ITEM 1 AND 2. OUR BUSINESS AND PROPERTIES

Overview

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 planned natural gas production assets collectively as the “Driftwood Project”. We currently estimate the total cost of the Driftwood Project to be approximately $28 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 billion with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for construction of the Driftwood terminal.

The proposed Pipeline Network will 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-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 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 billion for the Permian Global Access Pipeline, in each case before owners’ costs, financing costs and contingencies.

Our current upstream properties, acquired in a series of transactions during 2017 and 2018, consist of 10,233 net acres and 52 producing wells (18 operated) located in the Haynesville Shale trend of north 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 partnership interests in a subsidiary, Driftwood Holdings LLC (“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 — Significant Transactions — LNG Marketing.”

2018 Developments

Significant Transactions

Public Equity Offerings. In connection with our equity offering in December 2017, the underwriters were granted an option to purchase up to an additional 1.5 million shares of common stock within 30 days. The option was exercised in full in January 2018, resulting in proceeds of approximately $14.5 million, net of approximately $0.5 million in fees and commissions.

In June 2018, we completed another offering in which we sold 12.0 million shares of common stock for proceeds of approximately $115.2 million, net of approximately $3.6 million in fees and commissions. The underwriters were granted an option to purchase up to an additional 1.8 million shares of common stock within 30 days, which was not exercised.

Preferred Stock Issuance. In March 2018, we entered into a preferred stock purchase agreement with BDC Oil and Gas Holdings, LLC (“Bechtel Holdings”), a Delaware limited liability company and an affiliate of Bechtel, pursuant to which we sold to Bechtel Holdings approximately 6.1 million shares of our Series C convertible preferred stock (the “Preferred Stock”). In exchange for the Preferred Stock, Bechtel agreed to discharge approximately $22.7 million of the outstanding liabilities associated with the detailed engineering services for the Driftwood Project, and to apply approximately $27.3 million to additional future

detailed engineering services. During the year ended December 31, 2018, all of the approximately $27.3 million of future services were received and, as such, all $50.0 million has been recognized on our Consolidated Balance Sheets within deferred engineering costs.

Term Loan. On September 28, 2018 (the “Closing Date”), we entered into a three-year senior secured term loan credit agreement (the “Term Loan”) in the principal amount of $60.0 million at a price of 99% of par, resulting in an original issue discount of $0.6 million. Fees of $2.6 million were capitalized as deferred financing costs. Use of proceeds from the Term Loan is predominantly restricted to capital expenditures associated with certain development and drilling activities and fees related to the transaction itself and are presented within non-current restricted cash on our Consolidated Balance Sheet. Amounts borrowed under the Term Loan bear interest at a variable rate (three-month LIBOR) plus an applicable margin. The applicable margin is 5% through the end of the first year following the Closing Date, 7% through the end of the second year following the Closing Date and 8% thereafter. If the Term Loan is terminated within 12 months of the Closing Date, an early termination fee equal to 1% of the outstanding principal is required.

LNG Marketing. In September 2017, we entered into a vessel charter that enabled us to execute a number of LNG purchase and sale opportunities, as well as sub-charter opportunities, that resulted in revenue of approximately $5.9 million for the year ended December 31, 2018.  We continue to implement our marketing strategy by looking for other LNG purchase, sale and vessel charter opportunities.

Regulatory Developments

Export Approval. In February 2017, the DOE/FE issued an order authorizing Tellurian to export 27.6 mtpa of LNG to FTA countries, on its own behalf and as agent for others, for a term of 30 years. Our application for authority to export LNG to non-FTA countries is currently pending before the DOE/FE and is expected to be ruled upon in the first half of 2019.

FERC Application. In March 2017, Tellurian filed an application with FERC for authorization pursuant to Section 3 of the NGA to site, construct and operate the Driftwood terminal, and simultaneously sought authorization pursuant to Section 7 of the NGA for authorization to construct and operate interstate natural gas pipeline facilities. In December 2017, FERC issued the notice of schedule for the environmental review of both the Driftwood terminal and the Driftwood pipeline. In September 2018, we received our draft environmental impact statement (“EIS”) from FERC for the Driftwood terminal and pipeline. We received our final EIS from FERC on January 18, 2019. Refer to Note 19, Subsequent Events to the Consolidated Financial Statements included in this report, for further details.

Environmental Permits. In March 2017, we submitted permit applications to the USACE under the Clean Water Act and the Rivers and Harbors Act for certain dredging and wetland mitigation activities relating to the Driftwood terminal and pipeline. Also in March 2017, we submitted Title V and PSD air permit applications to the Louisiana Department of Environmental Quality under the Clean Air Act for air emissions relating to the Driftwood terminal and pipeline, and the associated permits were granted in July 2018. In addition, in May 2018, we received a Coastal Use Permit from the Louisiana Department of Natural Resources for the Driftwood terminal, which approves the placement of dredged material from the marine berth for beneficial use inside the Louisiana coastal zone. The regulatory review and approval process for the USACE permit is expected to be completed in the first half of 2019.

Natural Gas Properties

Reserves

As discussed in “Our Business and Properties — Overview,” our upstream properties, acquired in a series of transactions during 2017 and 2018, consist of 10,233 net acres and 52 producing wells (18 operated) located in the Haynesville Shale trend of north Louisiana. For the year ended December 31, 2018, these wells had average net production of approximately 3.9 MMcf/d. All of our proved reserves as of December 31, 2018 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, 2018 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 for each month from January through December 2018. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The prices used were $3.10 per MMbtu 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:

The standardized measure of discounted future net cash flow from our proved reserves (the “standardized measure”) as of December 31, 2018 was $145.8 million .

As of December 31, 2018, we had no proved undeveloped reserves that had remained undeveloped for more than five years.

Capital expenditures totaled approximately $17.1 million during 2018. We invested approximately $12.8 million during 2018 developing proved reserves and approximately $4.3 million on wells still in progress at year end.  During the year ended December 31, 2018, we converted approximately 9 Bcfe of proved undeveloped reserves to proved developed reserves.

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

Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used

Our December 31, 2018 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 provide to them. This information is reviewed by knowledgeable members of our Company for accuracy and completeness prior to submission to NSAI.

A letter which identifies the professional qualifications of the individual at NSAI who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2018, has been filed as an addendum to Exhibit 99.2 to this report and is incorporated by reference herein.

Internally, a Senior Vice President is responsible for overseeing our reserves process. Our Senior Vice President has over 17 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.

Production

For the years ended December 31, 2018 and 2017, we produced 1,399 MMcf and 190 MMcf of natural gas at an average sales price of $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, 2018 and 2017, were $1.71 and $1.25 per MMcfe, respectively.

Drilling Activity

As of December 31, 2018, we were in the process of drilling or completing operations on one operated well 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.

Wells and Acreage

As of December 31, 2018, we owned interests in 37 gross (18 net) productive natural gas wells and held by production 10,503 gross (9,074 net) developed leasehold acreage. Additionally, we hold 1,180 gross (1,159 net) undeveloped leasehold acreage. The majority of the undeveloped leasehold acreage is set to expire in 2020 based on two year contractual extensions granted in 2018, with 111 gross and net acres set to expire in 2019. As of December 31, 2018, there were 10 gross (4 net) in process wells.

Volume Commitments

We are not currently subject to any material volume commitments.

Gathering, Processing and Transportation

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.

Government Regulations

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”), 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 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 FERC, the U.S. Environmental Protection Agency (the “EPA”), the DOE/FE, the U.S. Department of Transportation (“DOT”), 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”) 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.

Federal Energy Regulatory Commission

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 obtain authorizations from FERC under Section 3 of the NGA as well as several other material governmental and regulatory approvals and permits. The EPAct 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, nothing in the EPAct 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 over 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 natural gas pipelines. Although the EPAct 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.

FERC has authority to approve, and if necessary set, “just and reasonable rates” 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 and the provision of services. 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 use and to natural gas companies engaged in such transportation or sale. FERC’s jurisdiction does not extend to the production, gathering, local distribution or export of natural gas.

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

The EPAct amends 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 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.

U.S. Department of Energy, Office of Fossil Energy Export License

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 Canada, Chile, Colombia, Jordan, Mexico, Singapore, South Korea and the Dominican Republic. Exports of natural gas to non-FTA countries are authorized unless the DOE/FE finds that the proposed exportation “will not be consistent with the public interest.”

Pipeline and Hazardous Materials Safety Administration

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 to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline, as necessary; and implement preventive and mitigation actions.

In April 2016, PHMSA issued a notice of proposed rulemaking addressing changes to the regulations governing the safety of gas transmission pipelines. Specifically, PHMSA is considering certain integrity management requirements for “moderate consequence areas,” requiring an integrity verification process for specific categories of pipelines, and mandating more explicit requirements for the integration of data from integrity assessments to an operator’s compliance procedures. 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.

Natural Gas Pipeline Safety Act of 1968

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.

Other Governmental Permits, Approvals and Authorizations

The construction and operation of the Driftwood Project will be 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.

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 Act Title V Operating Permit and the PSD Permit, of which the latter two permits are issued by the Louisiana Department of Environmental Quality. The Driftwood Project will also have to comply with the requirements of NEPA.

Environmental Regulation

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.

Clean Air Act. The CAA and comparable state laws and regulations regulate and restrict the emission of air pollutants from many sources and impose various monitoring and reporting requirements, among other requirements. The Driftwood Project is subject to the federal CAA and comparable state and local laws. We may be required to incur capital expenditures for air pollution control equipment in connection with maintaining or obtaining permits and approvals pursuant to the CAA and comparable state laws and regulations.

Greenhouse Gases. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of GHGs are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources, including LNG terminals.

In the past, Congress has considered proposed legislation to reduce emissions of GHGs. Congress has not adopted any significant legislation in this respect to date, but could do so in the future. In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.

The EPA issued the Clean Power Plan in 2015, which would have required existing power plants to reduce their carbon dioxide emissions. The Supreme Court stayed implementation of the Clean Power Plan in February 2016. In October 2017, the EPA proposed to repeal the Clean Power Plan. The comment period on the proposed rule closed on April 26, 2018. On August 21, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule, which would establish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACE would replace the Clean Power Plan.

The Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26-28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020. In June 2017, President Trump announced that the U.S. would initiate the formal process to withdraw from the Paris Agreement.

Coastal Zone Management Act. The siting and construction of the Driftwood terminal within the coastal zone may be subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act. The Driftwood Project is subject to the CWA and analogous state and local laws. The CWA and analogous state and local laws regulate discharges of pollutants to waters of the U.S. or waters of the state, including discharges of wastewater and storm water runoff and discharges of dredged or fill material into waters of the U.S., as well as spill prevention, control and countermeasure requirements. Permits must be obtained prior to discharging pollutants into state and federal waters or dredging or filling wetland and coastal areas. The CWA is administered by the EPA, the USACE and by the states. Additionally, the siting and construction of the Driftwood Project may potentially impact jurisdictional wetlands, which would require appropriate federal, state and/or local permits and approval prior to impacting such wetlands. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for regulated impacts to wetlands. The approval timeframe may also be longer than expected and could potentially affect project schedules.

In June 2015, the EPA issued a final rule that attempts to clarify the CWA’s jurisdictional reach over waters of the U.S. 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 2018 rule that attempted to delay the applicability date of the 2015 Clean Water Rule. Other district courts, however, have issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself. Taken together, the 2015 Clean Water Rule is currently in effect in 23 states, and temporarily stayed in the remaining states. In those remaining states, the 1986 rule and guidance remain in effect. On December 11, 2018, the EPA and the USACE issued a proposed new 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. According to the agencies, the proposed new rule is “intended to increase CWA program predictability and consistency by increasing clarity as to the scope of ‘waters of the United States’ federally regulated under the Act.” If finalized, this new definition of “waters of the United States” 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 expand the scope of the CWA’s jurisdiction, which could result in increased costs and delays with respect to obtaining permits for discharges or pollutants or dredge and fill activities in waters of the U.S., including wetland areas.

Resource Conservation and Recovery Act. The federal RCRA and comparable state requirements govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. In the event such wastes are generated or used in connection with our facilities, we will be subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes and could be required to perform corrective action measures to clean up releases of such wastes. The EPA and certain environmental groups have entered into an agreement pursuant to which the EPA is required to propose, no later than March 15, 2019, a rulemaking for revision of certain regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the EPA will be required to take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the exclusion from RCRA coverage for drilling fluids, produced waters and related wastes could result in a significant increase in our costs to manage and dispose of waste associated with our production operations.

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 Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”). CERCLA, often referred to as Superfund, and comparable state statutes, impose liability that is generally joint and several and that is retroactive for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a “hazardous substance” (or under state law, other specified substances) into the environment. So-called potentially responsible parties (“PRPs”) include the current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the cost of such action. Liability can arise from conditions on properties where operations are conducted, even under circumstances where such operations were performed by third parties and/or from conditions at disposal facilities where materials from operations were sent. Although CERCLA currently exempts petroleum (including oil and natural gas) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. We cannot ensure that this exemption will be preserved in any future amendments of the act. Such amendments could have a material impact on our costs or operations. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA or regulated under similar state statutes. We may also be the owner or operator of sites on which hazardous substances have been released and may be responsible for investigation, management and disposal of contaminated soils or dredge spoils in connection with our operations.

Oil and natural gas exploration and production, and possibly other activities, have been conducted at a majority 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 acquired reserves against certain liabilities for environmental claims associated with the properties.

Hydraulic Fracturing. Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We plan to use hydraulic fracturing extensively in our natural gas production operations. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations which are held open by the grains of sand, enabling the natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and natural gas commissions but is also subject to new and changing regulatory programs at the federal, state and local levels.

Beginning in 2012, the EPA implemented CAA standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to new and modified hydraulically fractured natural gas wells and certain storage vessels. The standards require, among other things, use of reduced emission completions, or “green” completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators.

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 by the EPA.

In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act 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.

The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017; however, the BLM’s rescission has been challenged by several states in the U.S. District Court of the District of Northern California.

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.

In June 2016, the EPA finalized additional new source performance standards under the CAA to reduce methane emissions from new and modified sources in the oil and natural gas sector. These new regulations impose, among other things, new requirements for leak detection and repair, control requirements at oil well completions, and additional control requirements for gathering, boosting, and compressor stations. On September 11, 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations.

In November 2016, the BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. On September 28, 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detection and repair. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California.

In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources.” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. In addition, the U.S. Department of Energy has investigated practices that the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These and similar studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms .

Endangered Species Act (“ESA”). Our operations may be restricted by requirements under the ESA. The ESA prohibits the harassment, harming or killing of certain protected species and destruction of protected habitats. Under the NEPA review process conducted by FERC, we will be required to consult with federal agencies to determine limitations on and mitigation measures applicable to activities that have the potential to result in harm to threatened or endangered species of plants, animals, fish and their designated habitats.

Regulation of Natural Gas Production

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.

Anti-Corruption Laws

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, 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 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.

Competition

We are subject to a high degree of competition in all aspects of our business. See “Item 1A — Risk Factors — Risks Relating to Our Business in General — Competition is intense in the energy industry and some of Tellurian’s competitors have greater financial, technological and other resources. ”

Production & Transportation. The natural gas and oil business is highly competitive in the exploration for and acquisition of reserves, the acquisition of natural gas and oil leases, equipment and personnel required to develop and produce reserves, and the gathering, transportation and marketing of natural gas and oil. Our competitors include national oil companies, major integrated natural gas and oil companies, other independent natural gas and oil companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers, such as operators of pipelines and other midstream facilities. Many of our competitors have longer operating histories, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we currently possess.

Liquefaction. The Driftwood terminal will compete with liquefaction facilities worldwide to supply low-cost liquefaction to the market. There are a number of liquefaction facilities worldwide that we compete with for customers. Many of the companies with which we compete have greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we do.

LNG Marketing. Tellurian competes with a variety of companies in the global LNG market, including (i) integrated energy companies that market LNG from their own liquefaction facilities, (ii) trading houses and aggregators with LNG supply portfolios, and (iii) liquefaction plant operators that market equity volumes. Many of the companies with which we compete have greater name recognition, larger staffs, greater access to the LNG market and substantially greater financial, technical, and marketing resources than we do.

Title to Properties

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 believe that we hold good title to our other properties, subject to customary burdens, liens, or encumbrances that we do not expect to materially interfere with our use of the properties.

Major Customers

We do not have any major customers.

Facilities

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, eight and 10 years for Singapore, London, Houston and Washington, D.C., respectively.

Employees

As of December 31, 2018, Tellurian had 172 full-time employees worldwide, none of whom are subject to collective bargaining arrangements.

Jurisdiction and Year of Formation

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

Available Information

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.