal harm or injury, penalties for non-compliance with relevant regulatory requirements or litigation, and a failure that results in aimpose significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may experience increased labor costs and liabilities on us.
The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the unavailabilitymost harm. As an operator, we are required to:
•perform ongoing assessments of skilled workers or our failurepipeline safety and compliance;
•identify and characterize applicable threats to attractpipeline segments that could impact a “high consequence area”;
•improve data collection, integration and retain qualified personnel could adversely affect us. In addition, changes in our senior management or other key personnel could affect our business results.analysis;
•repair and remediate the pipeline as necessary; and
•implement preventative and mitigating actions.
We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to constructmaintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operate our facilitiesoperating expenditures. Should we fail to comply with applicable statutes and pipelinesthe Office of Pipeline Safety’s rules and to provide our customers with the highest quality service. Our affiliates who hire personnel on our behalf are alsorelated regulations and orders, we could be subject to the Fair Labor Standards Act,significant penalties and fines, which governs such mattersfor certain violations can aggregate up to as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers or other general inflationary pressureshigh as $2.3 million.
Additions or changes in applicabletax laws and regulations could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers,
we do not have any employment contracts or other agreements with key personnel other than our employment agreement with our President and Chief Executive Officer binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business.
Our lack of diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Substantially all of our anticipated revenue in 2020 will be dependent upon our two facilities, the Sabine Pass LNG terminal located in southern Louisiana and the Corpus Christi LNG terminal in Texas. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG terminal or the Corpus Christi LNG terminal, including the related pipelines, or in the LNG industry, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.
We may incur impairments to goodwill or long-lived assets.
We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. We test goodwill for impairment annually during the fourth quarter, or more frequently as circumstances dictate. Significant negative industry or economic trends, including a significant decline in the market price of our common stock, reduced estimates of future cash flows for our business or disruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our goodwill or long-lived assets, we may be required to record a charge to earnings in our Consolidated Financial Statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.
We cannot guarantee that our share repurchase program will be fully consummated or that it will enhance long-term stockholder value.
In June 2019, our Board authorized a three-year, $1 billion share repurchase program and as of December 31, 2019, up to $751 million remains available for repurchase. Our share repurchase program does not obligate us to acquire any particular amount of common stock. Our share repurchase program may be modified, suspended or terminated at any time, which may result in a decrease in the trading price of our common stock.
The market price of our common stock has fluctuated significantly in the past and is likely to fluctuate in the future. Our stockholders could lose all or part of their investment.
The market price of our common stock has historically experienced and may continue to experience volatility. For example, during the three-year period ended December 31, 2019, the market price of our common stock ranged between $40.36 and $71.03. Such fluctuations may continue as a result of a variety of factors, some of which are beyond our control, including:
domestic and worldwide supply of and demand for natural gas and corresponding fluctuations in the price of natural gas;
fluctuations in our quarterly or annual financial results or those of other companies in our industry;
issuance of additional equity securities which causes further dilution to stockholders;
sales of a high volume of shares of our common stock by our stockholders;
operating and stock price performance of companies that investors deem comparable to us;
events affecting other companies that the market deems comparable to us;
changes in government regulation or proposals applicable to us;
actual or potential non-performance by any customer or a counterparty under any agreement;
announcements made by us or our competitors of significant contracts;
changes in accounting standards, policies, guidance, interpretations or principles;
general conditions in the industries in which we operate;
general economic conditions;
the failure of securities analysts to cover our common stock or changes in financial or other estimates by analysts; and
other factors described in these “Risk Factors.”
In addition, the United States securities markets have experienced significant price and volume fluctuations. These fluctuations have often been unrelated to the operating performance of companies in these markets. Market fluctuations and broad market, economic and industry factors may negatively affect the price of our common stock, regardless of our operating performance. If we were to be the object of securities class litigation as a result of volatility in our common stock price or for other reasons, it could result in substantial diversion of our management’s attention and resources, which could negativelypotentially affect our financial results.
We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact. Any changes to local, domestic or international tax laws and regulations, or their interpretation and application, including those with retroactive effect, could affect our tax obligations, profitability and cash flows in the future. | |
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
Additionally, there have been a number of tax reform proposals introduced in Congress recently that have proposed applying a corporate level tax to oil and gas master limited partnerships, such as CQP. If such a proposal were to be enacted, it would represent a substantial departure from current tax law, subjecting CQP to an entity level corporate tax, which could adversely impact the cash distributions that we receive from CQP. In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control. We continuously monitor and assess proposed tax legislation that could negatively impact our business.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.
LDEQ Matter
Certain of our subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG terminal and the commissioning of the SPL Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of our subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of our subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.
PHMSA Matter
In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal.terminal (the “2018 SPL tank incident”). These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to service. We continueIn July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to SPL alleging violations of federal pipeline safety regulations relating to the 2018 SPL tank incident and proposing civil penalties totaling $2,214,900. On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200. On October 12, 2021, SPL responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty. PHMSA notified SPL in a letter dated November 9, 2021 that the case was considered “closed.” SPL continues to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak,SPL tank incident, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation or resolution of the NOPV will have a material adverse impact on our financial results or operations.
Parallax and Related Litigation
In 2015, our wholly owned subsidiary Cheniere LNG Terminals, LLC (“CLNGT”), entered into discussions with Parallax Enterprises, LLC (“Parallax Enterprises”) regarding the potential joint development of two liquefaction plants in Louisiana (the “Potential Liquefaction Transactions”). While the parties negotiated regarding the Potential Liquefaction Transactions, CLNGT loaned Parallax Enterprises approximately $46 million, as reflected in a secured note dated April 23, 2015, as amended on June 30, 2015, September 30, 2015 and November 4, 2015 (the “Secured Note”). The Secured Note was secured by all assets of Parallax Enterprises and its subsidiary entities. On June 30, 2015, Parallax Enterprises’ parent entity, Parallax Energy LLC (“Parallax Energy”), executed a Pledge and Guarantee Agreement further securing repayment of the Secured Note by providing a parent guaranty and a pledge of all of the equity of Parallax Enterprises in satisfaction of the Secured Note (the “Pledge Agreement”). CLNGT and Parallax Enterprises never executed a definitive agreement to pursue the Potential Liquefaction Transactions. The
Secured Note matured on December 11, 2015, and Parallax Enterprises failed to make payment. On February 3, 2016, CLNGT filed an action against Parallax Energy, Parallax Enterprises and certain of Parallax Enterprises’ subsidiary entities, styled Cause No. 4:16-cv-00286, Cheniere LNG Terminals, LLC v. Parallax Energy LLC, et al., in the United States District Court for the Southern District of Texas (the “Texas Federal Suit”). CLNGT asserted claims in the Texas Federal Suit for (1) recovery of all amounts due under the Secured Note and (2) declaratory relief establishing that CLNGT is entitled to enforce its rights under the Secured Note and Pledge Agreement in accordance with each instrument’s terms and that CLNGT has no obligations of any sort to Parallax Enterprises concerning the Potential Liquefaction Transactions. On March 11, 2016, Parallax Enterprises and the other defendants in the Texas Federal Suit moved to dismiss the suit for lack of subject matter jurisdiction. On August 2, 2016, the court denied the defendants’ motion to dismiss without prejudice and permitted the parties to pursue jurisdictional discovery.
On March 11, 2016, Parallax Enterprises filed a suit against us and CLNGT styled Civil Action No. 62-810, Parallax Enterprises LLP v. Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC, in the 25th Judicial District Court of Plaquemines Parish, Louisiana (the “Louisiana Suit”), wherein Parallax Enterprises asserted claims for breach of contract, fraudulent inducement, negligent misrepresentation, detrimental reliance, unjust enrichment and violation of the Louisiana Unfair Trade Practices Act. Parallax Enterprises predicated its claims in the Louisiana Suit on an allegation that we and CLNGT breached a purported agreement to jointly develop the Potential Liquefaction Transactions. Parallax Enterprises sought $400 million in alleged economic damages and rescission of the Secured Note. On April 15, 2016, we and CLNGT removed the Louisiana Suit to the United States District Court for the Eastern District of Louisiana, which subsequently transferred the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was assigned Civil Action No. 4:16-cv-01628 and transferred to the same judge presiding over the Texas Federal Suit for coordinated handling. On August 22, 2016, Parallax Enterprises voluntarily dismissed all claims asserted against CLNGT and us in the Louisiana Suit without prejudice to refiling.
On July 27, 2017, the Parallax entities named as defendants in the Texas Federal Suit reurged their motion to dismiss and simultaneously filed counterclaims against CLNGT and third party claims against us for breach of contract, breach of fiduciary duty, promissory estoppel, quantum meruit and fraudulent inducement of the Secured Note and Pledge Agreement, based on substantially the same factual allegations Parallax Enterprises made in the Louisiana Suit. These Parallax entities also simultaneously filed an action styled Cause No. 2017-49685, Parallax Enterprises, LLC, et al. v. Cheniere Energy, Inc., et al., in the 61st District Court of Harris County, Texas (the “Texas State Suit”), which asserts substantially the same claims these entities asserted in the Texas Federal Suit. On July 31, 2017, CLNGT withdrew its opposition to the dismissal of the Texas Federal Suit without prejudice on jurisdictional grounds and the federal court subsequently dismissed the Texas Federal Suit without prejudice. We and CLNGT simultaneously filed an answer and counterclaims in the Texas State Suit, asserting the same claims CLNGT had previously asserted in the Texas Federal Suit. Additionally, CLNGT filed third party claims against Parallax principals Martin Houston, Christopher Bowen Daniels, Howard Candelet and Mark Evans, as well as Tellurian Investments, Inc., Driftwood LNG, LLC, Driftwood LNG Pipeline LLC and Tellurian Services LLC, formerly known as Parallax Services LLC, including claims for tortious interference with CLNGT’s collateral rights under the Secured Note and Pledge Agreement, fraudulent transfer, conspiracy/aiding and abetting.
ITEM 4. MINE SAFETY DISCLOSURE
On February 15, 2019, we filed an action with CLNGT against Charif Souki, our former Chairman of the Board and Chief Executive Officer, styled, Cause No. 2019-11529,
Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC v. Charif Souki, in the 55th District Court of Harris County, Texas, which asserts claims of breach of fiduciary duties, fraudulent transfer, tortious interference with CLNGT’s collateral rights under the Secured Note and Pledge Agreement, and conspiracy/aiding and abetting. On April 29, 2019, the court consolidated the Souki matter with the earlier filed pending case against Parallax, Tellurian and the individual defendants in the Texas State Suit.
On January 30, 2020, the parties filed an Agreed Motion to Dismiss and all claims were dismissed with prejudice.
The resolution of the foregoing litigation did not have a material adverse impact on our financial results.
On January 10, 2020, a purported shareholder of Cheniere filed a shareholder derivative action in state court in Houston, Texas. The complaint names as defendants ten of our current directors. The plaintiff alleges that those directors breached their fiduciary duties by abandoning a proposed joint-development arrangement with Parallax in 2015, which later was the subject of a separate lawsuit by Parallax discussed above. According to the complaint, the directors’ alleged breach of their fiduciary duties caused us to incur legal fees in the Parallax action and also exposed us to a potential damages award in the Parallax lawsuit. On January 30, 2020, Parallax voluntarily dismissed with prejudice all claims against us. We do not expect that the resolution of the foregoing litigation will have a material adverse impact on our financial results.
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ITEM 4. | MINE SAFETY DISCLOSURE |
Not applicable.
PART II
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ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information, Holders and DividendsDividend Policy
Our common stock has traded on the NYSE American under the symbol “LNG” since March 24, 2003. As of February 19, 2020,18, 2022, we had 254 million shares of common stock outstanding held by 9692 record owners.
We have never paidIn September 2021, Cheniere declared an inaugural quarterly dividend of $0.33 per common share. On January 25, 2022, we declared a cashquarterly dividend of $0.33 per common share that is payable on our common stock. Any future change in our dividend policy will be made atFebruary 28, 2022 to shareholders of record as of February 7, 2022. The declaration of dividends is subject to the discretion of our Board, of Directors (our “Board”) in light of ourand will depend on Cheniere’s financial condition capital requirements, earnings, prospects and any restrictions under any financing agreements, as well as other factors our Board deems relevant.deemed relevant by the Board.
Purchase of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes stock repurchases for the three months ended December 31, 2019:2021: |
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Period | | Total Number of Shares Purchased (1) | | Average Price Paid Per Share (2) | | Total Number of Shares Purchased as a Part of Publicly Announced Plans | | Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans (3) |
October 1 - 31, 2019 | | 324,138 | | $62.15 | | 322,000 | | $820,860,569 |
November 1 - 30, 2019 | | 372,766 | | $60.98 | | 372,400 | | $798,153,446 |
December 1 - 31, 2019 | | 784,815 | | $60.33 | | 783,700 | | $750,875,707 |
Total | | 1,481,719 | | $60.89 | | 1,478,100 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Period | | Total Number of Shares Purchased (1) | | Average Price Paid Per Share (2) | | Total Number of Shares Purchased as a Part of Publicly Announced Plans | | Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans (3) |
October 1 - 31, 2021 | | 22,220 | | $98.23 | | 17,949 | | $998,251,447 |
November 1 - 30, 2021 | | 603 | | $105.34 | | — | | $998,251,447 |
December 1 - 31, 2021 | | 11,046 | | $99.94 | | 6,895 | | $997,572,653 |
Total | | 33,869 | | $98.92 | | 24,844 | | |
| |
(1) | Includes shares surrendered to us by participants in our share-based compensation plans for payment of applicable tax withholdings on the vesting of share-based compensation awards. Associated shares surrendered by participants are repurchased pursuant to terms of the plan and award agreements and not as part of the publicly announced share repurchase plan. |
| |
(2) | The price paid per share was based on the average trading price of our common stock on the dates on which we repurchased the shares. |
| |
(3) | On June 3, 2019, we announced that our Board authorized a 3-year, $1 billion share repurchase program. For additional information, see Note 18—Share Repurchase Program of our Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.(1)Includes issued shares surrendered to us by participants in our share-based compensation plans for payment of applicable tax withholdings on the vesting of share-based compensation awards. Associated shares surrendered by participants are repurchased pursuant to terms of the plan and award agreements and not as part of the publicly announced share repurchase plan. (2)The price paid per share was based on the average trading price of our common stock on the dates on which we repurchased the shares. (3)On June 3, 2019, we announced that our Board authorized a 3-year, $1 billion share repurchase program. On September 7, 2021, the Board authorized a reset of the share repurchase program 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. For additional information, see Note 19—Stockholder’s Equity of our Notes to Consolidated Financial Statements.
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Total Stockholder Return
The following is a customized peer group consisting of 2717 companies (the “New Peer“Peer Group”) that were selected because they are publicly traded companies that have: (1) comparable Global Industries Classification Standards, (2) similar market capitalization, (3) similar enterprise values and (4) similar operating characteristics and capital intensity:
|
| | | | | | | |
New Peer Group |
Air Products and Chemicals, Inc. (APD) | | LyondellBasell Industries N.V. (LYB)Marathon Petroleum Corporation (MPC) |
Apache Corporation (APA) | | Marathon Oil Corporation (MRO) |
Baker Hughes Company (BKR) | | Marathon Petroleum Corporation (MPC) |
Concho Resources Inc. (CXO) | | Noble Energy, Inc. (NBL) |
ConocoPhillips (COP) | | Occidental Petroleum Corporation (OXY) |
Continental Resources, Inc. (CLR)ConocoPhillips (COP) | | ONEOK, Inc. (OKE) |
Devon Energy Corporation (DVN) | | Phillips 66 (PSX) |
Diamondback Energy, Inc. (FANG) | | Pioneer Natural Resources Company (PXD) |
Enterprise Products Partners L.P. (EPD) | | Schlumberger Limited (SLB)Phillips 66 (PSX) |
EOG Resources, Inc. (EOG) | | Suncor Energy Inc. (SU) |
Freeport-McMoRan Inc. (FCX)Halliburton Company (HAL) | | Targa Resources Corp. (TRGP) |
Halliburton Company (HAL)Hess Corporation (HES) | | Valero Energy Corporation (VLO) |
Hess Corporation (HES) | | The Williams Companies, Inc. (WMB) |
Kinder Morgan, Inc. (KMI) | | The Williams Companies, Inc. (WMB) |
LyondellBasell Industries N.V. (LYB) | | |
The New Peer Group companies were revised during 2019. Our previous peer group consisted of 29 companies (the “Old Peer Group”), which excluded Diamondback Energy, Inc. (FANG) and Targa Resources Corp. (TRGP) from the New Peer Group and included Anadarko Petroleum Corporation (APC), Andeavor (ANDV), EQT Corporation (EQT) and Praxair, Inc. (PX). Additionally, Baker Hughes, a GE company (BHGE) changed its name and ticker symbol to Baker Hughes Company (BKR) in October 2019.
The following graph compares the five-year total return on our common stock, the S&P 500 Index the New Peer Group and the Oldour Peer Group. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P 500 Index the New Peer Group and the Oldour Peer Group on December 31, 20142016 and that any dividends were fully reinvested.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Company / Index | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
Cheniere Energy, Inc. | | $ | 100.00 | | | $ | 129.95 | | | $ | 142.87 | | | $ | 147.41 | | | $ | 144.90 | | | $ | 245.56 | |
S&P 500 Index | | 100.00 | | | 121.82 | | | 116.47 | | | 153.13 | | | 181.29 | | | 233.28 | |
Peer Group | | 100.00 | | | 107.02 | | | 92.33 | | | 112.72 | | | 83.18 | | | 120.28 | |
| | | | | | | | | | | | |
ITEM 6. [Reserved]
|
| | | | | | | | | | | | | | | | | | |
Company / Index | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 |
Cheniere Energy, Inc. | | 100.00 |
| | 52.91 |
| | 58.85 |
| | 76.48 |
| | 84.08 |
| | 86.75 |
|
S&P 500 Index | | 100.00 |
| | 101.37 |
| | 113.49 |
| | 138.26 |
| | 132.19 |
| | 173.80 |
|
New Peer Group | | 100.00 |
| | 79.05 |
| | 110.62 |
| | 115.91 |
| | 91.57 |
| | 107.19 |
|
Old Peer Group | | 100.00 |
| | 79.89 |
| | 108.84 |
| | 113.88 |
| | 89.89 |
| | 103.49 |
|
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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ITEM 6. | SELECTED FINANCIAL DATA |
Selected financial data set forth below are derived from our audited Consolidated Financial Statements for the periods indicated (in millions, except per share data). The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report.
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| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
Consolidated Statement of Operations Data: | | | | | | | | | | |
Revenues | | $ | 9,730 |
| | $ | 7,987 |
| | $ | 5,601 |
| | $ | 1,283 |
| | $ | 271 |
|
Income (loss) from operations | | 2,361 |
| | 2,024 |
| | 1,388 |
| | (30 | ) | | (449 | ) |
Interest expense, net of capitalized interest | | (1,432 | ) | | (875 | ) | | (747 | ) | | (488 | ) | | (322 | ) |
Net income (loss) attributable to common stockholders | | 648 |
| | 471 |
| | (393 | ) | | (610 | ) | | (975 | ) |
Common Stock Data: | | | | | | | | | | |
Net income (loss) per share attributable to common stockholders—basic | | $ | 2.53 |
| | $ | 1.92 |
| | $ | (1.68 | ) | | $ | (2.67 | ) | | $ | (4.30 | ) |
Net income (loss) per share attributable to common stockholders—diluted | | $ | 2.51 |
| | $ | 1.90 |
| | $ | (1.68 | ) | | $ | (2.67 | ) | | $ | (4.30 | ) |
Weighted average number of common shares outstanding—basic | | 256.2 |
| | 245.6 |
| | 233.1 |
| | 228.8 |
| | 226.9 |
|
Weighted average number of common shares outstanding—diluted | | 258.1 |
| | 248.0 |
| | 233.1 |
| | 228.8 |
| | 226.9 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | December 31, |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
Consolidated Balance Sheet Data: | | | | | | | | | | |
Property, plant and equipment, net | | $ | 29,673 |
| | $ | 27,245 |
| | $ | 23,978 |
| | $ | 20,635 |
| | $ | 16,194 |
|
Total assets | | 35,492 |
| | 31,987 |
| | 27,906 |
| | 23,703 |
| | 18,809 |
|
Current debt, net | | — |
| | 239 |
| | — |
| | 247 |
| | 1,673 |
|
Long-term debt, net | | 30,774 |
| | 28,179 |
| | 25,336 |
| | 21,688 |
| | 14,920 |
|
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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
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
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
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 $27.9/MMBtu. This extreme price increase triggered a strong supply response from the U.S., which played a significant role in balancing the global LNG market. The U.S. exported 70 million tonnes of LNG in 2021, a gain of approximately 49% from the comparable 2020 period, as the market continued to pull on supplies from our facilities and those of our competitors. Exports from our Liquefaction Projects reached 39 million tonnes in aggregate, representing over 55% of the gain in the U.S. total over the same period.
Results of Operations
The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Projects (including both operational and commissioning volumes) during the years ended December 31, 2021 and 2020:
The following table summarizes the volumes of operational and commissioning LNG cargoes that were loaded from the Liquefaction Projects, which were recognized on our Consolidated Financial Statements during the year ended December 31, 2021:
| | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2021 |
(in TBtu) | | | | | Operational | | Commissioning |
Volumes loaded during the current period | | | | | 1,975 | | | 40 | |
Volumes loaded during the prior period but recognized during the current period | | | | | 26 | | | 3 | |
Less: volumes loaded during the current period and in transit at the end of the period | | | | | (49) | | | (1) | |
Total volumes recognized in the current period | | | | | 1,952 | | | 42 | |
Net loss attributable to common stockholders
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | |
(in millions, except per share data) | | | | | | | 2021 | | 2020 | | | | Variance ($) | | | |
Net loss attributable to common stockholders | | | | | | | $ | (2,343) | | | $ | (85) | | | | | $ | (2,258) | | | | | | |
Net loss per share attributable to common stockholders—basic and diluted | | | | | | | (9.25) | | | (0.34) | | | | | (8.91) | | | | | | |
| | | | | | | | | | | | | | | | | | |
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 $4.5 billion of non-cash unfavorable changes in fair value attributed to positions indexed to such prices (pre-tax and excluding the impact of non-controlling interest).
Derivative instruments, which in addition to managing exposure to commodity-related marketing and price risks are utilized to manage exposure to changing interest rates and foreign exchange volatility, are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreements, the underlying transactions being economically hedged are accounted for under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors, notwithstanding the operational intent to mitigate risk exposure over time.
Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) | | | | |
LNG revenues | | | | | | | $ | 15,395 | | | $ | 8,924 | | | | | $ | 6,471 | | | | | | | |
Regasification revenues | | | | | | | 269 | | | 269 | | | | | — | | | | | | | |
Other revenues | | | | | | | 200 | | | 165 | | | | | 35 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Total revenues | | | | | | | $ | 15,864 | | | $ | 9,358 | | | | | $ | 6,506 | | | | | | | |
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 millionand $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 millionand $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 billionand $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.
The following table presents the components of LNG revenues and the corresponding LNG volumes delivered:
| | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | | | 2021 | | 2020 | | |
LNG revenues (in millions): | | | | | | | | | |
LNG from the Liquefaction Projects sold under third party long-term agreements (1) | | | | | $ | 11,990 | | | $ | 6,303 | | | |
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements | | | | | 4,361 | | | 802 | | | |
LNG procured from third parties | | | | | 499 | | | 414 | | | |
LNG revenues associated with cargoes not delivered per customer notification (2) | | | | | — | | | 969 | | | |
Net derivative losses | | | | | (1,776) | | | (30) | | | |
Other revenues | | | | | 321 | | | 466 | | | |
Total LNG revenues | | | | | $ | 15,395 | | | $ | 8,924 | | | |
| | | | | | | | | |
Volumes delivered as LNG revenues (in TBtu): | | | | | | | | | |
LNG from the Liquefaction Projects sold under third party long-term agreements (1) | | | | | 1,608 | | | 1,158 | | | |
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements | | | | | 344 | | | 227 | | | |
LNG procured from third parties | | | | | 45 | | | 103 | | | |
Total volumes delivered as LNG revenues | | | | | 1,997 | | | 1,488 | | | |
| | | | | | | | | |
| | | | | | | | | |
(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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) | | | | |
Cost of sales | | | | | | | $ | 13,773 | | | $ | 4,161 | | | | | $ | 9,612 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Operating and maintenance expense | | | | | | | 1,444 | | | 1,320 | | | | | 124 | | | | | | | |
Development expense | | | | | | | 7 | | | 6 | | | | | 1 | | | | | | | |
Selling, general and administrative expense | | | | | | | 325 | | | 302 | | | | | 23 | | | | | | | |
Depreciation and amortization expense | | | | | | | 1,011 | | | 932 | | | | | 79 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Impairment expense and loss on disposal of assets | | | | | | | 5 | | | 6 | | | | | (1) | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Total operating costs and expenses | | | | | | | $ | 16,565 | | | $ | 6,727 | | | | | $ | 9,838 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
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.
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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) |
Interest expense, net of capitalized interest | | | | | | | $ | 1,438 | | | $ | 1,525 | | | | | $ | (87) | | | | | |
Loss on modification or extinguishment of debt | | | | | | | 116 | | | 217 | | | | | (101) | | | | | |
Interest rate derivative loss, net | | | | | | | 1 | | | 233 | | | | | (232) | | | | | |
Other expense, net | | | | | | | 22 | | | 112 | | | | | (90) | | | | | |
Total other expense | | | | | | | $ | 1,577 | | | $ | 2,087 | | | | | $ | (510) | | | | | |
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.
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)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance |
Income (loss) before income taxes and non-controlling interest | | | | | | | $ | (2,278) | | | $ | 544 | | | | | $ | (2,822) | | | | | |
Income tax provision (benefit) | | | | | | | $ | (713) | | | $ | 43 | | | | | $ | (756) | | | | | |
Effective tax rate | | | | | | | 31.3 | % | | 7.9 | % | | | | 23.4 | % | | | | |
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.
Net income attributable to non-controlling interest
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) |
Net income attributable to non-controlling interest | | | | | | | $ | 778 | | | $ | 586 | | | | | $ | 192 | | | | | |
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
Contractual Obligations
ResultsThe following information describes our ability to generate and obtain adequate amounts of Operations
Off-Balance Sheet Arrangements
Summary of Critical Accounting Estimates
Recent Accounting Standards
Overview of Business
Cheniere, a Delaware corporation, is a Houston-based energy infrastructure company primarily engaged in LNG-related businesses. We provide clean, secure and affordable LNGcash to integrated energy companies, utilities and energy trading companies around the world. We aspire to conductmeet our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers. We own and operate the Sabine Pass LNG terminal in Louisiana, one of the largest LNG production facilitiesrequirements in the world, through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. As of December 31, 2019, we owned 100% of the general partner interest and 48.6% of the limited partner interest in Cheniere Partners. We also own and operate the Corpus Christi LNG terminal in Texas, which is wholly owned by us.
The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners, through its subsidiary SPL, is currently operating five natural gas liquefaction Trains and is constructing one additional Train for a total production capacity of approximately 30 mtpa of LNG (the “SPL Project”) at the Sabine Pass LNG terminal. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ subsidiary, SPLNG, that include pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 17 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4 Bcf/d. Cheniere Partners also owns a 94-mile pipeline through its subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.
We also own the Corpus Christi LNG terminal near Corpus Christi, Texas, and are currently operating two Trains and are constructing one additional Train for a total production capacity of approximately 15 mtpa of LNG. Additionally, we are operating a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Trains, the “CCL Project”) through our subsidiaries CCL and CCP, respectively. The CCL Project, once fully constructed, will contain three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters.
We have contracted approximately 85% of the total production capacity from the SPL Projectshort term and the CCL Project (collectively,long term. In the “Liquefaction Projects”) on ashort term, basis. This includes volumes contracted under SPAs in which the customers are requiredwe expect to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, as well as volumes contracted under integrated production marketing (“IPM”) gas supply agreements.
Additionally, separate from the CCH Group, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project (“Corpus Christi Stage 3”) throughmeet our subsidiary CCL Stage III for up to seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG. We received approval from FERC in November 2019 to site, construct and operate the expansion project.
We remain focused on operational excellence and customer satisfaction. Increasing demand of LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We hold significant land positions at both the Sabine Pass LNG terminal and the Corpus Christi LNG terminal which provide opportunity for further liquefaction capacity expansion. 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 can make a final investment decision (“FID”).
Overview of Significant Events
Our significant events since January 1, 2019 and through the filing date of this Form 10-K include the following:
Strategic
In November 2019, we received approval from the FERC to site, construct and operate the Corpus Christi Stage 3 expansion project, which is being developed for up to seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG.
In September 2019, CCL and CCL Stage III entered into an IPM transaction with EOG Resources, Inc. (“EOG”) to purchase 140,000 MMBtu per day of natural gas, for a term of approximately 15 years beginning in early 2020, at a price based on the Platts Japan Korea Marker (“JKM”), net of a fixed liquefaction fee and certain costs incurred by Cheniere.
In May 2019, CCL Stage III entered into an IPM transaction with Apache Corporation to purchase 140,000 MMBtu per day of natural gas, for a term of approximately 15 years, at a price based on international LNG indices, net of a fixed liquefaction fee and certain costs incurred by Cheniere.
In May 2019, the board of directors of the general partner of Cheniere Partners made a positive FID with respect to Train 6 of the SPL Project and issued a full notice to proceed with construction to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) in June 2019.
In February 2019, Midship Pipeline Company, LLC (“Midship Pipeline”), in which we hold an equity interest, issued full notice to proceed to construct the Midship natural gas pipeline and related compression and interconnect facilities (the “Midship Project”) following receipt of final Notice to Proceed from the FERC and obtaining financing to construct the Midship Project.
Operational
As of February 21, 2020, over 1,000 cumulative LNG cargoes totaling over 70 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.
In March 2019, SPL achieved substantial completion of Train 5 of the SPL Project and commenced operating activities.
In February 2019 and August 2019, CCL achieved substantial completion of Trains 1 and 2 of the CCL Project, respectively, and commenced operating activities.
Financial
We completed the following debt transactions:
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◦ | In November 2019, CCH issued an aggregate principal amount of $1.5 billion of 3.700% Senior Secured Notes due 2029 (the "2029 CCH Senior Notes"). Net proceeds of the offering were used to prepay a portion of the outstanding borrowings under the amended and restated CCH Credit Facility (the “CCH Credit Facility”). |
| |
◦ | In October 2019, CCH issued an aggregate principal amount of $475 million of 3.925% Senior Secured Notes due 2039 (the "3.925% CCH Senior Notes") pursuant to a note purchase agreement with certain accounts managed by BlackRock Real Assets and certain accounts managed by MetLife Investment Management, to prepay a portion of the outstanding indebtedness under the CCH Credit Facility. |
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◦ | In September 2019, CCH issued an aggregate principal amount of $727 million of 4.80% Senior Secured Notes due 2039 (the “4.80% CCH Senior Notes”) pursuant to a note purchase agreement originally entered into in June |
2019 (“CCH Note Purchase Agreement”) with Allianz Global Investors GmbH, to prepay a portion of the outstanding indebtedness under the CCH Credit Facility.
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◦ | In September 2019, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 4.500% Senior Notes due 2029 (the “2029 CQP Senior Notes”) to prepay the outstanding balance under the $750 million term loan under Cheniere Partners’ credit facilities (the “2019 CQP Credit Facilities”), which were entered into in May 2019, and for general corporate purposes, including funding future capital expenditures in connection with the construction of Train 6 at the SPL Project. After applying the proceeds of the 2029 CQP Senior Notes, only a $750 million revolving credit facility, which is currently undrawn, remains as part of the 2019 CQP Credit Facilities. |
In September 2019, Fitch Ratings (“Fitch”) and S&P Global Ratings each assigned an investment grade rating of BBB- to CCH’s senior secured debt, and Fitch assigned an investment grade issuer default rating of BBB- to CCH. In October 2019, Moody’s Investors Service upgraded its rating of CCH’s senior secured debt from Ba2 to Ba1 (Positive Outlook).
In June 2019, we announced a capital allocation framework which prioritizes investments in the growth of our liquefaction platform, improvement of consolidated leverage metrics, and a return of excess capital to shareholders under a three-year, $1.0 billion share repurchase program. We commenced share repurchase activity in the second quarter of 2019 and commenced prepayment of outstanding debt in the third quarter of 2019.
We reached the following contractual milestones:
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◦ | In September 2019, the date of first commercial delivery was reached under the 20-year SPAs with Centrica plc and Total Gas & Power North America, Inc. (“Total”) relating to Train 5 of the SPL Project. |
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◦ | In June 2019, the date of first commercial delivery was reached under the 20-year SPAs with Endesa S.A. and PT Pertamina (Persero) relating to Train 1 of the CCL Project. |
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◦ | In March 2019, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC relating to Train 4 of the SPL Project. |
Liquidity and Capital Resources
Although results are consolidated for financial reporting, Cheniere, Cheniere Partners, SPL and the CCH Group operate with independent capital structures. Our capitalcash requirements include capital and investment expenditures, repayment of long-term debt and repurchase of our shares. We expect the cash needs for at least the next twelve months will be met for each of these independent capital structures as follows:
SPL through project debt and borrowings,using operating cash flows and equity contributions from Cheniere Partners;
Cheniere Partners throughavailable 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 from SPLNG, SPL and CTPL and debt or equity offerings;
CCH Group through operating cash flows from CCL and CCP, project debt and borrowings and equity contributions from Cheniere; and
Cheniere through existing unrestricted cash,other future potential sources of liquidity, which may include debt and equity offerings by us or our subsidiaries, operating cash flows, borrowings, services fees from our subsidiaries and distributions from our investment in Cheniere Partners.
subsidiaries. The following table below provides a summary of our available liquidity position at December 31, 2019 and 2018 (in millions):
|
| | | | | | | |
| December 31, |
| 2019 | | 2018 |
Cash and cash equivalents (1) | $ | 2,474 |
| | $ | 981 |
|
Restricted cash designated for the following purposes: | | | |
SPL Project | 181 |
| | 756 |
|
Cheniere Partners and cash held by guarantor subsidiaries | — |
| | 785 |
|
CCL Project | 80 |
| | 289 |
|
Other | 259 |
| | 345 |
|
Available commitments under the following credit facilities: | | | |
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”) | 786 |
| | 775 |
|
2019 CQP Credit Facilities | 750 |
| | — |
|
$2.8 billion Cheniere Partners’ Credit Facilities (“2016 CQP Credit Facilities”) | — |
| | 115 |
|
CCH Credit Facility | — |
| | 982 |
|
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) | 729 |
| | 716 |
|
$1.25 billion Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”) | 665 |
| | 1,250 |
|
| |
(1) | Amounts presented include balances held by our consolidated variable interest entity (“VIE”), Cheniere Partners as discussed in Note 9—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of December 31, 2019 and 2018, assets of Cheniere Partners, which are included in our Consolidated Balance Sheets, included $1.8 billion and zero, respectively, of cash and cash equivalents. |
Sabine Pass LNG Terminal
Liquefaction Facilities
The SPL Project is one of the largest LNG production facilities in the world. Through Cheniere Partners, we are currently operating five Trains and two marine berths at the SPL Project and are constructing one additional Train. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. We have achieved substantial completion of the first five Trains of the SPL Project and commenced commercial operating activities for each Train at various times starting in May 2016. The following table summarizes the project completion and construction status of Train 6 of the SPL Project as of December 31, 2019:
2021 (in millions). Future material sources of liquidity are discussed below. | | | | | | | |
| December 31, 2021 | | |
Cash and cash equivalents (1) | $ | 1,404 | | | |
Restricted cash and cash equivalents designated for the following purposes: | | | |
| | | |
SPL Project | 98 | SPL Train 6 | | |
Overall project completion percentage | | 43.7% | |
Completion percentage of: | |
| |
EngineeringCCL Project | 44 | 91.5% | | |
ProcurementCash held by our subsidiaries that is restricted to Cheniere | 271 | 60.9% | | |
Subcontract workAvailable commitments under our credit facilities (2): | | 37.4% | |
Construction | | 9.7% | |
Date$1.2 billion Working Capital Revolving Credit and Letter of expected substantial completionCredit Reimbursement Agreement (the “2020 SPL Working Capital Facility”) | 805 | 1H 2023 | | |
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”) | 750 | | | |
| | | |
| | | |
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) | 589 | | | |
Cheniere Revolving Credit Facility | 1,250 | | | |
| | | |
Total available commitments under our credit facilities | 3,394 | | | |
| | | |
Total available liquidity | $ | 5,211 | | | |
(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.
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 orderstable summarizes our estimate of future material sources of liquidity to be received from executed contracts as of December 31, 2021 (in billions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Revenues Under Executed Contracts by Period (1) |
| | | | | | | | |
| | 2022 | | 2023 - 2026 | | Thereafter | | Total |
LNG revenues (fixed fees) (2) | | $ | 5.7 | | | $ | 25.0 | | | $ | 76.4 | | | $ | 107.1 | |
LNG revenues (variable fees) (2) (3) | | 8.0 | | | 30.6 | | | 103.4 | | | 142.0 | |
Regasification revenues | | 0.3 | | | 1.0 | | | 0.6 | | | 1.9 | |
Financial derivatives (4) | | (0.3) | | | — | | | — | | | (0.3) | |
| | | | | | | | |
Total | | $ | 13.7 | | | $ | 56.6 | | | $ | 180.4 | | | $ | 250.7 | |
(1)Excludes contracts for which conditions precedent have not been issued bymet. Agreements in force as of December 31, 2021 that have terms dependent on project milestone dates are based on the DOE authorizingestimated 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 exporttiming difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of domestically produced 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 by vesselrevenues 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
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 Sabine Pass LNG terminal:
Trains 1 through 4—FTA countries for a 30-year term, which commenced in May 2016, and non-FTA countries for a 20-year term, which commenced in June 2016, in an amount up to a combined totalLiquefaction Projects. The majority of the equivalentcontracted capacity is comprised of 16 mtpa (approximately 803 Bcf/yr of natural gas).
Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term, both of which commenced in December 2018, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).
Trains 5 and 6—FTA countries and non-FTA countries for a 20-year term, which partially commenced in June 2019 and the remainder commenced in September 2019, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).
In each case, the terms of these authorizations began on the earlier of the date of first export thereunder or the date specified in the particular order. In addition, SPL received an order providing for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes SPL was authorized but unable to export during any portion of the initial 20-year export period of such order.
The DOE issued orders authorizing SPL to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing January 2020, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports under this order, when combined with exports under the orders above, may not exceed 1,509 Bcf/yr).
An application was filed in September 2019 to authorize additional exports from the SPL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 153 Bcf/yr of natural gas, for a total SPL Project export of approximately 1,662 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the SPL Project of the volumes contemplated in the application. The application is currently pending before DOE.
Customers
SPL has entered into fixed pricefixed-price, long-term SPAs generallythat SPL and CCL have executed with terms of 20 years (plus extension rights) with eight third parties forto 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 thesethe SPAs, the customers will purchase LNG from SPL 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 approximately 115% of Henry Hub. TheCertain 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. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’sour SPAs were generally sized at the time of entry into each SPA with the intentintention to cover the costs of gas purchases and variable transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.
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. 5 of the SPL Project.After giving effect to an SPA that Cheniere has committed to provide to SPL byand upon the enddate of 2020,first commercial delivery of Train 6 of the SPL Project, the annual fixed fee portion to be paid by the third-party SPA customers wouldis 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 which is expectedfor 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 occur upon the date of first commercial delivery of Train 6.
Consolidated Financial Statements.
In addition,
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 agreements with SPLa portfolio of long-, medium- and short-term SPAs to purchase, at Cheniere Marketing’s option, anydeliver commercial LNG cargoes to locations worldwide. These volumes are expected to be primarily sourced by LNG produced by SPL in excess of that required forthe Liquefaction Projects but supplemented by volumes procured from other customers. See locations worldwide, as needed.
Marketing section for additional information regarding agreements entered into by Cheniere Marketing.
Natural Gas Transportation, Storage and Supply
To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of December 31, 2019, SPL had secured up2021, Cheniere Marketing has sold or has options to sell approximately 3,8507,974 TBtu of natural gas feedstock throughLNG to be delivered to third party customers between 2022 and 2045, including 7,791 TBtu from long-term and short-term natural gas supplyexecuted contracts with remaining terms that range upare included in the Future Sources of Liquidity under Executed Contracts table above. The cargoes have been sold either on a FOB basis (delivered to 10 years, a portion of which is subject to conditions precedent.
Construction
SPL entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 6 of the SPL Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost,
schedule and performance risks unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.
The total contract price of the EPC contract for Train 6 of the SPL Project is approximately $2.5 billion, including estimated costs for an optional third marine berth. As of December 31, 2019, we have incurred $1.1 billion under this contract.
Regasification Facilities
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. Approximately 2 Bcf/d of the regasification capacitycustomer 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 been reserved underentered into two long-term, third-partythird 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. Each ofTerminal. Total and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1 Bcf/d of regasification capacity and isare 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.
The remaining approximately 2 Bcf/d of capacitySPLNG has been reserved underalso entered into a TUA by SPL.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 upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminalSPLNG that may be used to provide increased flexibilitystarted in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6.2019. 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. During the years ended December 31, 2019, 2018 and 2017,Payments made by SPL recorded $104 million, $30 million and $23 million, respectively, as operating and maintenance expenseto Total under this partial TUA assignment agreement.agreement are included in other purchase obligations in the Future Cash Requirements for Operations and
Under eachCapital Expenditures under Executed Contracts table below. Full discussion of these TUAs, SPLNG is entitledSPLNG’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 retain 2%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 deliveredcustomers. 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 terminal.
Capital Resources
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 currently expect that SPL’s capital resources requirements with respectare committed to the SPL Project will be financed through project debt and borrowings,make future cash flows under the SPAs and equity contributions from Cheniere Partners. We believe that with the net proceeds of borrowings, available commitments under the SPL Working Capital Facility, 2019 CQP Credit Facilities, cash flows frompayments for operations and equity contributions from Cheniere Partners, SPL will have adequate financial resources availablecapital expenditures pursuant to meet its currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6certain of the SPL Project. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.
our contracts. The following table provides a summarysummarizes our estimate of ourmaterial cash requirements for operations and capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Usesexpenditures under executed contracts as of Cash), at December 31, 2019 and 20182021 (in millions)billions):
|
| | | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
Senior notes (1) | | $ | 17,750 |
| | $ | 16,250 |
|
Credit facilities outstanding balance (2) | | — |
| | — |
|
Letters of credit issued (3) | | 414 |
| | 425 |
|
Available commitments under credit facilities (3) | | 1,536 |
| | 775 |
|
Total capital resources from borrowings and available commitments (4) | | $ | 19,700 |
| | $ | 17,450 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | | |
| | 2022 | | 2023 - 2026 | | Thereafter | | Total |
Purchase obligations (2): | | | | | | | | |
Natural gas supply agreements (3) | | $ | 8.4 | | | $ | 15.3 | | | $ | 12.5 | | | $ | 36.2 | |
Natural gas transportation and storage service agreements (4) | | 0.4 | | | 1.6 | | | 4.0 | | | 6.0 | |
Capital expenditures (5) | | 0.2 | | | — | | | — | | | 0.2 | |
Other purchase obligations (6) | | 0.4 | | | 0.6 | | | 0.6 | | | 1.6 | |
Leases (7) | | 0.8 | | | 2.0 | | | 0.9 | | | 3.7 | |
| | | | | | | | |
| | | | | | | | |
Total | | $ | 10.2 | | | $ | 19.5 | | | $ | 18.0 | | | $ | 47.7 | |
| |
(1) | Includes SPL’s 5.625% Senior Secured Notes due 2021, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), 4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”) and 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) (collectively, the “SPL Senior Notes”), as well as CQP’s $1.5 billion of 5.250% Senior Notes |
due 2025 (the “2025 CQP Senior Notes”), $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”) and the 2029 CQP Senior Notes (collectively, the “CQP Senior Notes”).
| |
(2) | Includes outstanding balances under the SPL Working Capital Facility and 2019 CQP Credit Facilities, inclusive of any portion of the 2019 CQP Credit Facilities that may be used for general corporate purposes. |
| |
(3) | Consists of SPL Working Capital Facility and 2019 CQP Credit Facilities. Balance at December 31, 2018 did not include the letters of credit issued or available commitments under the terminated 2016 CQP Credit Facilities, which were not specifically for the Sabine Pass LNG Terminal. |
| |
(4) | Does not include equity contributions that may be available from Cheniere’s borrowings under its convertible notes, which may be used for the Sabine Pass LNG Terminal. |
SPL Senior Notes
(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 SPL Senior Notesestimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are securednot 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)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 pari passu first-priority basis by a security interest in allportion of which is conditional on the membership interests in SPLin-service date of certain asset infrastructure and substantially all of SPL’s assets.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.
At any time prior to three months before the respective dates(5)Capital expenditures primarily consist of maturity for each series of the SPL Senior Notes (exceptcosts incurred through our EPC contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
Both the indenture governing the 2037 SPL Senior Notes (the “2037 SPL Senior Notes Indenture”) and the common indenture governing the remainder of the SPL Senior Notes (the “SPL Indenture”) include restrictive covenants. SPL may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes and the SPL Working Capital Facility. Under the 2037 SPL Senior Notes Indenture and the SPL Indenture, SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025 and are fully amortizing according to a fixed sculpted amortization schedule.
SPL Working Capital Facility
In September 2015, SPL entered into the SPL Working Capital Facility with aggregate commitments of $1.2 billion, which was amended in May 2019 in connection with commercialization and financing of Train 6 of the SPL Project. The SPL Working Capital Facility is intended to be used for loans to SPL (“SPL Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“SPL Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the SPL Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and incremental increases in commitments of up to an additional $390 million. As of December 31, 2019 and 2018, SPL had $786 million and $775 million of available commitments and $414 million and $425 million aggregate amount of issued letters of credit under the SPL Working Capital Facility, respectively. SPL did not have any outstanding borrowings under the SPL Working Capital Facility as of both December 31, 2019 and 2018.
The SPL Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. Loans deemed made in connection with a draw upon a letter of credit (“SPL LC Loans”) have a term of up to one year. SPL Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the SPL Working Capital Facility, (2) the date 15 days after such SPL Swing Line Loan is made and (3) the first borrowing date for a SPL Working Capital Loan or SPL Swing Line Loan occurring at least three business days following the date the SPL Swing Line Loan is made. SPL is required to reduce the aggregate outstanding principal amount of all SPL Working Capital Loans to zero for a period of five consecutive business days at least once each year.
The SPL Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. The obligations of SPL under the SPL Working Capital Facility are secured by substantially all of the assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes.
Cheniere Partners
CQP Senior Notes
The CQP Senior Notes are jointly and severally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (the “CQP Guarantors”). The CQP Senior Notes are governed by the same base indenture (the “CQP Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental Indenture, the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture and the 2029 CQP Senior Notes are further governed by the Third Supplemental Indenture. The indentures governing the CQP Senior Notes contain customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.
At any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, Cheniere Partners may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, Cheniere Partners may redeem up to 35% of the aggregate principal amount of the CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 105.250% of the aggregate principal amount of the 2025 CQP Senior Notes, 105.625% of the aggregate principal amount of the 2026 CQP Senior Notes and 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. Cheniere Partners also may at any time on or after October 1, 2020 through the maturity date of October 1, 2025 for the 2025 CQP Senior Notes, October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes and October 1, 2024 through the maturity date of October 1, 2029 for the 2029 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.
The CQP Senior Notes are Cheniere Partners’ senior obligations, ranking equally in right of payment with Cheniere Partners’ other existing and future unsubordinated debt and senior to any of its future subordinated debt. In the event that the aggregate amount of Cheniere Partners’ secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on substantially all the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.
2016 CQP Credit Facilities
In May 2019, Cheniere Partners terminated the remaining commitments under the 2016 CQP Credit Facilities.
2019 CQP Credit Facilities
In May 2019, Cheniere Partners entered into the 2019 CQP Credit Facilities, which consisted of the $750 million term loan (“CQP Term Facility”), which was prepaid and terminated upon issuance of the 2029 CQP Senior Notes in September 2019, and the $750 million revolving credit facility (“CQP Revolving Facility”). Borrowings under the 2019 CQP Credit Facilities will be used to fund the developmentengineering, procurement and construction of Train 6 of the SPL Project, and for general corporate purposes, subject to a sublimit,which achieved substantial completion on February 4, 2022, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit.
Loans under the 2019 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50%, and the adjusted one-month LIBOR plus 1.0%), plus the applicable margin. Under the CQP Revolving Facility, the applicable margin for LIBOR loans is 1.25% to 2.125% per annum, and the applicable margin for base rate loans is 0.25% to 1.125% per annum, in each case depending on the then-current rating of Cheniere Partners. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three-month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.
Cheniere Partners pays a commitment fee equal to an annual rate of 30% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears.
The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit Cheniere Partners’ ability to make restricted payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain conditions are satisfied.
The 2019 CQP Credit Facilities are unconditionally guaranteed and secured by a first priority lien (subject to permitted encumbrances) on substantially all of Cheniere Partners’ and the CQP Guarantors’ existing and future tangible and intangible assets and rights and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities).
Corpus Christi LNG Terminal
Liquefaction Facilities
We are currently operating two Trains and onethird marine berth at the CCL Projectthat is currently under construction.
(7)Leases include payments under (1) operating leases, (2) finance leases, (3) short-term leases and are constructing one additional Train and marine berth. We have received authorization from the FERC to site, construct and operate Trains 1 through 3 of the CCL Project. We completed construction of Trains 1 and 2 of the CCL Project and commenced commercial operating activities in February 2019 and August 2019, respectively. The following table summarizes the project completion and construction status of Train 3 of the CCL Project, including the related infrastructure,(4) vessel time charters that were executed as of December 31, 2019:2021 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.
|
| | | |
| | CCL Train 3 |
Overall project completion percentage | | 74.8% |
Completion percentage of: | | |
Engineering | | 98.7% |
Procurement | | 99.5% |
Subcontract work | | 28.3% |
Construction | | 49.5% |
Expected date of substantial completion | | 1H 2021 |
Natural Gas Supply, Transportation and Storage Service Agreements
SeparateWe 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 CCH Group,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 are also developing Corpus Christi Stage 3 through our subsidiary CCL Stage III, adjacenthave secured approximately 86% of the natural gas supply required to support the CCL Project. We received approval from FERC in November 2019 to site, construct and operate seven midscale Trains with an expected total forecasted production capacity of approximately 10 mtpathe Liquefaction Projects during 2022. Natural gas supply secured decreases as a percentage of LNG.
The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal:
CCL Project—FTA countries for a 25-year term and to non-FTA countries for a 20-year term, both of which commenced in June 2019, up to a combined totalforecasted production capacity beyond 2022. Natural gas supply is generally secured on an indexed pricing basis, with title transfer occurring upon receipt of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas.
Corpus Christi Stage 3—FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount equivalent to 582.14 Bcf/yr (approximately 11 mtpa) of natural gas.
In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specifiedcommodity. As further described in the particular order, which ranges from seven to 10 years fromLNG Revenues section above, the date the order was issued.
An application was filed in September 2019 to authorize additional exports from the CCL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalentpricing structure of approximately 108 Bcf/yr of natural gas, for a total CCL Project export of 875.16 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the CCL Project of the volumes contemplated in the application. The application is currently pending before DOE.
Customers
CCL has entered into fixed price long-term SPAs generallyour SPA arrangements with terms of 20 years (plus extension rights) with nine third parties for Trains 1 through 3 of the CCL Project. Under these SPAs, theour customers will purchase LNG from CCL on a 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) plusincorporates a variable fee per MMBtu of LNG generally equal to approximately 115% of Henry Hub. The customers may electHub, which is paid upon delivery, thus limiting our net exposure to cancel or suspend deliveriesfuture increases in natural gas prices. Inclusive of LNG cargoes,amounts under contracts with advance noticeunsatisfied conditions precedent as governedof December 31, 2021 and those executed by each respective SPA, in which case the customers would still be requiredCCL Stage III, we have secured up to pay the fixed fee with respect to the contracted volumes that are not delivered as a result10,872 TBtu of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the CCL Project was sized at the time of entry into each SPA with the intent to cover the costs ofnatural gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for the applicable Train, as specified in each SPA.
In aggregate, the minimum fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to approximately $1.4 billion upon the date of first commercial delivery for Train 2 and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the CCL Project.
In addition, Cheniere Marketing hasfeedstock through agreements with CCL to purchase: (1) 15 TBtu per annum of LNG with an approximate term of 23 years, (2) any LNG produced by CCL in excess ofremaining terms that required for other customers at Cheniere Marketing’s option and (3) 0.85 mtpa of LNG with a term ofrange up to seven years associated with the IPM15 years. A discussion of our natural gas supply agreement between CCL and EOG. SeeIPM agreements can be found in MarketingNote 7—Derivative Instruments section for additional information regarding agreements entered into by Cheniere Marketing.of our Notes to Consolidated Financial Statements.
Natural Gas Transportation, Storage and Supply
To ensure CCL isthat we are able to transport adequate natural gas feedstock to the Corpus Christi and Sabine Pass LNG terminal, it hasterminals, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CCP and certain third-partyfrom pipeline companies. CCL hasWe have also entered into a firm storage services agreementagreements with a third partyparties to assist in managing variability in natural gas needs for the CCL Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue toLiquefaction Projects.
Capital Expenditures
We enter into such agreements, in order to secure natural gas feedstock for the CCL Project. As of December 31, 2019, CCL had secured up to approximately 2,999 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to eight years, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.
CCL Stage III has also entered into long-term natural gas supply contracts with third parties, and anticipates continuing to enter into such agreements, in order to secure natural gas feedstock for Corpus Christi Stage 3. As of December 31, 2019, CCL Stage III had secured up to approximately 2,361 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to approximately 15 years, which is subject to the achievement of certain project milestones and other conditions precedent.
A portion of the natural gas feedstock transactions for CCL and CCL Stage III are IPM transactions, in which the natural gas producers are paid based on a global gas market price less a fixed liquefaction fee and certain costs incurred by us.
Construction
CCL entered into separate lump sum turnkey contracts with Bechtelthird party contractors for the engineering, procurement and construction (“EPC”) of Trains 1 through 3 of the CCL Project under whichour Liquefaction Projects. The historical contracts have been executed with Bechtel, chargeswho has charged a lump sum for all work performed and generally bearsbore project
cost, schedule and performance risks unless certain specified events occur, occurred,
in which case Bechtel may cause CCLcaused us to enter into a change order, or CCL agreeswe 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 3,6, which achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2019. As$2.5 billion. We anticipate our future cash requirements for capital expenditures will increase in connection with the expected final investment decision (“FID”) of December 31, 2019, we have incurred $2.0 billion under this contract.
Final Investment Decision for Corpus Christi Stage 33. 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 forof 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 be subject to, among other things, entering into an EPC contract, obtaining additional commercialinitially require, in support forof commercializing the project and securing the necessary financing arrangements.project.
Pipeline Facilities
In December 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the Natural Gas Act of 1938, as amended, authorizing CCP to construct and operate the Corpus Christi Pipeline. The Corpus Christi Pipeline is designed to transport 2.25 Bcf/d of natural gas feedstock required by the CCL Project from the existing regional natural gas pipeline grid. The construction of the Corpus Christi Pipeline was completed in the second quarter of 2018.
In November 2019, the FERC authorized CCP to construct and operate the pipeline for Corpus Christi Stage 3. The pipeline will be designed to transport 1.5 Bcf/d of natural gas feedstock required byBeyond Corpus Christi Stage 3, fromour significant land positions at the existing regional natural gasCorpus 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 grid.
Capital Resources
The CCH Group expectsinfrastructure and resources. We expect that any potential future expansion at the Corpus Christi or Sabine Pass LNG terminals would increase cash requirements to financesupport expanded operations, although expansion could be designed to leverage shared infrastructure to reduce the constructionincremental costs of the CCL Project from one or moreany potential expansion.
Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to certain of the following: operating cash flows from CCL and CCP, project debt and equity contributions from Cheniere.our contracts. The following table providessummarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2021 (in billions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | | |
| | 2022 | | 2023 - 2026 | | Thereafter | | Total |
Debt (2) | | $ | 0.9 | | | $ | 11.5 | | | $ | 17.9 | | | $ | 30.3 | |
Interest payments (2) | | 1.4 | | | 4.3 | | | 2.6 | | | 8.3 | |
Total | | $ | 2.3 | | | $ | 15.8 | | | $ | 20.5 | | | $ | 38.6 | |
(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 summaryresult of a variety of factors described in this annual report on Form 10-K.
(2)Debt and interest payments are based on the capital resources of the CCH Group from borrowingstotal debt balance, scheduled contractual maturities and available commitments for the CCL Project, excluding equity contributions from Cheniere,fixed or estimated forward interest rates in effect at December 31, 20192021, excluding debt and 2018 (in millions):
|
| | | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
Senior notes (1) | | $ | 6,952 |
| | $ | 4,250 |
|
11.0% Convertible Senior Secured Notes due 2025 (2) | | 1,000 |
| | 1,000 |
|
Credit facilities outstanding balance (3) | | 3,283 |
| | 5,324 |
|
Letters of credit issued (3) | | 471 |
| | 316 |
|
Available commitments under credit facilities (3) | | 729 |
| | 1,698 |
|
Total capital resources from borrowings and available commitments (4) | | $ | 12,435 |
| | $ | 12,588 |
|
| |
(1) | Includes CCH’s 7.000% Senior Secured Notes due 2024 (the “2024 CCH Senior Notes”), 5.875% Senior Secured Notes due 2025 (the “2025 CCH Senior Notes”), 5.125% Senior Secured Notes due 2027 (the “2027 CCH Senior Notes”), 2029 CCH Senior Notes, 4.80% CCH Senior Notes and 3.925% CCH Senior Notes (collectively,interest payments on the “CCH Senior Notes”). |
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(2) | Aggregate original principal amount before debt discount and debt issuance costs. |
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(3) | Includes CCH Credit Facility and CCH Working Capital Facility. |
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(4) | Does not include equity contributions that may be available from Cheniere’s borrowings under the 2021 Cheniere Convertible Unsecured Notes, 2045 Cheniere Convertible Senior Notes and Cheniere Revolving Credit Facility, which may be used for the CCL Project. |
2025 CCH HoldCo II Convertible Senior Notes
which are based on the redemption payment made January 5, 2022. In May 2015, CCH HoldCo IIDecember 2021, we issued $1.0a notice of redemption for all $0.6 billion aggregate principal amount outstanding of 11.0%the 2045 Cheniere Convertible Senior Secured Notes due 2025 (the “2025 CCH HoldCo II Convertible Senior Notes”)Notes. The redemption payment of $0.5 billion is included in 2022 debt payments for consistency
with expected cash flow presentation in our Consolidated Statements of Cash Flows when the instrument settles. Other than debt and interest payments on a private placement basis. The 2025 CCH HoldCo IIthe 2045 Cheniere Convertible Senior Notes, are convertible at the option of CCH HoldCo II or the holders on or after March 1, 2020debt and September 1, 2020, respectively, provided the total market capitalization of Cheniere atinterest payments do not contemplate repurchases, repayments and retirements that time is not less than $10.0 billion and certain other conditions are satisfied. CCH HoldCo II is restricted from making distributionswe expect to Cheniere under agreements governing its
indebtedness generally until, among other requirements, a historical debt service coverage ratio and a projected fixed debt service coverage ratio of 1.20:1.00 are achieved. The 2025 CCH HoldCo II Convertible Senior Notes are secured by a pledge by us of 100% of the equity interests in CCH HoldCo II, and a pledge by CCH HoldCo II of 100% of the equity interests in CCH HoldCo I. In addition, the 2025 CCH HoldCo II Convertible Senior Notes are secured by a security interest in the account into which all distributions from CCH HoldCo I to CCH HoldCo II must be deposited.
In May 2018, the amended and restated note purchase agreement under which the 2025 CCH HoldCo II Convertible Senior Notes were issued was subsequently amended in connection with commercialization and financing of Train 3 of the CCL Project and to provide the note holders with certain prepayment rights related thereto consistent with those under the CCH Credit Facility. All terms of the 2025 CCH HoldCo II Convertible Senior Notes substantially remained unchanged.
CCH Senior Notes
The CCH Senior Notes are jointly and severally guaranteed by CCH’s subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “CCH Guarantor” and collectively, the “CCH Guarantors”). The indentures governing the CCH Senior Notes contain customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a whole; or permit any CCH Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets. The covenants included in the respective indentures that govern the CCH Senior Notes are subject to a number of important limitations and exceptions.
The CCH Senior Notes are CCH’s senior secured obligations, ranking senior in right of payment to any and all of CCH’s future indebtedness that is subordinated to the CCH Senior Notes and equal in right of payment with CCH’s other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Notes. The CCH Senior Notes are secured by a first-priority security interest in substantially all of CCH’s and the CCH Guarantors’ assets.
At any time prior to
six months before the respective datescontractual maturity. See further discussion in Note 11—Debt of maturity for each of the CCH Senior Notes, CCH may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the appropriate indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time within six months of the respective dates of maturity for each of the CCH Senior Notes, CCH may redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Seniorour Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.Consolidated Financial Statements.CCH Credit Facility
Debt
In May 2018, CCH amended and restated the CCH Credit Facility to increase total commitments under the CCH Credit Facility from $4.6 billion to $6.1 billion. The obligations of CCH under the CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in CCH.
As of December 31, 2019 and 2018, CCH had zero and $1.02021, 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 available commitments and $3.3$2.0 billion and $5.2 billionconvertible notes with an outstanding principal balance of loans outstanding under the CCH Credit Facility, respectively. As part of the capital allocation framework announced in June 2019, we prepaid $153 million of outstanding borrowings under the CCH Credit Facility during the year ended December 31, 2019.
The CCH Credit Facility matures on June 30, 2024, with principal payments due quarterly commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following the completion of the CCL Project as defined in the common terms agreement and (2) a set date determined by reference to the date under which a certain LNG buyer linked to the last Train of the CCL Project to become operational is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the completion of Trains 1 through 3 and designed to achieve a minimum projected fixed debt service coverage ratio of 1.50:1.
Under the CCH Credit Facility, CCH is required to hedge not less than 65% of the variable interest rate exposure of its senior secured debt. CCH is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, the completion of the construction of Trains 1 through 3 of the CCL Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.
CCH Working Capital Facility
In June 2018, CCH amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility from $350 million to $1.2 billion. The CCH Working Capital Facility is intended to be used for loans to CCH (“CCH Working Capital Loans”) and the issuance of letters of credit on behalf of CCH for certain working capital requirements related to developing and operating the CCL Project and for related business purposes. Loans under the CCH Working Capital Facility are guaranteed by the CCH Guarantors. CCH may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed for working capital under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility.$625 million. As of December 31,
20192021, 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 Note11—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 2018, CCHour convertible notes had $729 millionan 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 $716 millioncounterparties 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 available commitments, $471 million and $316credit 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 and zero and $168 millionunder our credit facilities as of loans outstanding under the CCH Working Capital Facility, respectively.December 31, 2021.
The CCH Working Capital Facility matures on June 29, 2023, and CCH may prepay the CCH Working Capital Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans”) at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. CCHAdditional Future Cash Requirements for Financing
CQP Distribution
CQP is required by its partnership agreement to reduce the aggregate outstanding principal amount ofdistribute to unitholders all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.
The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. The obligations of CCH under the CCH Working Capital Facility are secured by substantially all of the assets of CCH and the CCH Guarantors as well as all of the membership interests in CCH and each of the CCH Guarantors on a pari passu basis with the CCH Senior Notes and the CCH Credit Facility.
Cheniere
Convertible Notes
In November 2014, we issued an aggregate principal amount of $1.0 billion of Convertible Unsecured Notes due 2021 (the “2021 Cheniere Convertible Unsecured Notes”). The 2021 Cheniere Convertible Unsecured Notes are convertibleavailable cash at the optionend of the holder into our common stock at the then applicable conversion rate, provided that the closing price of our common stock is greater than or equal to the conversion price on the date of conversion. In March 2015, we issued $625 million aggregate principal amount of unsecured 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”). We have the right, at our option, at any time after March 15, 2020, to redeem all or any part of the 2045 Cheniere Convertible Senior Notes at a redemption price equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date. We have the option to satisfy the conversion obligation for the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes with cash, common stock or a combination thereof.
Cheniere Revolving Credit Facility
In December 2018, we amended and restated the Cheniere Revolving Credit Facility to increase total commitments under the Cheniere Revolving Credit Facility from $750 million to $1.25 billion. The Cheniere Revolving Credit Facility is intended to fund, through loans and letters of credit, equity capital contributions to CCH HoldCo II and its subsidiaries for the development of the CCL Project and, provided that certain conditions are met, for general corporate purposes.
The Cheniere Revolving Credit Facility matures on December 13, 2022 and contains representations, warranties and affirmative and negative covenants customary for companies like us with lenders of the type participating in the Cheniere Revolving Credit Facility that limit our ability to make restricted payments, including distributions, unless certain conditions are satisfied, as well as limitations on indebtedness, guarantees, hedging, liens, investments and affiliate transactions. Under the Cheniere Revolving Credit Facility, we are required to ensure that the sum of our unrestricted cash andquarter less the amount of undrawn commitments
under the Cheniere Revolving Credit Facility is at least equal to the lesser of (1) 20% of the commitments under the Cheniere Revolving Credit Facility and (2) $200 million (the “Liquidity Covenant”).
From and after the time at which certain specified conditions are met (the “Trigger Point”), we will have increased flexibility under the Cheniere Revolving Credit Facility to, among other things, (1) make restricted payments and (2) raise incremental commitments. The Trigger Point will occur once (1) completion has occurred for each of Train 1 of the CCL Project (as defined in the CCH Indenture) and Train 5 of the SPL Project (as defined in SPL’s common terms agreement), which has occurred in February 2019 and March 2019, respectively; (2) the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit under the Cheniere Revolving Credit Facility is less than or equal to 10% of aggregate commitments under the Cheniere Revolving Credit Facility and (3) we elect on a go-forward basis to be governedany reserves established by a non-consolidated leverage ratio covenant not to exceed 5.75:1.00 (the “Springing Leverage Covenant”), which following such election will apply at any time that the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit under the Cheniere Revolving Credit Facility is greater than 30% of aggregate commitments under the Cheniere Revolving Credit Facility. Following the Trigger Point, at any time that the Springing Leverage Covenant is in effect, the Liquidity Covenant will not apply.
The Cheniere Revolving Credit Facility is secured by a first priority security interest (subject to permitted liens and other customary exceptions) in substantially all of our assets, including our interests in our direct subsidiaries (excluding CCH HoldCo II and certain other subsidiaries).
Cash Receipts from Subsidiaries
Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of December 31, 2019, we ownedits general partner. We own a 48.6% limited partner interest in Cheniere PartnersCQP in the form of 104.5239.9 million common units, and 135.4 million subordinated units. We also own 100% ofwith the generalremaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the incentive distribution rights in Cheniere Partners. We are eligible to receive quarterly equity distributions from Cheniere Partners related to our ownership interests and our incentive distribution rights.
We also receive fees for providing management services to some of our subsidiaries. We received $103 million, $76 million and $106 million in total service fees from these subsidiaries duringpublic. During the yearsyear ended December 31, 2019, 2018 and 2017, respectively.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
On June 3,In 2019, we announced that our Board authorized a 3-year,three-year, $1.0 billion share repurchase program. During the year ended December 31, 2019, we repurchased an aggregate of 4.0 million shares ofIn 2021, our common stock for $249 million, forBoard authorized a weighted average price per share of $62.27. As of December 31, 2019, we had up to $751 millionreset of the share repurchase program, available. Underwhich 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, repurchases can be made from time to time using a variety of methods, which may include open market purchases, privately negotiated transactions or otherwise, all in accordance with the rules of the SEC and other applicable legal requirements.program. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by our management based on market conditions and other factors. TheDuring 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 does not obligate us to acquire any particular amountcan be found in Item 5. Market for Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchase of common stock,Equity Securities.
Debt Repurchases, Repayments and may be modified, suspended or discontinued at any time or from time to time at our discretion.Redemptions
Marketing
We marketexpect 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 selllessen 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 produced byterminals is expanded beyond the Liquefaction Projects that is not required for other customers through our integrated marketing function. We have, and continue to develop, a portfolio of long-, medium- and short-term SPAs to transport and unload 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, 2019, we have sold or have options to sell approximately 4,935 TBtu of LNG to be delivered to customers between 2020 and 2045, excluding volumes for agreements anticipated to be assigned to SPL in the future. 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 LNG receiving terminal). We have chartered LNG vessels to be utilized for cargoes sold on a DAT basis. In addition,Stage 3, we have entered into a long-term agreement to sell LNG cargoes on a DAT basisexpect that is conditioned upon the buyer achieving certain milestones.
Cheniere Marketing entered into uncommitted trade finance facilities with available commitments of $420 million as of December 31, 2019, primarily toadditional financing would be used for the purchase and sale of LNG for ultimate resale in the course of its operations. The finance facilities are intended to be used for advances, guarantees or the issuance of letters of credit or standby letters of credit on behalf of Cheniere Marketing. As of December 31, 2019 and 2018, Cheniere Marketing had $41 million and $31 million, respectively, in standby letters of credit and guarantees outstanding under the finance facilities. As of December 31, 2018, Cheniere Marketing had $71 million in loans outstanding under the finance facilities. As of December 31, 2019, there were no loans outstanding under the finance facilities. Cheniere Marketing pays interest or fees on utilized commitments.
Corporate and Other Activities
We are required to maintain corporate and general and administrative functions to serve our business activities described above. The development of our 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 an FID.
We have made an equity investment in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline. Midship Pipeline is constructing the Midship Project with expected capacity of up to 1.44 million Dekatherms per day that will connect new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the Liquefaction Projects. Constructionfund construction of the Midship Project commenced in the first quarter of 2019 and is expected to be completed in the first half of 2020.expansion.
Restrictive Debt Covenants
As of December 31, 2019, each of our issuers was in compliance with all covenants related to their respective debt agreements.
LIBOR
The use of LIBOR is expected to be phased out by the end of 2021. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue to work with our lenders to pursue any amendments to our debt agreements that are currently subject to LIBOR and will continue to monitor, assess and plan for the phase out of LIBOR.
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, 2019, 20182021 and 20172020 (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.
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| Year Ended December 31, |
| 2021 | | 2020 | | |
| | | | | |
Net cash provided by operating activities | $ | 2,469 | | | $ | 1,265 | | | |
Net cash used in investing activities | (912) | | | (1,947) | | | |
Net cash used in financing activities | (1,817) | | | (235) | | | |
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Net decrease in cash, cash equivalents and restricted cash and cash equivalents | $ | (260) | | | $ | (917) | | | |
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| Year Ended December 31, |
| 2019 | | 2018 | | 2017 |
Operating cash flows | $ | 1,833 |
| | $ | 1,990 |
| | $ | 1,231 |
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Investing cash flows | (3,163 | ) | | (3,654 | ) | | (3,381 | ) |
Financing cash flows | 1,168 |
| | 2,207 |
| | 2,936 |
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Net increase (decrease) in cash, cash equivalents and restricted cash | (162 | ) |
| 543 |
| | 786 |
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Cash, cash equivalents and restricted cash—beginning of period | 3,156 |
| | 2,613 |
| | 1,827 |
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Cash, cash equivalents and restricted cash—end of period | $ | 2,994 |
| | $ | 3,156 |
| | $ | 2,613 |
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Operating Cash Flows
Our operating cash net inflows during the years ended December 31, 2019, 20182021 and 20172020 were $1,833 million, $1,990$2,469 million and $1,231$1,265 million, respectively. The $157 million decrease in operating cash inflows in 2019 compared to 2018 was primarily related to increased operating costs and expenses, which were partially offset by increased cash receipts from the sale of LNG cargoes, as a result of the additional Trains that were operating at the Liquefaction Projects in 2019. The $759$1,204 million increase in operating cash inflows in 20182021 compared to 20172020 was primarily related to increased cash receipts from the sale of LNG cargoes partially offset by increaseddue 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 expenses as a resultpayment of the additional Trains that were operating at the SPL Project in 2018.paid-in-kind interest on our convertible notes.
Investing Cash Flows
InvestingOur investing cash net outflows during thein both years ended December 31, 2019, 2018 and 2017 were $3,163 million, $3,654 million and $3,381 million, respectively, and were primarily used to fundwas 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 invested $105 million in Midship Holdings, our equity method investment, duringpurchased land adjacent to the year ended December 31, 2019. During the year ended December 31, 2018, we invested an additional $25 million in our equity method investment Midship Holdings, offset primarily byCCL Project for potential future expansion purposes and received proceeds of $12 million from the sale of our other investments. During the year ended December 31, 2017, we invested an additional $41 million in Midship Holdings and made paymentsfixed assets from divestment of $19 million, primarily for infrastructure to support the CCL Project and other capital projects. Partially offsetting these cash outflows during the year ended December 31, 2017 was a $36 million receipt from the return of collateral payments previously paid for the CCL Project.non-core land holdings.
Financing Cash FlowsResults of Operations
Financing cash net inflowsThe 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, 2019 were $1,168 million, primarily as a result of:2021:
issuance of an aggregate principal amount of $1.5 | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2021 |
(in TBtu) | | | | | Operational | | Commissioning |
Volumes loaded during the current period | | | | | 1,975 | | | 40 | |
Volumes loaded during the prior period but recognized during the current period | | | | | 26 | | | 3 | |
Less: volumes loaded during the current period and in transit at the end of the period | | | | | (49) | | | (1) | |
Total volumes recognized in the current period | | | | | 1,952 | | | 42 | |
Net loss attributable to common stockholders
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(in millions, except per share data) | | | | | | | 2021 | | 2020 | | | | Variance ($) | | | |
Net loss attributable to common stockholders | | | | | | | $ | (2,343) | | | $ | (85) | | | | | $ | (2,258) | | | | | | |
Net loss per share attributable to common stockholders—basic and diluted | | | | | | | (9.25) | | | (0.34) | | | | | (8.91) | | | | | | |
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Net loss attributable to common stockholders increased by$2.3 billion of the 2029 CQP Senior Notes, which was used to prepay the outstanding balance of the term loan under the 2019 CQP Credit Facilities;
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• | issuance of an aggregate principal amount of $1.5 billion of the 2029 CCH Senior Notes, $727 million of the 4.80% CCH Senior Notes and $475 million of the 3.925% CCH Senior Notes, which were used to prepay a portion of the outstanding balance of the CCH Credit Facility;
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$51 million of debt issuance costs primarily related to up-front fees paid upon the closing of the above transactions;
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• | $15 million of debt extinguishment cost related to the issuance of the 2029 CQP Senior Notes and the 2029 CCH Senior Notes;
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$982 million of borrowings and $2,855 million of repayments under the CCH Credit Facility;
$730 million of borrowings and repayments under the 2019 CQP Credit Facilities;
$521 million of borrowings and $689 million in repayments under the CCH Working Capital Facility;
$72 million of net repayments related to our Cheniere Marketing trade financing facilities;
$590 million of distributions to non-controlling interest by Cheniere Partners;
$249 million paid to repurchase approximately 4 million shares of our common stock under the share repurchase program; and
$19 million paid for tax withholdings for share-based compensation.
Financing cash net inflows during the year ended December 31, 2018 were $2,2072021 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 primarilyin 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:
issuance of an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, which was used to prepay $1.1 billion of the outstanding borrowings under the 2016 CQP Credit Facilities;
$2.9 billion of borrowingsincreases in both volume delivered and $281 million in repayments under the CCH Credit Facility;
$188 million of borrowings and $20 million in repayments under the CCH Working Capital Facility;
$71 million of net borrowings related to our Cheniere Marketing trade financing facilities;
$66 million of debt issuance costs related to up-front fees paid upon the closing of these transactions;
$17 million in debt extinguishment costs related to the prepayments of the 2016 CQP Credit Facilities and the CCH Credit Facility;
$576 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings;
$20 million paid for tax withholdings for share-based compensation; and
$7 million of transaction costs to acquire additional interest of Cheniere Holdings.
Financing cash net inflowsgross margin on LNG delivered per MMBtu during the year ended December 31, 2017 were $2,936 million,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 $4.5 billion of non-cash unfavorable changes in fair value attributed to positions indexed to such prices (pre-tax and excluding the impact of non-controlling interest).
Derivative instruments, which in addition to managing exposure to commodity-related marketing and price risks are utilized to manage exposure to changing interest rates and foreign exchange volatility, are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreements, the underlying transactions being economically hedged are accounted for under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors, notwithstanding the operational intent to mitigate risk exposure over time.
Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) | | | | |
LNG revenues | | | | | | | $ | 15,395 | | | $ | 8,924 | | | | | $ | 6,471 | | | | | | | |
Regasification revenues | | | | | | | 269 | | | 269 | | | | | — | | | | | | | |
Other revenues | | | | | | | 200 | | | 165 | | | | | 35 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Total revenues | | | | | | | $ | 15,864 | | | $ | 9,358 | | | | | $ | 6,506 | | | | | | | |
Total revenues increased during the year ended December 31, 2021 from the comparable period in 2020, primarily as a result of: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.
issuances
Prior to substantial completion of SPL’s senior notesa 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 millionand $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 millionand $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 billionand $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.
The following table presents the components of LNG revenues and the corresponding LNG volumes delivered:
| | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | | | 2021 | | 2020 | | |
LNG revenues (in millions): | | | | | | | | | |
LNG from the Liquefaction Projects sold under third party long-term agreements (1) | | | | | $ | 11,990 | | | $ | 6,303 | | | |
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements | | | | | 4,361 | | | 802 | | | |
LNG procured from third parties | | | | | 499 | | | 414 | | | |
LNG revenues associated with cargoes not delivered per customer notification (2) | | | | | — | | | 969 | | | |
Net derivative losses | | | | | (1,776) | | | (30) | | | |
Other revenues | | | | | 321 | | | 466 | | | |
Total LNG revenues | | | | | $ | 15,395 | | | $ | 8,924 | | | |
| | | | | | | | | |
Volumes delivered as LNG revenues (in TBtu): | | | | | | | | | |
LNG from the Liquefaction Projects sold under third party long-term agreements (1) | | | | | 1,608 | | | 1,158 | | | |
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements | | | | | 344 | | | 227 | | | |
LNG procured from third parties | | | | | 45 | | | 103 | | | |
Total volumes delivered as LNG revenues | | | | | 1,997 | | | 1,488 | | | |
| | | | | | | | | |
| | | | | | | | | |
(1)Long-term agreements include agreements with an aggregate principalinitial 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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) | | | | |
Cost of sales | | | | | | | $ | 13,773 | | | $ | 4,161 | | | | | $ | 9,612 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Operating and maintenance expense | | | | | | | 1,444 | | | 1,320 | | | | | 124 | | | | | | | |
Development expense | | | | | | | 7 | | | 6 | | | | | 1 | | | | | | | |
Selling, general and administrative expense | | | | | | | 325 | | | 302 | | | | | 23 | | | | | | | |
Depreciation and amortization expense | | | | | | | 1,011 | | | 932 | | | | | 79 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Impairment expense and loss on disposal of assets | | | | | | | 5 | | | 6 | | | | | (1) | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Total operating costs and expenses | | | | | | | $ | 16,565 | | | $ | 6,727 | | | | | $ | 9,838 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
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.
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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) |
Interest expense, net of capitalized interest | | | | | | | $ | 1,438 | | | $ | 1,525 | | | | | $ | (87) | | | | | |
Loss on modification or extinguishment of debt | | | | | | | 116 | | | 217 | | | | | (101) | | | | | |
Interest rate derivative loss, net | | | | | | | 1 | | | 233 | | | | | (232) | | | | | |
Other expense, net | | | | | | | 22 | | | 112 | | | | | (90) | | | | | |
Total other expense | | | | | | | $ | 1,577 | | | $ | 2,087 | | | | | $ | (510) | | | | | |
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.
$55 million
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 borrowingscertain outstanding derivatives in August 2020 that were in an unfavorable position and $369 milliona 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)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance |
Income (loss) before income taxes and non-controlling interest | | | | | | | $ | (2,278) | | | $ | 544 | | | | | $ | (2,822) | | | | | |
Income tax provision (benefit) | | | | | | | $ | (713) | | | $ | 43 | | | | | $ | (756) | | | | | |
Effective tax rate | | | | | | | 31.3 | % | | 7.9 | % | | | | 23.4 | % | | | | |
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 repayments madethe 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.
Net income attributable to non-controlling interest
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) |
Net income attributable to non-controlling interest | | | | | | | $ | 778 | | | $ | 586 | | | | | $ | 192 | | | | | |
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.
| | | | | | | |
| December 31, 2021 | | |
Cash and cash equivalents (1) | $ | 1,404 | | | |
Restricted cash and cash equivalents designated for the following purposes: | | | |
| | | |
SPL Project | 98 | | | |
| | | |
| | | |
CCL Project | 44 | | | |
Cash held by our subsidiaries that is restricted to Cheniere | 271 | | | |
Available commitments under our credit facilities (2): | | | |
| | | |
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 SPL Working Capital Facility”) | 805 | | | |
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”) | 750 | | | |
| | | |
| | | |
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) | 589 | | | |
Cheniere Revolving Credit Facility | 1,250 | | | |
| | | |
Total available commitments under our credit facilities | 3,394 | | | |
| | | |
Total available liquidity | $ | 5,211 | | | |
(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.
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):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Revenues Under Executed Contracts by Period (1) |
| | | | | | | | |
| | 2022 | | 2023 - 2026 | | Thereafter | | Total |
LNG revenues (fixed fees) (2) | | $ | 5.7 | | | $ | 25.0 | | | $ | 76.4 | | | $ | 107.1 | |
LNG revenues (variable fees) (2) (3) | | 8.0 | | | 30.6 | | | 103.4 | | | 142.0 | |
Regasification revenues | | 0.3 | | | 1.0 | | | 0.6 | | | 1.9 | |
Financial derivatives (4) | | (0.3) | | | — | | | — | | | (0.3) | |
| | | | | | | | |
Total | | $ | 13.7 | | | $ | 56.6 | | | $ | 180.4 | | | $ | 250.7 | |
(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
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 facilitiesrating 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 June 2015 (the “SPL Credit Facilities”);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
Capital Expenditures under Executed Contracts table below. Full discussion of borrowings and $334 million of repayments madeSPLNG’s revenues under the SPL Working Capital Facility;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. $1.5 billion of borrowings under the CCH Credit Facility;
issuance of an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, which was used to prepay $1.4 billion of outstanding borrowings under the CCH Credit Facility;Financial Derivatives
$24 million of borrowings and $24 million of repayments made under the CCH Working Capital Facility;
issuance of an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which was used to prepay $1.5 billion of the outstanding borrowings under the 2016 CQP Credit Facilities;
$24 million in net repayments made under the Cheniere Marketing trade finance facilities;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.$89 million
Additional Future Sources of debt issuanceLiquidity
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 deferred financing costs related2026.
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 up-front fees paid uponbe 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 closingproduction 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 these transactions;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.
$185 million of distributions
Future Cash Requirements for Operations and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings; andCapital Expenditures under Executed Contracts
$12 million paid for tax withholdings for share-based compensation.
Contractual Obligations
We are committed to make future cash payments in the futurefor operations and capital expenditures pursuant to certain of our contracts. The following table summarizes certain contractual obligations in placeour estimate of material cash requirements for operations and capital expenditures under executed contracts as of December 31, 20192021 (in millions)billions):
|
| | | | | | | | | | | | | | | | | | | | |
| | Payments Due By Period (1) |
| | Total | | 2020 | | 2021 - 2022 | | 2023 - 2024 | | Thereafter |
Debt (2) | | $ | 30,610 |
| | $ | — |
| | $ | 4,253 |
| | $ | 7,779 |
| | $ | 18,578 |
|
Interest payments (2) | | 11,315 |
| | 1,633 |
| | 3,419 |
| | 2,612 |
| | 3,651 |
|
Operating lease obligations (3) | | 530 |
| | 250 |
| | 78 |
| | 42 |
| | 160 |
|
Finance lease obligations (4) | | 187 |
| | 11 |
| | 20 |
| | 20 |
| | 136 |
|
Purchase obligations: (5) | |
|
| | | | | | | | |
Construction obligations (6) | | 1,301 |
| | 726 |
| | 534 |
| | 41 |
| | — |
|
Natural gas supply, transportation and storage service agreements (7) | | 13,468 |
| | 3,503 |
| | 3,943 |
| | 2,035 |
| | 3,987 |
|
Other purchase obligations (8) | | 1,658 |
| | 224 |
| | 299 |
| | 298 |
| | 837 |
|
Total | | $ | 59,069 |
|
| $ | 6,347 |
|
| $ | 12,546 |
|
| $ | 12,827 |
|
| $ | 27,349 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | | |
| | 2022 | | 2023 - 2026 | | Thereafter | | Total |
Purchase obligations (2): | | | | | | | | |
Natural gas supply agreements (3) | | $ | 8.4 | | | $ | 15.3 | | | $ | 12.5 | | | $ | 36.2 | |
Natural gas transportation and storage service agreements (4) | | 0.4 | | | 1.6 | | | 4.0 | | | 6.0 | |
Capital expenditures (5) | | 0.2 | | | — | | | — | | | 0.2 | |
Other purchase obligations (6) | | 0.4 | | | 0.6 | | | 0.6 | | | 1.6 | |
Leases (7) | | 0.8 | | | 2.0 | | | 0.9 | | | 3.7 | |
| | | | | | | | |
| | | | | | | | |
Total | | $ | 10.2 | | | $ | 19.5 | | | $ | 18.0 | | | $ | 47.7 | |
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(1) | (1)Excludes contracts for which conditions precedent have not been met. Agreements in force as of December 31, 2019 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2019. |
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(2) | Based on the total debt balance, scheduled maturities and fixed or estimated forward interest rates in effect at December 31, 2019. The repayment of paid in kind interest is included in interest payments. Interest payment obligations exclude adjustments for interest rate swap agreements. A discussion of our debt obligations can be found in Note 11—Debt of our Notes to Consolidated Financial Statements. |
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(3) | Operating lease obligations primarily relate to LNG vessel time charters, land sites related to the Liquefaction Projects and corporate office leases. Operating lease obligations do not include $2.0 billion of legally binding minimum lease payments for vessel charters which were executed as of December 31, 2019 but will commence between 2020 and 2022 and have fixed minimum lease terms of up to seven years. A discussion of our lease obligations can be found in Note 12—Leases of our Notes to Consolidated Financial Statements. |
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(4) | Finance lease obligations consist of tug leases related to the CCL Project, as further discussed in Note 12—Leases of our Notes to Consolidated Financial Statements. |
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(5) | 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 only contracts for which conditions precedent have been met. 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 expected to be exercised. |
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(6) | Construction obligations primarily consist of the estimated remaining cost pursuant to our EPC contracts as of December 31, 2019 for Trains with respect to which we have made an FID to commence construction. A discussion of these obligations can be found at Note 19—Commitments and Contingencies of our Notes to Consolidated Financial Statements. |
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(7) | Pricing of natural gas supply agreements are based on estimated forward prices and basis spreads as of December 31, 2019. |
In addition, as of December 31, 2019,2021 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.
(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.
(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,
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):
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| | Estimated Payments Due Under Executed Contracts by Period (1) |
| | | | | | | | |
| | 2022 | | 2023 - 2026 | | Thereafter | | Total |
Debt (2) | | $ | 0.9 | | | $ | 11.5 | | | $ | 17.9 | | | $ | 30.3 | |
Interest payments (2) | | 1.4 | | | 4.3 | | | 2.6 | | | 8.3 | |
Total | | $ | 2.3 | | | $ | 15.8 | | | $ | 20.5 | | | $ | 38.6 | |
(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
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 Note11—Debt of our Notes to Consolidated Financial Statements.
Interest
As of December 31, 2021, our senior notes had $1,470a 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. We also had tax agreements with certain local taxing jurisdictions for an aggregate amount of $212 million to be paid through 2033, based on estimated tax obligationsfacilities as of December 31, 2019.2021.
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.
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.
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| Year Ended December 31, |
| 2021 | | 2020 | | |
| | | | | |
Net cash provided by operating activities | $ | 2,469 | | | $ | 1,265 | | | |
Net cash used in investing activities | (912) | | | (1,947) | | | |
Net cash used in financing activities | (1,817) | | | (235) | | | |
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Net decrease in cash, cash equivalents and restricted cash and cash equivalents | $ | (260) | | | $ | (917) | | | |
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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.
Results of Operations
The following charts summarize the number of Trains that were in operation during the years ended December 31, 2019, 2018 and 2017 and total revenues and total LNG volumes loaded from our Liquefaction Projects (including both operational and commissioning volumes) forduring the respective periods: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, 2019:2021:
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| | | | | |
| Year Ended December 31, 2019 |
(in TBtu) | Operational | | Commissioning |
Volumes loaded during the current period | 1,466 |
| | 48 |
|
Volumes loaded during the prior period but recognized during the current period | 25 |
| | 3 |
|
Less: volumes loaded during the current period and in transit at the end of the period | (33 | ) | | — |
|
Total volumes recognized in the current period | 1,458 |
| | 51 |
|
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| | | Year Ended December 31, 2021 |
(in TBtu) | | | | | Operational | | Commissioning |
Volumes loaded during the current period | | | | | 1,975 | | | 40 | |
Volumes loaded during the prior period but recognized during the current period | | | | | 26 | | | 3 | |
Less: volumes loaded during the current period and in transit at the end of the period | | | | | (49) | | | (1) | |
Total volumes recognized in the current period | | | | | 1,952 | | | 42 | |
Our consolidated net income
Net loss attributable to common stockholders was $648 million, or $2.53 per share—basic and $2.51 per share—diluted, in
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | |
(in millions, except per share data) | | | | | | | 2021 | | 2020 | | | | Variance ($) | | | |
Net loss attributable to common stockholders | | | | | | | $ | (2,343) | | | $ | (85) | | | | | $ | (2,258) | | | | | | |
Net loss per share attributable to common stockholders—basic and diluted | | | | | | | (9.25) | | | (0.34) | | | | | (8.91) | | | | | | |
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Net loss attributable to common stockholders increased by$2.3 billion during the year ended December 31, 2019, compared2021 from the comparable period in 2020, primarily due to net income attributable to common stockholdersthe increase in derivative losses from changes in fair value and settlements of $471$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 or $1.92in 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 share—basic and $1.90 per share—diluted, inMMBtu during the year ended December 31, 2018. This $177 million increase
2021 from the comparable period in net income attributable to common stockholders in 2019 was primarily attributable to (1) increased gross margins due to increased volume of LNG sold partially offset by decreased pricing on LNG, (2) increased2020, as well as a tax benefit from the release of a significant portion of the valuation allowance previously recorded against our deferred tax assets, (3) increased LNG revenues as a result of derivative gains on commodity derivatives and (4) decreased net income attributable to non-controlling interest, which were partially offset by an increase in (1) interest expense, net of amounts capitalized, (2) operating and maintenance expense, (3) derivative loss, net, associated with our interest rate derivatives, (4) depreciation and amortization expense and (5) loss on equity method investments.
Our consolidated net loss attributable to common stockholders was $393 million, or $1.68 per share (basic and diluted), induring the year ended December 31, 2017. This $864 million increase in net income in 2018 compared2021.
Substantially all derivative losses relate to 2017 was primarily attributable to (1) increased income from operations due to additional Trains operating between the periods, (2) decreased loss on modification or extinguishmentuse of debt and (3) increased derivative gain, net, which were partially offset by decreased net income attributable to non-controlling interest and increased interest expense, net of amounts capitalized.
We enter intocommodity derivative instruments indexed to manageinternational 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 $4.5 billion of non-cash unfavorable changes in fair value attributed to positions indexed to such prices (pre-tax and excluding the impact of non-controlling interest).
Derivative instruments, which in addition to managing exposure to (1) changing interest rates, (2) commodity-related marketing and price risks are utilized to manage exposure to changing interest rates and (3) foreign exchange volatility. Derivative instrumentsvolatility, are reported at fair value on our Consolidated Financial Statements. In some cases,For commodity derivative instruments related to our IPM agreements, the underlying transactions being economically hedged receiveare accounted for under the accrual method of accounting, treatment, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may increase theresult in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.factors, notwithstanding the operational intent to mitigate risk exposure over time.
Revenues
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| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) | | | | |
LNG revenues | | | | | | | $ | 15,395 | | | $ | 8,924 | | | | | $ | 6,471 | | | | | | | |
Regasification revenues | | | | | | | 269 | | | 269 | | | | | — | | | | | | | |
Other revenues | | | | | | | 200 | | | 165 | | | | | 35 | | | | | | | |
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Total revenues | | | | | | | $ | 15,864 | | | $ | 9,358 | | | | | $ | 6,506 | | | | | | | |
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| Year Ended December 31, |
(in millions) | 2019 | | 2018 | | Change | | 2017 | | Change |
LNG revenues | $ | 9,246 |
| | $ | 7,572 |
| | $ | 1,674 |
| | $ | 5,317 |
| | $ | 2,255 |
|
Regasification revenues | 266 |
| | 261 |
| | 5 |
| | 260 |
| | 1 |
|
Other revenues | 218 |
| | 154 |
| | 64 |
| | 24 |
| | 130 |
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Total revenues | $ | 9,730 |
|
| $ | 7,987 |
|
| $ | 1,743 |
| | $ | 5,601 |
| | $ | 2,386 |
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2019 vs. 2018 and 2018 vs. 2017
We begin recognizing LNGTotal revenues from the Liquefaction Projects following the substantial completion and the commencement of operating activities of the respective Trains. The increase in revenues during each of the years was primarily attributable to the increased volume of LNG sold following the achievement of substantial completion of these Trains. The increase in revenue attributable to LNG volume sold during the year ended December 31, 20192021 from the comparable period in 2018 was partially offset by decreased LNG2020, primarily as a result of increased revenues per MMBtu which was primarily affected byand higher volume of LNG delivered between the periods. Revenues per MMBtu of LNG were higher due to improved market prices realized for volumes soldrecognized by our integrated marketing function. Additionally,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 increase in other revenues during eachcustomers take delivery of scheduled cargoes as opposed to exercising their contractual right to not take delivery. The volume of LNG delivered between the years wasperiods increased due to an increase in sub-chartering income. We expectthe non-recurrence of notification by our customers to not take delivery of scheduled LNG revenues to increase incargoes during the future upon Train 6year ended December 31, 2021 and as a result of the SPL Project andproduction from Train 3 of the CCL Project, becoming operational, in addition to full year operation of the Trains that were completed during 2019.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, 2019, 20182021 and 2017,2020, we realized offsets to LNG terminal costs of $301$319 millionand $19 million, corresponding to 51 TBtu of LNG, $140 million corresponding to 1742 TBtu and $320 million corresponding to 513 TBtu respectively, that were related to the sale of commissioning cargoes from Train 3 of the Liquefaction Projects.CCL Project and Train 6 of the SPL Project.
Also included in LNG revenues are gains and losses from derivative instruments and the salesales of certain unutilized natural gas procured for the liquefaction process. We recognizedprocess and other revenues, of $693which was $320 million $163 million and a loss of $8$466 million during the years ended December 31, 2019, 20182021 and 2017,2020, 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 billionand $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 other revenues from these transactions.available for sale to increase in the future as Train 6 of the SPL Project achieved substantial completion on February 4, 2022.
The following table presents the components of LNG revenues and the corresponding LNG volumes sold:delivered:
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| Year Ended December 31, |
| 2019 | | 2018 | | 2017 |
LNG revenues (in millions): | | | | | |
LNG from the Liquefaction Projects sold under third party long-term agreements (1) | $ | 6,342 |
| | $ | 4,762 |
| | $ | 2,588 |
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LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements | 1,943 |
| | 1,902 |
| | 1,756 |
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LNG procured from third parties | 268 |
| | 745 |
| | 981 |
|
Other revenues and derivative gains (losses) | 693 |
| | 163 |
| | (8 | ) |
Total LNG revenues | $ | 9,246 |
| | $ | 7,572 |
| | $ | 5,317 |
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Volumes sold as LNG revenues (in TBtu): | | | | | |
LNG from the Liquefaction Projects sold under third party long-term agreements (1) | 1,090 |
| | 761 |
| | 427 |
|
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements | 368 |
| | 212 |
| | 233 |
|
LNG procured from third parties | 40 |
| | 84 |
| | 98 |
|
Total volumes sold as LNG revenues | 1,498 |
| | 1,057 |
| | 758 |
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| | | Year Ended December 31, |
| | | | | 2021 | | 2020 | | |
LNG revenues (in millions): | | | | | | | | | |
LNG from the Liquefaction Projects sold under third party long-term agreements (1) | | | | | $ | 11,990 | | | $ | 6,303 | | | |
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements | | | | | 4,361 | | | 802 | | | |
LNG procured from third parties | | | | | 499 | | | 414 | | | |
LNG revenues associated with cargoes not delivered per customer notification (2) | | | | | — | | | 969 | | | |
Net derivative losses | | | | | (1,776) | | | (30) | | | |
Other revenues | | | | | 321 | | | 466 | | | |
Total LNG revenues | | | | | $ | 15,395 | | | $ | 8,924 | | | |
| | | | | | | | | |
Volumes delivered as LNG revenues (in TBtu): | | | | | | | | | |
LNG from the Liquefaction Projects sold under third party long-term agreements (1) | | | | | 1,608 | | | 1,158 | | | |
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements | | | | | 344 | | | 227 | | | |
LNG procured from third parties | | | | | 45 | | | 103 | | | |
Total volumes delivered as LNG revenues | | | | | 1,997 | | | 1,488 | | | |
| | | | | | | | | |
| | | | | | | | | |
(1)Long-term agreements include agreements with aan 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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) | | | | |
Cost of sales | | | | | | | $ | 13,773 | | | $ | 4,161 | | | | | $ | 9,612 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Operating and maintenance expense | | | | | | | 1,444 | | | 1,320 | | | | | 124 | | | | | | | |
Development expense | | | | | | | 7 | | | 6 | | | | | 1 | | | | | | | |
Selling, general and administrative expense | | | | | | | 325 | | | 302 | | | | | 23 | | | | | | | |
Depreciation and amortization expense | | | | | | | 1,011 | | | 932 | | | | | 79 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Impairment expense and loss on disposal of assets | | | | | | | 5 | | | 6 | | | | | (1) | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Total operating costs and expenses | | | | | | | $ | 16,565 | | | $ | 6,727 | | | | | $ | 9,838 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(in millions) | 2019 | | 2018 | | Change | | 2017 | | Change |
Cost of sales | $ | 5,079 |
| | $ | 4,597 |
| | $ | 482 |
| | $ | 3,120 |
| | $ | 1,477 |
|
Operating and maintenance expense | 1,154 |
| | 613 |
| | 541 |
| | 446 |
| | 167 |
|
Development expense | 9 |
| | 7 |
| | 2 |
| | 10 |
| | (3 | ) |
Selling, general and administrative expense | 310 |
| | 289 |
| | 21 |
| | 256 |
| | 33 |
|
Depreciation and amortization expense | 794 |
| | 449 |
| | 345 |
| | 356 |
| | 93 |
|
Restructuring expense | — |
| | — |
| | — |
| | 6 |
| | (6 | ) |
Impairment expense and loss on disposal of assets | 23 |
| | 8 |
| | 15 |
| | 19 |
| | (11 | ) |
Total operating costs and expenses | $ | 7,369 |
| | $ | 5,963 |
| | $ | 1,406 |
| | $ | 4,213 |
| | $ | 1,750 |
|
2019 vs. 2018 and 2018 vs. 2017
Our total operating costs and expenses increased during the year ended December 31, 20192021 from the years ended December 31, 2018 and 2017,comparable period in 2020, primarily as a result of the increase in operating Trains between eachincreased cost of the periods. During the year ended December 31, 2019, we further incurred increased third-party service and maintenance costs from turnaround and related activities at the SPL Project.
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, 20192021 from the comparable 2018 and 2017 periods,2020 period, primarily due to increased pricing of natural gas feedstock as a result of the increase in operating Trains between each of the periods. Cost of sales increased during the year ended December 31, 2019 from the year ended December 31, 2018 due tohigher U.S. natural gas prices and increased volume of natural gas feedstock partially offset by its decreased pricing and increased vessel charter costs. Partially offsetting this increase was increased derivative gains from an increaseLNG delivered, as well as unfavorable changes in fair value of theour commodity derivatives associated with economic hedges to secure natural gas feedstock for the Liquefaction Projects primarily duedriven by unfavorable shifts in international forward commodity curves, as discussed above under Net loss attributable to a favorable shift in long-term forward prices.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, andnet of margins from the sale of natural gas procured for the liquefaction process and other costs to convert natural gas into LNG. The increase during the year ended December 31, 2018 from the comparable period in 2017 was primarily related to the increase in the volume of natural gas feedstock related to our LNG sales.
Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Projects. The increase in operating and maintenance expense duringDuring the year ended December 31, 2019 from the comparable 20182021, operating and 2017 periods was primarily as a result of the increase in operating Trains between each of the periods. The increase during the year ended December 31, 2019maintenance expense increased from the comparable period in 2018 was2020, primarily related to: (1)due to increased natural gas transportation and storage capacity demand charges from operatingand increased third party service, generally as a result of an additional Train 5 ofthat was in operation between the SPL Project and Trains 1 and 2 of the CCL
Project following the respective substantial completions, (2) increased cost of turnaround and related activities at the SPL Project, (3) increased TUA reservation charges paid to Total from payments under the partial TUA assignment agreement and (4) increased payroll and benefit costs from increased headcount to operate Train 5 of the SPL Project and Trains 1 and 2 of the CCL Project. The increase during the year ended December 31, 2018 from the comparable period in 2017 was primarily related to third-party service and maintenance contract costs, payroll and benefit costs of operations personnel and natural gas transportation and storage capacity demand charges.periods. Operating and maintenance expense also includes insurance and regulatory costs and other operating costs.
Depreciation and amortization expense increased during each of the years ended December 31, 2019, 2018 and 2017 as a result of an increased number of operational Trains, as the related assets began depreciating upon reaching substantial completion.
Impairment expense and loss on disposal of assets increased during the year ended December 31, 2019 compared to the year ended December 31, 2018. The impairment expense and loss on disposal of assets recognized during the year ended December 31, 2019 was primarily related to the write down of assets used in non-core operations outside of our liquefaction activities, including losses from uncollectible notes receivable. Impairment expense and loss on disposal of assets decreased during the year ended December 31, 20182021 from the comparable 2017 period. The impairment expense and loss on disposal of assets recognized during the year ended December 31, 2018 related to the write down of prepaid assets and related to write down of assets usedperiod in non-core operations outside of our liquefaction activities during the year ended December 31, 2017. The impairment expense and loss on disposal of assets recognized during the year ended December 31, 2017 also included $6 million related to damaged infrastructure2020 as a result of Hurricane Harvey.commencing operations of Train 3 of the CCL Project in March 2021.
We expect our operating costs and expenses to generally increase in the future uponas Train 6 of the SPL Project and Train 3 of the CCL Project achievingachieved substantial completion on February 4, 2022, although we expect certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized.
Other expense (income)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) |
Interest expense, net of capitalized interest | | | | | | | $ | 1,438 | | | $ | 1,525 | | | | | $ | (87) | | | | | |
Loss on modification or extinguishment of debt | | | | | | | 116 | | | 217 | | | | | (101) | | | | | |
Interest rate derivative loss, net | | | | | | | 1 | | | 233 | | | | | (232) | | | | | |
Other expense, net | | | | | | | 22 | | | 112 | | | | | (90) | | | | | |
Total other expense | | | | | | | $ | 1,577 | | | $ | 2,087 | | | | | $ | (510) | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(in millions) | 2019 | | 2018 | | Change | | 2017 | | Change |
Interest expense, net of capitalized interest | $ | 1,432 |
| | $ | 875 |
| | $ | 557 |
| | $ | 747 |
| | $ | 128 |
|
Loss on modification or extinguishment of debt | 55 |
| | 27 |
| | 28 |
| | 100 |
| | (73 | ) |
Derivative loss (gain), net | 134 |
| | (57 | ) | | 191 |
| | (7 | ) | | (50 | ) |
Other expense (income) | 25 |
| | (48 | ) | | 73 |
| | (18 | ) | | (30 | ) |
Total other expense | $ | 1,646 |
| | $ | 797 |
| | $ | 849 |
| | $ | 822 |
| | $ | (25 | ) |
2019 vs. 2018 and 2018 vs. 2017
Interest expense, net of capitalized interest, increaseddecreased during the year ended December 31, 20192021 from the comparable 2018 and 2017 periods primarily2020 period as a result of lower interest costs as a decreaseresult 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 could be capitalized as additional Trainswas eligible for capitalization due to the completion of construction of Train 3 of the Liquefaction Projects completed construction between the periods.CCL Project in March 2021. During the years ended December 31, 2019, 20182021 and 2017,2020, we incurred $1.8 billion, $1.7$1.6 billion and $1.5$1.8 billion of total interest cost, respectively, of which we capitalized $414 million, $803$166 million and $779$248 million, respectively, which was primarily related to interest costs incurred for the construction of the Liquefaction Projects.
DerivativeInterest rate derivative loss, net increaseddecreased during the year ended December 31, 20192021 compared to the year ended December 31, 2018,comparable 2020 period, primarily due to the settlement of certain outstanding derivatives in August 2020 that were in an unfavorable shift in the long-term forward LIBOR curve between the periods, but decreased compared to the derivative gain during the year ended December 31, 2017 primarily due toposition and a favorable shift in the long-term forward LIBOR curve between the periods.periods
Other expense, increasednet decreased during the year ended December 31, 2019 compared to2021 from the years ended December 31, 2018 and 2017,comparable period in 2020 primarily due to a loss onlower other-than-temporary impairment losses related to our equity method investments, which wasinvestment 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 and restricted cash. Duringequivalents.
Income tax provision (benefit)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance |
Income (loss) before income taxes and non-controlling interest | | | | | | | $ | (2,278) | | | $ | 544 | | | | | $ | (2,822) | | | | | |
Income tax provision (benefit) | | | | | | | $ | (713) | | | $ | 43 | | | | | $ | (756) | | | | | |
Effective tax rate | | | | | | | 31.3 | % | | 7.9 | % | | | | 23.4 | % | | | | |
Our effective income tax rate for the year ended December 31, 2019, we recognized impairment losses2021 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 $87 million relatingthe valuation allowance on our Louisiana net operating loss carryforwards. The prior year tax expense was lower than the statutory income tax rate primarily due to our investmentsincome allocated to non-controlling interest that is not taxable to Cheniere. See further discussion in certain equity method investees, including Midship Holdings. Impairments were precipitated primarily by cost overruns and extended construction timelines for operating infrastructureNote 15 – Income Taxes of our investees’ projects, resultingNotes to Consolidated Financial Statements.
Our effective tax rate is subject to variation prospectively due to variability in a reductionour pre-tax and taxable earnings and the proportion of the expected fair value of our equitysuch earnings attributable to non-controlling interests. Other
Net income attributable to non-controlling interest
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | |
(in millions) | | | | | | | 2021 | | 2020 | | | | Variance ($) |
Net income attributable to non-controlling interest | | | | | | | $ | 778 | | | $ | 586 | | | | | $ | 192 | | | | | |
Net income attributable to non-controlling interest increased during the year ended December 31, 2018 compared to2021 from the year ended December 31, 2017,2020 primarily due to an increase in interest income earned on our cash and cash equivalents.
Income tax provision
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(in millions) | 2019 | | 2018 | | Change | | 2017 | | Change |
Income before income taxes and non-controlling interest | $ | 715 |
| | $ | 1,227 |
| | $ | (512 | ) | | $ | 566 |
| | $ | 661 |
|
Income tax benefit (provision) | 517 |
| | (27 | ) | | 544 |
| | (3 | ) | | (24 | ) |
Effective tax rate | (72.3 | )% | | 2.2 | % | | | | 0.5 | % | | |
2019 vs. 2018 and 2018 vs. 2017
The tax benefit of $517 million and effective tax rate of (72.3)% for the year ended December 31, 2019 is primarily attributable to releasing a significant portion of the valuation allowance previously recorded against our deferred tax assets.
We evaluate the recoverability of our deferred tax assets as of each reporting date, weighing all positive and negative evidence, and establish a valuation allowance if we determine that it is more likely than not that some or all of our deferred tax assets will not be realized. The assessment requires significant judgment and is performed in each of our applicable jurisdictions. In making such determination, we consider various factors such as historical profitability, future projections of sustained profitability, reversal of existing deferred tax liabilities, construction and operational milestones reached on our Liquefaction Projects and our long-term SPAs achieving date of first commercial delivery. We recorded a valuation allowance of $686 million in 2018 against our deferred tax assets due to being in a three-year cumulative loss position at the time, in addition to ongoing construction and performance risks related to our Liquefaction Projects. After weighing 2019 positive and negative evidence, we determined that sufficient positive evidence existed to support releasing the valuation allowance against significantly all of our federal deferred tax assets and a portion of our state deferred tax assets. The positive evidence supporting such conclusion included successful completion and subsequent operations of Trains 1 and 2 of the CCL Project and Train 5 of the SPL Project, our transitioning from a three-year cumulative loss position in 2018 to a three-year cumulative income position in 2019, achieving date of first commercial delivery on 12 of our long term customer SPAs and forecasts of sustained future profitability. As a result, we recorded a valuation allowance release of $490 million comprised of a $493 million federal valuation allowance release and a $49 million Louisiana valuation allowance release, partially offset by an increase to the valuation allowance of $52 million in various other state and foreign tax jurisdictions. We maintained a valuation allowance of $196 million at December 31, 2019 primarily against state net operating loss carryforward deferred tax assets, for which we continue to believe the more likely than not recognition threshold was not met.
The tax expense of $27 million and $3 million during the years ended December 31, 2018 and 2017 was primarily due to income earned in the UK related to our integrated marketing function. The effective tax rates during each of the years ended December 31, 2018 and 2017 were lower than the 21% and 35% federal statutory rates for the respective years, primarily as a result of maintaining a valuation allowance against our federal and state net deferred tax assets.
Net income attributable to non-controlling interest
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(in millions) | 2019 | | 2018 | | Change | | 2017 | | Change |
Net income attributable to non-controlling interest | $ | 584 |
| | $ | 729 |
| | $ | (145 | ) | | $ | 956 |
| | $ | (227 | ) |
2019 vs. 2018
Net income attributable to non-controlling interest decreased during the year ended December 31, 2019 from the year ended December 31, 2018 primarily due to the annualized decrease of non-controlling interest as a result of our merger with Cheniere
Holdings in September 2018, in which all publicly-held shares of Cheniere Holdings were canceled and the non-controlling interest in Cheniere Holdings was reduced to zero. The consolidated net income recognized by Cheniere Partners decreasedCQP, which increased from $1.3 billion in the year ended December 31, 2018 tonet income of $1.2 billion in the year ended December 31, 2019 primarily due a decrease in income from operations from higher operating and maintenance expense and an increase in interest expense, net of capitalized interest and increased depreciation and amortization expense, partially offset by increased margins due2020 to higher volumes of LNG sold but decreased pricing on LNG.
2018 vs. 2017
Net income attributable to non-controlling interest decreased during the year ended December 31, 2018 from the year ended December 31, 2017 due to the nonrecurrence of non-cash amortization of the beneficial conversion feature on Cheniere Partners’ Class B units that occurred during the comparable period in 2017, which was partially offset by the increase in consolidated net income recognized by Cheniere Partners in which the non-controlling interests are held, adjusting for the increase in the share of Cheniere Partners’ net income that is attributed to non-controlling interest holders as a result of changes in ownership percentages between years. Net income attributable to non-controlling interest during the year ended December 31, 2017 included approximately $748 million due to amortization of the beneficial conversion feature on Cheniere Partners’ Class B units, which ceased upon the conversion of Cheniere Partners’ Class B units into common units. The consolidated net income recognized by Cheniere Partners increased from $490 million in the year ended December 31, 2017 to $1.3$1.6 billion in the year ended December 31, 2018,2021.
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.
| | | | | | | |
| December 31, 2021 | | |
Cash and cash equivalents (1) | $ | 1,404 | | | |
Restricted cash and cash equivalents designated for the following purposes: | | | |
| | | |
SPL Project | 98 | | | |
| | | |
| | | |
CCL Project | 44 | | | |
Cash held by our subsidiaries that is restricted to Cheniere | 271 | | | |
Available commitments under our credit facilities (2): | | | |
| | | |
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 SPL Working Capital Facility”) | 805 | | | |
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”) | 750 | | | |
| | | |
| | | |
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) | 589 | | | |
Cheniere Revolving Credit Facility | 1,250 | | | |
| | | |
Total available commitments under our credit facilities | 3,394 | | | |
| | | |
Total available liquidity | $ | 5,211 | | | |
(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.
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):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Revenues Under Executed Contracts by Period (1) |
| | | | | | | | |
| | 2022 | | 2023 - 2026 | | Thereafter | | Total |
LNG revenues (fixed fees) (2) | | $ | 5.7 | | | $ | 25.0 | | | $ | 76.4 | | | $ | 107.1 | |
LNG revenues (variable fees) (2) (3) | | 8.0 | | | 30.6 | | | 103.4 | | | 142.0 | |
Regasification revenues | | 0.3 | | | 1.0 | | | 0.6 | | | 1.9 | |
Financial derivatives (4) | | (0.3) | | | — | | | — | | | (0.3) | |
| | | | | | | | |
Total | | $ | 13.7 | | | $ | 56.6 | | | $ | 180.4 | | | $ | 250.7 | |
(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
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 that were operating at1 through 6 of the SPL Project betweenand Trains 1 through 3 of the periods. Partially offsettingCCL 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 decreaseSPAs, 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 net income attributablewhich case the customers would still be required to non-controlling interest was an increase in ownership percentage by non-controlling interest holders betweenpay the periodsfixed 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 conversionintention 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 Partners’ Class B units into common units on August 2, 2017.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. Off-Balance Sheet Arrangements
As of December 31, 2019,2021, 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
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 no transactions$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 methas 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 definition of off-balance sheet arrangements that may have a current or future material effectproduction 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):
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| | Estimated Payments Due Under Executed Contracts by Period (1) |
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| | 2022 | | 2023 - 2026 | | Thereafter | | Total |
Purchase obligations (2): | | | | | | | | |
Natural gas supply agreements (3) | | $ | 8.4 | | | $ | 15.3 | | | $ | 12.5 | | | $ | 36.2 | |
Natural gas transportation and storage service agreements (4) | | 0.4 | | | 1.6 | | | 4.0 | | | 6.0 | |
Capital expenditures (5) | | 0.2 | | | — | | | — | | | 0.2 | |
Other purchase obligations (6) | | 0.4 | | | 0.6 | | | 0.6 | | | 1.6 | |
Leases (7) | | 0.8 | | | 2.0 | | | 0.9 | | | 3.7 | |
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Total | | $ | 10.2 | | | $ | 19.5 | | | $ | 18.0 | | | $ | 47.7 | |
(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.
(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.
(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,
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):
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| | Estimated Payments Due Under Executed Contracts by Period (1) |
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| | 2022 | | 2023 - 2026 | | Thereafter | | Total |
Debt (2) | | $ | 0.9 | | | $ | 11.5 | | | $ | 17.9 | | | $ | 30.3 | |
Interest payments (2) | | 1.4 | | | 4.3 | | | 2.6 | | | 8.3 | |
Total | | $ | 2.3 | | | $ | 15.8 | | | $ | 20.5 | | | $ | 38.6 | |
(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
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 Note11—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.
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 financial positioncredit 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.
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| Year Ended December 31, |
| 2021 | | 2020 | | |
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Net cash provided by operating activities | $ | 2,469 | | | $ | 1,265 | | | |
Net cash used in investing activities | (912) | | | (1,947) | | | |
Net cash used in financing activities | (1,817) | | | (235) | | | |
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Net decrease in cash, cash equivalents and restricted cash and cash equivalents | $ | (260) | | | $ | (917) | | | |
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Operating Cash Flows
Our operating results.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.
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
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):
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| | Year Ended December 31, |
| | 2021 | | 2020 | | |
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SPL: | | | | | | |
4.500% Senior Secured Notes due 2030 | | $ | — | | | $ | 1,995 | | | |
2037 SPL Private Placement Senior Secured Notes | | 482 | | | — | | | |
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CQP: | | | | | | |
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2031 CQP Senior Notes | | 1,500 | | | — | | | |
2032 CQP Senior Notes | | 1,200 | | | — | | | |
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CCH: | | | | | | |
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3.72% weighted average rate Senior Secured Notes due 2039 | | 750 | | | 769 | | | |
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CCH Working Capital Facility | | 400 | | | 281 | | | |
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Cheniere: | | | | | | |
4.625% Senior Secured Notes due 2028 | | — | | | 2,000 | | | |
Cheniere Revolving Credit Facility | | 1,359 | | | 455 | | | |
Cheniere’s term loan facility (“Cheniere Term Loan Facility”) | | 220 | | | 2,323 | | | |
Total issuances | | $ | 5,911 | | | $ | 7,823 | | | |
During the years ended December 31, 2021 and 2020, we incurred debt issuance costs and other financing costs of $53 millionand$125 million, respectively, related to the debt issuances above and closing of credit facilities during the respective periods.
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):
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SPL: | | | | | | |
2021 SPL Senior Notes | | $ | — | | | $ | (2,000) | | | |
2022 SPL Senior Notes | | (1,000) | | | — | | | |
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CQP: | | | | | | |
2025 CQP Senior Notes | | (1,500) | | | — | | | |
2026 CQP Senior Notes | | (1,100) | | | — | | | |
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CCH: | | | | | | |
CCH Credit Facility | | (898) | | | (141) | | | |
CCH Working Capital Facility | | (290) | | | (656) | | | |
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Cheniere: | | | | | | |
11% Convertible Senior Secured Notes due 2025 | | — | | | (1,000) | | | |
2021 Cheniere Convertible Notes | | (295) | | | (513) | | | |
Cheniere Revolving Credit Facility | | (1,359) | | | (455) | | | |
Cheniere Term Loan Facility | | (368) | | | (2,175) | | | |
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Total redemption and repayments | | $ | (6,810) | | | $ | (6,940) | | | |
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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 millionand $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.market as discussed below.
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, is predominantly driven by observable and unobservable market commodity prices and, as applicable to ourconsisting primarily of natural gas supply contracts our assessment offor the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair valueoperation of our physical commodity contracts incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physicalliquified natural gas flow. A portion of our physical
commodity contracts require us to make critical accounting estimates that involve significant judgment, as the fair valuefacilities, 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 contract duration.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.
GainsThe valuation of certain physical commodity derivatives requires the use of significant unobservable inputs and lossesjudgment 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.
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| Year Ended December 31, |
| 2021 | | 2020 |
Change in unrealized gain (loss) relating to instruments still held at end of period | $ | (4,305) | | | $ | 156 | |
The $4.3 billion unrealized valuation loss on derivative instruments are recognizedheld during the year ended December 31, 2021 is primarily attributed to significant appreciation in earnings. 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 interest rates,it relates to commodity prices given the level of volatility in the current year. See Item 7A. Quantitative and FX rates change.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
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project, the CCL Project and potential future development of Corpus Christi Stage 3 (“Liquefaction Supply Derivatives”). We have also entered into physical and financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (“LNG(collectively, “LNG Trading Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions):
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| December 31, 2021 | | December 31, 2020 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
Liquefaction Supply Derivatives | $ | (4,038) | | | $ | 903 | | | $ | 240 | | | $ | 204 | |
LNG Trading Derivatives | (400) | | | 38 | | | (134) | | | 44 | |
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| December 31, 2019 | | December 31, 2018 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
Liquefaction Supply Derivatives | $ | 149 |
| | $ | 179 |
| | $ | (42 | ) | | $ | 6 |
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LNG Trading Derivatives | 165 |
| | 22 |
| | (24 | ) | | 9 |
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See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.
Interest Rate Risk
We are exposed to interest rate risk primarily when we incur debt related to project financing. Interest rate risk is managed in part by replacing outstanding floating-rate debt with fixed-rate debt with varying maturities. CCH has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the CCH Credit Facility (“CCH Interest Rate Derivatives”) and to hedge against changes in interest rates that could impact anticipated future issuance of debt by CCH (“CCH Interest Rate Forward Start Derivatives”). In order to test the sensitivity of the fair value of the CCH Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward one-month LIBOR curve across the remaining terms of the CCH Interest Rate Derivatives and CCH Interest Rate Forward Start Derivatives as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
CCH Interest Rate Derivatives | $ | (40) | | | $ | — | | | $ | (140) | | | $ | 1 | |
| | | | | | | |
|
| | | | | | | | | | | | | | | |
| December 31, 2019 | | December 31, 2018 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
CCH Interest Rate Derivatives | $ | (81 | ) | | $ | 19 |
| | $ | 18 |
| | $ | 37 |
|
CCH Interest Rate Forward Start Derivatives | (8 | ) | | 15 |
| | — |
| | — |
|
See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.
Foreign Currency Exchange Risk
We have entered into foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with operations in countries outside of the United States (“FX Derivatives”). In order to test the sensitivity of the fair value of the FX Derivatives to changes in FX rates, management modeled a 10% change in FX rate between the U.S. dollar and the applicable foreign currencies as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
FX Derivatives | $ | 12 | | | $ | 2 | | | $ | (22) | | | $ | 2 | |
|
| | | | | | | | | | | | | | | |
| December 31, 2019 | | December 31, 2018 |
| Fair Value | | Change in Fair Value | | Fair Value | | Change in Fair Value |
FX Derivatives | $ | 4 |
| | $ | — |
| | $ | 15 |
| | $ | 1 |
|
| |
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S REPORT TO THE STOCKHOLDERS OF CHENIERE ENERGY, INC.
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere Energy, Inc. and its subsidiaries (“Cheniere”). In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Cheniere’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
Based on our assessment, we have concluded that Cheniere maintained effective internal control over financial reporting as of December 31, 2019,2021, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.
Cheniere’s independent registered public accounting firm, KPMG LLP, has issued an audit report on Cheniere’s internal control over financial reporting as of December 31, 2019,2021, which is contained in this Form 10-K.
Management’s Certifications
The certifications of Cheniere’s Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere’s Form 10-K.
CHENIERE ENERGY, INC.
|
| | | | | | | | | | | | | |
| | | | |
By: | /s/ Jack A. Fusco | | By: | /s/ Michael J. WortleyZach Davis |
| Jack A. Fusco | | | Michael J. WortleyZach Davis |
| President and Chief Executive Officer (Principal Executive Officer) | | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
Cheniere Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries (the Company) as of December 31, 20192021 and 2018,2020, the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2019,2021, and the related notes and financial statement scheduleschedules I to II (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019,2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 24, 202023, 2022 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgment.judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Fair value of the level 3 physical liquefaction supply derivatives
As discussed in noteNotes 2 and 7 to the consolidated financial statements, the Company recorded fair value of level 3 physical liquefaction supply derivatives of $138$(4,036) million, as of December 31, 2019.2021. The physical liquefaction supply derivatives consist of natural gas supply contracts for the operation of the liquefied natural gas facilities. The fair value of the Company’s level 3 physical liquefaction supply derivatives is developed through the use ofusing internal models using observable andthat incorporate significant unobservable market commodity prices.inputs.
We identified the evaluation of the fair value of the Company’s level 3 physical liquefaction supply derivatives as a critical audit matter. Specifically, there is subjectivity in certain assumptions used to estimate the fair value, such as the useincluding assumptions for future prices of liquidity assumptions and adjustmentsenergy units for unobservable commodity prices. Additionally, the fair value for certain of the liquefaction
supply derivatives is derived through the use of complex models, which include assumptions for unobservable commodity pricesperiods and volatility.liquidity.
The following are the primary procedures we performed to address this critical audit matter includematter. We evaluated the following. Wedesign and tested the operating effectiveness of certain internal controls overrelated to the valuation of the level 3 physical liquefaction
supply derivatives. This included controls related to the assumptions for significant unobservable inputs and the fair value models.model. For thea selection of level 3 liquefaction supply derivatives, selected, we involved valuation professionals with specialized skills and knowledge who assisted in:
•Assessingevaluating the models and volatility usedfuture prices of energy units for observable periods by the Company in its valuation by comparing to market data, including quoted or published forward prices
•developing independent fair value estimates and comparing the independently developed estimates to the Company’s fair value estimates, and
•Testing the market unobservable forward price curve adjustments and liquidity assumptions by comparing to market data, such as quoted or published forward prices for similar commodities.estimates.
In addition, we evaluated the Company’s assumptions for future prices of energy units for unobservable commodity pricesperiods and liquidity by comparing them to market or third partythird-party data, such asincluding adjustments for third party quoted transportation prices.
We have served as the Company’s auditor since 2014.
Houston, Texas
February 24, 202023, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
Cheniere Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Cheniere Energy, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 20192021 and 2018,2020, the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2019,2021, and the related notes and financial statement scheduleschedules I to II (collectively, the consolidated financial statements), and our report dated February 24, 202023, 2022 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Houston, Texas
February 24, 202023, 2022
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
CONSOLIDATED BALANCE SHEETS (1)
(in millions, except per share data)
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | | | 2021 | | 2020 | | 2019 |
Revenues | | | | | | | | | |
LNG revenues | | | | | $ | 15,395 | | | $ | 8,924 | | | $ | 9,246 | |
Regasification revenues | | | | | 269 | | | 269 | | | 266 | |
Other revenues | | | | | 200 | | | 165 | | | 218 | |
| | | | | | | | | |
Total revenues | | | | | 15,864 | | | 9,358 | | | 9,730 | |
| | | | | | | | | |
Operating costs and expenses | | | | | | | | | |
Cost of sales (excluding items shown separately below) | | | | | 13,773 | | | 4,161 | | | 5,079 | |
| | | | | | | | | |
Operating and maintenance expense | | | | | 1,444 | | | 1,320 | | | 1,154 | |
Development expense | | | | | 7 | | | 6 | | | 9 | |
Selling, general and administrative expense | | | | | 325 | | | 302 | | | 310 | |
Depreciation and amortization expense | | | | | 1,011 | | | 932 | | | 794 | |
| | | | | | | | | |
Impairment expense and loss on disposal of assets | | | | | 5 | | | 6 | | | 23 | |
| | | | | | | | | |
| | | | | | | | | |
Total operating costs and expenses | | | | | 16,565 | | | 6,727 | | | 7,369 | |
| | | | | | | | | |
Income (loss) from operations | | | | | (701) | | | 2,631 | | | 2,361 | |
| | | | | | | | | |
Other expense | | | | | | | | | |
Interest expense, net of capitalized interest | | | | | (1,438) | | | (1,525) | | | (1,432) | |
Loss on modification or extinguishment of debt | | | | | (116) | | | (217) | | | (55) | |
Interest rate derivative loss, net | | | | | (1) | | | (233) | | | (134) | |
Other expense, net | | | | | (22) | | | (112) | | | (25) | |
Total other expense | | | | | (1,577) | | | (2,087) | | | (1,646) | |
| | | | | | | | | |
Income (loss) before income taxes and non-controlling interest | | | | | (2,278) | | | 544 | | | 715 | |
Less: income tax provision (benefit) | | | | | (713) | | | 43 | | | (517) | |
Net income (loss) | | | | | (1,565) | | | 501 | | | 1,232 | |
Less: net income attributable to non-controlling interest | | | | | 778 | | | 586 | | | 584 | |
Net income (loss) attributable to common stockholders | | | | | $ | (2,343) | | | $ | (85) | | | $ | 648 | |
| | | | | | | | | |
Net income (loss) per share attributable to common stockholders—basic | | | | | $ | (9.25) | | | $ | (0.34) | | | $ | 2.53 | |
Net income (loss) per share attributable to common stockholders—diluted | | | | | $ | (9.25) | | | $ | (0.34) | | | $ | 2.51 | |
| | | | | | | | | |
Weighted average number of common shares outstanding—basic | | | | | 253.4 | | | 252.4 | | | 256.2 | |
Weighted average number of common shares outstanding—diluted | | | | | 253.4 | | | 252.4 | | | 258.1 | |
|
| | | | | | | |
| December 31, |
| 2019 | | 2018 |
ASSETS |
| | |
Current assets | | | |
Cash and cash equivalents | $ | 2,474 |
| | $ | 981 |
|
Restricted cash | 520 |
| | 2,175 |
|
Accounts and other receivables | 491 |
| | 585 |
|
Inventory | 312 |
| | 316 |
|
Derivative assets | 323 |
| | 63 |
|
Other current assets | 92 |
| | 114 |
|
Total current assets | 4,212 |
| | 4,234 |
|
| | | |
Property, plant and equipment, net | 29,673 |
| | 27,245 |
|
Operating lease assets, net | 439 |
| | — |
|
Non-current derivative assets | 174 |
| | 54 |
|
Goodwill | 77 |
| | 77 |
|
Deferred tax assets | 529 |
| | 8 |
|
Other non-current assets, net | 388 |
| | 369 |
|
Total assets | $ | 35,492 |
| | $ | 31,987 |
|
| | | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | |
| | |
|
Current liabilities | |
| | |
|
Accounts payable | $ | 66 |
| | $ | 58 |
|
Accrued liabilities | 1,281 |
| | 1,169 |
|
Current debt | — |
| | 239 |
|
Deferred revenue | 161 |
| | 139 |
|
Current operating lease liabilities | 236 |
| | — |
|
Derivative liabilities | 117 |
| | 128 |
|
Other current liabilities | 13 |
| | 9 |
|
Total current liabilities | 1,874 |
| | 1,742 |
|
| | | |
Long-term debt, net | 30,774 |
| | 28,179 |
|
Non-current operating lease liabilities | 189 |
| | — |
|
Non-current finance lease liabilities | 58 |
| | 57 |
|
Non-current derivative liabilities | 151 |
| | 22 |
|
Other non-current liabilities | 11 |
| | 58 |
|
| | | |
Commitments and contingencies (see Note 19) |
|
| |
|
|
| | | |
Stockholders’ equity | |
| | |
|
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued | — |
| | — |
|
Common stock, $0.003 par value, 480.0 million shares authorized | | | |
|
Issued: 270.7 million shares and 269.8 million shares at December 31, 2019 and 2018, respectively |
|
| |
|
|
Outstanding: 253.6 million shares and 257.0 million shares at December 31, 2019 and 2018, respectively | 1 |
| | 1 |
|
Treasury stock: 17.1 million shares and 12.8 million shares at December 31, 2019 and 2018, respectively, at cost | (674 | ) | | (406 | ) |
Additional paid-in-capital | 4,167 |
| | 4,035 |
|
Accumulated deficit | (3,508 | ) | | (4,156 | ) |
Total stockholders’ deficit | (14 | ) | | (526 | ) |
Non-controlling interest | 2,449 |
| | 2,455 |
|
Total equity | 2,435 |
| | 1,929 |
|
Total liabilities and stockholders’ equity | $ | 35,492 |
| | $ | 31,987 |
|
| |
(1) | Amounts presented include balances held by our consolidated variable interest entity (“VIE”), Cheniere Partners, as further discussed in Note 9— Non-controlling Interest and Variable Interest Entity. As of December 31, 2019, total assets and liabilities of Cheniere Partners, which are included in our Consolidated Balance Sheets, were $19.1 billion and $18.6 billion, respectively, including $1.8 billion of cash and cash equivalents and $0.2 billion of restricted cash. |
The accompanying notes are an integral part of these consolidated financial statements.
7257
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (1)
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2019 | | 2018 | | 2017 |
Revenues | | | | | |
LNG revenues | $ | 9,246 |
| | $ | 7,572 |
| | $ | 5,317 |
|
Regasification revenues | 266 |
| | 261 |
| | 260 |
|
Other revenues | 218 |
| | 154 |
| | 24 |
|
Total revenues | 9,730 |
| | 7,987 |
| | 5,601 |
|
| | | | | |
Operating costs and expenses | | | | | |
Cost of sales (excluding depreciation and amortization expense shown separately below) | 5,079 |
| | 4,597 |
| | 3,120 |
|
Operating and maintenance expense | 1,154 |
| | 613 |
| | 446 |
|
Development expense | 9 |
| | 7 |
| | 10 |
|
Selling, general and administrative expense | 310 |
| | 289 |
| | 256 |
|
Depreciation and amortization expense | 794 |
| | 449 |
| | 356 |
|
Restructuring expense | — |
| | — |
| | 6 |
|
Impairment expense and loss on disposal of assets | 23 |
| | 8 |
| | 19 |
|
Total operating costs and expenses | 7,369 |
| | 5,963 |
| | 4,213 |
|
| | | | | |
Income from operations | 2,361 |
| | 2,024 |
| | 1,388 |
|
| | | | | |
Other income (expense) | | | | | |
Interest expense, net of capitalized interest | (1,432 | ) | | (875 | ) | | (747 | ) |
Loss on modification or extinguishment of debt | (55 | ) | | (27 | ) | | (100 | ) |
Derivative gain (loss), net | (134 | ) | | 57 |
| | 7 |
|
Other income (expense) | (25 | ) | | 48 |
| | 18 |
|
Total other expense | (1,646 | ) | | (797 | ) | | (822 | ) |
| | | | | |
Income before income taxes and non-controlling interest | 715 |
|
| 1,227 |
| | 566 |
|
Income tax benefit (provision) | 517 |
|
| (27 | ) | | (3 | ) |
Net income | 1,232 |
|
| 1,200 |
| | 563 |
|
Less: net income attributable to non-controlling interest | 584 |
|
| 729 |
| | 956 |
|
Net income (loss) attributable to common stockholders | $ | 648 |
|
| $ | 471 |
| | $ | (393 | ) |
|
|
|
|
|
| | |
Net income (loss) per share attributable to common stockholders—basic (1) | $ | 2.53 |
|
| $ | 1.92 |
| | $ | (1.68 | ) |
Net income (loss) per share attributable to common stockholders—diluted (1) | $ | 2.51 |
| | $ | 1.90 |
| | $ | (1.68 | ) |
|
|
|
|
|
| | |
Weighted average number of common shares outstanding—basic | 256.2 |
| | 245.6 |
| | 233.1 |
|
Weighted average number of common shares outstanding—diluted | 258.1 |
| | 248.0 |
| | 233.1 |
|
| | | | | | | | | | | |
| December 31, |
| | | |
| 2021 | | 2020 |
ASSETS | | | |
Current assets | | | |
Cash and cash equivalents | $ | 1,404 | | | $ | 1,628 | |
Restricted cash and cash equivalents | 413 | | | 449 | |
Accounts and other receivables, net of current expected credit losses | 1,506 | | | 647 | |
| | | |
Inventory | 706 | | | 292 | |
Current derivative assets | 55 | | | 32 | |
Margin deposits | 765 | | | 25 | |
Other current assets | 207 | | | 96 | |
Total current assets | 5,056 | | | 3,169 | |
| | | |
| | | |
Property, plant and equipment, net of accumulated depreciation | 30,288 | | | 30,421 | |
Operating lease assets | 2,102 | | | 759 | |
| | | |
Derivative assets | 69 | | | 376 | |
Goodwill | 77 | | | 77 | |
Deferred tax assets | 1,204 | | | 489 | |
Other non-current assets, net | 462 | | | 406 | |
Total assets | $ | 39,258 | | | $ | 35,697 | |
| | | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
Current liabilities | | | |
Accounts payable | $ | 155 | | | $ | 35 | |
Accrued liabilities | 2,299 | | | 1,175 | |
| | | |
Current debt, net of discount and debt issuance costs | 366 | | | 372 | |
Deferred revenue | 155 | | | 138 | |
Current operating lease liabilities | 535 | | | 161 | |
Current derivative liabilities | 1,089 | | | 313 | |
Other current liabilities | 94 | | | 2 | |
Total current liabilities | 4,693 | | | 2,196 | |
| | | |
Long-term debt, net of premium, discount and debt issuance costs | 29,449 | | | 30,471 | |
Operating lease liabilities | 1,541 | | | 597 | |
Finance lease liabilities | 57 | | | 57 | |
| | | |
Derivative liabilities | 3,501 | | | 151 | |
Other non-current liabilities | 50 | | | 7 | |
| | | |
Commitments and contingencies (see Note 20) | 0 | | 0 |
| | | |
Stockholders’ equity | | | |
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued | — | | | — | |
Common stock, $0.003 par value, 480.0 million shares authorized; 275.2 million shares and 273.1 million shares issued at December 31, 2021 and 2020, respectively | 1 | | | 1 | |
| | | |
| | | |
| | | |
Treasury stock: 21.6 million shares and 20.8 million shares at December 31, 2021 and 2020, respectively, at cost | (928) | | | (872) | |
Additional paid-in-capital | 4,377 | | | 4,273 | |
Accumulated deficit | (6,021) | | | (3,593) | |
Total stockholders' deficit | (2,571) | | | (191) | |
Non-controlling interest | 2,538 | | | 2,409 | |
Total equity (deficit) | (33) | | | 2,218 | |
Total liabilities and stockholders’ equity (deficit) | $ | 39,258 | | | $ | 35,697 | |
| |
(1) | Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented. |
(1)Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 9—Non-controlling Interest and Variable Interest Entity. As of December 31, 2021, total assets and liabilities of CQP, which are included in our Consolidated Balance Sheets, were $19.0 billion and $18.6 billion, respectively, including $0.9 billion of cash and cash equivalents and $0.1 billion of restricted cash and cash equivalents.
The accompanying notes are an integral part of these consolidated financial statements.
7358