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 related pipelines (the “Pipeline Network”). We refer to the Driftwood terminal, the Pipeline Network and required natural gas production assets collectively as the “Driftwood Project.” Our existing natural gas production assets consist of 9,373 net acres and interests in 72 producing wells located in the Haynesville Shale trend of northern Louisiana. Our Business may be developed in phases.
In connection with the implementation of our Business, we are offering partnership interests in the Driftwood Project. Partners will contribute cash in exchange for equity in the Driftwood Project 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 the Driftwood Project and have engaged Goldman Sachs & Co. and Société Générale to serve as financial advisors.
We continue to evaluate, and discuss with potential partners, the scope and other aspects of the Driftwood Project in light of the evolving economic environment, needs of potential partners and other factors. Whether we implement changes to the project will be based on a variety of factors, including the results of our continuing analysis, changing business conditions and investor feedback.
Overview of Significant Events
2019 Term Loan
On May 23, 2019, Driftwood Holdings LP, a Delaware limited partnership and an indirect wholly owned subsidiary of Tellurian Inc. (“Driftwood Holdings”), entered into a senior secured term loan agreement (the “2019 Term Loan”) to borrow an aggregate principal amount of $60.0 million, an amount that was subsequently increased to $75.0 million. In conjunction with the 2019 Term Loan, we issued to the lender a warrant to purchase approximately 1.5 million shares of our common stock at $10.00 per share. During 2020, we entered into several amendments to the 2019 Term Loan and, in connection with those amendments, we issued to the lender a total of approximately 9.3 million shares of our common stock to retire $15.0 million of principal amount of the loan, repaid $19.1 million of principal amount of the loan in cash, replaced the original warrant with a warrant to purchase 9.0 million shares of our common stock at $1.00 per share and issued to the lender a new warrant to purchase 4.7 million shares of our common stock at $1.542 per share.
As amended, (i) the maturity date of the 2019 Term Loan is March 23, 2022, (ii) amounts borrowed bear interest at 16%, with an option on our part to defer 8% per annum as paid-in-kind, (iii) interest payments are made on a monthly basis, and (iv) we are required to maintain a month-end cash balance of at least $12.0 million. Following exercises of the warrants by the lender and reductions in the number of shares purchasable under the warrants resulting from partial repayments of amounts due under the 2019 Term Loan, the warrants give the lender the right, as of February 9, 2021, to purchase approximately 3.5 million shares of our common stock for $1.00 and approximately 0.2 million shares of our common stock for $1.542.
2020 Unsecured Note
On April 29, 2020, we issued a zero coupon $56.0 million senior unsecured note (the “2020 Unsecured Note”) to a third party, raising proceeds of approximately $47.4 million, net of approximately $2.6 million in fees and $6.0 million in original issue discount. We also issued to the lender a warrant to purchase 20.0 million shares of our common stock at a strike price of $1.542 per share. The 2020 Unsecured Note is subject to certain cash sweep provisions, and a portion of the 2020 Unsecured Note must be paid on the first day of every month, beginning on June 1, 2020. Due to the amount of proceeds generated from the sale of our common stock under our at-the-market program in June 2020, as well as the equity offering completed on July 24, 2020, these cash sweep provisions were triggered on July 1, 2020 and August 3, 2020, requiring us to make a total of $8.0 million in additional repayments of the outstanding principal balance. As a result of these additional repayments, the final payment associated with the 2020 Unsecured Note is scheduled to occur on April 1, 2021 instead of June 1, 2021 as originally scheduled.
Equity Offering
On July 24, 2020, we completed a registered direct offering pursuant to which we sold an aggregate of 35.0 million shares of our common stock at an offering price of $1.00 per share. Net proceeds from the transaction were approximately $32.8 million.
LNG Marketing
In July 2020, we purchased the first cargo of LNG pursuant to the master LNG sale and purchase agreement entered into on April 23, 2019. This cargo was subsequently sold to an unrelated third party, resulting in revenue of approximately $7.0 million.
Restructuring
In March 2020, we implemented a cost reduction and reorganization plan due to the sharp decline in oil and natural gas prices as well as the growing negative economic effects of the COVID-19 pandemic. We incurred approximately $6.4 million of severance and reorganization charges due to the reduction in workforce. We have satisfied all amounts owed to former employees.
Employee Retention Plan
In July 2020, the Company’s Board of Directors approved an employee retention incentive plan (the “Employee Retention Plan”) aggregating $12.0 million. The Employee Retention Plan vests in four equal installments upon the attainment of a ten-day average closing price of the Company’s common stock above $2.25, $3.25, $4.25 and $5.25 (the “Stock Performance Targets”). Subject to continued employment, the Employee Retention Plan’s awards are payable over a period of twelve months commencing with the later of (i) the first month following the month in which the applicable Stock Performance Target is attained, and (ii) June 2021. The Employee Retention Plan will expire if the Stock Performance Targets are not attained by March 31, 2022.
Natural Gas Properties
Reserves
Our natural gas production assets, acquired in a series of transactions during 2017 and 2018, consist of 9,373 net acres and interests in 72 producing wells located in the Haynesville Shale trend of north Louisiana. For the year ended December 31, 2020, these wells had average net production of approximately 46.2 MMcf/d. All of our proved reserves as of December 31, 2020 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, 2020 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 2020. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The price used was $1.99 per MMBtu of natural gas, adjusted for energy content, transportation fees and market differentials.
The following table shows our proved reserves as of December 31, 2020:
The standardized measure of discounted future net cash flow from our proved reserves (the “standardized measure”) as of December 31, 2020 was $6.9 million.
During the year ended December 31, 2020, we did not have any material capital expenditures related to the development of our undeveloped reserves and thus did not convert any meaningful quantities from proved undeveloped to proved developed reserves. As of December 31, 2020, we do not expect to have any proved undeveloped reserves that will remain undeveloped for more than five years from the date that they were initially booked.
Refer to Supplemental Disclosures About Natural Gas Producing Activities, starting on page 58, for additional details.
Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used
Our December 31, 2020 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 provided to them. This information was 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, 2020, 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 19 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, 2020, 2019 and 2018, we produced 16,893 MMcf, 13,901 MMcf and 1,399 MMcf of natural gas at an average sales price of $1.74, $2.07 and $2.97 per MMcf, respectively. Natural gas and condensate production and operating costs for the periods ended December 31, 2020, 2019 and 2018 were $0.28, $0.25 and $1.71 per MMcfe, respectively.
Drilling Activity
The table below represents the number of net productive and dry development wells drilled during the past three years:
Wells and Acreage
As of December 31, 2020, we owned working interests in 52 gross (21 net) productive natural gas wells and held by production 3,295 gross (3,026 net) developed leasehold acres. Additionally, we hold 6,765 gross (6,347 net) undeveloped leasehold acres. As of December 31, 2020, there were no in process wells.
Of the total gross and net undeveloped acreage, 246 gross and 246 net acres are not held by production, of which 136 gross and 136 net acres are set to expire in 2021. We plan to extend the terms of these leases either through operational or administrative actions.
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 (“EPAct 2005”), the Oil Pollution Act, the National Environmental Policy 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”), DOE/FE, the U.S. Department of Transportation (“DOT”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the Louisiana Department of Environmental Quality and the Louisiana Department of Natural Resources. 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 Service, 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, 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.
We have received regulatory permits and approvals in connection with the Driftwood terminal and Driftwood pipeline, including the following:
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 obtained authorizations from FERC under Section 3 and Section 7 of the NGA as well as several other material governmental and regulatory approvals and permits as detailed in the table above. In order to gain regulatory certainty with respect to certain potential commercial transactions, on November 13, 2020, Driftwood Holdings and Driftwood LNG LLC (jointly, “Driftwood”) filed a Petition with FERC requesting, among other things, a prospective limited waiver of FERC’s buy/sell prohibition as well as any other prospective waivers necessary to enable Driftwood to purchase natural gas from potentially
affiliated upstream suppliers that may be resold to a different affiliate under a long-term contract for export as LNG in foreign commerce. On January 19, 2021, FERC issued an order granting a prospective limited waiver of the prohibition on buy/sell arrangements for future proposed transactions in which Driftwood enters into: (1) an agreement to purchase natural gas from a potentially affiliated supplier; or (2) an agreement to sell LNG to affiliates in foreign commerce.
Federal Energy Regulatory Commission
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 EPAct 2005, nothing in the statute 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 to 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 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 terminal operations.
A certificate of public convenience and necessity from FERC is required for the construction and operation of facilities 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 Driftwood pipeline.
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:
•rates and charges for natural gas transportation and related services;
•the certification and construction of new facilities;
•the extension and abandonment of services and facilities;
•the maintenance of accounts and records;
•the acquisition and disposition of facilities;
•the initiation and discontinuation of services; and
•various other matters.
In addition, FERC has the 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.
EPAct 2005 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. 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.
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 but are not limited to 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.” 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 through December 31, 2050.
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 mitigative actions.
On December 27, 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act (PIPES Act) of 2020 was signed into law as part of the Consolidated Appropriations Act of 2021. The legislation reauthorizes the PHMSA pipeline safety program through fiscal year 2023 and provides for advances to improve pipeline safety. The legislation includes a directive to PHMSA to update its current regulations for large-scale LNG facilities.
On January 11, 2021, PHMSA published a final rule in the Federal Register amending the Federal Pipeline Safety Regulations to reduce regulatory burdens and offer greater flexibility with respect to the construction, maintenance, and operation of gas transmission, distribution, and gathering pipeline systems, including updates to corrosion control requirements and test requirements for pressure vessels. Pipeline operators may voluntarily comply with the rule starting on the effective date of March 12, 2021, but mandatory compliance is not required until October 1, 2021. This rule is subject to review for possible modification pursuant to executive orders signed by President Biden on or shortly after January 20, 2021.
The Pipeline Network will be subject to regulation under PHMSA, which will involve capital and operating costs for compliance-related equipment and operations. We have no reason to believe that these compliance costs will be material to our financial performance, but the significance of such costs will depend on future events and our ability to achieve and maintain compliance throughout the life of the Driftwood Project.
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 terminal and Driftwood pipeline are subject to 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 Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the EPA and the U.S. Department of Homeland Security. The necessary permits required for construction have been obtained and will be maintained 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 apply to the Driftwood terminal and Driftwood pipeline are the USACE Section 404 of the CWA/Section 10 of the Rivers and Harbors Act Permit, the CAA Title V Operating Permit and the Prevention of Significant Deterioration Permit, of which the latter two permits are issued by the Louisiana Department of Environmental Quality. Each of the Driftwood terminal 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 and Driftwood pipeline pursuant to 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.
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. 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.
The Biden Administration has issued a number of executive orders that direct federal agencies to take actions that may change regulations and guidance applicable to our business.
Executive Order 14008, “Tackling the Climate Crisis at Home and Abroad,” 86 FR 7619 (January 27, 2021), establishes a policy “promoting the flow of capital toward climate-aligned investments and away from high-carbon investments.” It also requires the heads of agencies to identify any fossil fuel subsidies provided by their respective agencies, and to seek to eliminate fossil fuel subsidies from the budget request for fiscal year 2022 and thereafter.
Executive Order 13990, “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,” 86 FR 7037 (January 20, 2021) directs agencies to review regulations and policies adopted by the Trump Administration and to “confront the climate crisis.” It specifically directs the EPA to consider suspending, revising or rescinding certain regulations, including restrictions on emissions from the oil and gas sector. In addition, Executive Order 13990 establishes a federal inter-agency working group to recommend methods for agencies to incorporate the “social cost of carbon” into their decision making. Finally, Executive Order 13990 directs the White House Council on Environmental Quality to rescind draft guidance restricting the review of climate change issues in reviews under the NEPA and to update regulations to strengthen climate change reviews.
Regulatory Freeze Pending Review. A White House Memorandum issued on January 20, 2021, entitled “Regulatory Freeze Pending Review,” requires all federal departments and agencies to withdraw any final rules that have not yet been published, and to consider postponing the effective dates of any rules published in the Federal Register that have not yet taken effect.
NEPA. NEPA and comparable state laws and regulations require that government agencies review the environmental impacts of proposed projects. On July 16, 2020, the White House Council on Environmental Quality published a final rule to “modernize and clarify” the prior NEPA implementation regulations and to streamline environmental reviews required by NEPA (the “Revised NEPA Regulations”). The Revised NEPA Regulations set a presumptive time limit for completion of NEPA reviews and limit the scope of NEPA reviews to those effects that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives. While these changes are not likely to require amendments to the USACE permits and NEPA-related findings that were completed prior to the effective date of the final NEPA rule, the changes in the NEPA regulations may impact new permits, permit modifications and other elements of the Driftwood Project that are under development. The Revised NEPA Regulations are currently subject to legal challenges. In addition, changes to policies and regulations may occur as a result of Executive Order 13990. Therefore, the impact on the Driftwood Project of the previously Revised NEPA Regulations and new NEPA regulations and guidance will not be determinable for the foreseeable future.
CAA. The CAA and comparable state laws and regulations restrict the emission of air pollutants from many sources and impose various monitoring and reporting requirements, among other requirements. The Driftwood Project includes facilities and operations that are subject to the federal CAA and comparable state and local laws, including requirements to obtain pre-construction permits and operating permits. 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.
In August 2020, the EPA issued two final rules that revised the new source performance standards under the CAA (the “2020 CAA Revisions”) to require reductions in emissions, including methane emissions, from new and modified sources in the oil and natural gas sector. The 2020 CAA Revisions addressed certain technical issues raised in administrative petitions and included proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and
compressor stations. The 2020 CAA Revisions also removed all emissions sources in the compressor stations, pneumatic controllers and underground storage vessels from regulation. The rules became effective on October 13, 2020. The 2020 CAA Revisions are currently subject to legal challenges. In addition, President Biden has specifically required the EPA to review the 2020 rules for possible rescission or modification. Therefore, the impact of the revised oil and gas new source performance standards on the Driftwood Project and Tellurian’s compliance obligations are not determinable at this time.
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 June 2019, the EPA issued the final Affordable Clean Energy rule, which, among other things, establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The Affordable Clean Energy rule was subject to legal challenges and, in January 2021, the U.S. Court of Appeals for the District of Columbia Circuit vacated the rule and remanded the rule to the EPA for revision or replacement.
The Biden Administration has communicated its intention to address climate change and has issued Executive Orders with respect to certain governmental actions related to climate change. In the future, the EPA may promulgate additional regulations for sources of GHG emissions that could affect the oil and gas sector, and Congress or states may enact new GHG legislation, either of which could impose emission limits on the Driftwood Project or require the Driftwood Project to implement additional pollution control technologies, pay fees related to GHG emissions or implement mitigation measures. The scope and effects of any new laws or regulations are difficult to predict, and the impact of such laws or regulations on the Driftwood Project cannot be predicted at this time.
Coastal Zone Management Act. Certain aspects of the Driftwood terminal are 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. Certain facilities that are part of the Driftwood Project obtained permits for construction and operation in coastal areas pursuant to the requirements of the CZMA.
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 United States or waters of the state, including discharges of wastewater and storm water runoff and discharges of dredged or fill material into waters of the United States, 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 terminal and Driftwood pipeline will 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. Although the CWA permits required for construction and operation of the Driftwood terminal and Driftwood pipeline have been obtained, other CWA permits may be required in connection with our projects that are under development and our future projects. The approval timeframe may also be longer than expected and could potentially affect project schedules.
In April 2020, the EPA and the USACE finalized a rule revising and narrowing the definition of “waters of the United States” and replacing prior rules defining the same issued in 1986 and 2015 (the “2020 Rule”). The 2020 Rule could reduce costs and delays with respect to obtaining permits for discharges of pollutants or dredge and fill activities in waters of the United States including in wetland areas for facilities of the Driftwood terminal and Driftwood pipeline that have not yet obtained CWA permits. The 2020 Rule is currently subject to legal challenges. Changes in the definition of “waters of the United States” are not likely to affect the permits already obtained for the Driftwood terminal and Driftwood pipeline, but further changes to the 2020 Rule or any judicial decisions that require modification to the 2020 Rule could affect other elements of the Driftwood terminal and Driftwood pipeline in ways that cannot be predicted at this time.
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.
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 entered into an agreement pursuant to which the EPA was required to propose, no later than March 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. In April 2019, the EPA determined that revision of the regulations is not necessary. Information comprising the EPA’s review and the decision is contained in a document entitled “Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action.” The EPA indicated that it would continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels. A loss of the exclusion from RCRA coverage for drilling fluids, produced waters and related wastes in the future could result in a significant increase in our costs to manage and dispose of waste associated with our production operations.
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, 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, or transported 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 were sent. Our operations involve the use or handling of materials that include or 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 the investigation, management and disposal of soils or dredge spoils containing hazardous substances in connection with our operations.
Oil and natural gas exploration and production, and possibly other activities, have been conducted at some 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. Accordingly, the Driftwood Project could incur material costs for remediation required under CERCLA or similar state statutes in the future.
Hydraulic Fracturing. Hydraulic fracturing is commonly used to stimulate the 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.
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 related to the 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. If the EPA regulates hydraulic fracturing fluid under TSCA in the future, such regulation may increase the cost of our gas production operations and the feedstock for the Driftwood terminal.
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. Certain activities of our Business are subject to the pretreatment
standards, which means that we are required to use disposal methods that may require additional permits or cost more to implement than disposal at publicly-owned treatment works.
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 in the United States.” 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. If the EPA proposes additional regulations of hydraulic fracturing in the future, they could impose additional emission limits and pollution control technology requirements on the Driftwood Project, which could limit our operations and revenues and potentially increase our costs of gas production or acquisition.
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 have been and 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. Although we have conducted studies and engaged in consultations with agencies in order to avoid harming protected species, inadvertent or incidental harm may occur in connection with the construction or operation of the Driftwood Project, which could result in fines or penalties. In addition, if threatened or endangered species are found on any part of the Driftwood Project sites, including pipeline rights of way, then we may be required to implement avoidance or mitigation measures that could limit our operations or impose additional costs.
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:
•the location of new wells;
•the method of drilling, completing and operating wells;
•the surface use and restoration of properties upon which wells are drilled;
•the plugging and abandoning of wells;
•notice to surface owners and other third parties; and
•produced water and waste disposal.
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
We 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 agents from authorizing, offering, or providing improper payments or anything else of value to foreign government officials or other covered persons to obtain or retain business or gain an improper business advantage. We face the risk that one of our employees or agents will offer, authorize, or provide something of value that could subject us to liability under the FCPA and 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. U.S. or foreign authorities may also seek to hold us liable for successor liability for FCPA violations committed by companies we acquire or in which we invest (for example, by way of acquiring equity interests, participating as a joint venture partner, or acquiring assets).
Competition
We are subject to a high degree of competition in all aspects of our business. See “Item 1A
ITEM 1A. RISK FACTORS
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:
•Risks Relating to Financial Matters;
•Risks Relating to Our Common Stock;
•Risks Relating to Our LNG Business;
•Risks Relating to Our Natural Gas and Oil Production Activities; and
•Risks Relating to Our Business in General.
Risks Relating to Financial Matters
Tellurian will be required to seek additional equity and/or debt financing in the future to complete the Driftwood Project and to grow its other operations, and may not be able to secure such financing on acceptable terms, or at all.
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 businesses. Tellurian will, therefore, need substantial amounts of additional financing to execute its business plan and to repay its indebtedness when necessary. 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 opportunities, and this could adversely affect its operations and financial condition to a significant extent. Tellurian intends to pursue a variety of potential financing transactions, including sales of equity of Driftwood Holdings to purchasers of its LNG. We do not know whether, and to what extent, LNG purchasers and other potential sources of financing will find the terms we propose acceptable.
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. 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.
Pandemics or disease outbreaks, such as the currently ongoing COVID-19 outbreak, may adversely affect our efforts to reach a final investment decision with respect to the Driftwood Project.
Pandemics or disease outbreaks such as the currently ongoing COVID-19 outbreak may have a variety of adverse effects on our business, including by depressing commodity prices and the market value of our securities and limiting the ability of our management to travel to meet with partners and potential partners. Prospects for the development and financing of the Driftwood Project are based in part on factors including global economic conditions that have been, and are likely to continue to be, adversely affected by the COVID-19 pandemic. Additional effects of the pandemic on our business may include limits on the ability of our employees, or those of partners or vendors, to provide necessary services due to illness or quarantines and governmental restrictions on travel, imports or exports or financial transactions.
The ultimate impact of the COVID-19 pandemic on our business, results of operations, financial condition and cash flows is dependent on future developments, including the severity and duration of the pandemic, actions that have been and may be taken by governmental authorities, the impact on the businesses of our customers, and the duration of the resulting macroeconomic conditions, all of which are uncertain and are difficult to predict at this time.
We have a limited operating history and expect to incur losses for a significant period of time.
We 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 2021 and thereafter, and expects to continue to incur operating losses and to experience negative operating cash flows for the next several years.
Tellurian’s exposure to the performance and credit risks of its counterparties may adversely affect its operating results, liquidity and access to financing.
Our operations involve our entering into various construction, purchase and sale, hedging, supply and other transactions with numerous third parties. In such arrangements, we will be exposed to the performance and credit risks of our counterparties, including the risk that one or more counterparties fail to perform their obligations under the applicable agreement. Some of these risks may increase during periods of commodity price volatility. In some cases, we will be dependent on a single counterparty or a small group of counterparties, all of whom may be similarly affected by changes in economic and other conditions. These risks include, but are not limited to, risks related to the construction of the Driftwood terminal discussed below in “ - Risks Relating to Our LNG Business - Tellurian will be dependent on third-party contractors for the successful completion of the Driftwood terminal, and these contractors may be unable to complete the Driftwood terminal.” Defaults by suppliers and other counterparties may adversely affect our operating results, liquidity and access to financing.
Our use of hedging arrangements may adversely affect our future operating results or liquidity.
As we continue to develop 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. 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.
Changes in tax laws or exposure to additional income tax liabilities could have a material impact on our financial condition, results of operations and liquidity.
Factors that could materially affect our future effective tax rates include but are not limited to:
•changes in the regulatory environment;
•changes in accounting and tax standards or practices;
•changes in U.S., state or foreign tax laws;
•changes in the composition of operating income by tax jurisdiction; and
•our operating results before taxes.
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 does not expect to generate sufficient cash to pay dividends until the completion of construction of the Driftwood Project.
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.
We may be unable to fulfill our obligations under our debt agreements.
We and certain of our subsidiaries have borrowed funds pursuant to agreements described in Note 9, Borrowings, of our Notes to Consolidated Financial Statements included in this report. Our ability to generate cash flows from operations or obtain refinancing capital sufficient to pay interest and principal on our indebtedness will depend on our future operating performance and financial condition and the availability of refinancing 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 our control. We do not currently have any material sources of operating cash flows. Our inability 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 debt or equity capital to satisfy the requirements of the debt agreements. These alternative measures may be unavailable or inadequate, in which case we could be forced into bankruptcy or liquidation, and may themselves adversely affect our overall business strategy.
Restrictions in our debt agreements could limit our growth and operations.
Our debt agreements contain restrictions on our activities, certain of which are described in Note 9, Borrowings, of our Notes to Consolidated Financial Statements included in this report.
These covenants may prevent us from taking actions that we believe would be in the best interest of our business and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. For example, the credit agreement to which Tellurian Production Holdings LLC (“Production Holdings”) is subject requires it to maintain a commodity hedge position that covers at least a specified minimum, but does not cover more than a specified maximum, of its anticipated future production, and these requirements may limit its ability to pursue its preferred hedging strategy. In addition, the entire amount of that loan is currently deemed to be outstanding, but Production Holdings is generally prohibited from using the borrowed funds except pursuant to a specified plan of development approved by the lenders. Accordingly, there could be circumstances in which Production Holdings is required to incur interest on funds borrowed but is unable to use those funds in the way it believes is most appropriate for its business.
If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under one or more of those agreements, which could result in an acceleration of amounts due under those agreements.
Our debt agreements contain financial and other covenants. If we are unable to satisfy certain covenants, we would be in default under the applicable 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 our assets. We may not have sufficient funds, or the ability to obtain sufficient funds, to repay the amounts then due. In those circumstances, we or one or more of our subsidiaries could be forced into bankruptcy or liquidation.
The phaseout of the London Interbank Offered Rate (LIBOR), or the replacement of LIBOR with a different reference rate, may adversely affect interest rates.
On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it would phase out LIBOR by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021, or if alternative rates or benchmarks will be adopted. Changes in the method of calculating LIBOR, or the replacement of LIBOR with an alternative rate or benchmark, may adversely affect interest rates and result in higher borrowing costs. This could materially and adversely affect the Company’s results of operations, cash flows and liquidity. We cannot predict the effect of the potential changes to LIBOR or the establishment and use of alternative rates or benchmarks. Changes in the method of calculating LIBOR, or the use of an alternative rate or benchmark, may negatively impact the terms of our existing or future indebtedness. If changes are made to the method of calculating LIBOR or LIBOR ceases to exist, we may need to amend certain contracts and cannot predict what alternative rate or benchmark would be negotiated. This may result in an increase to our interest expense.
Risks Relating to Our Common Stock
The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.
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. The trading price of our common stock during 2020 was as low as $0.67 per share and as high as $8.69 per share, and it has risen in the last few months. While this increase may be attributable, in whole or in part, to economic developments such as substantial recent increases in JKM prices for LNG, we cannot rule out the possibility that it resulted in whole or in part from market phenomena. If so, those market phenomena could reverse themselves at any time, leading to a rapid and substantial decline in the price of our stock.
The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock by us or our major shareholders.
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. Such pledges have in the past resulted, and could result in the future, in large amounts of shares of our stock being sold in the market in a short period and corresponding declines in the trading price of the common stock.
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.
Risks Relating to Our LNG Business
Various economic and political factors could negatively affect the development, construction and operation of LNG facilities, including the Driftwood terminal, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Commercial development of an LNG facility takes a number of years, requires substantial capital investment and may be delayed by factors such as:
•increased construction costs;
•economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
•decreases in the price of natural gas or LNG, which might decrease the expected returns relating to investments in LNG projects;
•the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities; and
•political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns.
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.
Tellurian’s estimated costs for the Driftwood Project and other projects may not be accurate and are subject to change.
We currently estimate the total cost of the Driftwood Project to be approximately $[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. 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 could materially increase construction costs. In particular, tariffs on imported steel may significantly increase our construction costs. Similarly, cost overruns could occur to portions of the project scope within the LSTK EPC agreements that are provisional such as dredging-related expenditures. Our estimate of the cost of construction of the Driftwood terminal is based on the prices set forth in our LSTK EPC agreements with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) that are subject to adjustment by change orders, including for consideration of certain increased costs.
Our failure to achieve our cost estimates could materially adversely affect our business, financial condition, operating results, liquidity and prospects.
If third-party pipelines and other facilities interconnected to our LNG facilities become unavailable to transport natural gas, this could have a material adverse effect on 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.
Tellurian’s ability to generate cash may depend upon it entering into contracts with third-party customers and the performance of those customers under those contracts.
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 commercial arrangements with third-party customers for products and services from the Driftwood Project. Tellurian’s business strategy may change regarding how and when the proposed Driftwood Project’s export capacity is marketed. Also, Tellurian’s business strategy may change due to an inability to enter into agreements with customers or based on a variety of factors, including the future price outlook, supply and demand of LNG, natural gas liquefaction capacity, and global regasification capacity. If our efforts to market the proposed Driftwood Project and the LNG it will produce are not successful, Tellurian’s business, results of operations, financial condition and prospects may be materially and adversely affected.
We may not be able to purchase, receive or produce sufficient natural gas to satisfy our delivery obligations under any LNG sale and purchase agreements, which could have an adverse effect on us.
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 construction and operation of the Driftwood Project and the Pipeline Network remain subject to further approvals, and some approvals may be subject to further conditions, review and/or revocation.
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. Such approvals and authorizations are often subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. 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. Although all the major permits required for construction and operation of the Driftwood terminal and Driftwood pipeline have been obtained, numerous permits and approvals will 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 no assurance that Tellurian will obtain and maintain these governmental permits, approvals and authorizations, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on its business, results of operations, financial condition and prospects.
Tellurian will be dependent on third-party contractors for the successful completion of the Driftwood terminal, and these contractors may be unable to complete the Driftwood terminal.
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. Timely and cost-effective completion of the Driftwood terminal in compliance with agreed-upon specifications will be highly dependent upon the performance of Bechtel and other third-party contractors pursuant to their agreements. However, Tellurian has not yet entered into definitive agreements with all of the contractors, advisors and consultants necessary for the development and construction of the Driftwood terminal. Tellurian may not be able to successfully enter into such construction contracts on terms or at prices that are acceptable to it.
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:
•design, engineer and receive critical components and equipment necessary for the Driftwood terminal to operate in accordance with specifications and address any start-up and operational issues that may arise in connection with the commencement of commercial operations;
•attract, develop and retain skilled personnel and engage and retain third-party subcontractors, and address any labor issues that may arise;
•post required construction bonds and comply with the terms thereof, and maintain their own financial condition, including adequate working capital;
•adhere to any warranties that the contractors provide in their EPC contracts; and
•respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control, and manage the construction process generally, including engaging and retaining third-party contractors, coordinating with other contractors and regulatory agencies and dealing with inclement weather conditions.
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.
Tellurian’s construction and operations activities are subject to a number of development risks, operational hazards, regulatory approvals and other risks, which could cause cost overruns and delays and could have a material adverse effect on its business, results of operations, financial condition, liquidity and prospects.
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:
•difficulties or delays in obtaining, or failure to obtain, sufficient equity or debt financing on reasonable terms;
•failure to obtain all necessary government and third-party permits, approvals and licenses for the construction and operation of the Driftwood Project or any other proposed LNG facilities;
•difficulties in engaging qualified contractors necessary to the construction of the contemplated Driftwood Project or other LNG facilities;
•shortages of equipment, material or skilled labor;
•natural disasters and catastrophes, such as hurricanes, explosions, fires, floods, industrial accidents and terrorism;
•unscheduled delays in the delivery of ordered materials;
•work stoppages and labor disputes;
•competition with other domestic and international LNG export terminals;
•unanticipated changes in domestic and international market demand for and supply of natural gas and LNG, which will depend in part on supplies of and prices for alternative energy sources and the discovery of new sources of natural resources;
•unexpected or unanticipated need for additional improvements; and
•adverse general economic conditions.
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.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect Tellurian’s LNG business and the performance of our customers and could lead to the reduced development of LNG projects worldwide.
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:
•competitive liquefaction capacity in North America;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
•insufficient or oversupply of LNG tanker capacity;
•weather conditions;
•reduced demand and lower prices for natural gas, including as a result of the COVID-19 pandemic or similar events and related economic disruptions;
•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•decreased oil and natural gas exploration activities, which may decrease the production of natural gas;
•cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
•political conditions in natural gas producing regions; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Technological innovation may render Tellurian’s anticipated competitive advantage or its processes obsolete.
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.
Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the 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:
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to our liquefaction project;
•decreases in the cost of competing sources of natural gas or alternative sources of energy such as coal, heavy fuel oil, diesel, nuclear, hydroelectric, wind and solar;
•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
•increases in capacity and utilization of nuclear power and related facilities;
•increases in the cost of LNG shipping; and
•displacement of LNG by pipeline natural gas or alternative fuels in locations where access to these energy sources is not currently available.
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.
There may be shortages of LNG vessels worldwide, which could have a material adverse effect on Tellurian’s business, results of operations, financial condition, 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:
•an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
•political or economic disturbances in the countries where the vessels are being constructed;
•changes in governmental regulations or maritime self-regulatory organizations;
•work stoppages or other labor disturbances at the shipyards;
•bankruptcies or other financial crises of shipbuilders;
•quality or engineering problems;
•weather interference or catastrophic events, such as a major earthquake, tsunami, or fire; or
•shortages of or delays in the receipt of necessary construction materials.
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-party engineers to estimate the future capacity ratings and performance capabilities of the Driftwood terminal, and these estimates may prove to be inaccurate.
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.
The Driftwood Project will be subject to a number of environmental and safety laws and regulations that impose significant compliance costs, and existing and future environmental, safety and similar laws and regulations could result in increased compliance costs, liabilities or additional operating restrictions.
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, governmental orders to shut down our facilities or capital expenditures related to pollution control equipment or remediation measures that could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.
As an 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.
Changes in legislation and regulations could have a material adverse impact on Tellurian’s business, results of operations, financial condition, liquidity and prospects.
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 the results of our operations. Each of the applicable regulatory requirements and limitations is subject to change, either through new regulations enacted on the federal, state or local level, or by new or modified regulations that may be implemented under existing law. The nature and effects of these changes in laws, rules, regulations and permits may be unpredictable and may have material effects on our business. Future legislation and regulations, such as those relating to the transportation and security of LNG exported from our proposed LNG facilities through the Calcasieu Ship Channel, could cause additional expenditures, restrictions and delays in connection with the proposed LNG facilities and their construction, the extent of which cannot be predicted and which may require Tellurian to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating costs and restrictions could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.
Our operations will be subject to significant risks and hazards, one or more of which may create significant liabilities and losses that could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.
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.
Hurricanes have 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.
Risks Relating to Our Natural Gas and Oil Production Activities
Acquisitions of natural gas and oil properties are subject to the uncertainties of evaluating reserves and potential liabilities, including environmental uncertainties.
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.
Natural gas and oil prices fluctuate widely, and lower prices for an extended period of time may have a material adverse effect on the profitability of our natural gas or oil production activities.
The revenues, operating results and profitability of our natural gas or oil production activities will depend significantly on the prices we receive for the natural gas or oil we sell. We will require substantial expenditures to replace reserves, sustain production and fund our business plans. Low natural gas or oil prices can negatively affect the amount of cash available for acquisitions and capital expenditures and our ability to raise additional capital and, as a result, could have a material adverse effect on our revenues, cash flow and reserves. In addition, low natural gas or oil prices may result in write-downs of our natural gas or oil properties, such as the $81.1 million impairment charge we incurred in 2020. Conversely, any substantial or extended increase in the price of natural gas would adversely affect the competitiveness of LNG as a source of energy. See risks discussed above in “ - Risks Relating to Our LNG Business - Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.” Part of our strategy involves adjusting the level of our natural gas development activities based on our judgment as to whether it will be most cost-effective to source
natural gas for the Driftwood terminal from our own production or, instead, from natural gas produced by third parties. In some circumstances, making these adjustments may involve costs. For example, a decrease in our activities may result in the expiration of leases or an increase in costs on a per-unit basis.
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.
Significant capital expenditures will be required to grow our natural gas or oil production activities in accordance with our plans.
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 modest cash flows for a significant period of time from our producing properties. Our ability to generate operating cash flow in the future will be subject to a number of risks and variables, such as the level of production from existing wells, the price of natural gas or oil, our success in developing and producing new reserves and the other risk factors discussed in this section. If we are unable to fund our capital expenditures for natural gas or oil production activities as planned, we could experience a curtailment of our development activity and a decline in our natural gas or oil production, and that could affect our ability to pursue our overall strategy.
We have limited control over the activities on properties we do not operate.
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.
Drilling and producing operations can be hazardous and may expose us to liabilities.
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 weather, natural disasters, groundwater contamination and other environmental hazards and risks. For our non-operated properties, we will be dependent on the operator for regulatory compliance and for the management of these risks.
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:
•injury or loss of life;
•severe damage to or destruction of property, natural resources or equipment;
•pollution or other environmental damage;
•facility or equipment malfunctions and equipment failures or accidents;
•clean-up responsibilities;
•regulatory investigations and administrative, civil and criminal penalties; and
•injunctions resulting in limitation or suspension of operations.
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.
Our drilling efforts may not be profitable or achieve our targeted returns and our reserve estimates are based on assumptions that may not be accurate.
Drilling for natural gas and oil may involve unprofitable efforts from wells that are either unproductive or 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. Natural gas and oil reserve engineering requires estimates of underground accumulations of hydrocarbons and assumptions concerning future prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect. Our estimates of proved reserves are determined based in part on costs at the date of the estimate. Any significant variance from these costs could greatly affect our estimates of reserves. At December 31, 2020, approximately 73% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame.
Our production activities are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner and feasibility of doing business, and further regulation in the future could increase costs, impose additional operating restrictions and cause delays.
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:
•conduct of drilling, completion, production and midstream activities;
•amounts and types of emissions and discharges;
•generation, management, and disposal of hazardous substances and waste materials;
•reclamation and abandonment of wells and facility sites; and
•remediation of contaminated sites.
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.
Federal, state or local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Laws or regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations are proposed from time to time at the federal, state and local levels. 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.
We expect to drill the locations we acquire over a multi-year period, making them susceptible to uncertainties that could materially alter the occurrence or timing of drilling.
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 unavailability or high cost of drilling rigs, equipment, supplies, personnel and services could adversely affect our ability to execute our development plans within budgeted amounts and on a timely basis.
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 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 may be adversely affected by pipeline and gathering system capacity constraints.
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.
Risks Relating to Our Business in General
We are pursuing a strategy of participating in multiple aspects of the natural gas business, which exposes us to risks.
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. The legal structure we have proposed for capitalizing the Driftwood Project may make it less attractive to some potential customers and partners. For example, some participants in the LNG market may prefer to acquire LNG on the spot market or through long-term supply contracts rather than through a partnership investment in the Driftwood Project.
Tellurian will be subject to risks related to doing business in, and having counterparties based in, foreign countries.
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:
•currency fluctuations;
•war or terrorist attack;
•expropriation or nationalization of assets;
•renegotiation or nullification of existing contracts;
•changing political conditions;
•changing laws and policies affecting trade, taxation, and investment;
•multiple taxation due to different tax structures;
•general hazards associated with the assertion of sovereignty over areas in which operations are conducted; and
•the unexpected credit rating downgrade of countries in which Tellurian’s LNG customers are based.
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.
Potential legislative and regulatory actions addressing climate change, and the physical effects of climate change, could significantly impact us.
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.
A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational damage.
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 attack or military incident could result in delays in, or cancellation of, construction or closure of our facilities or other disruption to our business.
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 our costs and decrease our 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.
Cyber-attacks targeting systems and infrastructure used in our business may adversely impact our operations.
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-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.
Failure to retain and attract key personnel such as Tellurian’s Executive Chairman, Vice Chairman or other skilled professional and technical employees could have an adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.
The success of Tellurian’s business relies heavily on key personnel such as its Executive 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.
Competition is intense in the energy industry and some of Tellurian’s competitors have greater financial, technological and other resources.
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.
For example, many competing companies have secured access to, or are pursuing development or acquisition of, LNG facilities to serve the North American natural gas market, including other proposed liquefaction facilities in North America. Tellurian may face competition from major energy companies and others in pursuing its proposed business strategy to provide liquefaction and export products and services at its proposed Driftwood terminal. In addition, competitors have developed and are developing additional LNG terminals in other markets, which will also compete with our proposed LNG facilities.
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.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURE
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information, Holders and Dividends
Our common stock trades on the Nasdaq under the symbol “TELL.” As of February 9, 2021, there were approximately 748 record holders of Tellurian’s common stock. The Company does not intend to pay cash dividends on its common stock in the foreseeable future.
Recent Sales of Unregistered Securities
None that occurred during the three months ended December 31, 2020.
Use of Proceeds from Registered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None that occurred during the three months ended December 31, 2020.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
None.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past development activities, current financial condition and outlook for the future organized as follows:
•Our Business
•Overview of Significant Events
•Liquidity and Capital Resources
•Capital Development Activities
•Results of Operations
•Commitments and Contingencies
•Summary of Critical Accounting Estimates
•Recent Accounting Standards
Our Business
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 related pipelines (the “Pipeline Network”). We refer to the Driftwood terminal, the Pipeline Network and required natural gas production assets collectively as the “Driftwood Project.” Our existing natural gas production assets consist of 9,373 net acres and interests in 72 producing wells located in the Haynesville Shale trend of northern Louisiana. Our Business may be developed in phases.
In connection with the implementation of our Business, we are offering partnership interests in the Driftwood Project. Partners will contribute cash in exchange for equity in the Driftwood Project 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 the Driftwood Project and have engaged Goldman Sachs & Co. and Société Générale to serve as financial advisors.
We continue to evaluate, and discuss with potential partners, the scope and other aspects of the Driftwood Project in light of the evolving economic environment, needs of potential partners and other factors. Whether we implement changes to the project will be based on a variety of factors, including the results of our continuing analysis, changing business conditions and investor feedback.
Overview of Significant Events
2019 Term Loan
On May 23, 2019, Driftwood Holdings LP, a Delaware limited partnership and an indirect wholly owned subsidiary of Tellurian Inc. (“Driftwood Holdings”), entered into a senior secured term loan agreement (the “2019 Term Loan”) to borrow an aggregate principal amount of $60.0 million, an amount that was subsequently increased to $75.0 million. In conjunction with the 2019 Term Loan, we issued to the lender a warrant to purchase approximately 1.5 million shares of our common stock at $10.00 per share. During 2020, we entered into several amendments to the 2019 Term Loan and, in connection with those amendments, we issued to the lender a total of approximately 9.3 million shares of our common stock to retire $15.0 million of
principal amount of the loan, repaid $19.1 million of principal amount of the loan in cash, replaced the original warrant with a warrant to purchase 9.0 million shares of our common stock at $1.00 per share and issued to the lender a new warrant to purchase 4.7 million shares of our common stock at $1.542 per share.
As amended, (i) the maturity date of the 2019 Term Loan is March 23, 2022, (ii) amounts borrowed bear interest at 16%, with an option on our part to defer 8% per annum as paid-in-kind, (iii) interest payments are made on a monthly basis, and (iv) we are required to maintain a month-end cash balance of at least $12.0 million. Following exercises of the warrants by the lender and reductions in the number of shares purchasable under the warrants resulting from partial repayments of amounts due under the 2019 Term Loan, the warrants give the lender the right, as of February 9, 2021, to purchase approximately 3.5 million shares of our common stock for $1.00 and approximately 0.2 million shares of our common stock for $1.542.
2020 Unsecured Note
On April 29, 2020, we issued a zero coupon $56.0 million senior unsecured note (the “2020 Unsecured Note”) to a third party, raising proceeds of approximately $47.4 million, net of approximately $2.6 million in fees and $6.0 million in original issue discount. We also issued to the lender a warrant to purchase 20.0 million shares of our common stock at a strike price of $1.542 per share. The 2020 Unsecured Note is subject to certain cash sweep provisions, and a portion of the 2020 Unsecured Note must be paid on the first day of every month, beginning on June 1, 2020. Due to the amount of proceeds generated from the sale of our common stock under our at-the-market program in June 2020, as well as the equity offering completed on July 24, 2020, these cash sweep provisions were triggered on July 1, 2020 and August 3, 2020, requiring us to make a total of $8.0 million in additional repayments of the outstanding principal balance. As a result of these additional repayments, the final payment associated with the 2020 Unsecured Note is scheduled to occur on April 1, 2021 instead of June 1, 2021 as originally scheduled.
Equity Offering
On July 24, 2020, we completed a registered direct offering pursuant to which we sold an aggregate of 35.0 million shares of our common stock at an offering price of $1.00 per share. Net proceeds from the transaction were approximately $32.8 million.
LNG Marketing
In July 2020, we purchased the first cargo of LNG pursuant to the master LNG sale and purchase agreement entered into on April 23, 2019. This cargo was subsequently sold to an unrelated third party resulting in revenue of approximately $7.0 million.
Restructuring
In March 2020, we implemented a cost reduction and reorganization plan due to the sharp decline in oil and natural gas prices as well as the growing negative economic effects of the COVID-19 pandemic. We incurred approximately $6.4 million of severance and reorganization charges due to the reduction in workforce. We have satisfied all amounts owed to former employees.
Employee Retention Plan
In July 2020, the Company’s Board of Directors approved an employee retention incentive plan (the “Employee Retention Plan”) aggregating $12.0 million. The Employee Retention Plan vests in four equal installments upon the attainment of a ten-day average closing price of the Company’s common stock above $2.25, $3.25, $4.25 and $5.25 (the “Stock Performance Targets”). Subject to continued employment, the Employee Retention Plan’s awards are payable over a period of twelve months commencing with the later of (i) the first month following the month in which the applicable Stock Performance Target is attained, and (ii) June 2021. The Employee Retention Plan will expire if the Stock Performance Targets are not attained by March 31, 2022.
Liquidity and Capital Resources
Capital Resources
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We are currently funding our operations, development activities and general working capital needs through our cash on hand. Our current capital resources consist of approximately $78.3 million of cash and cash equivalents as of December 31, 2020 on a consolidated basis, of which approximately $47.0 million is maintained at a wholly owned subsidiary of Tellurian Production Holdings LLC. We currently maintain an at-the-market equity offering program under which, as of the date of this filing, we have remaining availability to raise aggregate gross sales proceeds of approximately $274.9 million. Since January 1, 2021, and through February 9, 2021, we have sold approximately 25.6 million shares of common stock under our at-the-market program for total proceeds of approximately $57.2 million, net of approximately $1.8 million in fees and commissions.
As of December 31, 2020, we had total indebtedness of approximately $111.1 million, of which approximately $72.8 million is scheduled to be repaid within the next twelve months. We also had contractual obligations associated with our finance and operating leases totaling $108.6 million, of which $4.8 million is scheduled to be paid within the next twelve months. Since January 1, 2021, we have repaid approximately $56.6 million in principal associated with our indebtedness.
We are planning to generate proceeds from our at-the-market program and have determined that it is probable that such proceeds will satisfy our obligations and fund our working capital needs for at least twelve months following the issuance of the financial statements. We also continue to evaluate generating additional proceeds from various other potential financing transactions, such as issuances of equity, equity-linked and debt securities or similar transactions to fund our obligations and working capital needs.
Sources and Uses of Cash
The following table summarizes the sources and uses of our cash and cash equivalents and costs and expenses for the periods presented (in thousands):
Cash used in operating activities for the year ended December 31, 2020 decreased by approximately $43.0 million compared to the same period in 2019 due to an overall decrease in disbursements in the normal course of business.
Cash used in investing activities for the year ended December 31, 2020 decreased by approximately $64.6 million compared to the same period in 2019. This decrease is predominantly driven by decreased natural gas development activities.
Cash provided by financing activities for the year ended December 31, 2020 increased by approximately $20.7 million compared to the same period in 2019. This increase primarily relates to common stock issuances that raised net proceeds of approximately $99.7 million offset by approximately $60.1 million in principal repayments of our indebtedness and by an overall decrease in borrowings of approximately $25.0 million. See Note 9, Borrowings, and Note 11, Stockholders’ Equity, of our Notes to Consolidated Financial Statements for further information.
Capital Development Activities
The activities we have proposed will require significant amounts of capital and are subject to risks and delays in completion. We have received all regulatory approvals and, as a result, our business success will depend to a significant extent upon our ability to obtain the funding necessary to construct assets on a commercially viable basis and to finance the costs of staffing, operating and expanding our company during that process.
We currently estimate the total cost of the Driftwood Project to be approximately $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. We have entered into four LSTK EPC agreements currently totaling $15.5 billion, or $561 per tonne, with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for construction of the Driftwood terminal. The proposed Driftwood terminal will have a liquefaction capacity of up to 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.
In addition, part of our strategy involves acquiring additional natural gas properties, including properties in the Haynesville shale trend. We intend to pursue potential acquisitions of such assets, or public or private companies that own such assets, in 2021. We would expect to use stock, cash on hand, or cash raised in financing transactions to complete an acquisition of this type.
We anticipate funding our more immediate liquidity requirements relative to the detailed engineering work and other developmental costs, natural gas development costs, and general and administrative costs through the use of cash on hand, proceeds from operations, and proceeds from completed and future issuances of securities by us. Consistent with our overall financing strategy, the Company has considered, and in some cases discussed with investors, various potential financing transactions, including issuances of debt, equity and equity-linked securities or similar transactions, to support its short- and medium-term capital requirements. The Company will continue to evaluate its cash needs and business outlook, and it may execute one or more transactions of this type in the future.
We currently expect that our long-term capital requirements will be financed by proceeds from future debt, equity and/or equity-linked transactions. In addition, part of our financing strategy is expected to involve seeking equity investments by LNG customers at a subsidiary level.
Results of Operations
The following table summarizes costs and expenses for the periods presented (in thousands):
Our consolidated net loss was approximately $210.7 million for the year ended December 31, 2020, compared to a net loss of approximately $151.8 million for the same period of 2019. This $58.9 million increase in net loss was primarily a result of the following:
•Approximately $81.1 million related to an impairment charge of our proved natural gas properties primarily due to depressed natural gas prices caused by the combined impact of increased production and falling demand brought about by current economic conditions. For further information regarding this impairment charge, see Note 3, Property, Plant and Equipment, of our Notes to Consolidated Financial Statements.
•Increase of approximately $27.1 million in interest expense, net, which is primarily attributable to both the 2019 Term Loan and 2020 Unsecured Note incurring interest charges during the current period compared to only a portion of the 2019 Term Loan incurring charges during the prior period.
•Increase of approximately $10.2 million in cost of sales primarily attributable to the sale of an LNG cargo.
•Approximately $7.4 million in related party charges incurred during the current period compared to zero in the prior period. For further information regarding these related party charges, see Note 7, Related Party Transactions, of our Notes to Consolidated Financial Statements.
•Approximately $6.4 million in severance and reorganization charges incurred during the period compared to zero in the prior period. For further information regarding the severance and reorganization charges, see Note 12, Severance and Reorganization, of our Notes to Consolidated Financial Statements.
The above increases in expenses were partially offset by an increase in total revenue of approximately $8.7 million due primarily to the sale of an LNG cargo and a decrease in general and administrative expenses of approximately $40.1 million as well as a decrease in development expenses of approximately $32.1 million due to an overall decline in business activities during the current period.
A discussion of variances between 2019 and 2018 can be found in the “Results of Operations” section on pages 39 through 40 of the Company’s 2019 Annual Report on Form 10-K filed with the SEC on February 24, 2020.
Commitments and Contingencies
The information set forth in Note 10, Commitments and Contingencies, to the accompanying Consolidated Financial Statements included in Part II, Item 8 of this Form 10-K is incorporated herein by reference.
Summary of Critical Accounting Estimates
Our accounting policies are more fully described in Note 1, Basis of Presentation and Summary of Significant Accounting Policies, of our Notes to Consolidated Financial Statements included in this report. As disclosed in Note 1, the preparation of financial statements requires the use of judgments and estimates. We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from these estimates. We identified our most critical accounting estimates to be:
•valuations of long-lived assets; and
•share-based compensation.
We believe that the following discussion addresses our critical accounting policies, which are those that require our most difficult, subjective or complex judgments about future events and related estimations that are fundamental to our results of operations.
Valuation of Long-Lived Assets
When there are indicators that our proved natural gas properties carrying value may not be recoverable, we compare expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on our estimates of (and assumptions regarding) future natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the income approach in accordance with GAAP. Estimates of undiscounted future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation. In addition, such assumptions and estimates are reasonably likely to change in the future.
Proved reserves are the estimated quantities of natural gas and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, because we use the units-of-production method to deplete our natural gas properties, the quantity of reserves could significantly impact our DD&A expense. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Finally, these reserves are the basis for our supplemental natural gas disclosures. See Item 1 and 2 - Our Business and Properties for additional information on our estimate of proved reserves.
Share-Based Compensation
Share-based compensation transactions are measured based on the grant-date estimated fair value. For awards containing only service conditions or performance conditions deemed probable of occurring, the fair value is recognized as expense over the requisite service period using the straight-line method. We recognize compensation cost for awards with performance conditions if and when we conclude that it is probable that the performance condition will be achieved. For awards where the performance or market condition is not considered probable, compensation cost is not recognized until the performance or market condition becomes probable. We reassess the probability of vesting at each reporting period for awards with performance conditions and adjust compensation cost based on our probability assessment. We recognize forfeitures as they occur.
Recent Accounting Standards
We do not believe that any recently issued, but not yet effective, accounting standards, if currently adopted, would have a material effect on our Consolidated Financial Statements or related disclosures.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We do not believe that we hold, or are party to, instruments that are subject to market risks that are material to our business.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TELLURIAN INC.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the Company’s Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Tellurian Inc.’s internal control over financial reporting was effective as of December 31, 2020.
/s/ Octávio M.C. Simões/s/ L. Kian Granmayeh/s/ Khaled A. Sharafeldin
Octávio M.C. SimõesL. Kian GranmayehKhaled A. Sharafeldin
President and Chief Executive Officer
(as Principal Executive Officer)Chief Financial Officer
(as Principal Financial Officer)Chief Accounting Officer
(as Principal Accounting Officer)
Houston, Texas
February 24, 2021
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Tellurian Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Tellurian Inc. and subsidiaries (the "Company") as of December 31, 2020 and 2019, the related consolidated statements of operations, stockholders’ equity and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes and the schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Proved Natural Gas Properties and Depletion - Natural Gas Reserves - Refer to Note 1 and 3 to the financial statements
Critical Audit Matter Description
The Company’s proved natural gas properties are depleted using the successful efforts method and are evaluated for impairment by comparison to the future cash flows of the underlying natural gas reserves. The development of the Company’s natural gas reserve quantities and the related future cash flows requires management to make significant estimates and assumptions related to future natural gas prices and the discount rate used when there is a fair value measurement for impairment. The Company engages an independent reservoir engineer, management’s specialist, to estimate natural gas quantities using generally accepted methods, calculation procedures and engineering data. Changes in these assumptions or engineering data could have a significant impact on the amount of depletion and any proved natural gas impairment. Proved natural gas properties were $24.6 million as of December 31, 2020, and depletion expense was $16.6 million for the year then ended. Impairment expense of $81.1 million was recognized during the twelve-month period ended December 31, 2020.
Given the significant judgments made by management and management’s specialist, performing audit procedures to evaluate the Company’s natural gas reserve quantities and the related net cash flows including management’s estimates and assumptions related to future natural gas prices and the discount rate used when there is a fair value measurement for impairment requires a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s significant judgments and assumptions related to crude oil and condensate, NGLs, and natural gas reserves included the following, among others:
With the assistance of our fair value specialists, we evaluated the reasonableness of natural gas prices by comparing such amounts to:
•Forward published natural gas pricing indexes.
◦Third party industry sources.
◦Historical realized natural gas prices.
◦Historical realized natural gas price differentials.
•With the assistance of our fair value specialists, we assessed management’s estimated discount rate by understanding the methodology used by management for determining its discount rate and comparing assumptions and estimates to publicly traded debt and equity securities and published indices and third-party sources.
•We evaluated the experience, qualifications and objectivity of management’s specialist, an independent reservoir engineering firm, including the methodologies and calculation procedures used to estimate natural gas reserves and performing analytical procedures on the reserve quantities.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We plan to develop, own and operate a global natural gas business and to deliver natural gas to customers worldwide. Tellurian is developing a portfolio of natural gas production, LNG marketing, and infrastructure assets, including a LNG terminal facility (the “Driftwood terminal”) and an associated pipeline (the “Driftwood pipeline”) in southwest Louisiana. Tellurian plans to develop the Driftwood pipeline as part of what we refer to as the “Pipeline Network.” The Driftwood terminal, the Pipeline Network and required natural gas production assets are collectively referred to as the “Driftwood Project”.
The terms “we,” “our,” “us,” “Tellurian” and the “Company” as used in this report refer collectively to Tellurian Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity associated with Tellurian Inc.
Basis of Presentation
Our Consolidated Financial Statements were prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Tellurian Inc. and its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.
Liquidity
Our Consolidated Financial Statements were prepared in accordance with GAAP, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business as well as the Company’s ability to continue as a going concern. As of the date of the Consolidated Financial Statements, we have generated losses and negative cash flows from operations, and have an accumulated deficit. We have not yet established an ongoing source of revenues that is sufficient to cover our future operating costs and obligations as they become due during the twelve months following the issuance of the financial statements.
We are planning to generate proceeds from our at-the-market program and have determined that it is probable that such proceeds will satisfy our obligations and fund our working capital needs for at least twelve months following the issuance of the financial statements. We also continue to evaluate generating additional proceeds from various other potential financing transactions, such as issuances of equity, equity-linked and debt securities or similar transactions to fund our obligations and working capital needs.
Segments
Management allocates resources and assesses financial performance on a consolidated basis. As such, for purposes of financial reporting under GAAP during the years ended December 31, 2020, 2019 and 2018, the Company operated as a single operating segment.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions on a regular basis. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value
The Company uses three levels of the fair value hierarchy of inputs to measure the fair value of an asset or a liability. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.
Revenue Recognition
For the sale of natural gas, we consider the delivery of each unit (MMBtu) to be a separate performance obligation that is satisfied upon delivery to the designated sales point and therefore is recognized at a point in time. These contracts are either fixed price contracts or contracts with a fixed differential to an index price, both of which are deemed fixed consideration that is allocated to each performance obligation and represents the relative standalone selling price basis.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Each LNG cargo, in its entirety, is deemed to be a single performance obligation due to each molecule of LNG being distinct and substantially the same and therefore meeting the criteria for the transfer of a series of distinct goods. Accordingly, LNG sales are recognized at a point in time when the LNG has completed discharging to the customer. These contracts are contracts with a fixed differential to an index price, which is deemed fixed consideration that is allocated to each performance obligation and represents the relative standalone selling price basis. These LNG sales are recorded on a gross basis and reported in “LNG sales” on the Consolidated Statements of Operations.
Purchases and sales of LNG inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “LNG sales” on the Consolidated Statements of Operations. For such LNG sales, we require payment within 10 days from delivery.
Other LNG revenue represents revenue earned from sub-charter agreements and is accounted for outside of Accounting Standards Codification 606, Revenue from Contracts with Customers.
We exclude all taxes from the measurement of the transaction price.
Cash, Cash Equivalents and Restricted Cash
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents that are restricted as to withdrawal or use under the terms of certain contractual agreements are recorded in Non-current restricted cash on our Consolidated Balance Sheets. The carrying value of cash, cash equivalents and restricted cash approximates their fair value.
Concentration of Cash
We maintain cash balances and restricted cash at financial institutions, which may, at times, be in excess of federally insured levels. We have not incurred losses related to these balances to date.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the criteria for and we elect the normal purchases and sales exception.
Changes in the fair value of our derivative instruments are recorded in earnings, and, at present, we have elected not to apply hedge accounting. See Note 6, Financial Instruments, for additional details about our derivative instruments.
Property, Plant and Equipment
Natural gas development and production activities are accounted for using the successful efforts method of accounting. Costs incurred to acquire a property (whether proved or unproved) are capitalized when incurred. Costs to develop proved reserves are capitalized and we deplete our natural gas reserves using the units-of-production method.
Fixed assets are recorded at cost. We depreciate our property, plant and equipment, excluding land, using the straight-line depreciation method over the estimated useful life of the asset. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed, and the resulting gains or losses are recorded in our Consolidated Statements of Operations. Management tests property, plant and equipment for impairment whenever there are indicators that the carrying amount of property, plant and equipment might not be recoverable.
Accounting for LNG Development Activities
As we have been in the preliminary stage of developing the Driftwood terminal, substantially all the costs related to such activities have been expensed. These costs primarily include professional fees associated with FEED studies and applying to FERC for authorization to construct our terminal and other required permitting for the Driftwood Project.
Costs incurred in connection with a project to develop the Driftwood terminal shall generally be treated as development expenses until the project has reached the notice-to-proceed state (“NTP State”) and the following criteria (the “NTP Criteria”) have been met: (i) the necessary regulatory permits have been obtained, (ii) financing for the project has been secured and (iii) management has committed to commence construction.
In addition, certain costs incurred prior to achieving the NTP State will be capitalized though the NTP Criteria have not been met. Costs to be capitalized prior to achieving the NTP State include land purchase costs, land improvement costs, costs associated with preparing the facility for use and any fixed structure construction costs (fence, storage areas, drainage, etc.). Furthermore, activities directly associated with detailed engineering and/or facility designs shall be capitalized. All amounts capitalized are periodically assessed for impairment and may be impaired if indicators are present. For additional details regarding capitalized amounts, please refer to Note 4, Deferred Engineering Costs.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Debt
Discounts, fees and expenses incurred with the issuance of debt are amortized over the term of the debt. These amounts are presented as a reduction of our indebtedness on the accompanying Consolidated Balance Sheets. See Note 9, Borrowings, for additional details about our loans.
Share-Based Compensation
Share-based compensation transactions are measured based on the grant-date estimated fair value. For awards containing only service conditions or performance conditions deemed probable of occurring, the fair value is recognized as expense over the requisite service period using the straight-line method. We recognize compensation cost for awards with performance conditions if and when we conclude that it is probable that the performance condition will be achieved. For awards where the performance or market condition is not considered probable, compensation cost is not recognized until the performance or market condition becomes probable. We reassess the probability of vesting at each reporting period for awards with performance conditions and adjust compensation cost based on our probability assessment. We recognize forfeitures as they occur. See Note 13, Share-Based Compensation, for additional details about our loans.
Income Taxes
We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, we determine deferred tax assets and liabilities on the basis of the differences between the financial statement and tax basis of assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to be realized or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a determination, we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. If we determine that we would be able to realize our deferred tax assets in the future in excess of their net recorded amount, we will make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.
Net Loss Per Share (EPS)
Basic net loss per share excludes dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period. Diluted net loss per share reflects potential dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued and were dilutive.
NOTE 2 - PREPAID EXPENSES AND OTHER CURRENT ASSETS
The components of prepaid expenses and other current assets consist of the following (in thousands):
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 - PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of fixed assets and natural gas properties, as shown below (in thousands):
Depreciation and depletion expenses for the years ended December 31, 2020, 2019 and 2018 were approximately $17.2 million, $20.4 million and $1.5 million, respectively.
Land
We own land in Louisiana for the purpose of constructing the Driftwood Project.
Proved Properties Impairment
The carrying values of our proved natural gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. During the second quarter of 2020, there were indicators that the carrying values of certain of our properties may be impaired as a result of depressed natural gas prices and a decline in demand for natural gas. We determined that these adverse market conditions represented a triggering event to perform an impairment assessment of our proved natural gas properties.
To determine whether impairment had occurred, we compared the estimated expected undiscounted future cash flows from our natural gas properties to the carrying values of those properties. The estimated future cash flows used in the recoverability test are based on proved and, if determined reasonable by management, risk-adjusted probable and possible reserves and assumptions generally consistent with those used by us for internal planning and budgeting purposes. These include, among other things, the intended use of the asset, anticipated production from reserves, future market prices of natural gas adjusted for basis differentials, and future operating costs. Proved properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value.
During the second quarter of 2020, we recognized an impairment charge of approximately $81.1 million primarily associated with our assets located in northern Louisiana. The impairment charge was recorded as a reduction to the assets’ carrying values to their estimated fair values of approximately $28.7 million. The estimated fair value of the impaired assets, as determined as of June 30, 2020, was based on significant inputs that are not observable in the market and, as such, are considered a Level 3 fair value measurement. Key assumptions included in the calculation of the fair value included values for the following: (i) reserves, (ii) future commodity prices and (iii) future operating and development costs.
Unproved Properties
On September 10, 2019 (the “Sale Closing Date”), we sold our wholly owned subsidiary, Magellan Petroleum (UK) Investments Holdings Limited (“Magellan Petroleum UK”), to a third party for approximately $14.8 million. The assets and liabilities of Magellan Petroleum UK consisted predominantly of non-operated interests in the Weald Basin, United Kingdom. The sale of Magellan Petroleum UK generated an overall gain of approximately $4.2 million, all of which was recognized in 2019 as Other income, net in our Consolidated Statements of Operations.
NOTE 4 - DEFERRED ENGINEERING COSTS
Deferred engineering costs of approximately $110.5 million and $106.4 million at December 31, 2020 and 2019, respectively, represent detailed engineering services related to the Driftwood terminal. The balance in this account will be transferred to construction in progress upon reaching an affirmative FID by the Company’s board of directors.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 - OTHER NON-CURRENT ASSETS
Other non-current assets consist of the following (in thousands):
Land Lease and Purchase Options
We hold lease and purchase option agreements (the “Options”) for certain tracts of land and associated river frontage. Upon exercise of the Options, the leases are subject to maximum terms of 50 years (inclusive of various renewals, at the option of the Company). Costs of the Options are amortized over the life of the lease once obtained or capitalized into the land if purchased.
Permitting Costs
Permitting costs primarily represent the purchase of wetland credits in connection with our permit application to the USACE in 2017 and 2018. These wetland credits will be applied to our permit in accordance with the Clean Water Act and the Rivers and Harbors Act, which require us to mitigate the impact to Louisiana wetlands caused by the construction of the Driftwood Project. In May 2019, we received the USACE permit. The permitting costs will be transferred to construction in progress upon reaching an affirmative FID by the Company’s board of directors.
NOTE 6 - FINANCIAL INSTRUMENTS
As discussed in Note 9, Borrowings, as part of entering into the senior secured term loan credit agreement in 2018, we are required to enter into and maintain certain hedging transactions. As a result, we use derivative financial instruments, namely over the counter (“OTC”) commodity swap instruments (“commodity swaps”), to maintain compliance with this covenant. We do not hold or issue derivative financial instruments for trading purposes.
Commodity swap agreements involve payments to or receipts from counterparties based on the differential between two prices for the commodity, and include basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices. The fair value of our commodity swaps is classified as Level 2 in the fair value hierarchy and is based on standard industry income approach models that use significant observable inputs, including, but not limited to, New York Mercantile Exchange (NYMEX) natural gas forward curves and basis forward curves, all of which are validated to external sources, at least monthly.
The Company recognizes all derivative instruments as either assets or liabilities at fair value on a net basis as they are with a single counterparty and subject to a master netting arrangement. These derivative instruments are reported as either current or non-current assets or liabilities, based on their maturity dates. The Company can net settle its derivative instruments at any time. As of December 31, 2020, we had a current asset, net of $0.8 million, and a non-current asset, net of $0.1 million, related to the fair value of the current and non-current portions of our commodity swaps.
We do not apply hedge accounting for our commodity swaps; therefore, all changes in fair value of the Company’s derivative instruments are recognized within Other income, net, in the Consolidated Statements of Operations. For the years ended December 31, 2020 and 2019, we recognized a realized gain of $5.1 million and $3.7 million, respectively, and an unrealized loss of $2.6 million and unrealized gain of $3.4 million, respectively, related to the changes in fair value of the commodity swaps in our Consolidated Statements of Operations. Derivative contracts that result in physical delivery of a commodity expected to be used or sold by the Company in the normal course of business are designated as normal purchases and sales and are exempt from derivative accounting. OTC arrangements require settlement in cash. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Consolidated Statements of Cash Flows.
With respect to the commodity swaps, the Company hedged 7.5 Bcf of its fixed price and basis exposure, which represents a portion of its expected sales of equity production as of December 31, 2020. The open positions at December 31, 2020 had maturities extending through September 2022. For additional details, refer to Note 9, Borrowings.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 - RELATED PARTY TRANSACTIONS
Accounts Payable due to Related Parties
In conjunction with the dismissal of prior litigation, we agreed to reimburse the Vice Chairman of our Board of Directors, Martin Houston, for reasonable attorneys’ fees and expenses he incurred during the litigation. As of December 31, 2020, we paid approximately $5.1 million to third parties to settle outstanding amounts incurred by Mr. Houston for reasonable attorneys’ fees and expenses. We also paid Mr. Houston approximately $1.4 million for other expenses he incurred in connection with the litigation. As of December 31, 2020, a balance of approximately $0.9 million remained owed to Mr. Houston and has been classified within Accounts payable due to related parties on the Consolidated Balance Sheets.
Accounts Receivable due from Related Parties
The approximately $1.3 million in accounts receivable due from related parties consisted of tax indemnities from employees who received share-based compensation in 2016. The statute of limitations related to the tax indemnities expired in October 2020; therefore, this receivable is no longer warranted.
Other
A member of our board of directors is a partner at a law firm that has provided legal services to the Company. Fees incurred for such services were approximately $0.1 million, $0.4 million and $0.1 million for the years ended December 31, 2020, 2019 and 2018, respectively.
NOTE 8 - ACCRUED AND OTHER LIABILITIES
The components of accrued and other liabilities consist of the following (in thousands):
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9 - BORROWINGS
The following tables summarize the Company’s borrowings as of December 31, 2020, and December 31, 2019 (in thousands):
2020 Senior Unsecured Note
On April 29, 2020, we issued a zero coupon $56.0 million face amount senior unsecured note (the “2020 Unsecured Note”) to an unrelated third party. Net proceeds raised from the 2020 Unsecured Note were approximately $47.4 million, after deducting approximately $2.6 million in fees and $6.0 million in original issue discount. The 2020 Unsecured Note is required to be repaid in installments on the first day of every month, and these repayments began on June 1, 2020. As of December 31, 2020, we repaid $40.0 million of the 2020 Unsecured Note. The remaining repayments are scheduled as follows (in thousands):
The 2020 Unsecured Note contains certain cash sweep provisions requiring that a portion of the proceeds from certain of our equity offerings and convertible securities offerings be used to repay the outstanding principal balance through additional amortization payments. Due to the amount of proceeds generated from the sale of our common stock under our at-the-market program in June 2020, as well as the equity offering completed on July 24, 2020, these cash sweep provisions were triggered on July 1, 2020 and August 3, 2020, requiring us to make the maximum amount of additional amortization payments for a total of $8.0 million in additional repayments of the outstanding principal balance. As a result of these additional repayments, the final payment associated with the 2020 Unsecured Note is scheduled to occur on April 1, 2021 instead of June 1, 2021 as originally scheduled. For more information about the transactions that triggered the cash sweep provisions, see Note 11, Stockholders’ Equity.
In conjunction with the 2020 Unsecured Note, we issued to the lender a warrant to purchase 20.0 million shares of our common stock (the “Unsecured Warrant”). The fair value of the Unsecured Warrant of approximately $16.1 million has been recognized as an original issue discount to the 2020 Unsecured Note. For more information about the Unsecured Warrant, see Note 11, Stockholders’ Equity.
The lender may require us to repurchase the 2020 Unsecured Note upon a Fundamental Change (as defined in the 2020 Unsecured Note) or an event of default at 105% and 115%, respectively, of the remaining outstanding principal balance. If an event of default occurs which cannot be cured within certain time periods, we have the right to pay in cash. However, to the extent that we do not pay in cash, the lender will have the right to convert the outstanding face amount into shares of our
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
common stock based on a formula defined in the 2020 Unsecured Note. We may prepay the 2020 Unsecured Note in whole or in part from time to time without premium or penalty.
2019 Term Loan
On May 23, 2019, Driftwood Holdings LP (“Driftwood Holdings”), a wholly owned subsidiary of the Company, entered into a senior secured term loan agreement (the “2019 Term Loan”) to borrow an aggregate principal amount of $60.0 million. On July 16, 2019, the principal amount was increased by an additional $15.0 million after certain criteria stipulated in the 2019 Term Loan agreement were met. Borrowings under the 2019 Term Loan bore a fixed annual interest rate of 12%, of which 4% could be added to the outstanding principal as paid-in-kind interest at the end of each reporting period. In addition to the fixed annual interest rate, upon maturity or early repayment of the 2019 Term Loan, Driftwood Holdings was also obligated to pay to the lender a fee equal to 20% of the principal amount borrowed less financing costs and cash interest paid (the “Final Payment Fee”). We issued to the lender a warrant to purchase approximately 1.5 million shares of our common stock at $10.00 per share (the “Original Warrant”). Fees associated with entering into the 2019 Term Loan of approximately $2.2 million have been capitalized as deferred financing costs.
On February 28, 2020, Driftwood Holdings entered into an amendment (the “First Amendment”) to the 2019 Term Loan which allowed us to enter into a land lease for the Driftwood Project. There was no financial statement impact as a result of the First Amendment.
On March 23, 2020, Driftwood Holdings entered into a second amendment (the “Second Amendment”) to the 2019 Term Loan. The Second Amendment, among other things, modified the 2019 Term Loan as follows:
•Extended the maturity date from May 23, 2020 to November 23, 2021;
•Modified the frequency of interest payments from quarterly to monthly;
•Modified the interest rate from 12% per annum, with the ability to defer 4% per annum as paid-in-kind, to 16% per annum, with the ability to defer 8% per annum as paid-in-kind;
•Required a principal payment of $3.0 million by April 22, 2020; and
•Reduced the required month-end collateral amount from $30.0 million to $12.0 million.
Upon entering into the Second Amendment, we repaid a portion of the outstanding principal and issued approximately 11.0 million shares of our common stock in exchange for cancellation of the Final Payment Fee and all accrued paid-in-kind interest through March 22, 2020 of approximately $11.0 million. Further, as part of the Second Amendment, the Original Warrant was replaced with a new warrant (the “Replacement Warrant”).
On April 28, 2020, Driftwood Holdings entered into a third amendment (the “Third Amendment”) to the 2019 Term Loan, in order to seek the lender’s consent with specific operational needs. As part of the Third Amendment, we issued to the lender a common stock purchase warrant (the “Third Amendment Warrant”). On September 21, 2020, Driftwood Holdings entered into a fourth amendment (the “Fourth Amendment”), which extended the maturity date of the 2019 Term Loan from November 23, 2021 to March 23, 2022.
In connection with the Second Amendment, Third Amendment and Fourth Amendment (collectively, the “Amendments”), we issued to the lender a total of approximately 9.3 million shares of our common stock to retire approximately $15.0 million of principal amount of the 2019 Term Loan and repaid in cash approximately $19.1 million of principal amount of the 2019 Term Loan.
The result of the Replacement and Third Amendment Warrants was an increase of approximately $6.0 million in the debt issuance discount associated with the 2019 Term Loan. Refer to Note 11, Stockholders’ Equity, for further details.
The Amendments were accounted for as debt modifications with no gain or loss recognized, and differences in fair value for amounts settled or paid were capitalized as part of the 2019 Term Loan debt issuance discount.
On December 2, 2020, we repaid $1.0 million of the outstanding principal due to the lender exercising a portion of the Replacement Warrant. See Note 11, Stockholders’ Equity, for further information.
We may prepay the 2019 Term Loan in whole or in part from time to time without premium or penalty. Borrowings under the 2019 Term Loan are guaranteed by Tellurian Inc. and certain of its subsidiaries and are secured by substantially all of the assets of Tellurian Inc. and certain of its subsidiaries, other than Tellurian Production Holdings LLC (“Production Holdings”) and its subsidiaries, under one or more security agreements and pledge agreements.
2018 Term Loan
On September 28, 2018 (the “Closing Date”), Production Holdings entered into a three-year senior secured term loan credit agreement (the “2018 Term Loan”) in an aggregate principal amount of $60.0 million.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our use of proceeds from the 2018 Term Loan is predominantly restricted to capital expenditures associated with certain development and drilling activities and fees related to the transaction itself. At December 31, 2020, unused proceeds from the 2018 Term Loan totaled $3.4 million and were classified as Non-current restricted cash on our Consolidated Balance Sheets.
We have the right, but not the obligation, to make voluntary principal repayments starting six months following the Closing Date in a minimum amount of $5.0 million or any integral multiples of $1.0 million in excess thereof. If no voluntary principal repayments are made, the principal amount, together with any accrued interest, is payable at the maturity date of September 28, 2021. The 2018 Term Loan can be terminated without penalty, with an early termination payment equal to the outstanding principal plus accrued interest.
Amounts borrowed under the 2018 Term Loan are guaranteed by Tellurian Inc. and each of Production Holdings’ subsidiaries. The 2018 Term Loan is collateralized by a first priority lien on all assets of Production Holdings and its subsidiaries, including our proved natural gas properties.
Covenant Compliance
As of December 31, 2020, the Company was in compliance with all covenants under its credit agreements. Refer to Note 6, Financial Instruments, for details of hedging transactions, as of and for the period ended December 31, 2020, entered into as required by the 2018 Term Loan described above.
Fair Value
As of December 31, 2020, the fair value of the 2020 Unsecured Note, on a discounted cash flow basis, was approximately $15.8 million as the 2020 Unsecured Note effective interest rate was higher than current market levels. As of December 31, 2020, the fair value of the 2019 Term Loan, on a discounted cash flow basis, was approximately $47.6 million as the 2019 Term Loan effective interest rate was higher than current market levels. As of December 31, 2020, the fair value of the 2018 Term Loan, on a discounted cash flow basis, was approximately $60.6 million as the 2018 Term Loan effective interest rate was higher than current market levels. The 2020 Unsecured Note, 2019 Term Loan and 2018 Term Loan represent Level 3 instruments in the fair value hierarchy.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
Contractual Obligations
On April 23, 2019, we entered into a master LNG sale and purchase agreement and related confirmation notices (collectively, the “SPA”) with an unrelated third-party LNG merchant. Pursuant to the SPA, we committed to purchase one cargo of LNG per quarter, based on the JKM price in effect at the time of each purchase, beginning in June 2020 through October 2022.
NOTE 11 - STOCKHOLDERS’ EQUITY
At-the-Market Program
We maintain an at-the-market equity offering program pursuant to which we may sell shares of our common stock from time to time on the Nasdaq. For the year ended December 31, 2020, we issued approximately 43.7 million shares of our common stock under our at-the-market program for net proceeds of approximately $53.8 million. As of December 31, 2020, we had remaining availability under the at-the-market program to raise aggregate gross sales proceeds of up to approximately $333.8 million. See Note 17, Subsequent Events, for further information.
Common Stock Issuances
On February 11, 2020, we sold approximately 2.1 million shares of our common stock in a registered direct offering at a price of $6.36 per share. Net proceeds from this offering, after deducting fees and expenses, were approximately $13.1 million. Additionally, on July 24, 2020, we completed a registered direct offering pursuant to which we sold 35.0 million shares of our common stock at an offering price of $1.00 per share. Net proceeds from this transaction were approximately $32.8 million.
In June 2018, 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. In January 2018, and in connection with a common stock issuance in December 2017, the underwriters exercised their option to purchase an additional 1.5 million shares of our common stock for proceeds of approximately $14.5 million, net of approximately $0.5 million in fees and commissions.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Common Stock Purchase Warrants
2020 Unsecured Note
As discussed in Note 9, Borrowings, on April 29, 2020 (the “Issuance Date”), in conjunction with the issuance of the 2020 Unsecured Note, we issued a warrant providing the lender with the right to purchase up to 20.0 million shares of our common stock at $1.542 per share. The Unsecured Warrant, which vested on the Issuance Date, was not exercisable until October 29, 2020 and will expire five years after it became exercisable. The Unsecured Warrant was valued using a Black-Scholes option pricing model that resulted in a relative fair value of approximately $16.1 million on the Issuance Date and is not subject to subsequent remeasurement. The Unsecured Warrant has been classified as equity and is recognized within Additional paid-in capital on our Consolidated Balance Sheets. The Unsecured Warrant has been excluded from the computation of diluted loss per share because including it in the computation would have been antidilutive for the periods presented.
2019 Term Loan
As discussed in Note 9, Borrowings, we have entered into four amendments to the 2019 Term Loan. Pursuant to the Second Amendment, we replaced the previously issued Original Warrant, which provided the lender with the right to purchase up to 1.5 million shares of our common stock at $10.00 per share, with the Replacement Warrant, which provides the lender with the right to purchase 9.0 million shares of our common stock at $1.00 per share. Pursuant to the Third Amendment, we issued the Third Amendment Warrant, which provides the lender with the right to purchase approximately 4.7 million shares of our common stock at $1.542 per share. The Third Amendment Warrant expires five years after the date of the Third Amendment. Half of the Third Amendment Warrant vested immediately, but was not exercisable until October 29, 2020, and the remaining half vested, and became exercisable, on October 29, 2020.
The aggregate number of unvested shares of our common stock provided to the lender under the Replacement Warrant and the Third Amendment Warrant will be reduced proportionately as a result of any partial repayment of the 2019 Term Loan principal and, in the event the outstanding balance of the 2019 Term Loan is repaid in full, any unvested tranches will be canceled as of the date of such repayment. As of December 31, 2020, the aggregate number of unvested shares of our common stock provided to the lender under the Replacement Warrant and the Third Amendment Warrant has been reduced by approximately 2.4 million shares due primarily to partial repayments of the outstanding principal balance.
The Replacement Warrant expires five years after the date of the Second Amendment and vests as follows (in thousands):
On December 2, 2020, the lender purchased 1.0 million shares of our common stock for proceeds of $1.0 million under the terms of the Replacement Warrant. See Note 17, Subsequent Events, for further information.
The Replacement Warrant was valued using a Black-Scholes option pricing model that resulted in a fair value of approximately $3.6 million on the date of the Second Amendment. The difference between the fair values of the Original Warrant and the Replacement Warrant was an increase of approximately $0.3 million and has been classified as equity and recognized within Additional paid-in capital on our Consolidated Balance Sheets. However, as the total number of warrants was no longer fixed, approximately $2.4 million was recognized as a liability on the date of the Second Amendment. This liability is remeasured every period end while it remains unvested, and if the vesting event occurs, the applicable portion of the liability will be remeasured on said vesting date and reclassified to equity. As of December 31, 2020, we had recognized approximately $3.8 million within Accrued and other liabilities on our Consolidated Balance Sheets associated with the Replacement Warrant. For the year ended December 31, 2020, we recognized an unrealized loss of approximately $1.4 million within Other income, net, on our Consolidated Statement of Operations due to the remeasurement of the unvested portion of the Replacement Warrant.
The Third Amendment Warrant was valued using a Black-Scholes option pricing model that resulted in a fair value of approximately $5.7 million on the date of the Third Amendment. As only half of the Third Amendment Warrant had vested on the date of the Third Amendment, and was therefore fixed, approximately $2.9 million was classified as equity and recognized within Additional paid-in capital on our Consolidated Balance Sheets. The remaining approximately $2.8 million did not meet the fixed-for-fixed criteria for equity classification, and was recognized as a liability on the date of the Third Amendment. This liability was remeasured every period end while it remained unvested. On October 29, 2020, the remaining half of the Third
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amendment Warrant vested and approximately $1.1 million was reclassified to equity. We recognized a realized gain of approximately $1.7 million within Other income, net, on our Consolidated Statement of Operations due to the remeasurement of the Third Amendment Warrant.
The Replacement Warrant and Third Amendment Warrant have been excluded from the computation of diluted loss per share because including it in the computation would have been antidilutive for the periods presented.
Preferred Stock
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 Oil, Gas and Chemicals, Inc., a Delaware corporation, pursuant to which we sold to Bechtel Holdings approximately 6.1 million shares of our Series C convertible preferred stock (the “Preferred Stock”).
The holders of the Preferred Stock do not have dividend rights but do have a liquidation preference over holders of our common stock. The holders of the Preferred Stock may convert all or any portion of their shares into shares of our common stock on a one-for-one basis. At any time after “Substantial Completion” of “Project 1,” each as defined in and pursuant to the LSTK EPC Agreement for the Driftwood LNG Phase 1 Liquefaction Facility, dated as of November 10, 2017, or at any time after March 21, 2028, we have the right to cause all of the Preferred Stock to be converted into shares of our common stock on a one-for-one basis. The Preferred Stock has been excluded from the computation of diluted loss per share because including it in the computation would have been antidilutive for the periods presented.
NOTE 12 - SEVERANCE AND REORGANIZATION
We implemented a cost reduction and reorganization plan during the first quarter of 2020 due to the sharp decline in oil and natural gas prices as well as the negative economic effects of the COVID-19 pandemic. We have satisfied all amounts owed to former employees and incurred approximately $6.4 million of severance and reorganization charges during the year ended December 31, 2020 due to reductions in workforce. The charges are presented within the caption Severance and reorganization charges on our Consolidated Statements of Operations.
Employee Retention Plan
In July 2020, the Company’s Board of Directors approved an employee retention incentive plan (the “Employee Retention Plan”) aggregating $12.0 million. The Employee Retention Plan vests in four equal installments upon the attainment of a ten-day average closing price of the Company’s common stock above $2.25, $3.25, $4.25 and $5.25 (the “Stock Performance Targets”). Subject to continued employment, the Employee Retention Plan’s awards are payable over a period of twelve months commencing with the later of (i) the first month following the month in which the applicable Stock Performance Target is attained, and (ii) June 2021. The Employee Retention Plan will expire if the Stock Performance Targets are not attained by March 31, 2022.
No accrual has been made in the accompanying consolidated financial statements for the Employee Retention Plan as amounts are contingent on the occurrence of future events and service.
NOTE 13 - SHARE-BASED COMPENSATION
We have granted restricted stock and restricted stock units (collectively, “Restricted Stock”), as well as unrestricted stock and stock options, to employees, directors and outside consultants (collectively, the “grantees”) under the Tellurian Inc. 2016 Omnibus Incentive Compensation Plan, as amended (the “2016 Plan”), and the Amended and Restated Tellurian Investments Inc. 2016 Omnibus Incentive Plan (the “Legacy Plan”). The maximum number of shares of Tellurian common stock authorized for issuance under the 2016 Plan is 40 million shares of common stock, and no further awards can be made under the Legacy Plan.
For the years ended December 31, 2020, 2019 and 2018, Tellurian recognized approximately $2.7 million, $4.2 million and $5.1 million, respectively, of share-based compensation expense related to all share-based awards. As of December 31, 2020, unrecognized compensation expense, based on the grant date fair value, for all share-based awards totaled approximately $203.2 million.
Restricted Stock
Upon the vesting of restricted stock, shares of common stock will be released to the grantee. Upon the vesting of certain restricted stock units, the units will be converted into shares of common stock and released to the grantee. In March 2018, we began issuing phantom units that may be settled in either cash, stock or a combination thereof. As of December 31, 2020, there was no Restricted Stock that would be required to be settled in cash.
As of December 31, 2020, we had approximately 29.6 million shares of performance-based Restricted Stock outstanding, of which approximately 19.3 million shares will vest entirely based upon an affirmative FID by the Company’s
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
board of directors, as defined in the award agreements, and approximately 9.6 million shares will vest in one-third increments at FID and the first and second anniversaries of FID. The remaining shares of primarily performance-based Restricted Stock, totaling approximately 0.7 million shares, will vest based on other criteria. As of December 31, 2020, no expense had been recognized in connection with performance-based Restricted Stock.
As of December 31, 2020, we had approximately 5.4 million shares of time-based Restricted Stock outstanding. They primarily represent the settlement of the 2019 employee bonuses, which were included in our accrued liabilities balance as of December 31, 2019, and will vest in their entirety during 2021.
The fair value of the Restricted Stock was established by the market price on the date of grant and, for service-based awards, is being recognized as compensation expense ratably over the vesting term. Further, the approximately 35.0 million shares of performance-based and time-based Restricted Stock have been excluded from the computation of diluted loss per share because including them in the computation would have been antidilutive for the periods presented.
The following table provides a summary of our Restricted Stock transactions for the year ended December 31, 2020 (shares and units in thousands):
(1) The weighted-average per share grant date fair value of Restricted Stock granted during the years ended December 31, 2019 and 2018 was $8.53 and $11.02, respectively.
The total grant date fair value of restricted stock vested during the years ended December 31, 2020, 2019 and 2018 was approximately $11.7 million, $1.2 million and $2.5 million, respectively.
Stock Options
Participants in the 2016 Plan have been granted non-qualified options to purchase shares of common stock. Stock options are granted at a price not less than the market price of the common stock on the date of grant. The following table provides a summary of our stock option transactions for the year ended December 31, 2020 (stock options in thousands):
The stock options that were granted to a recipient during the year ended December 31, 2020, vest and become exercisable upon the achievement of both triggers as follows (stock options in thousands):
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The stock options granted during the year ended December 31, 2020, expire on the fifth anniversary of the date of its grant. There were no stock options granted during the years ended December 31, 2019 or 2018.
The fair value of each stock option awarded in 2020 was estimated using a Monte Carlo simulation and, due to the service trigger, is being recognized as compensation expense ratably over the vesting term. Valuation assumptions used to value stock options granted during the year ended December 31, 2020 were as follows:
Due to our limited history, the expected volatility is based on a blend of our historical annualized volatility and the implied volatility utilizing options quoted or traded. The expected dividend yield is based on historical yields on the date of grant. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of the grant.
There were approximately zero, 7 thousand and zero stock options exercised during the years ended December 31, 2020, 2019 and 2018, respectively. Further, the approximately 11.4 million stock options outstanding have been excluded from the computation of diluted loss per share because including them in the computation would have been antidilutive for the periods presented.
NOTE 14 - INCOME TAXES
Income tax benefit (provision) included in our reported net loss consisted of the following (in thousands):
The sources of loss from operations before income taxes were as follows (in thousands):
The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Significant components of our deferred tax assets and liabilities are as follows (in thousands):
As of December 31, 2020, we had federal, state and international net operating loss (“NOL”) carryforwards of $306.6 million, $220.1 million and $29.1 million, respectively. Approximately $245.3 million of these NOLs have an indefinite carryforward period. All other NOLs will expire between 2036 and 2037.
Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal, state and international deferred tax assets as of December 31, 2020 and 2019. We will continue to evaluate the realizability of our deferred tax assets in the future. The increase in the valuation allowance was $49.8 million for the year ended December 31, 2020.
In addition, we experienced a Section 382 ownership change in April 2017. An analysis of the annual limitation on the utilization of our NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not materially limit the use of our NOLs over the carryover period. We will continue to monitor trading activity in our shares which could cause an additional ownership change. If the Company experiences a Section 382 ownership change, it could further affect our ability to utilize our existing NOL carryforwards.
As of December 31, 2020, the Company determined that it has no uncertain tax positions, interest or penalties as defined within ASC 740-10. The Company does not have unrecognized tax benefits. The Company does not believe that it is reasonably possible that the total unrecognized benefits will significantly increase within the next 12 months.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We are subject to tax in the U.S. and various state and foreign jurisdictions. We are not currently under audit by any taxing authority. Federal and state tax returns filed with each jurisdiction remain open to examination under the normal three-year statute of limitations.
Pursuant to ASC 740-30-25-17, the Company recognizes deferred tax liabilities associated with outside basis differences on investments in foreign subsidiaries unless the difference is considered essentially permanent in duration. As of December 31, 2020, the Company has not recorded any deferred taxes on unremitted earnings as the Company has no undistributed earnings and profits. If circumstances change in the foreseeable future and it becomes apparent that some or all of the undistributed earnings and profits will not be reinvested indefinitely, or will be remitted in the foreseeable future, a deferred tax liability will be recorded for some or all of the outside basis difference.
NOTE 15 - LEASES
Finance Leases
Our land leases are classified as financing leases and include one or more options to extend the lease term for up to 40 years, as well as to terminate the lease within five years, at our sole discretion. We are reasonably certain that those options will be exercised, and that our termination rights will not be exercised, and we have, therefore, included those assumptions within our right of use assets and corresponding lease liabilities. As of December 31, 2020, the weighted-average remaining lease term for our financing leases was approximately fifty years. As none of our finance leases provide an implicit rate, we have determined our own discount rate, which, on a weighted-average basis at December 31, 2020, was approximately 13%.
As of December 31, 2020, our financing leases had a corresponding right of use asset of approximately $20.0 million, which is recognized within Property, plant and equipment, net, and a total lease liability of approximately $13.5 million, which is recognized in Other non-current liabilities. For the years ended December 31, 2020 and 2019, our finance lease costs, which are associated with the interest on our lease liabilities, were approximately $1.7 million and $0.2 million, respectively, of which approximately $1.1 million had been paid as of December 31, 2020. For the years ended December 31, 2020 and 2019, we paid approximately $2.9 million and $2.2 million, respectively, in cash for amounts included in the measurement of finance lease liabilities, all of which are presented within the finance section of our cash flows.
Operating Leases
Our office space leases are classified as operating leases and include one or more options to extend the lease term up to 10 years, at our sole discretion. As we are not reasonably certain that those options will be exercised, none are recognized as part of our right of use assets and lease liabilities. As of December 31, 2020, our weighted-average remaining lease term for our operating leases was approximately six years. As none of our operating leases provide an implicit rate, we have determined our own discount rate, which, on a weighted-average basis at December 31, 2020, was approximately 8%.
As of December 31, 2020, our operating leases had a corresponding right of use asset of approximately $11.9 million, which is recognized within Other non-current assets, and a total lease liability of approximately $13.7 million which is recognized within Accrued and other liabilities (approximately $1.9 million) and Other non-current liabilities (approximately $11.8 million). For the years ended December 31, 2020, 2019 and 2018, our operating lease costs were $2.7 million, $3.6 million and $3.2 million, respectively. For the years ended December 31, 2020, 2019 and 2018, we paid approximately $2.8 million, $3.2 million and $2.2 million, respectively, in cash for amounts included in the measurement of operating lease liabilities, all of which are presented within operating cash flows.
The table below presents a maturity analysis of our lease liability on an undiscounted basis and reconciles those amounts to the present value of the lease liability as of December 31, 2020 (in thousands):
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 16 - SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides information regarding the net changes in working capital (in thousands):
The following table provides supplemental disclosure of cash flow information (in thousands):
The statement of cash flows for the year ended December 31, 2020 reflects approximately $78.5 million and $2.1 million in non-cash movements related to the 2019 Term Loan and the Replacement Warrant, respectively. The statement of cash flows for the year ended December 31, 2019 reflects a $0.4 million non-cash movement for funds deposited in escrow in December 2018 that were cleared in March 2019 for the purchase of land.
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of such amounts shown in the Consolidated Statements of Cash Flows (in thousands):
NOTE 17 - SUBSEQUENT EVENTS
At-the-Market Program
After December 31, 2020, and through the date of this filing, we issued 25.6 million shares of common stock under our at-the-market equity offering program for total proceeds of approximately $57.2 million, net of approximately $1.8 million in fees and commissions. As of February 9, 2021, we have remaining capacity under our at-the-market program to raise aggregate gross sales proceeds of approximately $274.9 million.
2018 Term Loan Repayment
After December 31, 2020, we voluntarily repaid approximately $43.0 million of the 2018 Term Loan outstanding principal utilizing the cash generated and held by Production Holdings.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Exercises of Common Stock Purchase Warrants
After December 31, 2020, the holder of the Replacement and Third Amendment Warrants purchased approximately 6.0 million shares of our common stock for aggregate exercise price proceeds of approximately $8.2 million. We utilized the proceeds received to repay $5.6 million of the 2019 Term Loan outstanding principal.
TELLURIAN INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES
In accordance with FASB and SEC disclosure requirements for natural gas producing activities, this section provides supplemental information on Tellurian’s natural gas producing activities in six separate tables. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on the Company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves and changes in estimated discounted future net cash flows.
Table I - Capitalized Costs Related to Natural Gas Producing Activities
Capitalized costs related to Tellurian’s natural gas producing activities are summarized as follows (in thousands):
Table II - Costs Incurred in Exploration, Property Acquisitions and Development
Costs incurred in natural gas property acquisition (inclusive of producing well costs), exploration and development activities are summarized as follows (in thousands):
Table III - Results of Operations for Natural Gas Producing Activities
The following table includes revenues and expenses directly associated with our natural gas and condensate producing activities. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas operations. Tellurian’s results of operations from natural gas and condensate producing activities for the periods presented are as follows (in thousands):
Table IV - Natural Gas Reserve Quantity Information
Our estimated proved reserves are located in Louisiana. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve
TELLURIAN INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
estimates may occur in the future, development and production of the natural gas and condensate reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in these estimates.
The estimates of our proved reserves as of December 31, 2020, 2019 and 2018 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants.
2019 to 2020 Changes
•Had total negative revisions of approximately 152 Bcfe, comprised primarily of a 149 Bcfe negative revision due to the downturn in commodity prices and a 17 Bcfe negative revision from the loss of leases. These downward revisions were offset by a 14 Bcfe positive revision due to improved well performance.
PUD Changes
•Had total negative revisions of approximately 165 Bcfe, comprised of a 148 Bcfe negative revision due to the downturn in commodity prices and a 17 Bcfe negative revision from lease expirations.
2018 to 2019 Changes
•Added approximately 13 Bcfe of proved reserves, comprised of 12 Bcfe from additional proved undeveloped locations and 1 Bcfe from drilling activities.
TELLURIAN INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
•Had total positive revisions of approximately 4 Bcfe, comprised of a 4 Bcfe negative revision due to prices, a 2 Bcfe negative revision from changes in operating expenses, a 9 Bcfe positive revision from well performance and a 1 Bcfe positive revision from changes in ownership.
PUD Changes
•Converted approximately 29 Bcfe to proved developed reserves.
•Added approximately 12 Bcfe from additional proved undeveloped locations.
•Had total positive revisions of approximately 8 Bcfe, comprised primarily of a 9 Bcfe positive revision from well performance, a 2 Bcfe negative revision due to prices and a 1 Bcfe positive revision from changes in ownership.
2017 to 2018 Changes
•Added approximately 22 Bcfe of proved reserves, comprised primarily of 19 Bcfe from additional proved undeveloped locations as a result of a more detailed analysis from an updated development plan and a 3 Bcfe increase from drilling activities.
•Had negative revisions of approximately 85 Bcfe, comprised primarily of 59 Bcfe as a result of newly acquired 3D seismic data indicating additional geological faulting risks, which led to a reduction in proved undeveloped locations and some lateral lengths, 14 Bcfe, net, from changes in estimating lateral lengths of proved undeveloped locations as a result of more detailed analysis from an updated development plan, and 12 Bcfe due to loss of leases.
•Recorded positive revisions of approximately 1 Bcfe due to an increase in commodity prices.
•Acquired approximately 1 Bcfe of proved reserves through minor interest acquisitions.
Table V - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas Reserves
ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Tellurian has followed these guidelines, which are briefly discussed below.
Future cash inflows and future production and development costs as of December 31, 2020, 2019 and 2018 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of natural gas and condensate to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on the continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates, including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the FASB and do not necessarily reflect our expectations of actual revenue to be derived from those reserves or their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.
The following summary sets forth our future net cash flows relating to proved natural gas and condensate reserves based on the standardized measure (in thousands):
Table VI - Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas Reserves
TELLURIAN INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth the changes in the standardized measure of discounted future net cash flows (in thousands):
The accompanying notes are an integral part of these condensed financial statements.
The accompanying notes are an integral part of these condensed financial statements.
The accompanying notes are an integral part of these condensed financial statements.
SCHEDULE I - CONTINUED
TELLURIAN INC.
NOTES TO PARENT COMPANY FINANCIAL STATEMENTS
NOTE 1 - BASIS OF PRESENTATION
Tellurian Inc. is a Delaware corporation based in Houston, Texas (“Tellurian”), which wholly owns Driftwood LP Holdings LLC (“Driftwood LP Holdings”), which in turn wholly owns Driftwood Holdings LP (“Driftwood Holdings”).
These condensed parent company financial statements reflect the activity of Tellurian as the parent company to Driftwood Holdings and have been prepared in accordance with Rules 5-04 and 12-04 of Regulation S-X, as the restricted net assets of Driftwood Holdings exceeds 25% of the consolidated net assets of Tellurian. This information should be read in conjunction with the consolidated financial statements of Tellurian included in this report under the caption Item 8, “Financial Statements and Supplementary Data.”
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Octávio Simões, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Kian Granmayeh, the Company’s Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2020, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information we are required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We made no changes in our internal control over financial reporting during the year ended December 31, 2020, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the U.S. We make modifications to improve the design and effectiveness of our disclosure controls and may take other corrective action if our reviews identify deficiencies or weaknesses in our controls.
Management’s Annual Report on Internal Control Over Financial Reporting
The management report called for by Item 308(a) of Regulation S-K is set forth in Item 8 of Part II of this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting during the quarter ended December 31, 2020, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Pursuant to Section 13(r) of the Exchange Act, if during the year ended December 31, 2020, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our annual report on Form 10-K as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (the “ITRSHRA”). Disclosure is generally required even if the activities were conducted outside the U.S. by non-U.S. entities in compliance with applicable law. During the year ended December 31, 2020, we did not engage in any transactions with Iran or with persons or entities related to Iran.
Total Delaware, Inc. and TOTAL S.A. have beneficial ownership of approximately 12% of the outstanding Tellurian common stock. Total Delaware, Inc. has the right to designate for election one member of Tellurian’s Board of Directors. Total Delaware, Inc. will retain this right for so long as its percentage ownership of Tellurian voting stock is at least 10%. On March 20, 2020, TOTAL S.A. included information in its Annual Report on Form 20-F for the year ended December 31, 2019 (the “Total 2019 Annual Report”) regarding activities during 2019 that require disclosure under the ITRSHRA. The relevant disclosures were reproduced in Exhibit 99.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, filed with the SEC on May 4, 2020 and are incorporated by reference herein. We have no involvement in or control over such activities, and we have not independently verified or participated in the preparation of the disclosures made in the Total 2019 Annual Report.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item is incorporated by reference from Tellurian’s Definitive Proxy Statement with respect to its 2020 Annual Meeting of Stockholders to be filed not later than April 30, 2021.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from Tellurian’s Definitive Proxy Statement with respect to its 2020 Annual Meeting of Stockholders to be filed not later than April 30, 2021.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTER
The information required by this Item with respect to security ownership of certain beneficial owners and management is incorporated by reference from Tellurian’s Definitive Proxy Statement with respect to its 2020 Annual Meeting of Stockholders to be filed not later than April 30, 2021.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference from Tellurian’s Definitive Proxy Statement with respect to its 2020 Annual Meeting of Stockholders to be filed not later than April 30, 2021.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated by reference from Tellurian’s Definitive Proxy Statement with respect to its 2020 Annual Meeting of Stockholders to be filed not later than April 30, 2021.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The following financial statements, financial statement schedules and exhibits are filed as part of this report:
1.Financial Statements. Tellurian’s consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.
2.Financial Statement Schedules. Our financial statement schedules filed herewith are set forth in Item 8 of Part II of this report as follows: Schedule I - Condensed Financial Information of Registrant Tellurian Inc. All valuation and qualifying accounts schedules was omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedule.
3.Exhibits. The exhibits listed below are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
*Filed herewith.
**Furnished herewith.
†Management contract or compensatory plan or arrangement.
††
Portions of this exhibit have been omitted in accordance with Item 601(b)(2) or 601(b)(10) of Regulation S-K. The omitted information is not material and would likely cause competitive harm to the registrant if publicly disclosed. The registrant hereby agrees to furnish supplementally an unredacted copy of this exhibit to the Securities and Exchange Commission upon request.
‡Certain schedules or similar attachments to this exhibit have been omitted in accordance with Item 601(a)(5) of Regulation S-K. The registrant hereby agrees to furnish supplementally to the Securities and Exchange Commission upon request a copy of any omitted schedule or attachment to this exhibit.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TELLURIAN INC.
Date:February 24, 2021By:/s/ L. Kian Granmayeh
L. Kian Granmayeh
Chief Financial Officer
(as Principal Financial Officer)
Tellurian Inc.
Date:February 24, 2021By:/s/ Khaled A. Sharafeldin
Khaled A. Sharafeldin
Chief Accounting Officer
(as Principal Accounting Officer)
Tellurian Inc.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.