Tellurian Inc. (“Tellurian,” “we,” “us,” “our,” or the “Company”) intends to create value for shareholders by building a low-cost, global natural gas business, profitably delivering natural gas to customers worldwide (the “Business”). We are developing a portfolio of natural gas production, LNG marketing, and infrastructure assets that includes an LNG terminal facility (the “Driftwood terminal”), and three related pipelines (the “Pipeline Network”). We refer to the Driftwood terminal, the Pipeline Network and our existing and plannedcertain natural gas production assets collectively as the “Driftwood Project”. We currently estimate the total cost of the Driftwood Project to be approximately $28$28.9 billion, including owners’ costs, transaction costs and contingencies but excluding interest costs incurred during construction of the Driftwood terminal and other financing costs. Our Business may be developed in phases.

The proposed Driftwood terminal will have a liquefaction capacity of approximately 27.6 Mtpa and will be situated on approximately 1,000 acres in Calcasieu Parish, Louisiana. The proposed Driftwood terminal will include up to 20 liquefaction Trains, three full containment LNG storage tanks and three marine berths. We have entered into four LSTK EPC agreements totaling $15.2$15.5 billion with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for construction of the Driftwood terminal.

The proposed Pipeline Network willis currently expected to consist of three pipelines, the Driftwood pipeline, the Haynesville Global Access Pipeline and the Permian Global Access Pipeline. The Driftwood pipeline will be a 96-mile large diameter pipeline that will interconnect with 14 existing interstate pipelines throughout southwest Louisiana to secure adequate natural gas feedstock for the Driftwood terminal. The Driftwood pipeline will be comprised of 48-inch, 42-inch 36-inch and 30-inch36-inch diameter pipeline segments and three compressor stations totaling approximately 274,000 horsepower, all as necessary to provide approximately 4 Bcf/d of average daily natural gas transportation service. We estimate construction costs for the Driftwood pipeline of up to approximately $2.3 billion before owners’ costs, financing costs and contingencies.

The Haynesville Global Access Pipeline is expected to run approximately 200 miles from northern to southwest Louisiana. The Permian Global Access Pipeline is expected to run approximately 625 miles from west Texas to southwest Louisiana. Each of these pipelines is expected to have a diameter of 42 inches and be capable of delivering approximately 2 Bcf/d of natural gas. We currently estimate that construction costs will be approximately $1.4 billion for the Haynesville Global Access Pipeline and approximately $3.7$4.2 billion for the Permian Global Access Pipeline, in each case before owners’ costs, financing costs and contingencies. We are also considering the potential development of a fourth pipeline, the Delhi Connector Pipeline, which would run approximately 180 miles from Perryville/Delhi in northeast Louisiana to Lake Charles, Louisiana.

Our current upstream properties, acquired in a series of transactions during 2017 and 2018, consist of 10,23310,260 net acres and 5267 producing wells (18(21 operated) located in the Haynesville Shale trend of northnorthern Louisiana. For the year ended December 31, 2018, these wells had average net production of approximately 3.9 MMcf/d. As of December 31, 2018, our estimate of net proved reserves was approximately 265 Bcfe. We began drilling certain locations on our properties in the fourth quarter of 2018 using proceeds from the Term Loan (as described in “2018 Developments — Significant Transactions — Term Loan” below). 

In connection with the implementation of our Business, we are offering limited partnership interests in a subsidiary, Driftwood Holdings LLCLP (“Driftwood Holdings”), which will own the Driftwood Project. Partners will contribute cash in exchange for equity in Driftwood Holdings and will receive LNG volumes at the cost of production, including the cost of debt, for the life of the Driftwood terminal. We plan to retain a portion of the ownership in Driftwood Holdings and have engaged Goldman Sachs & Co. and Société Générale to serve as financial advisors for Driftwood Holdings. We also continue to develop our LNG marketing activities as described below in “2018 Developments“Overview of Significant Events — Significant Transactions — LNG Marketing.”

As discussed in “Our Business and Properties — Overview,” our upstream properties, acquired in a series of transactions during 2017 and 2018, consist of 10,23310,260 net acres and 5267 producing wells (18(21 operated) located in the Haynesville Shale trend of north Louisiana. For the year ended December 31, 2018,2019, these wells had average net production of approximately 3.938.1 MMcf/d. All of our proved reserves as of December 31, 20182019 were associated with those properties. Proved reserves are the estimated quantities of natural gas and condensate which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., costs as of the date the estimate is made). Proved reserves are categorized as either developed or undeveloped.

Our reserves as of December 31, 20182019 were estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm, and are set forth in the following table. Per SEC rules, NSAI based its estimates on the 12-month unweighted arithmetic average of the first-day-of-the-month price of natural gas for each month from January through December 2018.2019. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The pricesprice used were $3.10was $2.58 per MMbtuMMBtu of natural gas, and $65.56 per barrel of condensate, adjusted for energy content, transportation fees and market differentials.

The following table shows our proved reserves as of December 31, 2018:2019:

The standardized measure of discounted future net cash flow from our proved reserves (the “standardized measure”) as of December 31, 20182019 was $145.8$53.2 million.

Refer to Supplemental Disclosures About Natural Gas Producing Activities, starting on page 60,69, for additional details.

Our December 31, 20182019 reserve report was prepared by NSAI in accordance with guidelines established by the SEC. Reserve definitions comply with the definitions provided by Regulation S‑X of the SEC. NSAI prepared the reserve report based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provideprovided to them. This information iswas reviewed by knowledgeable members of our Company for accuracy and completeness prior to submission to NSAI.

Internally, a Senior Vice President is responsible for overseeing our reserves process. Our Senior Vice President has over 1718 years of experience in the oil and natural gas industry, with the majority of that time in reservoir engineering and asset management. She is a graduate of Virginia Polytechnic Institute and State University with dual degrees in Chemical Engineering and French, and a graduate of the University of Houston with a Masters of Business Administration degree. During her career, she has had multiple responsibilities in technical and leadership roles, including reservoir engineering and reserves management, production engineering, planning, and asset management for multiple U.S. onshore and international projects. She is also a licensed Professional Engineer in the State of Texas.

For the years ended December 31, 2019, 2018 and 2017, we produced 13,901 MMcf, 1,399 MMcf and 190 MMcf of natural gas at an average sales price of $2.07, $2.97 and $2.42 per MMcf, respectively. For the years ended December 31, 2018 and 2017, we produced 988 barrels and 150 barrels of condensate at an average sales price of $60.46 per barrel and $57.01 per barrel, respectively. Natural gas and condensate production and operating costs for the periods ended December 31, 2019, 2018 and 2017, were $0.25, $1.71 and $1.25 per MMcfe, respectively.

AsThe table below represents the number of December 31, 2018, we were in the process of drilling or completing operations on one operated wellnet productive and 12 non-operated wells. Of these 12 non-operated wells, as of December 31, 2018, six had been turned in line. We had no exploratory wells drilled in 2018 or 2017. In addition, we had no dry development wells in 2018 or 2017.drilled during the past three years:

As of December 31, 2018,2019, we owned interests in 3748 gross (18(21 net) productive natural gas wells and held by production 10,5033,672 gross (9,074(3,004 net) developed leasehold acreage. Additionally, we hold 1,1808,037 gross (1,159(7,256 net) undeveloped leasehold acreage. The majorityAs of December 31, 2019, there were 4 gross in process wells.

We are not currently subject to any material volume commitments.

As part of our acquisitions of natural gas properties, we also acquired certain gathering systems that deliver the natural gas we produce into third-party gathering systems. We believe that these systems and other available midstream facilities and services in the Haynesville Shale trend are adequate for our current operations and near-term growth.

Our operations are and will be subject to extensive federal, state and local statutes, rules, regulations, and laws that include, but are not limited to, the NGA, the Energy Policy Act of 2005 (the “EPAct”(“EPAct 2005”), the Oil Pollution Act, the National Environmental Protection Act (“NEPA”), the Clean Air Act (the “CAA”), the Clean Water Act (the “CWA”), the Resource Conservation and Recovery Act (“RCRA”), the Pipeline Safety Improvement Act of 2002 (the “PSIA”), and the Coastal Zone Management Act (the “CZMA”). These statutes cover areas related to the authorization, construction and operation of LNG facilities, natural gas pipelines and natural gas producing properties, including discharges and releases to the air, land and water, and the handling, generation, storage and disposal of hazardous materials and solid and hazardous wastes due to the development, construction and operation of the facilities. These laws are administered and enforced by governmental agencies including but not limited to FERC, the U.S. Environmental Protection Agency (the “EPA”), the DOE/FE, the U.S. Department of Transportation (“DOT”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the Louisiana Department of Environmental Quality, the Texas Commission on Environmental Quality, the Louisiana Department of Natural Resources, and the Texas Railroad Commission. Additionally, numerous other governmental and regulatory permits and approvals will be required to build and operate our Business, including, with respect to the construction and operation of the Driftwood Project, consultations and approvals by the Advisory Council on Historic Preservation, USACE, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, and U.S. Department of Homeland Security. For example, throughout the life of our liquefaction project, we will be subject to regular reporting requirements to FERC, the DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”)PHMSA and other federal and state regulatory agencies regarding the operation and maintenance of our facilities.

Failure to comply with applicable federal, state, and local laws, rules, and regulations could result in substantial administrative, civil and/or criminal penalties and/or failure to secure and retain necessary authorizations.

The design, construction and operation of liquefaction facilities and pipelines, the export of LNG and the transportation of natural gas are highly regulated activities. In order to site, construct and operate our LNG facilities, we are required to obtainobtained authorizations from FERC under Section 3 and Section 7 of the NGA as well as several other material governmental and regulatory approvals and permits. Thepermits as detailed in the table above. EPAct 2005 amended Section 3 of the NGA to establish or clarify FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, although except as specifically provided in the EPAct 2005, nothing in the EPActstatute is intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals.

In 2002, FERC concluded that it would apply light-handed regulation overto the rates, terms and conditions agreed to by parties for LNG terminalling services, such that LNG terminal owners would not be required to provide open-access service at non-discriminatory rates or maintain a tariff or rate schedule on file with FERC, as distinguished from the requirements applied to FERC-regulated interstate natural gas pipelines. Although the EPAct 2005 codified FERC’s policy, those provisions expired on January 1, 2015. Nonetheless, we see no indication that FERC intends to modify its longstanding policy of light-handed regulation of LNG terminals.terminal operations.

A certificate of public convenience and necessity from FERC has authority to approve, and if necessary set, “just and reasonable rates”is required for the transportation or sale of natural gas in interstate commerce. Relatedly, under the NGA, our proposed pipelines will not be permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including our own affiliates. FERC has the authority to grant certificates authorizing the construction and operation of facilities such as pipelines, used in interstate natural gas transportation, including pipeline facilities, in addition to other required governmental and regulatory approvals. In this regard, in April 2019, we obtained a certificate of public convenience and necessity to construct and operate the provisionDriftwood pipeline. Similarly, in anticipation of services. filing an application to construct and operate the Permian Global Access Pipeline, we have initiated the FERC pre-filing review process, which is ongoing.

FERC’s jurisdiction under the NGA generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate consumption for domestic, commercial, industrial or any other

Specifically, FERC’s authority to regulate interstate natural gas pipelines includes:

EPAct amends2005 amended the NGA to make it unlawful for “any entity,” including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. The EPAct 2005 also gives FERC authority to impose civil penalties for violations of the NGA or Natural Gas Policy Act of up to $1 million per violation.

Transportation of the natural gas we produce, and the prices we pay for such transportation, will be significantly affected by the foregoing laws and regulations.

Under the NGA, exports of natural gas to FTA countries are “deemed to be consistent with the public interest,” and authorization to export LNG to FTA countries shall be granted by the DOE/FE “without modification or delay.” FTA countries currently capable of importing LNG include but are not limited to Canada, Chile, Colombia, Jordan, Mexico, Singapore, South Korea and the Dominican Republic. Exports of natural gas to non-FTANon-FTA countries are authorized unless the DOE/FE finds that the proposed exportation “will not be consistent with the public interest.” We have authorization from the DOE/FE to export LNG in a volume up to the equivalent of 1,415.3 Bcf per year of natural gas to FTA countries for a term of 30 years and to Non-FTA countries for a term of 20 years.

The Natural Gas Pipeline Safety Act of 1968 (the “NGPSA”) authorizes DOT to regulate pipeline transportation of natural (flammable, toxic, or corrosive) gas and other gases, as well as the transportation and storage of LNG. Amendments to the NGPSA include the Pipeline Safety Act of 1979, which addresses liquids pipelines, and the PSIA, which governs the areas of testing, education, training, and communication.

PHMSA administers pipeline safety regulations for jurisdictional gas gathering, transmission, and distribution systems under minimum federal safety standards. PHMSA also establishes and enforces safety regulations for onshore LNG facilities, which are defined as pipeline facilities used for the transportation or storage of LNG subject to such safety standards. Those regulations address requirements for siting, design, construction, equipment, operations, personnel qualification and training, fire protection, and security of LNG facilities. The Driftwood terminal will be subject to such PHMSA regulations.

Tellurian’s proposed pipelines will also be subject to regulation by PHMSA, including those under the PSIA. The PHMSA Office of Pipeline Safety administers the PSIA, which requires pipeline companies to perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as “high consequence areas.” Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for natural gas transportation pipelines, which requires pipeline operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats

In April 2016,On October 1, 2019, PHMSA issued a notice of proposed rulemaking addressing changesfinal rule revising the Federal Pipeline Safety Regulations to the regulations governingimprove the safety of onshore gas transmission pipelines. Specifically, PHMSA is considering certainThis final rule addresses congressional mandates and National Transportation Safety Board recommendations, and responds to public input. The amendments in this final rule address integrity management requirements for “moderateand other requirements, and they focus on the actions an operator must take to reconfirm the maximum allowable operating pressure of previously untested natural gas transmission pipelines and pipelines lacking certain material or operational records, the periodic assessment of pipelines in populated areas not designated as “high consequence areas,” requiring anthe reporting of exceedances of maximum allowable operating pressure, the consideration of seismicity as a risk factor in integrity verification processmanagement, safety features on in-line inspection launchers and receivers, a six-month grace period for specific categoriesseven-calendar-year integrity management reassessment intervals, and related recordkeeping provisions. The effective date of pipelines, and mandating more explicit requirements for the integration of data from integrity assessments to an operator’s compliance procedures.this final rule is July 1, 2020. PHMSA is also considering whether to revise requirements for corrosion control and expanding the definition of regulated gathering lines. These notices of proposed rulemaking are still pending at PHMSA and have not been finalized.

Louisiana administers federal pipeline safety standards under the NGPSA, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal sanctions.

The construction and operation of the Driftwood Project will beis subject to additional federal permits, orders, approvals and consultations required by other federal and state agencies, including DOT, the Advisory Council on Historic Preservation, USACE, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the EPA and U.S. Department of Homeland Security. The necessary permits have been obtained for the Driftwood terminal and Driftwood pipeline. Similarly, additional permits, orders, approvals and consultations will be required for the other elements of the Driftwood Project.

Three significant permits that may apply to the Driftwood Project are the USACE Section 404 of the Clean Water Act/Section 10 of the Rivers and Harbors Act Permit, the Clean Air ActCAA Title V Operating Permit and the PSDPrevention of Significant Deterioration Permit, of which the latter two permits are issued by the Louisiana Department of Environmental Quality. TheEach of the Driftwood Project will also haveterminal and Driftwood pipeline has received its permit from USACE, including a review and approval by USACE of the findings and conditions set forth in an Environmental Impact Statement and Record of Decision issued for the Driftwood terminal pursuant to comply with the requirements of NEPA. The Louisiana Department of Environmental Quality has issued the Prevention of Significant Deterioration permit, which is required to commence construction of the Driftwood terminal as well as the Title V Operating Permit. These material approvals will be required for the other elements of the Driftwood Project.

Our operations are and will be subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources, the handling, generation, storage and disposal of hazardous materials and solid and hazardous wastes and other matters. These environmental laws and regulations, which can restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment, will require significant expenditures for compliance, can affect the cost and output of operations, may impose substantial administrative, civil and/or criminal penalties for non-compliance and can result in substantial liabilities. The statutes, regulations and permit requirements imposed under environmental laws are modified frequently, sometimes retroactively. Such changes are difficult to predict or prepare for, and may impose material costs for new permits, capital investment or operational limitations or changes.

In June 2015, the EPA and the USACE issued a final rule that attempts to clarifydefining the CWA’s jurisdictional reach over waters“waters of the U.S.United States” (the “2015 Clean Water Rule”) and replacing the previous definition of “waters of the United States” in a 1986 rule and related guidance. In February 2018, the EPA issued a rule that delays the applicability of the new definition of the waters of the U.S. until February 2020. On August 16, 2018, the U.S. District Court for South Carolina found that the EPA and the USACE failed to comply with the Administrative Procedure Act and struck the 2018issued a rule that attempted to delay the applicability date of the 2015 Clean Water Rule.Rule until February 2020, but this delay rule was struck down following a court challenge. Other federal district courts, however, have issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself.in several states. Taken together, the 2015 Clean Water Rule is currentlywas in effect in 2322 states and temporarily stayed in the remaining27 states. In those remaining states where the 2015 Clean Water Rule

In January 2020, the EPA and the USACE finalized a rule that would differently revise the definition of “waters of the United States” and essentially replace both the 1986 rule and the 2015 Clean Water Rule.Rule (the “2020 Rule”). According to the agencies, the proposed new rule is “intended to increase CWA program2020 Rule “increases the predictability and consistency by increasing clarity as toconsistency” of the CWA “by clarifying the scope of ‘waters of the United States’ federally regulatedregulated” under the Act.” If finalized, this new definitionCWA. As of “waters ofFebruary 14, 2020, the United States”2020 Rule has not been published in the Federal Register. It will become effective 60 days after publication. Once the 2020 Rule is published, it will likely be challenged and sought to be enjoined in federal court. If and when a final rule (as issued or revised) goes into effect, it could expandThe 2020 Rule is intended to narrow the scopedefinition of “waters of the CWA’s jurisdiction, whichUnited States” from the 2015 Clean Water Rule. Therefore, the 2020 Rule could result in increasedreduce costs and delays with respect to obtaining permits for discharges orof pollutants or dredge and fill activities in waters of the U.S., including in wetland areas.

Federal laws including the CWA require certain owners or operators of facilities that store or otherwise handle oil and produced water to prepare and implement spill prevention, control, countermeasure and response plans addressing the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) subjects owners and operators of facilities to strict and joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills, including the government’s response costs. Spills subject to the OPA may result in varying civil and criminal penalties and liabilities. The Driftwood Project incorporates appropriate equipment and operational measures to reduce the potential for spills of oil and establish protocols for responding to spills, but oil spills remain an operational risk that could adversely affect our operations and result in additional costs or fines or penalties.

Oil and natural gas exploration and production, and possibly other activities, have been conducted at a majoritysome of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in certain instances may require remediation. In some instances, we have agreed to indemnify the sellers of producing properties from whom we have

In February 2014, the EPA issued permitting guidance under the Safe Drinking Water Act (the “SDWA”) for the underground injection of liquids from hydraulically fractured wells and other wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities byrelated to the EPA.Driftwood Project.

In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act (“TSCA”) pursuant to which it will collect extensive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors.

In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and natural gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and natural gas extraction facilities to publicly-owned treatment works.

Our natural gas production operations are subject to a number of additional laws, rules and regulations that require, among other things, permits for the drilling of wells, drilling bonds and reports concerning operations. States, parishes and municipalities in which we operate may regulate, among other things:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states, including Louisiana, allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells and generally prohibit the venting or flaring of natural gas and require that oil and natural gas be produced in a prorated, equitable system. These laws and regulations may limit the amount of oil and natural gas that we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, most states generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their jurisdictions. Many local authorities also impose an ad valorem tax on the minerals in place. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

Our international operations are subject to one or more anti-corruption laws in various jurisdictions, such as the U.S. Foreign Corrupt Practices Act of 1977, as amended (the “FCPA”), the U.K. Bribery Act of 2010 and other anti-corruption laws. The FCPA and these other laws generally prohibit employees and intermediaries from bribing or making other prohibited payments to foreign officials or other persons to obtain or retain business or gain some other business advantage. We participate in relationships with third parties whose actions could potentially subject us to liability under the FCPA or other anti-corruption laws. In addition, we cannot predict the nature, scope or effect of future regulatory requirements to which our international operations might be subject or the manner in which existing laws might be administered or interpreted.

We are also subject to other laws and regulations governing our international operations, including regulations administered by the U.S. Department of Commerce’s Bureau of Industry and Security, the U.S. Department of Treasury’s Office of Foreign Assets Control, and various non-U.S. government entities, including applicable export control regulations, economic sanctions on countries and persons, customs requirements, currency exchange regulations, and transfer pricing regulations (collectively, “Trade Control laws”).

We are also subject to new U.K. corporate criminal offenses for failure to prevent the facilitation of tax evasion pursuant to the Criminal Finances Act 2017, which imposes criminal liability on a company where it has failed to prevent the criminal facilitation of tax evasion by a person associated with the company.

We have instituted policies, procedures and ongoing training of employees with regard to business ethics, designed to ensure that we and our employees comply with the FCPA, other anti-corruption laws, Trade Control laws and the Criminal Finances Act 2017. However, there is no assurance that our efforts have been and will be completely effective in ensuring our compliance with all applicable anti-corruption laws, including the FCPA or other legal requirements. If we are not in compliance with the FCPA, other anti-corruption laws, the Trade Control laws or the Criminal Finances Act 2017, we may be subject to criminal and civil penalties, disgorgement and other sanctions and remedial measures, and legal expenses, which could have a material adverse impact on our business, financial condition, results of operations and liquidity. Likewise, any investigation of any potential violations of the FCPA, other anti-corruption laws the Trade Control laws or the Criminal Finances Act 2017 by the U.S. or foreign authorities could have a material adverse impact on our reputation, business, financial condition and results of operations.

With respect to our natural gas producing properties, we believe that we hold good and defensible leasehold title to substantially all of our properties in accordance with standards generally accepted in the industry. A preliminary title examination is conducted at the time the properties are acquired. Our natural gas properties are subject to royalty, overriding royalty, and other outstanding interests.

We do not have any major customers.

Certain subsidiaries of Tellurian have entered into operating leases for office space in Houston, Texas, Washington, D.C., London, England and Singapore. The tenors of the leases are three, five, eighttwo, four, seven and 10nine years for Singapore, London, Houston and Washington, D.C., respectively.

As of December 31, 2018,2019, Tellurian had 172176 full-time employees worldwide, noneworldwide. None of whomthem are subject to collective bargaining arrangements.

The Company is a Delaware corporation originally formed in 1967 and formerly known as Magellan Petroleum Corporation.

We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.tellurianinc.com. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact Tellurian Inc., Investor Relations, 1201 Louisiana Street, Suite 3100, Houston, Texas 77002.

Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Our risk factors are grouped into the following categories:

Tellurian will be unable to generate any significant revenue from the Driftwood Project for multiple years, and expects cash flow from its other lines of business to be modest for an extended period as it focuses on the development and growth of these operations.businesses. Tellurian will, therefore, need substantial amounts of additional financing to execute its business plan. There can be no assurance that Tellurian will be able to raise sufficient capital on acceptable terms, or at all. If such financing is not available on satisfactory terms or is not available at all, Tellurian may be required to delay, scale back or cancel the development of business

Debt or preferred equity financing, if obtained, may involve agreements that include liens or restrictions on Tellurian’s assets and covenants limiting or restricting our ability to take specific actions, such as paying dividends or making distributions, incurring additional debt, acquiring or disposing of assets and increasing expenses. Debt financing would also be required to be repaid regardless of Tellurian’s operating results.

In addition, the ability to obtain financing for the proposed Driftwood Project may depend in part on Tellurian’s ability to enter into sufficient commercial agreements prior to the commencement of construction. To date,Except for the equity capital contribution agreement and LNG sale and purchase agreement with affiliates of TOTAL S.A., which agreements remain subject to certain conditions precedent, Tellurian has not entered into any definitive third-party agreements for the proposed Driftwood Project, and it may not be successful in negotiating and entering into such agreements.

We only recently commenced operations.have a limited operating history. Although Tellurian’s current directors, managers and officers have prior professional and industry experience, our business is in an early stage of development. Accordingly, the prior history, track record and historical financial information you may use to evaluate our prospects are limited.

Tellurian has not yet commenced the construction of the Driftwood Project and expects to incur significant additional costs and expenses through the completion of development and construction of that project. The Company also expects to devote substantial amounts of capital to the growth and development of its other operations. Tellurian expects that operating losses will increase substantially in 20192020 and thereafter, and expects to continue to incur operating losses and to experience negative operating cash flows for the next several years.

As we continue to ramp updevelop our LNG and natural gas marketing and natural gas production activities, we may enter into commodity hedging arrangements in an effort to reduce our exposure to fluctuations in price and timing risk, anyrisk. Any hedging arrangements entered into would expose us to the risk of financial loss when (i) the counterparty to the hedging contract defaults on its contractual obligations or (ii) there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.

Also, commodity derivative arrangements may limit the benefit we would otherwise receive from a favorable change in the relevant commodity price. In addition, regulations issued by the Commodities Futures Trading Commission, the SEC and other federal agencies establishing regulation of the over-the-counter derivatives market could adversely affect our ability to manage our price risks associated with our LNG and natural gas activity and therefore have a negative impact on our operating results and cash flows.

Factors that could materially affect our future effective tax rates include but are not limited to:

We are subject to income taxes in the U.S. and several foreign jurisdictions. Our future effective tax rates could be affected by changes in the composition of earnings in countries with differing tax rates, changes in deferred tax assets and liabilities or changes in tax laws. Foreign jurisdictions have also increased the volume of tax audits of multinational corporations. Further,

In December 2017, the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act of 2017 (the “Tax Act”), was signed into law, making significant changes to the Internal Revenue Code of 1986, as amended. At this time, the U.S. Department of Treasury has not yet issued final regulations on all provisions of the Tax Act. There may be future Congressional technical corrections to the Tax Act and other regulatory guidance and/or administrative interpretations toof the Tax Act that are yet to be issued. We will continue to examine the impact that new guidance and interpretation of the Tax Act may have on our business. We urge our stockholders to consult with their legal and tax advisors with respect to the legislation and potential tax consequences of investing in our stock.

In addition to the impact of the Tax Act on our federal taxes, it may impact taxation in other jurisdictions such as state income taxes. The various state legislatures have not had sufficient time to respond to the Tax Act. Accordingly, it is uncertain as to how the laws will apply in the various state jurisdictions. Additionally, other foreign governing bodies may enact changes in their tax laws in reaction to the Tax Act that could result in changes to our global tax position and materially affect our financial position.

We are also subject to examination by the Internal Revenue Service (the “IRS”) and other tax authorities, including state revenue agencies and other foreign governments. While we regularly assess the likelihood of favorable or unfavorable outcomes resulting from examinations by the IRS and other tax authorities to determine the adequacy of our provision for income taxes, there can be no assurance that the actual outcome resulting from these examinations will not materially adversely affect our financial condition and operating results. Additionally, the IRS and several foreign tax authorities have increasingly focused attention on intercompany transfer pricing with respect to sales of products and services and the use of intangibles. Tax authorities could disagree with our cross-jurisdictional transfer pricing or other matters and assess additional taxes. If we do not prevail in any such disagreements, our profitability may be affected.

Tellurian’s directly and indirectly held assets currently consist primarily of cash held for certain start-up and operating expenses, applications for permits from regulatory agencies relating to the Driftwood Project and certain real property and mineral interests related to that project. Tellurian’s cash flow, and consequently its ability to distribute earnings, is solely dependent upon the cash flow its subsidiaries receive from the Driftwood Project and its other operations. Tellurian’s ability to complete the Driftwood Project, as discussed further below, is dependent upon its subsidiaries’ ability to obtain and maintain necessary regulatory approvals and raise the capital necessary to fund the development of the project. We expect that cash flows from our operations will be reinvested in the business rather than used to fund dividends, that pursuing our strategy will require substantial amounts of capital, and that the required capital will exceed cash flows from operations for a significant period.

Tellurian’s ability to pay dividends in the future is uncertain and will depend on a variety of factors, including limitations on the ability of it or its subsidiaries to pay dividends under applicable law and/or the terms of debt or other agreements, and the judgment of the board of directors or other governing body of the relevant entity.

As described in “Our Business and Properties — 2018 Developments — Significant Transactions,” inIn September 2018, Tellurian Production Holdings LLC, a subsidiary of Tellurian (“Production Holdings”), entered into a credit agreement providing for thea term loan (the “2018 Term Loan,Loan”), and Tellurian Inc. entered into a parent guarantee pursuant to which it guaranteed the obligations of Production Holdings relating to the 2018 Term Loan.

The ability of each of Production Holdings’ abilityHoldings and Driftwood Holdings to generate cash flows from operations or obtain refinancing capital sufficient to pay interest and principal on its indebtedness will depend on its future operating performance and financial condition and the availability of refinancing indebtedness,debt or equity capital, which will be affected by prevailing commodity prices and economic conditions and financial, business and other factors, many of which are beyond its control. If Production Holdings or Driftwood Holdings is unable to satisfy its obligations under theits Term Loan, Tellurian Inc.and/or certain of its subsidiaries may be obligated to pay interest and/or principal on the indebtedness pursuant to the parent guarantee,applicable guarantee(s), and itthey may not have the financial resources to do so. Tellurian Inc. does not currently have any material sources of operating cash flows. An inability on the part of Production Holdings or Driftwood Holdings to generate adequate cash flows from operations could adversely affect our ability to execute our overall business plan, and we could be required to sell assets, reduce our capital expenditures or seek refinancing indebtednessdebt or equity capital to satisfy the requirements of the Term LoanLoans and the parent guarantee.related guarantees. These alternative measures may be unavailable or inadequate and may themselves adversely affect our overall business strategy.

These covenants may prevent Production Holdings or Driftwood Holdings from taking actions that it believes would be in the best interest of its business and may make it difficult for it to successfully execute its business strategy or effectively compete with companies that are not similarly restricted.

The credit agreement containsagreements governing each Term Loan contain financial covenants. If Production Holdings or Driftwood Holdings is unable to satisfy thesethe applicable covenants, it would be in default under the agreement, and the lenders could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, and institute foreclosure proceedings with respect to its assets. The lenders could also seek to enforce the parent guarantee against Tellurian Inc., and/or any other guarantor, which may not have sufficient funds, or the ability to obtain sufficient funds, to repay the amounts then due. In those circumstances, Production Holdings, Driftwood Holdings, Tellurian Inc. and/or Tellurian Inc.other guarantors could be forced into bankruptcy or liquidation.

The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events could trigger a significant decline in the trading price of our common stock, including, among others, failure to obtain necessary permits, unfavorable changes in commodity prices or commodity price expectations, adverse regulatory developments, loss of a relationship with a partner, litigation and departures of key personnel. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of equity securities generally could affect the price of our stock. The stock markets frequently experience price and volume volatility that affects many companies’ stock prices, often in ways unrelated to the operating performance of those companies. These fluctuations may affect the market price of our common stock.

Sales of a substantial number of shares of our common stock in the market by us or any of our major shareholders, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares in the public market, or the possibility of such sales, could impair our ability to raise capital through the sale of additional equity securities. Our insider trading policy permits our officers and directors, some of whom own substantial percentages of our outstanding common stock, to pledge shares of stock that they own as collateral for loans subject to certain requirements. Some of our officers and directors have pledged shares of stock in accordance with this policy. In some circumstances, such pledges

In addition, in the future, we may issue shares of our common stock, or securities convertible into our common stock, in connection with acquisitions of assets or businesses or for other purposes. Such issuances may result in dilution to our existing stockholders and could have an adverse effect on the market value of shares of our common stock, depending on market conditions at the time, the terms of the issuance, and if applicable, the value of the business or assets acquired and our success in exploiting the properties or integrating the businesses we acquire.

Commercial development of an LNG facility takes a number of years, requires substantial capital investment and may be delayed by factors such as:

Our failure to execute our business plan within budget and on schedule could materially adversely affect our business, financial condition, operating results, liquidity and prospects.

We currently estimate the total cost of the Driftwood Project to be approximately $28$28.9 billion, including owners’ costs, transaction costs and contingencies but excluding interest costs incurred during construction of the Driftwood terminal and other financing costs. However, cost estimates for these and other projects we may pursue are only approximations of the actual costs of construction. Moreover, cost estimates may be inaccurate and may change due to various factors, such as cost overruns, change orders, delays in construction, legal and regulatory requirements, site issues, increased component and material costs, escalation of labor costs, labor disputes, changes in commodity prices, changes in foreign currency exchange rates, increased spending to maintain Tellurian’s construction schedule and other factors. For example, new or increased tariffs on materials needed in the construction process have been proposed or may be proposed in the future and such new or increased tariffs could materially increase construction costs. In particular, tariffs on imported steel may significantly increase our construction costs. Similarly, cost overruns could occur as a result of dredging-related expenditures incurred to comply with water depth regulations in the Calcasieu Ship Channel. Our estimate of the cost of construction of the Driftwood terminal is based on the prices set forth in our LSTK EPC contractsagreements with Bechtel which are subject to adjustment by change orders, including for consideration of cost escalation associated with the issuance of a “notice to proceed” with respect to the Driftwood terminal after December 31, 2017. Our cost estimates for the Haynesville Global Access Pipeline and the Permian Global Access Pipeline are more preliminary than is the estimate for the Driftwood pipeline.

Our failure to achieve our cost estimates could materially adversely affect our business, financial condition, operating results, liquidity and prospects.

We will depend upon third-party pipelines and other facilities that will provide natural gas delivery options to our natural gas production operations and our LNG facilities. 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 or any other reason, our ability to meet our LNG sale and purchase agreement obligations and continue shipping natural gas from producing operations or regions to end markets could be restricted, thereby reducing our revenues. This could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

Except for the equity capital contribution agreement and LNG sale and purchase agreement with affiliates of TOTAL S.A., which agreements remain subject to certain conditions precedent, Tellurian has not yet entered into and may never be able to enter into, satisfactory commercial arrangements with third- partythird-party customers for products and services from the Driftwood Project.

Under LNG sale and purchase agreements with our customers, we may be required to make available to them a specified amount of LNG at specified times. However, we may not be able to acquire or produce sufficient quantities of natural gas or LNG to satisfy those obligations, which may provide affected customers with the right to terminate their LNG sale and purchase agreements. Our failure to purchase, receive or produce sufficient quantities of natural gas or LNG in a timely manner could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The design, construction and operation of LNG export terminals is a highly regulated activity. The approval of FERC under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, is required to construct and operate an LNG terminal. Even if the necessarySuch approvals and authorizations initially required to operate our proposed LNG facilities are obtained, such authorizations areoften subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. Further, Tellurian must obtain and maintain approvals to export LNG to FTA and non-FTA countries in order to execute its business strategy. Tellurian and its affiliates will be required to obtain and maintain governmental approvals and authorizations to implement its proposed business strategy, which includes the construction and operation of the Driftwood Project. In particular, authorization from FERCAlthough all the major permits required for construction and operation of the DOE/FE is required to constructDriftwood terminal and operate our proposed LNG facilities. In addition to seeking to obtain approval for export to FTA countries, Tellurian has filed an application to obtain approval for export to non-FTA countries. NumerousDriftwood pipeline have been obtained, numerous permits and approvals will also be required in connection with other aspects of the Driftwood Project, including the construction and operation of the Pipeline Network and our upstream operations.

There is limited recent industry experience in the U.S. regarding the construction or operation of large-scale LNG facilities. The construction of the Driftwood terminal is expected to take several years, will be confined to a limited geographic area and could be subject to delays, cost overruns, labor disputes and other factors that could adversely affect financial performance or impair Tellurian’s ability to execute its proposed business plan.

Further, faulty construction that does not conform to Tellurian’s design and quality standards may have an adverse effect on Tellurian’s business, results of operations, financial condition and prospects. For example, improper equipment installation may lead to a shortened life of Tellurian’s equipment, increased operations and maintenance costs or a reduced availability or production capacity of the affected facility. The ability of Tellurian’s third-party contractors to perform successfully under any agreements to be entered into is dependent on a number of factors, including force majeure events and such contractors’ ability to:

Furthermore, Tellurian may have disagreements with its third-party contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under the related contracts, resulting in a contractor’s unwillingness to perform further work on the relevant project. Tellurian may also face difficulties in commissioning a newly constructed facility. Any significant delays in the development of the Driftwood terminal could materially and adversely affect Tellurian’s business, results of operations, financial condition and prospects. In addition, the construction of the pipelines in the Pipeline Network and other infrastructure we build in connection with the Driftwood Project or otherwise will be subject to substantially all of the foregoing risks, and the occurrence of any construction-related problem could have a variety of adverse effects on our operations. In particular, completion of the Driftwood pipeline will be required for the long-term operations of the Driftwood terminal.   

Siting, development and construction of the Driftwood Project will be subject to the risks of delay or cost overruns inherent in any construction project resulting from numerous factors, including, but not limited to, the following:

Delays beyond the estimated development periods, as well as cost overruns, could increase the cost of completion beyond the amounts that are currently estimated, which could require Tellurian to obtain additional sources of financing to fund the activities until the proposed Driftwood terminal is constructed and operational (which could cause further delays). Any delay in completion of the Driftwood Project may also cause a delay in the receipt of revenues projected from the Driftwood Project or cause a loss of one or more customers. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects. Similar risks may affect the construction of other facilities and projects we elect to pursue.

Tellurian’s plans and expectations regarding its business and the development of domestic LNG facilities and projects are generally based on assumptions about the future price of natural gas and LNG and the conditions of the global natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to remain in the future, volatile and subject to wide fluctuations that are difficult to predict. Such fluctuations may be caused by various factors, including, but not limited to, one or more of the following:

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, liquidity and prospects.

Tellurian’s success will depend on its ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, although Tellurian plans to construct the Driftwood terminal using proven technologies that it believes provide it with certain advantages, Tellurian does not have any exclusive rights to any of the technologies that it will be utilizing. In addition, the technology Tellurian anticipates using in the Driftwood Project may be rendered obsolete or uneconomical by legal or regulatory requirements, technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of its competitors or others, which could materially and adversely affect Tellurian’s business, results of operations, financial condition, liquidity and prospects.

Operations of the Driftwood Project will be dependent upon our ability to deliver LNG supplies from the U.S., 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 U.S., which could increase the available supply of natural gas outside the U.S. and could result in natural gas in those markets being available at a lower cost than that of LNG exported to those markets.

Factors which may negatively affect potential demand for LNG from our liquefaction projects are diverse and include, among others:

Political instability in foreign countries that import natural gas, or strained relations between such countries and the U.S., may also impede the willingness or ability of LNG suppliers, purchasers and merchants in such countries to import LNG from the U.S. Furthermore, some foreign purchasers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or our competitors’ liquefaction facilities in the U.S.

As a result of these and other factors, LNG may not be a competitive source of energy 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 U.S. on a commercial basis. Any significant impediment to the ability to deliver LNG from the U.S. generally, or from the Driftwood Project specifically, could have a material adverse effect on our customers and 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 Tellurian’s business and customers due to a variety of factors, including, but not limited to, the following:

Any of these factors could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.

We will rely on third parties for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of the Driftwood terminal. Any of our LNG facilities, when constructed, may not have the capacity ratings and performance capabilities that we intend or estimate. Failure of any of our facilities to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our current or future LNG sale and purchase agreements and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We will be subject to extensive federal, state and local environmental and safety regulations and laws, including regulations and restrictions related to discharges and releases to the air, land and water and the handling, storage, generation and disposal of hazardous materials and solid and hazardous wastes in connection with the development, construction and operation of our LNG facilities and pipelines. Failure to comply with these regulations and laws could result in the imposition of administrative, civil and criminal sanctions.

These regulations and laws, which include the CAA, the Oil Pollution Act, the CWA and RCRA, and analogous state and local laws and regulations, will restrict, prohibit or otherwise regulate the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities. These laws and regulations, including NEPA, will require and have required us to obtain and maintain permits with respect to our facilities, prepare environmental impact assessments, provide governmental authorities with access to our facilities for inspection and provide reports related to compliance. 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. Violation of these laws and regulations could lead to substantial liabilities, fines and penalties, the denial or revocation of permits necessary for our operations,

As thean owner and the operator of the Driftwood Project, we could be liable for the costs of investigating and cleaning up hazardous substances released into the environment and for damage to natural resources, whether caused by us or our contractors or existing at the time construction commences. Hazardous substances present in soil, groundwater and dredge spoils may need to be processed, disposed of or otherwise managed to prevent releases into the environment. Tellurian or its affiliates may be responsible for the investigation, cleanup, monitoring, removal, disposal and other remedial actions with respect to hazardous substances on, in or under properties that Tellurian owns or operates, or released at a site where materials are disposed of from our operations, without regard to fault or the origin of such hazardous substances. Such liabilities may involve material costs that are unknown and not predictable.

Tellurian’s business will be subject to governmental laws, rules, regulations and permits that impose various restrictions and obligations that may have material effects on ourthe results of our operations.

We will face numerous risks in developing and conducting our operations. For example, the plan of operations for the proposed Driftwood Project is subject to the inherent risks associated with LNG, pipeline and upstream operations, including explosions, pollution, leakage or release of toxic substances, fires, hurricanes and other adverse weather conditions, leakage of hydrocarbons, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the proposed Driftwood Project or damage to persons and property. In addition, operations at the proposed Driftwood Project and vessels or facilities of third parties on which Tellurian’s operations are dependent could face possible risks associated with acts of aggression or terrorism.

In 2005, 2008 and 2017, hurricanes damaged coastal and inland areas located in the Gulf Coast area, resulting in disruption and damage to certain LNG terminals located in the area. 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 Driftwood terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Driftwood terminal or other facilities. Storms, disasters and accidents could also damage or interrupt the activities of vessels that we or third parties operate in connection with our LNG business. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels. If any such effects were to occur, they could have an adverse effect on our coastal operations.

Our LNG business will face other types of risks and liabilities as well. For instance, our LNG marketing activities will expose us to possible financial losses, including the risk of losses resulting from adverse changes in the index prices upon which contracts for the purchase and sale of LNG cargoes are based. Our LNG marketing activities will also be subject to various domestic and international regulatory and foreign currency risks.

Tellurian does not, nor does it intend to, maintain insurance against all of these risks and losses, and many risks are not insurable. Tellurian may not be able to maintain desired or required insurance in the future at rates that it considers reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on Tellurian’s business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We expect to pursue acquisitions of natural gas and oil properties from time to time. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include reserves, development potential, future commodity prices, operating costs, title issues, and potential environmental and other liabilities. Such assessments are inexact, and their accuracy is inherently uncertain. In connection with our assessments, we perform due diligence that we believe is generally consistent with industry practices.

However, our due diligence activities are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition, and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface, and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we may acquire acreage without any warranty of title except as to claims made by, through or under the transferor.

When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We may acquire interests in properties on an “as is” basis with limited or no remedies for breaches of representations and warranties.

Therefore, we could incur significant unknown liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks, and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire.

In addition, acquiring additional natural gas and oil properties, or businesses that own or operate such properties, when attractive opportunities arise is a significant component of our strategy, and we may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to pursue our overall strategy.

Historically, the markets for natural gas and oil have been volatile, and they are likely to continue to be volatile. Wide fluctuations in natural gas or oil prices may result from relatively minor changes in the supply of or demand for natural gas or oil, market uncertainty and other factors that are beyond our control. The volatility of the energy markets makes it extremely difficult to predict future natural gas or oil price movements, and we will be unable to fully hedge our exposure to natural gas or oil prices.

Our planned development and acquisition activities will require substantial capital expenditures. We intend to fund our capital expenditures for our natural gas and oil production activities through cash on hand and financing transactions that may include public or private equity or debt offerings or borrowings under additional debt agreements. We expect to generate only

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower natural gas or oil prices. These limitations and our dependence on the operator and third-party working interest owners for these projects could cause us to incur unexpected future costs, reduce our production and materially and adversely affect our financial condition and results of operations.

Natural gas and oil operations are subject to many risks, including well blowouts, explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, leakages or releases of hydrocarbons, severe

These risks could materially and adversely affect our revenues and expenses by reducing production from wells, causing wells to be shut in or otherwise negatively impacting our projected economic performance. If any of these risks occurs, we could sustain substantial losses as a result of:

Any of these events could expose us to liabilities, monetary penalties or interruptions in our business operations. In addition, certain of these risks are greater for us than for many of our competitors in that some of the natural gas we produce has a high sulphur content (sometimes referred to as “sour” gas), which increases its corrosiveness and the risk of an accidental release of hydrogen sulfide gas, exposure to which can be fatal. We may not maintain insurance against such risks, and some risks are not insurable. Even when we are insured, our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future, we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which we are not fully insured may expose us to liabilities.

Drilling for natural gas and oil may involve unprofitable efforts from wells that are productive but do not produce sufficient commercial quantities to cover drilling, operating and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons.

Our natural gas production activities and properties are (and to the extent that we acquire oil producing properties, these properties will be) subject to numerous federal, regional, state and local laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:

In addition, these laws and regulations may result in substantial liabilities for our failure to comply or for any contamination resulting from our operations, including the assessment of administrative, civil and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area.

Environmental laws and regulations change frequently, and these changes are difficult to predict or anticipate. Future environmental laws and regulations imposing further restrictions on the emission of pollutants into the air, discharges into state or U.S. waters, wastewater disposal and hydraulic fracturing, or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our natural gas or oil production. We cannot predict the actions that future regulation will require or prohibit, but our business and operations could be subject to increased operating and compliance costs if certain regulatory proposals are adopted. In addition, such regulations may have an adverse impact on our ability to develop and produce our reserves.

Several states are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. There are also certain governmental reviews either underway or being proposed that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. These studies assess, among other things, the risks of groundwater contamination and earthquakes caused by hydraulic fracturing and other exploration and production activities. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate or even ban such activities, as some state and local governments have already done. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions. Among other things, this could adversely affect the cost to produce natural gas, either by us or by third-party suppliers, and therefore LNG, and this could adversely affect the competitiveness of LNG relative to other sources of energy.

Our management team has identified certain well locations on our natural gas properties. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these factors, we do not know if the well locations we have identified will ever be drilled or if we will be able to produce natural gas from these or any other potential locations.

The demand for qualified and experienced field and technical personnel to conduct our operations can fluctuate significantly, often in correlation with hydrocarbon prices. The price of services and equipment may increase in the future and availability may decrease.

In addition, it is possible that oil prices could increase without a corresponding increase in natural gas prices, which could lead to increased demand and prices for equipment, facilities and personnel without an increase in the price at which we sell our natural gas to third parties. This could have an adverse effect on the competitiveness of the LNG produced from the Driftwood Project.terminal. In this scenario, necessary equipment, facilities and services may not be available to us at economical prices. Any shortages in availability or increased costs could delay us or cause us to incur significant additional expenditures, which could have a material adverse effect on the competitiveness of the natural gas we sell and therefore on our business, financial condition and results of operations.

Our natural gas and oil production activities will rely on third parties to meet our needs for midstream infrastructure and services. Capital constraints could limit the construction of new infrastructure by third parties. We may experience delays in producing and selling natural gas or oil from time to time when adequate midstream infrastructure and services are not available. Such an event could reduce our production or result in other adverse effects on our business.

We plan to develop, own and operate a global natural gas business and to deliver natural gas to customers worldwide. We may not be successful in executing our strategy in the near future, or at all. Our management will be required to understand and manage a diverse set of business opportunities, which may distract their focus and make it difficult to be successful in increasing value for shareholders.

Tellurian may engage in operations or make substantial commitments and investments, or enter into agreements with counterparties, located outside the U.S., which would expose Tellurian to political, governmental, and economic instability and foreign currency exchange rate fluctuations.

Any disruption caused by these factors could harm Tellurian’s business, results of operations, financial condition, liquidity and prospects. Risks associated with operations, commitments and investments outside of the U.S. include but are not limited to risks of:

Because Tellurian’s reporting currency is the U.S. dollar, any of the operations conducted outside the U.S. or denominated in foreign currencies would face additional risks of fluctuating currency values and exchange rates, hard currency shortages and controls on currency exchange. In addition, Tellurian would be subject to the impact of foreign currency fluctuations and exchange rate changes on its financial reports when translating the value of its assets, liabilities, revenues and expenses from operations outside of the U.S. into U.S. dollars at then-applicable exchange rates. These translations could result in changes to the results of operations from period to period.

Various state governments and regional organizations have considered enacting new legislation and promulgating new regulations governing or restricting the emission of GHGs, including GHG emissions from stationary sources such as oil and natural gas production equipment and facilities. At the federal level, the EPA has already made findings and issued regulations that will require us to establish and report an inventory of GHG emissions. Additional legislative and/or regulatory proposals for restricting GHG emissions or otherwise addressing climate change could require us to incur additional operating costs. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program. Even without federal legislation or regulation of GHG emissions, states may impose these requirements either directly or indirectly.

Some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as higher sea levels, increased frequency and severity of storms, droughts, floods, and other climatic events. If any such effects were to occur, they could adversely affect our facilities and operations, and have an adverse effect on our financial condition and results of operations. Further, adverse weather events may accelerate changes in law and regulations aimed at reducing GHG emissions, which could result in declining demand for natural gas and LNG, and could adversely affect our business generally.

Tellurian will be subject to extensive federal, state and local health and safety regulations and laws. Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, penalties for non-compliance with relevant laws and regulations or litigation, and a failure that results in a 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.

A terrorist or military incident could disrupt our business. For example, an incident involving an LNG carrier or LNG facility may result in delays in, or cancellation of, construction of new LNG facilities, including our proposed LNG facilities, which would increase Tellurian’sour costs and decrease itsour cash flows. A terrorist incident may also result in the temporary or permanent closure of Tellurian facilities or operations, which could increase costs and decrease cash flows, depending on the duration 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. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas or oil that could adversely affect Tellurian’s business and customers, including by impairing the ability of Tellurian’s suppliers or customers to satisfy their respective obligations under Tellurian’s commercial agreements.

We depend on digital technology in many aspects of our business, including the processing and recording of financial and operating data, analysis of information, and communications with our employees and third parties. Cyber-attacks on our systems and those of third partythird-party vendors and other counterparties occur frequently and have grown in sophistication. A successful cyber-attack on us or a vendor or other counterparty could have a variety of adverse consequences, including theft of proprietary or commercially sensitive information, data corruption, interruption in communications, disruptions to our existing or planned activities or transactions, and damage to third parties, any of which could have a material adverse impact on us. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks.

The success of Tellurian’s business relies heavily on key personnel such as its Chairman and Vice Chairman. Should such persons be unable to perform their duties on behalf of Tellurian, or should Tellurian be unable to retain or attract other members of management, Tellurian’s business, results of operations, financial condition, liquidity and prospects could be materially impacted.

Additionally, we are dependent upon an available labor pool of skilled employees. We will 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 to provide our customers with the highest quality service. A shortage of skilled workers or other general inflationary pressures or changes in applicable 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, or increases in the amounts we are obligated to pay our contractors, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.

Tellurian plans to operate in various aspects of the natural gas and oil business and will face intense competition in each area. Depending on the area of operations, competition may come from independent, technology-driven companies, large, established companies and others.

As another example, our business will face competition in, among other things, buying and selling reserves and leases and obtaining goods and services needed to operate properties and market natural gas and oil. Competitors include multinational oil companies, independent production companies and individual producers and operators.

Many of our competitors have longer operating histories, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than Tellurian currently possesses. The superior resources that some of these competitors have available for deployment could allow them to compete successfully against Tellurian, which could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.

None.

In July 2017, Tellurian Investments Inc. (now known as Tellurian Investments LLC), Driftwood LNG, LLC (“Driftwood LNG”), Martin Houston, and three other individuals were named as third-party defendants in a lawsuit filed in state court in Harris County, Texas between Cheniere Energy, Inc. and one of its affiliates, on the one hand (collectively, “Cheniere”), and Parallax Enterprises LLC and certain of its affiliates (not including Parallax Services LLC, now known as Tellurian Services LLC) on the other hand (collectively, “Parallax”). In October 2017, Driftwood Pipeline LLC (“Driftwood Pipeline”) and Tellurian Services LLC were also named by Cheniere as third-party defendants.defendants in the lawsuit. In April 2019, Charif Souki was also named by Cheniere allegesas a third-party defendant in the lawsuit. Cheniere alleged that it entered into a note and a pledge agreement with Parallax. Cheniere claimsclaimed, among other things, that the third-party defendants tortiously interfered with the note and pledge agreement and aided in the fraudulent transfer of Parallax assets. Cheniere is seekingsought unspecified amounts of monetary damages and certain equitable relief. We believe that Cheniere’s

In December 2019, Cheniere withdrew its claims against Tellurian Investments, Driftwood LNG, Driftwood Pipeline and Tellurian Services LLC are without merit and do not expect the resolutioneach of the suit to have a material effect onthree individuals other than Martin Houston named as third-party defendants in the lawsuit when it was first filed in July 2017. On January 30, 2020, Cheniere withdrew all claims it had asserted against our results of operation or financial condition. Trial has been set for June 2019.subsidiaries and directors, and all such claims were dismissed with prejudice.

Our common stock trades on the NASDAQ Capital Market (“NASDAQ”)Nasdaq under the symbol “TELL.” As of February 15, 2019,14, 2020, there were approximately 571693 record holders of Tellurian’s common stock. The Company does not intend to pay cash dividends on its common stock in the foreseeable future.

OnNone that occurred during the three months ended December 5, 2018, the Company issued 143,500 shares of its common stock, subject to certain vesting requirements, as consideration under a management consulting agreement for certain services.  The shares were issued in a private placement under Section 4(a)(2) of the Securities Act of 1933, as amended.     31, 2019.  

None.

The information contained in this Stock Performance Graph section shall not be deemed to be “soliciting material” or “filed” or incorporated by reference in future filings with the SEC, or subject to the liabilities of Section 18 of the Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act of 1933 or the Securities Exchange Act of 1934.

Shareholder returns over the indicated period are based on historical data and should not be considered indicative of future shareholder returns.