What changed in this filing

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Item 1. Business

2021-03-25 compared with 2020-03-03 · 86 added, 75 removed, 57 unchanged (74% of the section changed)

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We were incorporated in Delaware on May 21, 2014 and were formed for the purpose of acquiring, through a merger, share exchange, asset acquisition, stock purchase, recapitalization, reorganization or other similar business combination, one or more businesses or entities.

On July 24, 2017, one of our subsidiaries merged with and into NextDecade LLC, a LNG development company founded in 2010 to develop LNG export projects and associated pipelines.

Prior to the merger with NextDecade LLC, we had no operations and our assets consisted of cash proceeds received in connection with our initial public offering.

Our common stock trades on the Nasdaq Capital Market (“Nasdaq”) under the symbol “NEXT.”

Our warrants issued in connection with our initial public offering in 2015 (the “IPO Warrants”) trade on the OTC Pink Market under the symbol “NEXTW.”

Our common stock trades on the Nasdaq Capital Market (“Nasdaq”) under the symbol “NEXT.”

Our warrants issued in connection with our initial public offering in 2015 (the “IPO Warrants”) trade on the OTC Pink Market under the symbol “NEXTW.”

Company Overview

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We believe the Terminal possesses competitive advantages in several important areas, including engineering, design, commercial, regulatory and gas supply.

We submitted a pre-filing request for the Terminal and the Pipeline (as described below) to the Federal Energy Regulatory Commission (the “FERC”) in March 2015 and filed a formal application with the FERC in May 2016.

We also believe we have robust commercial offtake and gas supply strategies and we estimate that the Terminal will commence commercial operations as early as 2023.

On March 2, 2020, we completed the sale of Rio Bravo to Spectra Energy Transmission II, LLC, a wholly owned subsidiary of Enbridge, Inc.

Rio Bravo is developing a proposed 137-mile interstate natural gas pipeline (the “Pipeline”) to supply natural gas to the Terminal.

In connection with the sale of Rio Bravo, our indirect, wholly owned subsidiary, Rio Grande LNG Gas Supply LLC (“Rio Grande Gas Supply”), entered into precedent agreements (the “Transportation Precedent Agreements”) with Rio Bravo and Valley Crossing Pipeline, LLC (“VCP”), pursuant to which Rio Grande Gas Supply will retain its rights to the natural gas firm transportation capacity on the Pipeline for a term of at least twenty years and Rio Bravo and VCP, will provide firm pipeline transportation service to Rio Grande Gas Supply in order to supply natural gas to the Terminal.

As of March 2, 2020, VCP and Rio Bravo are wholly owned subsidiaries of Enbridge, Inc.

We believe that the Terminal, to be located on a 984-acre site in Brownsville, Texas, along with the Pipeline to connect the Terminal to the Agua Dulce supply area, is well-positioned among the second wave of United States (“U.S.”) LNG projects.

We submitted a pre-filing request for the Terminal to the Federal Energy Regulatory Commission (the “FERC”) in March 2015 and filed a formal application with the FERC in May 2016.

We also believe we have robust commercial offtake and gas supply strategies.

On March 2, 2020, we completed the sale of Rio Bravo Pipeline Company, LLC (“Rio Bravo”) to Spectra Energy Transmission II, LLC, a wholly owned subsidiary of Enbridge, Inc ("Enbridge").

Rio Bravo is developing a proposed interstate natural gas pipeline (the “Pipeline”) to supply natural gas to the Terminal. 

In connection with the sale of Rio Bravo, our indirect, wholly owned subsidiary, Rio Grande LNG Gas Supply LLC (“Rio Grande Gas Supply”), entered into precedent agreements (the “Transportation Precedent Agreements”) with Rio Bravo and Valley Crossing Pipeline, LLC (“VCP”), pursuant to which Rio Grande Gas Supply will retain its rights to the natural gas firm transportation capacity on the Pipeline for a term of at least twenty years and Rio Bravo and VCP, will provide pipeline transportation service to Rio Grande Gas Supply in order to supply natural gas to the Terminal.

As of March 2, 2020, VCP and Rio Bravo were wholly owned subsidiaries of Enbridge.

It is located to take advantage of natural gas resources in Texas, including the Permian Basin and Eagle Ford Shale.

We plan to construct, develop, own and operate the Terminal.

On November 22, 2019, the Terminal and the Pipeline received an order from the FERC (“the Order”) authorizing the siting, construction, and operation of six liquefaction trains, four LNG storage tanks (each with a capacity of 180,000 cubic meters), two marine jetties for ocean-going LNG vessels, one turning basin, and six truck loading bays for LNG and natural gas liquids and all associated facilities for the production of up to 27 million tonnes per annum ("mtpa").

Simultaneously, FERC issued a certificate of public convenience and necessity authorizing the construction of the Pipeline, which will be developed by a third-party following our sale of Rio Bravo and is expected to be comprised of twin, 137-mile-long, 42-inch-outside diameter, natural gas pipelines, three 180,000-horsepower compressor stations, two 30,000- horsepower interconnect booster stations, six mainline valve sites, four metering sites, and various ancillary facilities.

The twin pipelines are expected to be rated to a maximum allowable operating pressure of 1,480 pounds per square inch and total deliverability of at least 4.5 billion cubic feet per day (“Bcf/d”).

On January 23, 2020, the FERC issued its final order on rehearing rejecting all challenges to the Order.

While the Order authorizes six liquefaction trains, we may make a positive FID on as few as two liquefaction trains.

We have also leased a 994-acre site on the Houston Ship Channel in Texas City, Texas for our second U.S.

LNG project, which is expected to be permitted for up to three trains (each with a nominal capacity of 5.5 mtpa), a minimum of two LNG storage tanks (each with a capacity of 200,000 cubic meters), two marine jetties for ocean-going LNG vessels and one turning basin (the “Galveston Bay Terminal”).

We intend to use similar design and engineering for the Galveston Bay Terminal as for the Terminal.

We plan to construct, develop, own and operate the Terminal. 

Simultaneously, the FERC issued a certificate of public convenience and necessity authorizing the construction of the Pipeline.

On January 23, 2020, the FERC issued its final order on rehearing rejecting all challenges to the Order. While the Order authorizes six liquefaction trains, we may make a positive FID on as few as two liquefaction trains.

The original front-end engineering and design for the Terminal was based on six LNG trains capable of producing 27 mtpa of LNG for export.

The technologies that were selected and filed with the FERC in 2015 and 2016 have evolved over the five-year permitting period;

the individual LNG trains are now more efficient and will produce a greater volume of LNG with lower total carbon dioxide equivalent (“CO 2 e”) emissions.

Multiple optimizations have been identified that will lead to the delivery of a LNG project capable of producing 27 mtpa with just five LNG trains instead of six.

We expect the optimization to a five-train project to result in several environmental and community benefits when compared with our original six-train project including (i) approximately 21 percent lower CO 2 e emissions, (ii) a shortened construction timeline for the full 27 mtpa project, (iii) reduced facility footprint, and (iv) an expected reduction in roadway traffic.

On August 13, 2020, the FERC approved the change of the design for the Terminal from six trains to five trains.

On October 9, 2020, the FERC issued a notice of denial of rehearing for such approval in regards to challenges to its approval of the design change.

Any future development of Train 6 will require us to secure authorization from the FERC, the U.S.

Department of Energy (the “DOE”), and any other relevant federal or state agency with jurisdiction over the export project.

In January 2021, we determined that the site in Texas City, Texas for our proposed second LNG facility (“Galveston Bay LNG”) is not suitable for a LNG facility and related infrastructure and utilities and, therefore, elected to forfeit such site.

We have informed the FERC of our intent to withdraw Galveston Bay LNG from FERC pre-filing proceedings and cease all related activities.

In March 2021, the DOE terminated its June 2018 authorization for export of LNG from Galveston Bay LNG.

Engineering, Procurement, and Construction

During the third quarter of 2018, we initiated a competitive engineering, procurement and construction (“EPC”) bid process.

We received expressions of interest (the “EOIs”) from multiple EPC contractors to participate in the EPC process.

During the third quarter of 2018, we initiated a competitive engineering, procurement and construction (“EPC”) bid process.

We received expressions of interest (the “EOIs”) from multiple EPC contractors to participate in the EPC process.

We reviewed the EOIs against a series of selection criteria and issued formal invitations to bid to Bechtel Oil, Gas and Chemicals, Inc.

("Bechtel"), Fluor Enterprises, Inc.

("Fluor") and McDermott International, Inc.

In December 2018, each of the EPC bidders provided us with an endorsement of the Terminal’s front-end engineering and design (“FEED”), which indicates the bidders’ confirmation that the Terminal is technically feasible and can be further designed, engineered, permitted, constructed, commissioned and safely placed into operations.

On April 22, 2019, we received EPC bid packages from each of Bechtel and Fluor, two of the global LNG market’s leading EPC contractors.

The technical and commercial bid packages, which were received on-schedule, were for fully wrapped lump-sum separated turnkey (“LSTK”) EPC contracts for the Terminal.

On May 24, 2019, Rio Grande entered into two LSTK EPC agreements with Bechtel for the construction of (i) two LNG trains with expected aggregate production capacity up to approximately 11.74 mtpa, two 180,000m 3 full containment LNG tanks, one marine loading berth, related utilities and facilities, and all related appurtenances thereto, together with certain additional work options (the “Trains 1 and 2 EPC Agreement”) and (ii) an LNG train with expected production capacity of up to approximately 5.87 mtpa, related utilities and facilities, and all related appurtenances thereto (the “Train 3 EPC Agreement” and together with the Trains 1 and 2 EPC Agreement, the “EPC Agreements”).

During 2019, we issued two limited notice to proceed (“LNTP”) to Bechtel under the Trains 1 and 2 EPC Agreement.

(“Bechtel”), Fluor Enterprises, Inc.

(“Fluor”) and McDermott International, Inc (“McDermott”). In December 2018, each of the EPC bidders provided us with an endorsement of the Terminal’s front-end engineering and design (“FEED”), which indicates the bidders’

confirmation that the Terminal is technically feasible and can be further designed, engineered, permitted, constructed, commissioned and safely placed into operations.

On April 22, 2019, we received EPC bid packages from each of Bechtel and Fluor, two of the global LNG market’s leading EPC contractors.  The technical and commercial bid packages, which were received on-schedule, were for fully wrapped lump-sum separated turnkey (“LSTK”) EPC contracts for the Terminal.

On May 24, 2019, Rio Grande entered into two LSTK EPC agreements with Bechtel for the construction of (i) two LNG trains with expected aggregate production capacity up to approximately 11.74 mtpa, two 180,000m 3  full containment LNG tanks, one marine loading berth, related utilities and facilities, and all related appurtenances thereto, together with certain additional work options (the “Trains 1 and 2 EPC Agreement”) and (ii) an LNG train with expected production capacity of up to approximately 5.87 mtpa, related utilities and facilities, and all related appurtenances  thereto (the “Train 3 EPC Agreement”

and together with the Trains 1 and 2 EPC Agreement, the “EPC Agreements”). 

During each of 2020 and 2019, we issued two limited notices to proceed to Bechtel under the Trains 1 and 2 EPC Agreement.

In 2020, we developed proprietary carbon capture processes that, with the addition of storage technology, could reduce CO 2 e emissions at the Terminal by approximately 90 percent. 

While we are advancing our work in this area, we are also exploring options to address the remaining CO 2 e emissions to enable the Terminal to achieve carbon-neutrality.

We are continuing commercial discussions with a variety of parties ranging from large utilities and state-sponsored enterprises to portfolio and multinational commodity interests.

Leveraging the global relationships and extensive experience of our management team, we expect to sign long-term binding offtake commitments for substantially all of the Terminal’s capacity prior to a FID.

We believe the Terminal’s location will provide customers with access to low-cost natural gas from the Permian Basin and Eagle Ford Shale.

We are focused on selling LNG to customers through a “free on board” model whereby a marketing affiliate would acquire feed gas, the Terminal would produce the LNG and the title transfer would occur at the interface between the Terminal and the customer’s ship.

We offer multiple LNG pricing options, meeting the evolving needs of our customers and maximizing our total addressable market.

We believe the Terminal’s location will provide customers with access to low-cost natural gas from the Permian Basin and Eagle Ford Shale.

We are focused on selling LNG to customers through a “free on board”

(“FOB”) model whereby a marketing affiliate would acquire feed gas, the Terminal would produce the LNG and the title transfer would occur at the interface between the Terminal and the customer’s ship.

We offer multiple LNG pricing options, meeting the evolving needs of our customers and maximizing our total addressable market.

Global LNG customers are expressing interest in contracting their LNG offtake to indexes other than Henry Hub.

We are working with U.S.

producers to provide alternative indexation, including netback pricing, to satisfy global LNG customers’ needs.

LNG pricing options may include indexation to Brent Crude Oil, Agua Dulce hub, Waha hub, Japan Korea Marker ("JKM") and Title Transfer Facility ("TTF"), among others.

In March 2019, we entered into a 20-year sale and purchase agreement (the "SPA") with Shell NA LNG LLC (“Shell”) for the supply of two million tonnes per annum of liquefied natural gas from the Terminal.

Pursuant to the SPA, Shell will purchase LNG on a free-on-board basis starting from the commercial operation date of the Terminal, currently expected in 2023, with approximately three-quarters of the purchased LNG volume indexed to Brent and the remaining volume indexed to domestic United States gas indices, including Henry Hub.

The Shell SPA becomes effective upon the satisfaction of certain conditions precedent, which include a positive FID in the Terminal.

producers to provide alternative indexation, including netback pricing, to satisfy global LNG customers’

LNG pricing options may include indexation to Brent Crude Oil, Agua Dulce hub, Waha hub, Japan Korea Marker and Title Transfer Facility, among others.

In March 2019, we entered into a 20-year sale and purchase agreement (the “SPA”) with Shell NA LNG LLC (“Shell”) for the supply of two mtpa of liquefied natural gas from the Terminal. 

Pursuant to the SPA, Shell will purchase LNG on a FOB basis starting from the date the first liquefaction train of the Terminal that is commercially operable, with approximately three-quarters of the purchased LNG volume indexed to Brent and the remaining volume indexed to domestic United States gas indices, including Henry Hub.

In the first quarter of 2020, the SPA became effective upon the conditions precedent in the SPA being satisfied or waived. 

The SPA obligates Rio Grande to deliver the contracted volumes of LNG to Shell at the FOB delivery point, subject to the first liquefaction train at the Terminal being commercially operable.

Governmental Permits, Approvals and Authorizations

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The design, construction and operation of LNG export terminals is a regulated activity and is subject to Section 3 of the Natural Gas Act (the "NGA").

Federal law has bifurcated regulatory jurisdiction of LNG export activities.

Federal law has bifurcated regulatory jurisdiction of LNG export activities.

The FERC has jurisdiction over the siting, construction and permitting of LNG export facilities.

Department of Energy (the “DOE”) has jurisdiction over the import and export of the natural gas commodity, including natural gas in the form of LNG.

The FERC also has jurisdiction over the siting, construction and operation of interstate natural gas pipelines under Section 7 of the NGA and regulates interstate pipelines’ terms and conditions of service under Sections 4 and 5 of the NGA.

In 2002, the FERC established a policy of not regulating the terms and conditions of service for LNG import or export facilities or requiring that LNG import or export facilities operate as “open access” facilities for all customers.

The DOE has jurisdiction over the import and export of the natural gas commodity, including natural gas in the form of LNG.

The FERC also has jurisdiction over the siting, construction and operation of interstate natural gas pipelines under Section 7 of the NGA and regulates interstate pipelines’

terms and conditions of service under Sections 4 and 5 of the NGA.

facilities for all customers.

The Energy Policy Act of 2005, which amended the NGA, codified this policy until January 1, 2015, and the FERC has not indicated that it intends to depart from its policy of not regulating the terms or conditions of service or requiring that LNG terminals operate on an open access basis.

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These agencies include the U.S.

Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (the “PHMSA”), the U.S.

Coast Guard (the “Coast Guard”), the U.S.

Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (the “PHMSA”), the U.S.

Coast Guard (the “Coast Guard”), the U.S.

Army Corps of Engineers, the U.S.

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Similarly, the Coast Guard has established safety regulations for marine operations at LNG facilities and the operation of LNG carriers.

The FERC, the PHMSA and the Coast Guard entered into a Memorandum of Understanding in 2004 that establishes the FERC’s primary role in evaluating LNG terminal applications and defines the process for coordinating the review of an LNG import or export terminal application with the PHMSA and the Coast Guard.

In 2018, the FERC and the PHMSA entered into a separate Memorandum of Understanding that establishes the process and timeline by which the PHMSA should determine whether an LNG terminal project will meet the PHMSA’s LNG safety siting standards.

We filed our formal application for the Terminal with the FERC on May 5, 2016, received a Final Environmental Impact Statement from the FERC on April 26, 2019 and received the Order on November 22, 2019 authorizing the siting, construction and operation of the Terminal.

We filed our formal application for the Terminal with the FERC on May 5, 2016, received a Final Environmental Impact Statement from the FERC on April 26, 2019 and received the Order on November 22, 2019 authorizing the siting, construction and operation of the Terminal (the “Order”).

Other major regulatory permits obtained in 2019 include the Biological Opinion and Incidental Take Statement from the U.S.

Fish and Wildlife Service.

Following receipt of the Order on November 22, 2019, two requests for re-hearing were filed challenging the Order.

Fish and Wildlife Service. 

Following receipt of the Order, two requests for re-hearing were filed.

One of those requests for rehearing also requested that the FERC stay the Order.

On January 23, 2020, the FERC issued its Order on Rehearing and Stay in which the FERC rejected all challenges presented in the requests for rehearing and the request for stay.

Separately, we submitted a pre-filing request to the FERC for the Galveston Bay Terminal on August 31, 2018, and the FERC initiated its pre-filing process for that application on October 10, 2018.

Section 3 of the NGA requires prior authorization by the DOE for the import or export of natural gas, including LNG, from the U.S.

The DOE’s practice has been to include certain reporting requirements in its LNG export authorizations, including mandating the reporting of the foreign destination of U.S.-sourced LNG.

In December 2018, the DOE clarified its reporting requirements, directing LNG export authorization holders and their downstream counterparties to report the destination to which the U.S.-sourced LNG was “actually delivered,” in contrast to the agency’s prior policy requiring the reporting of where the LNG was “delivered for end use.” This revised policy recognizes the increasing flexibility and liquidity in the global LNG market.

On January 23, 2020, the FERC issued its Order on Rehearing and Stay in which the FERC rejected all challenges presented in the requests for rehearing and the request for stay of the Order. 

The parties who filed the requests for re-hearing have petitioned the U.S.

Court of Appeals for the District of Columbia to review the Order and the order denying rehearing, and that appeal is still pending. 

 A second appeal has also been filed with the same court by the same parties, seeking a review of the FERC letter order amending the Order to account for the design change from six to five trains and this appeal is also pending.

Similar appeals are also pending in the U.S Court of Appeals for the Fifth Circuit in respect of other permits issued by the U.S.

Army Corps of Engineers and the U.S.

Fish and Wildlife Service.

On September 7, 2016, Rio Grande obtained an authorization for export of LNG to countries with which the U.S.

has a Free Trade Agreement (“FTA”) on our own behalf and as an agent for others for a term of 30 years.

On June 13, 2018, Galveston Bay obtained a similar authorization for export of LNG to FTA countries on our own behalf and as an agent for others for a term of 20 years.

The DOE’s December 2018 order adjusting the reporting requirements applies to both of the authorizations for LNG to FTA countries.

However, many of our target markets are not FTA countries.

We have applied to the DOE for approval to export LNG to non-FTA countries for both projects.

As a result of the legal standard under the NGA and consistent with federal appeals court precedent, the DOE has adopted an approach whereby it issues a non-FTA authorization after the FERC issues its order authorizing the project facilities.

On February 10, 2020, the DOE issued its “Opinion and Order Granting Long-Term Authorization to Export Liquefied Natural Gas to Non-Free Trade Agreement Nations to Rio Grande" in DOE/FE Order No.

There are no legal intervenors in the docket and therefore we expect that this order is final.

has a Free Trade Agreement (“FTA”) on our own behalf and as an agent for others for a term of 30 years. On February 10, 2020, the DOE issued its “Opinion and Order Granting Long-Term Authorization to Export Liquefied Natural Gas to Non-Free Trade Agreement Nations to Rio Grande" in DOE/FE Order No.

In addition, on October 21, 2020, the DOE issued its Order Extending Export Term for Authorization to Non-Free Trade Agreement Nations through December 31, 2050.

The proposed Terminal site will be located in Brownsville, Texas, benefiting from close access to the Permian Basin and Eagle Ford Shale.

We expect to realize material benefits from providing our customers with access to these low-cost associated gas resources.

Major oil companies and independent shale producers have created extraordinary efficiencies and improvements, including enhanced well recoveries through extended lateral lengths and hydraulic fracturing technology, rig productivity, and operating and lifecycle costs.

We expect to realize material benefits from providing our customers with access to these low-cost associated gas resources. Major oil companies and independent shale producers have created extraordinary efficiencies and improvements, including enhanced well recoveries through extended lateral lengths and hydraulic fracturing technology, rig productivity, and reductions in operating and lifecycle costs.

However, U.S.

demand has not risen proportionally with the growth in recoverable reserves.

Through the Pipeline, projected to have interconnects with a combined receipt capacity of more than 10 Bcf/d, we believe that we will have supply flexibility established by the Transportation Precedent Agreements.

The combination of increased production and expanding takeaway capacity indicates that the Agua Dulce supply area, from which the Pipeline is proposed to be routed, is expected to become increasingly liquid and remain competitively priced to Henry Hub.

Through the Pipeline, projected to have interconnects with a combined receipt capacity of more than 10 billion cubic feet per day (“Bcf/d”), we believe that we will have supply flexibility established by the Transportation Precedent Agreements.

The combination of increased production and expanding takeaway capacity indicates that the Agua Dulce supply area, from which the Pipeline is proposed to be routed, is expected to become increasingly liquid and remain competitively priced to Henry Hub.

We believe our proximity to two major gas reserves basins, increasing takeaway capacity in the area, a significant influx of production and infrastructure investment, as well as our existing contacts and discussions with some of the largest regional operators, represent key elements of a compelling feed gas strategy for partners and customers alike.

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The Permian Basin offers one of the deepest inventories of economic natural gas resource in the world.

According to RS Energy Group, there are approximately 700 trillion cubic feet ("Tcf") of remaining natural gas resource in the Permian Basin and Eagle Ford Shale.

According to Enverus, there are approximately 700 trillion cubic feet ("Tcf") of remaining natural gas resource in the Permian Basin and Eagle Ford Shale.

Permian Basin economics are largely driven by the production of oil, not gas;

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According to data from the Energy Information Administration ("EIA"), natural gas production in the Permian Basin, alone, has grown by more than 40 percent annually in recent years.

By the end 2019, the Permian Basin was producing more than 11 billion cubic feet per day ("Bcf/d") of natural gas.

We estimate dry gas production in Texas could still reach nearly 40 Bcf/d by 2030.

There is not enough domestic demand within Texas to support our projections for Texas natural gas production.

By the end of 2019, the Permian Basin was producing more than 11 Bcf/d of natural gas and additional discoveries continue to be made in Texas, including a new dry gas stacked play in the Eagle Ford Shale with announced recoverable resource of approximately 21 Tcf and a breakeven price below $1.25 per MMBtu.

We estimate dry gas production in Texas to reach nearly 40 Bcf/d by 2030.

We do not believe there is sufficient domestic demand within Texas to support our projections for Texas natural gas production.

We believe new LNG projects will need to absorb large volumes of natural gas.

To support Permian Basin gas production, Texas may need more than 14 Bcf/d of LNG export capacity by 2030;

To support Permian Basin and Eagle Ford gas production, Texas may need more than 9.3 Bcf/d of incremental LNG export capacity by 2030;

in a higher oil price environment, even more LNG export capacity may be needed.

To date, only 6 Bcf/d of LNG export capacity on the Texas Gulf Coast has achieved a final investment decision.

We estimate that 8.2 Bcf/d of incremental LNG FIDs – equivalent to more than 60 mtpa – may be needed in the next 12 to 36 months to support Permian Basin gas production forecasts.

We estimate that at least 6.1 Bcf/d of incremental LNG FIDs, equivalent to more than 47 mtpa, may be needed in the next 12 to 36 months to support expected Permian Basin and Eagle Ford Shale natural gas production growth.

We are subject to a high degree of competition in all aspects of our business.

See “Item 1.A — Risk Factors — Competition in the energy industry is intense , and some of our competitors have greater financial, technological and other resources.

See “Item 1.A —

Risk Factors —

Competition in the energy industry is intense , and some of our competitors have greater financial, technological and other resources.

The Terminal will compete with liquefaction facilities worldwide to supply low-cost liquefaction to the market.

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We intend to use our website as a means of disclosing material non-public information and for complying with disclosure obligations under Regulation FD.

Such disclosures will be included on our website under the heading “Investors.” Accordingly, investors should monitor such portion of our website, in addition to following our press releases and SEC filings.

Within our website under the heading “Investors,” we make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws.

Such disclosures will be included on our website under the heading “Investors.”

Accordingly, investors should monitor such portion of our website, in addition to following our press releases and SEC filings.

Within our website under the heading “Investors,”

we make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws.

These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business