10-K 1 tell12311810-k.htm 10-K Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
     x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
         o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission File Number 001-5507
tellurianlogoa15.jpg
Tellurian Inc.
(Exact name of registrant as specified in its charter)
 
Delaware
 
06-0842255
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
1201 Louisiana Street, Suite 3100, Houston, TX
 
77002
(Address of principal executive offices)
 
(Zip Code)
(832) 962-4000
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common stock, $0.01 par value
 
NASDAQ Capital Market
 
 
 
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
x
No
¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes
¨
No
x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes
x
No
¨



Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes
x
No
¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
x
Accelerated filer
¨
 
 
 
 
Non-accelerated filer
¨ 
Smaller reporting company
¨
 
 
 
 
 
 
Emerging growth company
¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
¨
No
x
The aggregate market value of the voting and non-voting stock held by non-affiliates of the registrant, as of June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $766,390 thousand, based on the per share closing sale price of $8.32 on that date. Solely for purposes of this disclosure, shares of common stock held by executive officers and directors of the registrant, as well as certain stockholders, as of such date have been excluded because such persons may be deemed to be affiliates. This determination of executive officers and directors as affiliates is not necessarily a conclusive determination for any other purposes.
240,460,607 shares of common stock were issued and outstanding as of February 15, 2019.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement related to the 2019 annual meeting of stockholders, to be filed within 120 days after December 31, 2018, are incorporated by reference in Part III of this annual report on Form 10-K.
 
 
 
 
 



Tellurian Inc.
Form 10-K
For the Fiscal Year Ended December 31, 2018
TABLE OF CONTENTS
 
 
Page
 
 
Item 1 and 2.
Our Business and Properties
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
 
 
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9B.
Other Information
 
 
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accounting Fees and Services
 
 
Item 15.
Exhibits, Financial Statement Schedules
Item 16.
Form 10-K Summary
Signatures
 




Cautionary Information About Forward-Looking Statements
The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, that address activity, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “initial,” “intend,” “may,” “plan,” “potential,” “project,” “proposed,” “should,” “will,” “would” and similar expressions are intended to identify forward-looking statements. These forward-looking statements relate to, among other things:
our businesses and prospects and our overall strategy;
planned or estimated capital expenditures;
availability of liquidity and capital resources;
our ability to obtain additional financing as needed and the terms of financing transactions, including at Driftwood Holdings LLC;
revenues and expenses;
progress in developing our projects and the timing of that progress;
future values of the Company’s projects or other interests, operations or rights; and
government regulations, including our ability to obtain, and the timing of, necessary governmental permits and approvals.
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that could cause actual results and performance to differ materially from any future results or performance expressed or implied by the forward-looking statements include, but are not limited to, the following:
the uncertain nature of demand for and price of natural gas and LNG;
risks related to shortages of LNG vessels worldwide;
technological innovation which may render our anticipated competitive advantage obsolete;
risks related to a terrorist or military incident involving an LNG carrier;
changes in legislation and regulations relating to the LNG industry, including environmental laws and regulations that impose significant compliance costs and liabilities;
governmental interventions in the LNG industry, including increases in barriers to international trade;
uncertainties regarding our ability to maintain sufficient liquidity and attract sufficient capital resources to implement our projects;
our limited operating history;
our ability to attract and retain key personnel;
risks related to doing business in, and having counterparties in, foreign countries;
our reliance on the skill and expertise of third-party service providers;
the ability of our vendors to meet their contractual obligations;
risks and uncertainties inherent in management estimates of future operating results and cash flows;
our ability to maintain compliance with our senior secured term loan and other agreements;
changes in competitive factors, including the development or expansion of LNG, pipeline and other projects that are competitive with ours;
development risks, operational hazards and regulatory approvals;
our ability to enter and consummate planned financing and other transactions; and
risks and uncertainties associated with litigation matters.
The forward-looking statements in this report speak as of the date hereof. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws.



DEFINITIONS
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. As used in this document, the terms listed below have the following meanings:
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
Bcf
Billion cubic feet of natural gas
Bcf/d
Billion cubic feet per day
Bcfe
Billion cubic feet of natural gas equivalent
Condensate
Hydrocarbons that exist in a gaseous phase at original reservoir temperature and pressure, but when produced, are in the liquid phase at surface pressure and temperature
DD&A
Depreciation, depletion, and amortization
DOE/FE
U.S. Department of Energy, Office of Fossil Energy
EPC
Engineering, procurement, and construction
FASB
Financial Accounting Standards Board
FEED
Front-End Engineering and Design
FERC
U.S. Federal Energy Regulatory Commission
FTA countries
Countries with which the U.S. has a free trade agreement providing for national treatment for trade in natural gas
GAAP
Generally accepted accounting principles in the U.S.
LNG
Liquefied natural gas
LSTK
Lump Sum Turnkey
Mcf
Thousand cubic feet of natural gas
MMBtu
Million British thermal unit
MMcf
Million cubic feet of natural gas
MMcf/d
MMcf per day
MMcfe
Million of cubic feet gas equivalent volumes using a ratio of 6 Mcf to 1 barrel of liquid.
Mtpa
Million tonnes per annum
Nasdaq
Nasdaq Capital Market
NGA
Natural Gas Act of 1938, as amended
Non-FTA countries
Countries with which the U.S. does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
Oil
Crude oil and condensate
PSD
Prevention of Significant Deterioration
PUD
Proved undeveloped reserves
SEC
U.S. Securities and Exchange Commission
Train
An industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
U.K.
United Kingdom
U.S.
United States
USACE
U.S. Army Corps of Engineers
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.



PART I
ITEM 1 AND 2. OUR BUSINESS AND PROPERTIES
Overview
Tellurian Inc. (“Tellurian,” “we,” “us,” “our,” or the “Company”) intends to create value for shareholders by building a low-cost, global natural gas business, profitably delivering natural gas to customers worldwide (the “Business”). We are developing a portfolio of natural gas production, LNG marketing, and infrastructure assets that includes an LNG terminal facility (the “Driftwood terminal”), and three related pipelines (the “Pipeline Network”). We refer to the Driftwood terminal, the Pipeline Network and our existing and planned natural gas production assets collectively as the “Driftwood Project”. We currently estimate the total cost of the Driftwood Project to be approximately $28 billion, including owners’ costs, transaction costs and contingencies but excluding interest costs incurred during construction of the Driftwood terminal and other financing costs. Our Business may be developed in phases.
The proposed Driftwood terminal will have a liquefaction capacity of approximately 27.6 Mtpa and will be situated on approximately 1,000 acres in Calcasieu Parish, Louisiana. The proposed Driftwood terminal will include up to 20 liquefaction Trains, three full containment LNG storage tanks and three marine berths. We have entered into four LSTK EPC agreements totaling $15.2 billion with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for construction of the Driftwood terminal.
The proposed Pipeline Network will consist of three pipelines, the Driftwood pipeline, the Haynesville Global Access Pipeline and the Permian Global Access Pipeline. The Driftwood pipeline will be a 96-mile large diameter pipeline that will interconnect with 14 existing interstate pipelines throughout southwest Louisiana to secure adequate natural gas feedstock for the Driftwood terminal. The Driftwood pipeline will be comprised of 48-inch, 42-inch, 36-inch and 30-inch diameter pipeline segments and three compressor stations totaling approximately 274,000 horsepower, all as necessary to provide approximately 4 Bcf/d of average daily natural gas transportation service. We estimate construction costs for the Driftwood pipeline of approximately $2.3 billion before owners’ costs, financing costs and contingencies.
The Haynesville Global Access Pipeline is expected to run approximately 200 miles from northern to southwest Louisiana. The Permian Global Access Pipeline is expected to run approximately 625 miles from west Texas to southwest Louisiana. Each of these pipelines is expected to have a diameter of 42 inches and be capable of delivering approximately 2 Bcf/d of natural gas. We currently estimate that construction costs will be approximately $1.4 billion for the Haynesville Global Access Pipeline and approximately $3.7 billion for the Permian Global Access Pipeline, in each case before owners’ costs, financing costs and contingencies.
Our current upstream properties, acquired in a series of transactions during 2017 and 2018, consist of 10,233 net acres and 52 producing wells (18 operated) located in the Haynesville Shale trend of north Louisiana. For the year ended December 31, 2018, these wells had average net production of approximately 3.9 MMcf/d. As of December 31, 2018, our estimate of net proved reserves was approximately 265 Bcfe. We began drilling certain locations on our properties in the fourth quarter of 2018 using proceeds from the Term Loan (as described in “2018 Developments — Significant Transactions — Term Loan” below). 
In connection with the implementation of our Business, we are offering partnership interests in a subsidiary, Driftwood Holdings LLC (“Driftwood Holdings”), which will own the Driftwood Project. Partners will contribute cash in exchange for equity in Driftwood Holdings and will receive LNG volumes at the cost of production, including the cost of debt, for the life of the Driftwood terminal.  We plan to retain a portion of the ownership in Driftwood Holdings and have engaged Goldman Sachs & Co. and Société Générale to serve as financial advisors for Driftwood Holdings. We also continue to develop our LNG marketing activities as described below in “2018 Developments — Significant Transactions — LNG Marketing.”
2018 Developments
Significant Transactions
Public Equity Offerings. In connection with our equity offering in December 2017, the underwriters were granted an option to purchase up to an additional 1.5 million shares of common stock within 30 days. The option was exercised in full in January 2018, resulting in proceeds of approximately $14.5 million, net of approximately $0.5 million in fees and commissions.
In June 2018, we completed another offering in which we sold 12.0 million shares of common stock for proceeds of approximately $115.2 million, net of approximately $3.6 million in fees and commissions. The underwriters were granted an option to purchase up to an additional 1.8 million shares of common stock within 30 days, which was not exercised.
Preferred Stock Issuance. In March 2018, we entered into a preferred stock purchase agreement with BDC Oil and Gas Holdings, LLC (“Bechtel Holdings”), a Delaware limited liability company and an affiliate of Bechtel, pursuant to which we sold to Bechtel Holdings approximately 6.1 million shares of our Series C convertible preferred stock (the “Preferred Stock”). In exchange for the Preferred Stock, Bechtel agreed to discharge approximately $22.7 million of the outstanding liabilities associated with the detailed engineering services for the Driftwood Project, and to apply approximately $27.3 million to additional future

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detailed engineering services. During the year ended December 31, 2018, all of the approximately $27.3 million of future services were received and, as such, all $50.0 million has been recognized on our Consolidated Balance Sheets within deferred engineering costs.
Term Loan. On September 28, 2018 (the “Closing Date”), we entered into a three-year senior secured term loan credit agreement (the “Term Loan”) in the principal amount of $60.0 million at a price of 99% of par, resulting in an original issue discount of $0.6 million. Fees of $2.6 million were capitalized as deferred financing costs. Use of proceeds from the Term Loan is predominantly restricted to capital expenditures associated with certain development and drilling activities and fees related to the transaction itself and are presented within non-current restricted cash on our Consolidated Balance Sheet. Amounts borrowed under the Term Loan bear interest at a variable rate (three-month LIBOR) plus an applicable margin. The applicable margin is 5% through the end of the first year following the Closing Date, 7% through the end of the second year following the Closing Date and 8% thereafter. If the Term Loan is terminated within 12 months of the Closing Date, an early termination fee equal to 1% of the outstanding principal is required.
LNG Marketing. In September 2017, we entered into a vessel charter that enabled us to execute a number of LNG purchase and sale opportunities, as well as sub-charter opportunities, that resulted in revenue of approximately $5.9 million for the year ended December 31, 2018.  We continue to implement our marketing strategy by looking for other LNG purchase, sale and vessel charter opportunities.
Regulatory Developments
Export Approval. In February 2017, the DOE/FE issued an order authorizing Tellurian to export 27.6 mtpa of LNG to FTA countries, on its own behalf and as agent for others, for a term of 30 years. Our application for authority to export LNG to non-FTA countries is currently pending before the DOE/FE and is expected to be ruled upon in the first half of 2019.
FERC Application. In March 2017, Tellurian filed an application with FERC for authorization pursuant to Section 3 of the NGA to site, construct and operate the Driftwood terminal, and simultaneously sought authorization pursuant to Section 7 of the NGA for authorization to construct and operate interstate natural gas pipeline facilities. In December 2017, FERC issued the notice of schedule for the environmental review of both the Driftwood terminal and the Driftwood pipeline. In September 2018, we received our draft environmental impact statement (“EIS”) from FERC for the Driftwood terminal and pipeline. We received our final EIS from FERC on January 18, 2019. Refer to Note 19, Subsequent Events to the Consolidated Financial Statements included in this report, for further details.
Environmental Permits. In March 2017, we submitted permit applications to the USACE under the Clean Water Act and the Rivers and Harbors Act for certain dredging and wetland mitigation activities relating to the Driftwood terminal and pipeline. Also in March 2017, we submitted Title V and PSD air permit applications to the Louisiana Department of Environmental Quality under the Clean Air Act for air emissions relating to the Driftwood terminal and pipeline, and the associated permits were granted in July 2018. In addition, in May 2018, we received a Coastal Use Permit from the Louisiana Department of Natural Resources for the Driftwood terminal, which approves the placement of dredged material from the marine berth for beneficial use inside the Louisiana coastal zone. The regulatory review and approval process for the USACE permit is expected to be completed in the first half of 2019.
Natural Gas Properties
Reserves
As discussed in “Our Business and Properties — Overview,” our upstream properties, acquired in a series of transactions during 2017 and 2018, consist of 10,233 net acres and 52 producing wells (18 operated) located in the Haynesville Shale trend of north Louisiana. For the year ended December 31, 2018, these wells had average net production of approximately 3.9 MMcf/d. All of our proved reserves as of December 31, 2018 were associated with those properties. Proved reserves are the estimated quantities of natural gas and condensate which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., costs as of the date the estimate is made). Proved reserves are categorized as either developed or undeveloped.
Our reserves as of December 31, 2018 were estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm, and are set forth in the following table. Per SEC rules, NSAI based its estimates on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month from January through December 2018. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The prices used were $3.10 per MMbtu of natural gas and $65.56 per barrel of condensate, adjusted for energy content, transportation fees and market differentials.

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The following table shows our proved reserves as of December 31, 2018:
 
 
Gas
(MMcf)
 
Condensate
(Mbbl)
 
Gas Equivalent
(MMcfe)
Proved reserves (as of December 31, 2018):
 

 

 

Developed producing
 
17,007

 
7

 
17,052

Developed non-producing
 
515

 

 
515

Undeveloped
 
247,332

 

 
247,332

Total
 
264,854

 
7

 
264,899

The standardized measure of discounted future net cash flow from our proved reserves (the “standardized measure”) as of December 31, 2018 was $145.8 million.
As of December 31, 2018, we had no proved undeveloped reserves that had remained undeveloped for more than five years.
Capital expenditures totaled approximately $17.1 million during 2018. We invested approximately $12.8 million during 2018 developing proved reserves and approximately $4.3 million on wells still in progress at year end.  During the year ended December 31, 2018, we converted approximately 9 Bcfe of proved undeveloped reserves to proved developed reserves.
Refer to Supplemental Disclosures About Natural Gas Producing Activities, starting on page 60, for additional details.
Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used
Our December 31, 2018 reserve report was prepared by NSAI in accordance with guidelines established by the SEC. Reserve definitions comply with the definitions provided by Regulation S‑X of the SEC. NSAI prepared the reserve report based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provide to them. This information is reviewed by knowledgeable members of our Company for accuracy and completeness prior to submission to NSAI.
A letter which identifies the professional qualifications of the individual at NSAI who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2018, has been filed as an addendum to Exhibit 99.2 to this report and is incorporated by reference herein.
Internally, a Senior Vice President is responsible for overseeing our reserves process. Our Senior Vice President has over 17 years of experience in the oil and natural gas industry, with the majority of that time in reservoir engineering and asset management. She is a graduate of Virginia Polytechnic Institute and State University with dual degrees in Chemical Engineering and French, and a graduate of the University of Houston with a Masters of Business Administration degree. During her career, she has had multiple responsibilities in technical and leadership roles, including reservoir engineering and reserves management, production engineering, planning, and asset management for multiple U.S. onshore and international projects. She is also a licensed Professional Engineer in the State of Texas.
Production
For the years ended December 31, 2018 and 2017, we produced 1,399 MMcf and 190 MMcf of natural gas at an average sales price of $2.97 and $2.42 per MMcf, respectively. For the years ended December 31, 2018 and 2017, we produced 988 barrels and 150 barrels of condensate at an average sales price of $60.46 per barrel and $57.01 per barrel, respectively. Natural gas and condensate production and operating costs for the periods ended December 31, 2018 and 2017, were $1.71 and $1.25 per MMcfe, respectively.
Drilling Activity
As of December 31, 2018, we were in the process of drilling or completing operations on one operated well and 12 non-operated wells. Of these 12 non-operated wells, as of December 31, 2018, six had been turned in line. We had no exploratory wells drilled in 2018 or 2017. In addition, we had no dry development wells in 2018 or 2017.
Wells and Acreage
As of December 31, 2018, we owned interests in 37 gross (18 net) productive natural gas wells and held by production 10,503 gross (9,074 net) developed leasehold acreage. Additionally, we hold 1,180 gross (1,159 net) undeveloped leasehold acreage. The majority of the undeveloped leasehold acreage is set to expire in 2020 based on two year contractual extensions granted in 2018, with 111 gross and net acres set to expire in 2019. As of December 31, 2018, there were 10 gross (4 net) in process wells.

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Volume Commitments
We are not currently subject to any material volume commitments.
Gathering, Processing and Transportation
As part of our acquisitions of natural gas properties, we also acquired certain gathering systems that deliver the natural gas we produce into third-party gathering systems. We believe that these systems and other available midstream facilities and services in the Haynesville Shale trend are adequate for our current operations and near-term growth.
Government Regulations
Our operations are and will be subject to extensive federal, state and local statutes, rules, regulations, and laws that include, but are not limited to, the NGA, the Energy Policy Act of 2005 (the “EPAct”), the Oil Pollution Act, the National Environmental Protection Act (“NEPA”), the Clean Air Act (the “CAA”), the Clean Water Act (the “CWA”), the Resource Conservation and Recovery Act (“RCRA”), the Pipeline Safety Improvement Act of 2002 (the “PSIA”), and the Coastal Zone Management Act (the “CZMA”). These statutes cover areas related to the authorization, construction and operation of LNG facilities and natural gas producing properties, including discharges and releases to the air, land and water, and the handling, generation, storage and disposal of hazardous materials and solid and hazardous wastes due to the development, construction and operation of the facilities. These laws are administered and enforced by governmental agencies including FERC, the U.S. Environmental Protection Agency (the “EPA”), the DOE/FE, the U.S. Department of Transportation (“DOT”), the Louisiana Department of Natural Resources, and the Texas Railroad Commission. Additionally, numerous other governmental and regulatory permits and approvals will be required to build and operate our Business, including, with respect to the construction and operation of the Driftwood Project, consultations and approvals by the Advisory Council on Historic Preservation, USACE, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, and U.S. Department of Homeland Security. For example, throughout the life of our liquefaction project, we will be subject to regular reporting requirements to FERC, the DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and other federal and state regulatory agencies regarding the operation and maintenance of our facilities.
Failure to comply with applicable federal, state, and local laws, rules, and regulations could result in substantial administrative, civil and/or criminal penalties and/or failure to secure and retain necessary authorizations.
Federal Energy Regulatory Commission
The design, construction and operation of liquefaction facilities and pipelines, the export of LNG and the transportation of natural gas are highly regulated activities. In order to site, construct and operate our LNG facilities, we are required to obtain authorizations from FERC under Section 3 of the NGA as well as several other material governmental and regulatory approvals and permits. The EPAct amended Section 3 of the NGA to establish or clarify FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, although except as specifically provided in the EPAct, nothing in the EPAct is intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals.
In 2002, FERC concluded that it would apply light-handed regulation over the rates, terms and conditions agreed to by parties for LNG terminalling services, such that LNG terminal owners would not be required to provide open-access service at non-discriminatory rates or maintain a tariff or rate schedule on file with FERC, as distinguished from the requirements applied to FERC-regulated natural gas pipelines. Although the EPAct codified FERC’s policy, those provisions expired on January 1, 2015. Nonetheless, we see no indication that FERC intends to modify its longstanding policy of light-handed regulation of LNG terminals.
FERC has authority to approve, and if necessary set, “just and reasonable rates” for the transportation or sale of natural gas in interstate commerce. Relatedly, under the NGA, our proposed pipelines will not be permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including our own affiliates. FERC has the authority to grant certificates authorizing the construction and operation of facilities, such as pipelines, used in interstate natural gas transportation and the provision of services. FERC’s jurisdiction under the NGA generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate consumption for domestic, commercial, industrial or any other use and to natural gas companies engaged in such transportation or sale. FERC’s jurisdiction does not extend to the production, gathering, local distribution or export of natural gas.
Specifically, FERC’s authority to regulate interstate natural gas pipelines includes:
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;

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the maintenance of accounts and records;
the acquisition and disposition of facilities;
the initiation and discontinuation of services; and
various other matters.
The EPAct amends the NGA to make it unlawful for “any entity,” including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. The EPAct also gives FERC authority to impose civil penalties for violations of the NGA or Natural Gas Policy Act of up to $1 million per violation.
Transportation of the natural gas we produce, and the prices we pay for such transportation, will be significantly affected by the foregoing laws and regulations.
U.S. Department of Energy, Office of Fossil Energy Export License
Under the NGA, exports of natural gas to FTA countries are “deemed to be consistent with the public interest,” and authorization to export LNG to FTA countries shall be granted by the DOE/FE “without modification or delay.” FTA countries currently capable of importing LNG include Canada, Chile, Colombia, Jordan, Mexico, Singapore, South Korea and the Dominican Republic. Exports of natural gas to non-FTA countries are authorized unless the DOE/FE finds that the proposed exportation “will not be consistent with the public interest.”
Pipeline and Hazardous Materials Safety Administration
The Natural Gas Pipeline Safety Act of 1968 (the “NGPSA”) authorizes DOT to regulate pipeline transportation of natural (flammable, toxic, or corrosive) gas and other gases, as well as the transportation and storage of LNG. Amendments to the NGPSA include the Pipeline Safety Act of 1979, which addresses liquids pipelines, and the PSIA, which governs the areas of testing, education, training, and communication.
PHMSA administers pipeline safety regulations for jurisdictional gas gathering, transmission, and distribution systems under minimum federal safety standards. PHMSA also establishes and enforces safety regulations for onshore LNG facilities, which are defined as pipeline facilities used for the transportation or storage of LNG subject to such safety standards. Those regulations address requirements for siting, design, construction, equipment, operations, personnel qualification and training, fire protection, and security of LNG facilities. The Driftwood terminal will be subject to such PHMSA regulations.
Tellurian’s proposed pipelines will also be subject to regulation by PHMSA, including those under the PSIA. The PHMSA Office of Pipeline Safety administers the PSIA, which requires pipeline companies to perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as “high consequence areas.” Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for natural gas transportation pipelines, which requires pipeline operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline, as necessary; and implement preventive and mitigation actions.
In April 2016, PHMSA issued a notice of proposed rulemaking addressing changes to the regulations governing the safety of gas transmission pipelines. Specifically, PHMSA is considering certain integrity management requirements for “moderate consequence areas,” requiring an integrity verification process for specific categories of pipelines, and mandating more explicit requirements for the integration of data from integrity assessments to an operator’s compliance procedures. PHMSA is also considering whether to revise requirements for corrosion control and expanding the definition of regulated gathering lines. These notices of proposed rulemaking are still pending at PHMSA and have not been finalized.
Natural Gas Pipeline Safety Act of 1968
Louisiana administers federal pipeline safety standards under the NGPSA, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal sanctions.

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Other Governmental Permits, Approvals and Authorizations
The construction and operation of the Driftwood Project will be subject to additional federal permits, orders, approvals and consultations required by other federal and state agencies, including DOT, the Advisory Council on Historic Preservation, USACE, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the EPA and U.S. Department of Homeland Security.
Three significant permits that may apply to the Driftwood Project are the USACE Section 404 of the Clean Water Act/Section 10 of the Rivers and Harbors Act Permit, the Clean Air Act Title V Operating Permit and the PSD Permit, of which the latter two permits are issued by the Louisiana Department of Environmental Quality. The Driftwood Project will also have to comply with the requirements of NEPA.
Environmental Regulation
Our operations are and will be subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources, the handling, generation, storage and disposal of hazardous materials and solid and hazardous wastes and other matters. These environmental laws and regulations, which can restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment, will require significant expenditures for compliance, can affect the cost and output of operations, may impose substantial administrative, civil and/or criminal penalties for non-compliance and can result in substantial liabilities.
Clean Air Act. The CAA and comparable state laws and regulations regulate and restrict the emission of air pollutants from many sources and impose various monitoring and reporting requirements, among other requirements. The Driftwood Project is subject to the federal CAA and comparable state and local laws. We may be required to incur capital expenditures for air pollution control equipment in connection with maintaining or obtaining permits and approvals pursuant to the CAA and comparable state laws and regulations.
Greenhouse Gases. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of GHGs are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources, including LNG terminals.
In the past, Congress has considered proposed legislation to reduce emissions of GHGs. Congress has not adopted any significant legislation in this respect to date, but could do so in the future. In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.
The EPA issued the Clean Power Plan in 2015, which would have required existing power plants to reduce their carbon dioxide emissions. The Supreme Court stayed implementation of the Clean Power Plan in February 2016. In October 2017, the EPA proposed to repeal the Clean Power Plan. The comment period on the proposed rule closed on April 26, 2018. On August 21, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule, which would establish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACE would replace the Clean Power Plan.
The Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26-28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020. In June 2017, President Trump announced that the U.S. would initiate the formal process to withdraw from the Paris Agreement.
Coastal Zone Management Act. The siting and construction of the Driftwood terminal within the coastal zone may be subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.
Clean Water Act. The Driftwood Project is subject to the CWA and analogous state and local laws. The CWA and analogous state and local laws regulate discharges of pollutants to waters of the U.S. or waters of the state, including discharges of wastewater and storm water runoff and discharges of dredged or fill material into waters of the U.S., as well as spill prevention, control and countermeasure requirements. Permits must be obtained prior to discharging pollutants into state and federal waters or dredging or filling wetland and coastal areas. The CWA is administered by the EPA, the USACE and by the states. Additionally, the siting and construction of the Driftwood Project may potentially impact jurisdictional wetlands, which would require appropriate federal, state and/or local permits and approval prior to impacting such wetlands. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for regulated impacts to wetlands. The approval timeframe may also be longer than expected and could potentially affect project schedules.

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In June 2015, the EPA issued a final rule that attempts to clarify the CWA’s jurisdictional reach over waters of the U.S. In February 2018, the EPA issued a rule that delays the applicability of the new definition of the waters of the U.S. until February 2020. On August 16, 2018, the U.S. District Court for South Carolina found that the EPA and the USACE failed to comply with the Administrative Procedure Act and struck the 2018 rule that attempted to delay the applicability date of the 2015 Clean Water Rule. Other district courts, however, have issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself. Taken together, the 2015 Clean Water Rule is currently in effect in 23 states, and temporarily stayed in the remaining states. In those remaining states, the 1986 rule and guidance remain in effect. On December 11, 2018, the EPA and the USACE issued a proposed new rule that would differently revise the definition of “waters of the United States” and essentially replace both the 1986 rule and the 2015 Clean Water Rule. According to the agencies, the proposed new rule is “intended to increase CWA program predictability and consistency by increasing clarity as to the scope of ‘waters of the United States’ federally regulated under the Act.” If finalized, this new definition of “waters of the United States” will likely be challenged and sought to be enjoined in federal court. If and when a final rule (as issued or revised) goes into effect, it could expand the scope of the CWA’s jurisdiction, which could result in increased costs and delays with respect to obtaining permits for discharges or pollutants or dredge and fill activities in waters of the U.S., including wetland areas.
Resource Conservation and Recovery Act. The federal RCRA and comparable state requirements govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. In the event such wastes are generated or used in connection with our facilities, we will be subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes and could be required to perform corrective action measures to clean up releases of such wastes. The EPA and certain environmental groups have entered into an agreement pursuant to which the EPA is required to propose, no later than March 15, 2019, a rulemaking for revision of certain regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the EPA will be required to take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the exclusion from RCRA coverage for drilling fluids, produced waters and related wastes could result in a significant increase in our costs to manage and dispose of waste associated with our production operations.
Federal laws including the CWA require certain owners or operators of facilities that store or otherwise handle oil and produced water to prepare and implement spill prevention, control, countermeasure and response plans addressing the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) subjects owners and operators of facilities to strict and joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills, including the government’s response costs. Spills subject to the OPA may result in varying civil and criminal penalties and liabilities.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”). CERCLA, often referred to as Superfund, and comparable state statutes, impose liability that is generally joint and several and that is retroactive for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a “hazardous substance” (or under state law, other specified substances) into the environment. So-called potentially responsible parties (“PRPs”) include the current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the cost of such action. Liability can arise from conditions on properties where operations are conducted, even under circumstances where such operations were performed by third parties and/or from conditions at disposal facilities where materials from operations were sent. Although CERCLA currently exempts petroleum (including oil and natural gas) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. We cannot ensure that this exemption will be preserved in any future amendments of the act. Such amendments could have a material impact on our costs or operations. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA or regulated under similar state statutes. We may also be the owner or operator of sites on which hazardous substances have been released and may be responsible for investigation, management and disposal of contaminated soils or dredge spoils in connection with our operations.
Oil and natural gas exploration and production, and possibly other activities, have been conducted at a majority of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in certain instances may require remediation. In some instances, we have agreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with the properties.
Hydraulic Fracturing. Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We plan to use hydraulic fracturing extensively in our natural gas production operations. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations which are held open by the grains of sand, enabling the natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and natural gas commissions but is also subject to new and changing regulatory programs at the federal, state and local levels.

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Beginning in 2012, the EPA implemented CAA standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to new and modified hydraulically fractured natural gas wells and certain storage vessels. The standards require, among other things, use of reduced emission completions, or “green” completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators.
In February 2014, the EPA issued permitting guidance under the Safe Drinking Water Act (the “SDWA”) for the underground injection of liquids from hydraulically fractured wells and other wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by the EPA.
In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act pursuant to which it will collect extensive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors.
The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017; however, the BLM’s rescission has been challenged by several states in the U.S. District Court of the District of Northern California.
In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and natural gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and natural gas extraction facilities to publicly-owned treatment works.
In June 2016, the EPA finalized additional new source performance standards under the CAA to reduce methane emissions from new and modified sources in the oil and natural gas sector. These new regulations impose, among other things, new requirements for leak detection and repair, control requirements at oil well completions, and additional control requirements for gathering, boosting, and compressor stations. On September 11, 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations.
In November 2016, the BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. On September 28, 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detection and repair. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California.
In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources.” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. In addition, the U.S. Department of Energy has investigated practices that the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These and similar studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.
Endangered Species Act (“ESA”). Our operations may be restricted by requirements under the ESA. The ESA prohibits the harassment, harming or killing of certain protected species and destruction of protected habitats. Under the NEPA review process conducted by FERC, we will be required to consult with federal agencies to determine limitations on and mitigation measures applicable to activities that have the potential to result in harm to threatened or endangered species of plants, animals, fish and their designated habitats.
Regulation of Natural Gas Production
Our natural gas production operations are subject to a number of additional laws, rules and regulations that require, among other things, permits for the drilling of wells, drilling bonds and reports concerning operations. States, parishes and municipalities in which we operate may regulate, among other things:
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;

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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
Our international operations are subject to one or more anti-corruption laws in various jurisdictions, such as the U.S. Foreign Corrupt Practices Act of 1977, as amended (the “FCPA”), the U.K. Bribery Act of 2010 and other anti-corruption laws. The FCPA and these other laws generally prohibit employees and intermediaries from bribing or making other prohibited payments to foreign officials or other persons to obtain or retain business or gain some other business advantage. We participate in relationships with third parties whose actions could potentially subject us to liability under the FCPA or other anti-corruption laws. In addition, we cannot predict the nature, scope or effect of future regulatory requirements to which our international operations might be subject or the manner in which existing laws might be administered or interpreted.
We are also subject to other laws and regulations governing our international operations, including regulations administered by the U.S. Department of Commerce’s Bureau of Industry and Security, the U.S. Department of Treasury’s Office of Foreign Assets Control, and various non-U.S. government entities, including applicable export control regulations, economic sanctions on countries and persons, customs requirements, currency exchange regulations, and transfer pricing regulations (collectively, “Trade Control laws”).
We are also subject to new U.K. corporate criminal offenses for failure to prevent the facilitation of tax evasion pursuant to the Criminal Finances Act 2017, which imposes criminal liability on a company where it has failed to prevent the criminal facilitation of tax evasion by a person associated with the company.
We have instituted policies, procedures and ongoing training of employees with regard to business ethics, designed to ensure that we and our employees comply with the FCPA, other anti-corruption laws, Trade Control laws and the Criminal Finances Act 2017. However, there is no assurance that our efforts have been and will be completely effective in ensuring our compliance with all applicable anti-corruption laws, including the FCPA or other legal requirements. If we are not in compliance with the FCPA, other anti-corruption laws, Trade Control laws or the Criminal Finances Act 2017, we may be subject to criminal and civil penalties, disgorgement and other sanctions and remedial measures, and legal expenses, which could have a material adverse impact on our business, financial condition, results of operations and liquidity. Likewise, any investigation of any potential violations of the FCPA, other anti-corruption laws or the Criminal Finances Act 2017 by the U.S. or foreign authorities could have a material adverse impact on our reputation, business, financial condition and results of operations.
Competition
We are subject to a high degree of competition in all aspects of our business. See “Item 1A — Risk Factors — Risks Relating to Our Business in General — Competition is intense in the energy industry and some of Tellurian’s competitors have greater financial, technological and other resources.
Production & Transportation. The natural gas and oil business is highly competitive in the exploration for and acquisition of reserves, the acquisition of natural gas and oil leases, equipment and personnel required to develop and produce reserves, and the gathering, transportation and marketing of natural gas and oil. Our competitors include national oil companies, major integrated natural gas and oil companies, other independent natural gas and oil companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers, such as operators of pipelines and other midstream facilities. Many of our competitors have longer operating histories, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we currently possess.
Liquefaction. The Driftwood terminal will compete with liquefaction facilities worldwide to supply low-cost liquefaction to the market. There are a number of liquefaction facilities worldwide that we compete with for customers. Many of the companies with which we compete have greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we do.

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LNG Marketing. Tellurian competes with a variety of companies in the global LNG market, including (i) integrated energy companies that market LNG from their own liquefaction facilities, (ii) trading houses and aggregators with LNG supply portfolios, and (iii) liquefaction plant operators that market equity volumes. Many of the companies with which we compete have greater name recognition, larger staffs, greater access to the LNG market and substantially greater financial, technical, and marketing resources than we do.
Title to Properties
With respect to our natural gas producing properties, we believe that we hold good and defensible leasehold title to substantially all of our properties in accordance with standards generally accepted in the industry. A preliminary title examination is conducted at the time the properties are acquired. Our natural gas properties are subject to royalty, overriding royalty, and other outstanding interests.
We believe that we hold good title to our other properties, subject to customary burdens, liens, or encumbrances that we do not expect to materially interfere with our use of the properties.
Major Customers
We do not have any major customers.
Facilities
Certain subsidiaries of Tellurian have entered into operating leases for office space in Houston, Texas, Washington, D.C., London, England and Singapore. The tenors of the leases are three, five, eight and 10 years for Singapore, London, Houston and Washington, D.C., respectively.
Employees
As of December 31, 2018, Tellurian had 172 full-time employees worldwide, none of whom are subject to collective bargaining arrangements.
Jurisdiction and Year of Formation
The Company is a Delaware corporation originally formed in 1967 and formerly known as Magellan Petroleum Corporation.
Available Information
We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.tellurianinc.com. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact Tellurian Inc., Investor Relations, 1201 Louisiana Street, Suite 3100, Houston, Texas 77002.
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 operations. Tellurian will therefore need substantial amounts of additional financing to execute its business plan. There can be no assurance that Tellurian will be able to raise sufficient capital on acceptable terms, or at all. If such financing is not available on satisfactory terms, or is not available at all, Tellurian may be required to delay, scale back or cancel the development of business

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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. To date, Tellurian has not entered into any definitive third-party agreements for the proposed Driftwood Project, and it may not be successful in negotiating and entering into such agreements.
We have a very limited operating history and expect to incur losses for a significant period of time.
We only recently commenced operations. 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 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 2019 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 Project discussed below in “ — Risks Relating to Our LNG Business — Tellurian will be dependent on third-party contractors for the successful completion of the Driftwood Project, and these contractors may be unable to complete the Driftwood Project.” 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 ramp up our LNG and natural gas marketing activities, 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 the composition of operating income by tax jurisdiction; and
our operating results before taxes.
We are subject to income taxes in the U.S. and several foreign jurisdictions. Our future effective tax rates could be affected by changes in the composition of earnings in countries with differing tax rates, changes in deferred tax assets and liabilities or changes in tax laws. Foreign jurisdictions have also increased the volume of tax audits of multinational corporations.

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Further, many countries have either recently changed or are considering changes to their tax laws. Changes in tax laws could affect the distribution of our earnings, result in double taxation and adversely affect our results.
In December 2017, the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) was signed into law, making significant changes to the Internal Revenue Code of 1986, as amended. At this time, the U.S. Department of Treasury has not yet issued final regulations on all provisions of the Tax Act. There may be future Congressional technical corrections to the Tax Act and other regulatory guidance and/or administrative interpretations to the Tax Act that are yet to be issued. We will continue to examine the impact that new guidance and interpretation of the Tax Act may have on our business. We urge our stockholders to consult with their legal and tax advisors with respect to the legislation and potential tax consequences of investing in our stock.
In addition to the impact of the Tax Act on our federal taxes, it may impact taxation in other jurisdictions such as state income taxes. The various state legislatures have not had sufficient time to respond to the Tax Act. Accordingly, it is uncertain as to how the laws will apply in the various state jurisdictions. Additionally, other foreign governing bodies may enact changes in their tax laws in reaction to the Tax Act that could result in changes to our global tax position and materially affect our financial position.
We are also subject to examination by the Internal Revenue Service (the “IRS”) and other tax authorities, including state revenue agencies and other foreign governments. While we regularly assess the likelihood of favorable or unfavorable outcomes resulting from examinations by the IRS and other tax authorities to determine the adequacy of our provision for income taxes, there can be no assurance that the actual outcome resulting from these examinations will not materially adversely affect our financial condition and operating results. Additionally, the IRS and several foreign tax authorities have increasingly focused attention on intercompany transfer pricing with respect to sales of products and services and the use of intangibles. Tax authorities could disagree with our cross-jurisdictional transfer pricing or other matters and assess additional taxes. If we do not prevail in any such disagreements, our profitability may be affected.
Tellurian 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 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.
Tellurian Production Holdings LLC and Tellurian Inc. may be unable to fulfill their obligations under the credit agreement and related guarantee.
As described in “Our Business and Properties — 2018 Developments — Significant Transactions,” in September 2018, Tellurian Production Holdings LLC (“Production Holdings”) entered into a credit agreement providing for the Term Loan, and Tellurian Inc. entered into a parent guarantee pursuant to which it guaranteed the obligations of Production Holdings relating to the Term Loan. Production Holdings’ ability to generate cash flows from operations sufficient to pay interest and principal on its indebtedness will depend on its future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing commodity prices and economic conditions and financial, business and other factors, many of which are beyond its control. If Production Holdings is unable to satisfy its obligations under the Term Loan, Tellurian Inc. may be obligated to pay interest and/or principal on the indebtedness pursuant to the parent guarantee, and it may not have the financial resources to do so. Tellurian Inc. does not currently have any material sources of operating cash flows. An inability on the part of Production Holdings 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 indebtedness to satisfy the requirements of the Term Loan and the parent guarantee. These alternative measures may be unavailable or inadequate and may themselves adversely affect our overall business strategy.
Restrictions in the credit agreement could limit the growth and operations of Production Holdings.
The credit agreement governing the Term Loan contains restrictions on Production Holdings’ activities, certain of which are described in Note 13, Long-Term Borrowings, to the Consolidated Financial Statements included in this report.

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These covenants may prevent Production Holdings from taking actions that it believes would be in the best interest of its business and may make it difficult for it to successfully execute its business strategy or effectively compete with companies that are not similarly restricted.
In addition, the credit agreement requires Production Holdings 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 Production Holdings’ ability to pursue its preferred hedging strategy. In addition, the entire amount of the Term 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 Production Holdings is unable to comply with the restrictions and covenants in the credit agreement governing the Term Loan, there could be a default under the agreement, which could result in an acceleration of payment of funds borrowed under the agreement.
The credit agreement contains financial covenants. If Production Holdings is unable to satisfy these covenants, it would be in default under the agreement, and the lenders could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, and institute foreclosure proceedings with respect to its assets. The lenders could also seek to enforce the parent guarantee against Tellurian Inc., which may not have sufficient funds, or the ability to obtain sufficient funds, to repay the amounts then due. In those circumstances, Production Holdings and/or Tellurian Inc. could be forced into bankruptcy or liquidation.
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 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. In some circumstances, such pledges could result in large amounts of shares of our stock being sold in the market in a short period, which would be expected to have a significant adverse effect on the trading price of the common stock. In addition, in the future, we may issue shares of our common stock in connection with acquisitions of assets or businesses or for other purposes. Such issuances 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;

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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 due to several factors.
We currently estimate the total cost of the Driftwood Project to be approximately $28 billion, including owners’ costs, transaction costs and contingencies but excluding interest costs incurred during construction of the Driftwood terminal and other financing costs. However, cost estimates for these and other projects we may pursue are only approximations of the actual costs of construction. Moreover, cost estimates may be inaccurate and may change due to various factors, such as cost overruns, change orders, delays in construction, legal and regulatory requirements, site issues, increased component and material costs, escalation of labor costs, labor disputes, changes in commodity prices, changes in foreign currency exchange rates, increased spending to maintain Tellurian’s construction schedule and other factors. For example, new or increased tariffs on materials needed in the construction process have been proposed or may be proposed in the future and such new or increased tariffs could materially increase construction costs. In particular, tariffs on imported steel may significantly increase our construction costs. Similarly, cost overruns could occur as a result of dredging-related expenditures incurred to comply with water depth regulations in the Calcasieu Ship Channel. Our estimate of the cost of construction of the Driftwood terminal is based on the prices set forth in our LSTK EPC contracts with Bechtel which are subject to adjustment by change orders, including for consideration of cost escalation associated with the issuance of a “notice to proceed” with respect to the Driftwood terminal after December 31, 2017. Our cost estimates for the Haynesville Global Access Pipeline and the Permian Global Access Pipeline are more preliminary than the estimate for the Driftwood pipeline.
Our failure to achieve our cost estimates could materially adversely affect our business, financial condition, operating results, liquidity and prospects.
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.
Tellurian has not yet entered into, and may never be able to enter into, satisfactory 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.

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The construction and operation of the Driftwood Project and the Pipeline Network remains 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. Even if the necessary authorizations initially required to operate our proposed LNG facilities are obtained, such authorizations are subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. Further, Tellurian must obtain and maintain approvals to export LNG to FTA and non-FTA countries in order to execute its business strategy. Tellurian and its affiliates will be required to obtain governmental approvals and authorizations to implement its proposed business strategy, which includes the construction and operation of the Driftwood Project. In particular, authorization from FERC and the DOE/FE is required to construct and operate our proposed LNG facilities. In addition to seeking to obtain approval for export to FTA countries, Tellurian has filed an application to obtain approval for export to non-FTA countries. Numerous permits and approvals will also be required in connection with other aspects of the Driftwood Project, including the construction and operation of the Pipeline Network and our upstream operations.
There is 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.
There is limited recent industry experience in the U.S. regarding the construction or operation of large-scale LNG facilities. The construction of the Driftwood terminal is expected to take several years, will be confined to a limited geographic area and could be subject to delays, cost overruns, labor disputes and other factors that could adversely affect financial performance or impair Tellurian’s ability to execute its proposed business plan.
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 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.   

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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;
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;

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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 alternate 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.

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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 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 laws and regulations that impose significant compliance costs, and existing and future environmental 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 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. 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 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 the owner and 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 investigation, cleanup, monitoring, removal, disposal and other remedial actions with respect to hazardous substances on, in or under properties Tellurian owns or operates, 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 our results of operations.

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In addition, 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.
In 2005, 2008 and 2017, hurricanes damaged coastal and inland areas located in the Gulf Coast area, resulting in disruption and damage to certain LNG terminals located in the area. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Driftwood terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Driftwood terminal or other facilities. Storms, disasters and accidents could also damage or interrupt the activities of vessels that we or third parties operate in connection with our LNG business. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels. If any such effects were to occur, they could have an adverse effect on our coastal operations.
Our LNG business will face other types of risks and liabilities as well. For instance, our LNG marketing activities will expose us to possible financial losses, including the risk of losses resulting from adverse changes in the index prices upon which contracts for the purchase and sale of LNG cargoes are based. Our LNG marketing activities will also be subject to various domestic and international regulatory and foreign currency risks.
Tellurian does not, nor does it intend to, maintain insurance against all of these risks and losses, and many risks are not insurable. Tellurian may not be able to maintain desired or required insurance in the future at rates that it considers reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on Tellurian’s business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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.


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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. 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

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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 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 at costs at the date of the estimate. Any significant variance from these costs could greatly affect our estimates of reserves. At December 31, 2018, approximately 93% 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

21


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

22


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.
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.
Tellurian Investments and certain other Tellurian subsidiaries (collectively, the “Tellurian Defendants”) are defendants in a lawsuit that could result in equitable relief and/or monetary damages that could have a material adverse effect on Tellurian’s operating results and financial condition.
The Tellurian Defendants, along with Tellurian director Martin Houston and three other individuals as well as certain entities in which each of them owned membership interests, as applicable, have been named as defendants in a lawsuit as described in “Item 3 — Legal Proceedings.” Although the Tellurian Defendants believe the plaintiffs’ claims are without merit, the Tellurian Defendants may not ultimately be successful and any potential liability they may incur is not reasonably estimable. Moreover, even if the Tellurian Defendants are successful in defense of this litigation, they could incur costs and suffer both an economic loss and an adverse impact on their reputations, which could have a material adverse effect on our business. In addition, any adverse judgment or settlement of the litigation could have an adverse effect on our operating results and financial condition.
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.

23


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 Tellurian’s costs and decrease its 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 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 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.

24


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 Project. 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. UNRESOLVED STAFF COMMENTS    
None.
ITEM 3. LEGAL PROCEEDINGS
In July 2017, Tellurian Investments, Driftwood LNG LLC (“Driftwood LNG”), Martin Houston, and three other individuals were named as third-party defendants in a lawsuit filed in state court in Harris County, Texas between Cheniere Energy, Inc. and one of its affiliates, on the one hand (collectively, “Cheniere”), and Parallax Enterprises LLC and certain of its affiliates (not including Parallax Services LLC, now known as Tellurian Services LLC) on the other hand (collectively, “Parallax”). In October 2017, Driftwood Pipeline LLC (“Driftwood Pipeline”) and Tellurian Services LLC were also named by Cheniere as third-party defendants. Cheniere alleges that it entered into a note and a pledge agreement with Parallax. Cheniere claims that the third-party defendants tortiously interfered with the note and pledge agreement and aided in the fraudulent transfer of Parallax assets. Cheniere is seeking unspecified amounts of monetary damages and certain equitable relief. We believe that Cheniere’s claims against Tellurian Investments, Driftwood LNG, Driftwood Pipeline and Tellurian Services LLC are without merit and do not expect the resolution of the suit to have a material effect on our results of operation or financial condition. Trial has been set for June 2019.
ITEM 4. MINE SAFETY DISCLOSURE
None.
PART II
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 Capital Market (“NASDAQ”) under the symbol “TELL.” As of February 15, 2019, there were approximately 571 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
On December 5, 2018, the Company issued 143,500 shares of its common stock, subject to certain vesting requirements, as consideration under a management consulting agreement for certain services.  The shares were issued in a private placement under Section 4(a)(2) of the Securities Act of 1933, as amended.     
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, 2018.
Stock Performance Graph
The information contained in this Stock Performance Graph section shall not be deemed to be “soliciting material” or “filed” or incorporated by reference in future filings with the SEC, or subject to the liabilities of Section 18 of the Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act of 1933 or the Securities Exchange Act of 1934.

25


The following graph compares the cumulative total shareholder return, calculated on a dividend reinvested basis, on $100.00 invested at the closing of the market on December 31, 2013, through and including the market close on December 31, 2018, with the cumulative total return for the same time period of the same amount invested in the Russell 2000 index and a peer group index. Our peer group index consists of the following companies: (1) Cheniere Energy Partners LP (CQP), (2) ONEOK, Inc. (OKE), (3) Golar LNG Limited (GLNG), (4) Enable Midstream Partners LP (ENBL), (5) Cheniere Energy, Inc. (LNG), (6) Teekay Lng Partners, L.P. (TGP), (7) Teekay Corporation (TK), (8) GasLog Ltd (GLOG), (9) Targa Resources Corporation (TRGP) and (10) Anadarko Petroleum Corporation (APC). This peer group was selected based on a review of publicly available information about these companies and our determination that they met one or more of the following criteria: (i) comparable industries, (ii) similar market capitalization and (iii) similar operational characteristics, capital intensity, business and operating risks.
Shareholder returns over the indicated period are based on historical data and should not be considered indicative of future shareholder returns.
chart-b9de2166134d5e949aba01.jpg

12/31/2013

12/31/2014

12/31/2015

12/31/2016

12/31/2017

12/31/2018

Tellurian Inc.
100

88

7

137

118

84

Russell 2000
100

104

98

117

132

116

Peer Group
100

113

56

83

88

79

ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below (in thousands, except per share amounts) are not necessarily indicative of the results of future operations and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and the related notes.We have derived the selected financial data presented below as of December 31, 2018 and 2017 and for the years ended December 31, 2018, 2017 and 2016 (the “Successor”) and for the period from January 1, 2016 to April 9, 2016 (the “Predecessor”) from our Consolidated Financial Statements and related notes included in this report. See Explanatory Note in Item 7. We have derived the selected financial data presented below as of April 9, 2016, December 31, 2015 and 2014 and for the years ended December 31, 2015 and 2014 from financial statements that are not included in this report.

26


 
Successor
 
 
Predecessor
 
Year Ended December 31,
 
 
For the period from January 1, 2016 through April 9, 2016
Year Ended December 31,
 
2018
2017
2016
 
 
2015
2014
Total revenue
$
10,286

$
5,441

$

 
 
$
31

$
1,686

$
1,460

Income (loss) from operations
(127,720
)
(238,567
)
(93,730
)
 
 
(638
)
105

631

Net income (loss)
(125,745
)
(231,459
)
(96,655
)
 
 
(638
)
105

631

Net loss per common share - basic and diluted
(0.59
)
(1.23
)
(1.01
)
 
 
na*

na*

na*

 
 
 
 
 
 
 
 
 
 
Successor
 
 
Predecessor
 
December 31,
 
 
April 9,
December 31,
 
2018
2017
2016
 
 
2016
2015
2014
Cash and cash equivalents
$
133,714

$
128,273

$
21,398

 
 
$
210

$
589

$
258

Property, plant and equipment, net
130,580

115,856

10,993

 
 
480

148

111

Deferred engineering costs
69,000

18,000


 
 



Non-current restricted cash
49,875



 
 



Total assets
408,548

276,823

39,078

 
 
1,108

1,137

1,515

Long-term borrowings
57,048



 
 



 
 
 
 
 
 
 
 
 
* Not applicable.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Explanatory Note
In February 2017, Tellurian Inc., which was formerly known as Magellan Petroleum Corporation (“Magellan”), completed a merger (the “Merger”) with Tellurian Investments Inc. (“Tellurian Investments”). At the effective time of the Merger, a subsidiary of Magellan merged with and into Tellurian Investments, with Tellurian Investments continuing as the surviving corporation and a subsidiary of Magellan. Immediately following the completion of the Merger, Magellan amended its certificate of incorporation and bylaws to change its name to “Tellurian Inc.”
In connection with the Merger, each outstanding share of common stock of Tellurian Investments was exchanged for 1.3 shares of Magellan common stock. The Merger is accounted for as a “reverse acquisition,” with Tellurian Investments being treated as the accounting acquirer.
Except where the context indicates otherwise, (i) references to “we,” “us,” “our,” “Tellurian” or the “Company” refer, for periods prior to the completion of the Merger, to Tellurian Investments and its subsidiaries, and for periods following the completion of the Merger, to Tellurian Inc. and its subsidiaries and (ii) references to “Magellan” refer to Tellurian Inc. and its subsidiaries prior to the completion of the Merger.
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
Off-balance Sheet Arrangements
Commitments and Contingencies

27


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 three related pipelines (the “Pipeline Network”). We refer to the Driftwood terminal, the Pipeline Network and our existing and planned natural gas production assets collectively as the “Driftwood Project”. We currently estimate the total cost of the Driftwood Project to be approximately $28 billion, including owners’ costs, transaction costs and contingencies but excluding interest costs incurred during construction of the Driftwood terminal and other financing costs. Our Business may be developed in phases.
The proposed Driftwood terminal will have a liquefaction capacity of approximately 27.6 Mtpa and will be situated on approximately 1,000 acres in Calcasieu Parish, Louisiana. The proposed Driftwood terminal will include up to 20 liquefaction Trains, three full containment LNG storage tanks and three marine berths. We have entered into four LSTK EPC agreements totaling $15.2 billion with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for construction of the Driftwood terminal.
The proposed Pipeline Network will consist of three pipelines, the Driftwood pipeline, the Haynesville Global Access Pipeline and the Permian Global Access Pipeline. The Driftwood pipeline will be a 96-mile large diameter pipeline that will interconnect with 14 existing interstate pipelines throughout southwest Louisiana to secure adequate natural gas feedstock for the Driftwood terminal. The Driftwood pipeline will be comprised of 48-inch, 42-inch, 36-inch and 30-inch diameter pipeline segments and three compressor stations totaling approximately 274,000 horsepower, all as necessary to provide approximately 4 Bcf/d of average daily natural gas transportation service. We estimate construction costs for the Driftwood pipeline of approximately $2.3 billion before owners’ costs, financing costs and contingencies.
The Haynesville Global Access Pipeline is expected to run approximately 200 miles from northern to southwest Louisiana. The Permian Global Access Pipeline is expected to run approximately 625 miles from west Texas to southwest Louisiana. Each of these pipelines is expected to have a diameter of 42 inches and be capable of delivering approximately 2 Bcf/d of natural gas. We currently estimate that construction costs will be approximately $1.4 billion for the Haynesville Global Access Pipeline and approximately $3.7 billion for the Permian Global Access Pipeline, in each case before owners’ costs, financing costs and contingencies.
Our current upstream properties, acquired in a series of transactions during 2017 and 2018, consist of 10,233 net acres and 52 producing wells (18 operated) located in the Haynesville Shale trend of north Louisiana. For the year ended December 31, 2018, these wells had average net production of approximately 3.9 MMcf/d. As of December 31, 2018, our estimate of net proved reserves was approximately 265 Bcfe. We began drilling certain locations on our properties in the fourth quarter of 2018 using proceeds from the Term Loan (as described in “2018 Developments — Significant Transactions — Term Loan” below). 
In connection with the implementation of our Business, we are offering partnership interests in a subsidiary, Driftwood Holdings LLC (“Driftwood Holdings”), which will own the Driftwood Project. Partners will contribute cash in exchange for equity in Driftwood Holdings and will receive LNG volumes at the cost of production, including the cost of debt, for the life of the Driftwood terminal.  We plan to retain a portion of the ownership in Driftwood Holdings and have engaged Goldman Sachs & Co. and Société Générale to serve as financial advisors for Driftwood Holdings. We also continue to develop our LNG marketing activities as described below in “2018 Developments — Significant Transactions — LNG Marketing.”
Overview of Significant Events
Significant Transactions
Public Equity Offerings. In connection with our equity offering in December 2017, the underwriters were granted an option to purchase up to an additional 1.5 million shares of common stock within 30 days. The option was exercised in full in January 2018, resulting in proceeds of approximately $14.5 million, net of approximately $0.5 million in fees and commissions.
In June 2018, we completed another offering in which we sold 12.0 million shares of common stock for proceeds of approximately $115.2 million, net of approximately $3.6 million in fees and commissions. The underwriters were granted an option to purchase up to an additional 1.8 million shares of common stock within 30 days, which was not exercised.
Preferred Stock Issuance. In March 2018, we entered into a preferred stock purchase agreement with BDC Oil and Gas Holdings, LLC (“Bechtel Holdings”), a Delaware limited liability company and an affiliate of Bechtel, pursuant to which we sold to Bechtel Holdings approximately 6.1 million shares of our Series C convertible preferred stock (the “Preferred Stock”). In exchange for the Preferred Stock, Bechtel agreed to discharge approximately $22.7 million of the outstanding liabilities associated with the detailed engineering services for the Driftwood Project, and to apply approximately $27.3 million to additional future

28


detailed engineering services. During the year ended December 31, 2018, all of the approximately $27.3 million of future services were received and, as such, all $50.0 million has been recognized on our Consolidated Balance Sheets within deferred engineering costs.
Term Loan. On September 28, 2018 (the “Closing Date”), we entered into a three-year senior secured term loan credit agreement (the “Term Loan”) in the principal amount of $60.0 million at a price of 99% of par, resulting in an original issue discount of $0.6 million. Fees of $2.6 million were capitalized as deferred financing costs. Use of proceeds from the Term Loan is predominantly restricted to capital expenditures associated with certain development and drilling activities and fees related to the transaction itself and are presented within non-current restricted cash on our Consolidated Balance Sheet. Amounts borrowed under the Term Loan bear interest at a variable rate (three-month LIBOR) plus an applicable margin. The applicable margin is 5% through the end of the first year following the Closing Date, 7% through the end of the second year following the Closing Date and 8% thereafter. If the Term Loan is terminated within 12 months of the Closing Date, an early termination fee equal to 1% of the outstanding principal is required.
LNG Marketing. In September 2017, we entered into a vessel charter that enabled us to execute a number of LNG purchase and sale opportunities, as well as sub-charter opportunities, that resulted in revenue of approximately $5.9 million for the year ended December 31, 2018.  We continue to implement our marketing strategy by looking for other LNG purchase, sale and vessel charter opportunities.
Regulatory Developments
Export Approval. In February 2017, the DOE/FE issued an order authorizing Tellurian to export 27.6 mtpa of LNG to FTA countries, on its own behalf and as agent for others, for a term of 30 years. Our application for authority to export LNG to non-FTA countries is currently pending before the DOE/FE and is expected to be ruled upon in the first half of 2019.
FERC Application. In March 2017, Tellurian filed an application with FERC for authorization pursuant to Section 3 of the NGA to site, construct and operate the Driftwood terminal, and simultaneously sought authorization pursuant to Section 7 of the NGA for authorization to construct and operate interstate natural gas pipeline facilities. In December 2017, FERC issued the notice of schedule for the environmental review of both the Driftwood terminal and the Driftwood pipeline. In September 2018, we received our draft environmental impact statement (“EIS”) from FERC for the Driftwood terminal and pipeline. We received our final EIS from FERC on January 18, 2019. Refer to Note 19, Subsequent Events to the Consolidated Financial Statements included in this report, for further details.
Environmental Permits. In March 2017, we submitted permit applications to the USACE under the Clean Water Act and the Rivers and Harbors Act for certain dredging and wetland mitigation activities relating to the Driftwood terminal and pipeline. Also in March 2017, we submitted Title V and PSD air permit applications to the Louisiana Department of Environmental Quality under the Clean Air Act for air emissions relating to the Driftwood terminal and pipeline, and the associated permits were granted in July 2018. In addition, in May 2018, we received a Coastal Use Permit from the Louisiana Department of Natural Resources for the Driftwood terminal, which approves the placement of dredged material from the marine berth for beneficial use inside the Louisiana coastal zone. The regulatory review and approval process for the USACE permit is expected to be completed in the first half of 2019.
Liquidity and Capital Resources
Capital Resources
We are currently funding our operations, development activities and general working capital needs through our cash on hand. We are funding our specific development and drilling activities with the proceeds from the Term Loan. Our current capital resources consist of approximately $133.7 million of cash and cash equivalents as of December 31, 2018 on a consolidated basis, which are primarily the result of issuances of common stock in 2017 and in the first half of 2018, and approximately $49.6 million of non-current restricted cash from the Term Loan proceeds. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
We also have the ability to raise funds through common or preferred stock issuances, debt financings, an at-the-market equity offering program or sale of assets.
We maintain an at-the-market equity offering program through Credit Suisse Securities (USA) LLC under which we may raise aggregate sales proceeds of up to $189.7 million.
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):

29


 
 
Year Ended December 31,
 
 
For the period from January 1, 2016 through April 9, 2016
 
 
 
 
 
 
2018
 
2017
 
2016
 
 
Cash used in operating activities
 
$
(103,752
)
 
$
(109,229
)
 
$
(50,430
)
 
 
$
(111
)
Cash used in investing activities
 
(21,687
)
 
(95,565
)
 
(10,506
)
 
 
(268
)
Cash provided by financing activities
 
180,755

 
311,669

 
82,334

 
 

 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
 
55,316

 
106,875

 
21,398

 
 
(379
)
Cash, cash equivalents and restricted cash, beginning of the period
 
128,273

 
21,398

 

 
 
589

Cash, cash equivalents and restricted cash, end of the period
 
$
183,589

 
$
128,273

 
$
21,398

 
 
$
210

 
 
 
 
 
 
 
 
 
 
Net working capital
 
$
87,664

 
$
81,393

 
$
17

 
 
$
(784
)
Cash used in operating activities for the year ended December 31, 2018 decreased approximately $5.5 million compared to the same period in 2017. The decrease in cash used in operating activities primarily relates to the absence of one-off Merger-related expenses of approximately $4.9 million.
Cash used in investing activities for the year ended December 31, 2018 decreased approximately $73.9 million compared to the same period in 2017, primarily due to reduced acquisition and development activities related to natural gas properties. During 2018, we invested approximately $13.5 million in such activities compared to approximately $90.1 million paid for acquisitions in 2017.
Cash provided by financing activities for the year ended December 31, 2018 decreased approximately $130.9 million compared to the same period in 2017, primarily due to the issuance of common stock through equity offerings and through our at-the-market equity program during 2017, which resulted in aggregate net proceeds of approximately $312.5 million, compared to the common stock issuances during the same period in 2018, which resulted in net proceeds of approximately $129.7 million. The comparative decrease of approximately $182.8 million was partially offset by approximately $56.8 million of net proceeds from the Term Loan.
Cash used in operating activities for the year ended December 31, 2017 increased approximately $58.8 million compared to the same period in 2016, primarily due to one-time payments of approximately $12.5 million related to our development activities, approximately $4.9 million of Merger-related expenses and approximately $41.4 million of disbursements in the normal course of business. Disbursements increased primarily due to the increased development activities and a substantial increase in the number of Tellurian employees, which resulted in an increase of approximately $21.6 million and $12.3 million, respectively.
Cash used in investing activities for the year ended December 31, 2017 increased approximately $85.1 million compared to the same period in 2016, primarily due to approximately $90.1 million paid for the acquisition of natural gas properties in northern Louisiana, net of an accrual of $0.1 million offset by approximately $4.6 million of proceeds received from the sale of investment securities.
Cash provided by financing activities for the year ended December 31, 2017 increased approximately $229.3 million compared to the same period in 2016 primarily as a result of net proceeds from the issuance of common shares.
Long-Term Borrowings
As of December 31, 2018, we had total indebtedness of $57.0 million, all of which was secured indebtedness. At December 31, 2018, we were in compliance with the covenants under the credit agreement governing the Term Loan. For additional details regarding our borrowing activity, refer to Note 13, Long-Term Borrowings, to the Consolidated Financial Statements included in this report.
Contractual Obligations 
We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2018 (in thousands):

30


 
Payments Due By Period
 
Total
 
2019
 
2020-2021
 
2022-2023
 
Thereafer
Senior secured term loan (1)
$
60,000

 
$

 
$
60,000

 
$

 
$

Operating lease obligations (2)
$
25,848

 
3,126

 
6,950

 
7,711

 
8,061

Other obligations (3)
$
3,727

 
2,087

 
1,158

 
46

 
436

     Total
$
89,575

 
$
5,213

 
$
68,108

 
$
7,757

 
$
8,497

(1) Includes future principal on the Term Loan through scheduled maturity date. Interest payments are excluded as the Term Loan bears interest at a variable rate. In addition, amortization of debt issuance and other costs related to indebtedness are also excluded. Refer to Note 13, Long-Term Borrowings, to the Consolidated Financial Statements included in this report for further details.
(2) Represents the minimum lease payments for non-cancelable operating leases for various office locations.
(3) Represents primarily options to lease certain properties for the Driftwood Project.
Capital Development Activities
The activities we have proposed will require significant amounts of capital and are subject to risks and delays in completion. We expect to receive all regulatory approvals and commence construction of the Driftwood terminal and Driftwood pipeline in 2019, produce the first LNG in 2023 and achieve full operations in 2026. 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.
Tellurian estimates construction costs of approximately $15.2 billion, or $550 per tonne, for the Driftwood terminal and approximately $2.3 billion for the Driftwood pipeline, in each case before owners’ costs, financing costs and contingencies. We also are in the preliminary routing stage of developing the Haynesville Global Access Pipeline and the Permian Global Access Pipeline, which combined are estimated to cost approximately $5.1 billion before owners’ costs, financing costs and contingencies. In addition, the natural gas production activities we are pursuing will require considerable capital resources. We anticipate funding our more immediate liquidity requirements relative to the detailed engineering work and other developmental and general and administrative costs through the use of cash from the completed equity issuances discussed above and future issuances of equity or debt securities by us.
We currently expect that our long-term capital requirements will be financed by proceeds from future debt and equity offerings. In addition, part of our financing strategy is expected to involve seeking equity investments by LNG customers at a subsidiary level. If the types of financing we expect to pursue are not available, we will be required to seek alternative sources of financing, which may not be available on acceptable terms, if at all.
Results of Operations    
The following table summarizes costs and expenses for the periods presented (in thousands):

31


 
 
Successor
 
 
Predecessor
 
 
 
 
 
 
 
For the
period from
January 1,
2016 through April 9, 2016
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
 
 
2018
 
2017
 
2016
 
 
Total revenue
 
$
10,286

 
$
5,441

 
$

 
 
$
31

Cost of sales
 
6,115

 
7,565

 

 
 

Development expenses
 
44,034

 
59,498

 
47,146

 
 
44

Depreciation, depletion and amortization
 
1,567

 
479

 
69

 
 
8

General and administrative expenses
 
81,777

 
98,874

 
46,515

 
 
617

Impairment charge and loss on transfer of assets
 
4,513

 

 

 
 

Goodwill impairment
 

 
77,592

 

 
 

Loss from operations
 
(127,720
)
 
(238,567
)
 
(93,730
)
 
 
(638
)
Gain (loss) on preferred stock exchange feature
 

 
2,209

 
(3,308
)
 
 

Interest income, net
 
1,574

 
1,022

 

 
 

Other income, net
 
211

 
4,062

 
217

 
 

Income tax benefit (provision)
 
190

 
(185
)
 
166

 
 

Net loss
 
$
(125,745
)
 
$
(231,459
)
 
$
(96,655
)
 
 
$
(638
)
Our consolidated net loss was approximately $125.8 million for the year ended December 31, 2018, compared to a net loss of approximately $231.5 million for the year ended December 31, 2017. This $105.7 million decrease in net loss is primarily due to the absence of a goodwill impairment charge during the current period compared to a $77.6 million charge in 2017. The decrease in our net loss is also a result of the following:
Revenue during the year ended December 31, 2018 increased approximately $4.8 million compared to the same period in 2017, primarily due to the increase in natural gas revenue as a result of a full year of operations and participation in certain wells that became operational in the current period.
The $15.5 million decrease in development expenses is primarily due to the nature of services related to our largest development vendor, Bechtel. The services Bechtel provided during the year ended December 31, 2018, which primarily consisted of detailed engineering services for the Driftwood terminal, are being capitalized, whereas the FEED studies on the Driftwood Project were expensed during the same period in 2017. For more information regarding the detailed engineering services provided by Bechtel, see Note 3, Deferred Engineering Costs, of our Notes to Consolidated Financial Statements included in this report.
The $17.1 million decrease in general and administrative expenses is attributable to a decrease in share-based compensation and share-based payments to vendors, partially offset by an increase in compensation expense due to an overall increase in headcount when compared to the same period in 2017.
The decrease in net loss for the year ended December 31, 2018 was partially offset by the following:
Approximately $2.7 million and $1.8 million resulting from the impairment of certain non-producing proved properties and loss on the transfer of the Australian exploration permit, respectively, both of which are outlined in Note 5, Property, Plant and Equipment, of our Notes to the Consolidated Financial Statements included in this report.
Other income, net for the year ended December 31, 2018 decreased approximately $3.9 million compared to the same period in 2017. The decrease is primarily attributable to an absence of a gain on sale of securities of approximately $3.5 million in 2017.
Our consolidated net loss was approximately $231.5 million for the year ended December 31, 2017, compared to a net loss of approximately $96.7 million for the year ended December 31, 2016. This $134.8 million increase in net loss is primarily a result of the following:
Development expenses for the year ended December 31, 2017 increased approximately $12.4 million compared to the same period in 2016. This increase is due to an overall increase in activity associated with the permitting process with FERC.
General and administrative expenses during the year ended December 31, 2017 increased approximately $52.4 million compared to the same period in 2016. The increase is attributable to non-cash share-based payments related

32


to commercial development and management consulting contractors of approximately $19.4 million which were not incurred in 2016, an increase in salaries and benefits of approximately $14.3 million due to a substantial increase in the number of employees, and an increase in corporate marketing and investor development activities.
Goodwill impairment during the year ended December 31, 2017 increased approximately $77.6 million due to goodwill recognized as a result of the Merger that was subsequently determined to be unrecoverable.
Cost of sales during the year ended December 31, 2017 increased approximately $7.6 million compared to the same period in 2016. This increase is primarily due to LNG marketing transaction costs of approximately $7.1 million.
The increase in expenses for the year ended December 31, 2017 was partially offset by the following:
Revenue during the year ended December 31, 2017 increased approximately $5.4 million compared to the same period in 2016. This increase is primarily due to LNG sales revenue of approximately $3.3 million and LNG sub-charter revenue of approximately $1.7 million.
Approximately $5.5 million was recognized due to an exchange feature of the Tellurian Investments Series A convertible preferred stock issued during 2016.
Other income, net for the year ended December 31, 2017 increased approximately $3.8 million compared to the same period in 2016. The increase is primarily attributable to a gain on sale of securities of approximately $3.5 million.
Off-Balance Sheet Arrangements
As of December 31, 2018, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.
Commitments and Contingencies
The information set forth in Note 8, 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 to the 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, including intangible assets and goodwill;
purchase price allocation for acquired businesses;
forecasting our effective income tax rate, including the realizability of deferred tax assets;
impairment considerations for tangible and intangible assets; and
share-based compensation.
We believe 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.
Fair Value
When necessary or required by GAAP, we estimate the fair value of (i) long-lived assets for impairment testing, (ii) reporting units for goodwill impairment testing and (iii) assets acquired and liabilities assumed in business combinations. When there is not a market-observable price for the asset or liability or a similar asset or liability, we use the cost, income, or market valuation approach, depending on the quality of information available to support management’s assumptions.
The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of projected cash flows and discounts the expected cash flows using a commensurate risk-adjusted discount rate. The market approach is based on management’s best assumptions regarding prices and other relevant information from market transactions involving comparable assets. Such evaluations involve significant judgment, and the results are based on expected future events or conditions. Assumptions used in fair value measurement would reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

33


Income Taxes
Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance if, based on all available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. In determining the need for a valuation allowance, 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. We have recorded a full valuation allowance on our net deferred tax assets as of December 31, 2018 and 2017. We intend to maintain a valuation allowance on our net deferred tax assets until there is sufficient evidence to support the reversal of these allowances.
Reserves Estimates
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.
Impairments
When circumstances indicate that proved natural gas properties may be impaired, 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. In addition, such assumptions and estimates are reasonably likely to change in the future.
We test goodwill for impairment annually during the fourth quarter, or more frequently as circumstances dictate. The first step in assessing whether an impairment of goodwill is necessary is an optional qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is greater than its carrying amount. If we conclude that it is more likely than not that the fair value of the reporting unit exceeds the related carrying amount, further testing is not necessary. If the qualitative assessment is not performed or indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we compare the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill. An impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value is then recognized.
See Note 2, Merger and Acquisition, to the Consolidated Financial Statements included in this report for additional information regarding impairment of goodwill.
Share-Based Compensation    
Share-based compensation transactions are measured based on 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
For descriptions of recently issued accounting standards, see Note 18, Recent Accounting Standards, to the Consolidated Financial Statements included in this report.
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.

34


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
TELLURIAN INC.
 
 
 
 
Page
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements:
 
 
Consolidated Balance Sheets
 
Consolidated Statements of Operations
 
Consolidated Statements of Stockholders’ Equity
 
Consolidated Statements of Cash Flows
 
Notes to the Consolidated Financial Statements
Supplementary Information
 
 
Supplemental Disclosures About Natural Gas Producing Activities (unaudited)
Schedule I
 
 
Condensed Financial Information of Registrant Tellurian Inc.


35


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, 2018.
Deloitte & Touche LLP, an independent registered public accounting firm, audited the effectiveness of Tellurian Inc.’s internal control over financial reporting as of December 31, 2018, as stated in their report on page 38.
/s/ Meg A. Gentle
 
/s/ Antoine J. Lafargue
 
/s/ Khaled A. Sharafeldin
Meg A. Gentle
 
Antoine J. Lafargue
 
Khaled A. Sharafeldin
President and Chief Executive Officer
(as Principal Executive Officer)
 
Senior Vice President and Chief Financial Officer
(as Principal Financial Officer)
 
Chief Accounting Officer
(as Principal Accounting Officer)
 
 
 
 
 
 
 
 
 
 
Houston, Texas
 
 
 
 
 
 
 
February 27, 2019
 
 
 
 
 
 
 




36


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, 2018 and 2017, the related consolidated statements of operations, stockholders’ equity and cash flows, for each of the three years in the period ended December 31, 2018 (Successor statements of operations, stockholders’ equity and cash flows), as well as the consolidated statements of operations and cash flows for the period from January 1, 2016 through April 9, 2016 (Predecessor statements of operations and cash flows), 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, as well as the period from January 1, 2016 to April 9, 2016, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2019, expressed an unqualified opinion on the Company’s internal control over financial reporting.
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. 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 to 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.
/s/ DELOITTE & TOUCHE LLP
 
 
 
Houston, Texas
 
 
February 27, 2019
 
 
 
 
 
We have served as the Company’s auditor since 2016.













37


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Tellurian, Inc.
Opinions on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Tellurian, Inc. and subsidiaries (the "Company") as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2018, of the Company and our report dated February 27, 2019, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
 
 
 
Houston, Texas
 
 
February 27, 2019
 
 





38


TELLURIAN INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share amounts)
 
 
 
 
 
December 31,
 
 
2018
 
2017
ASSETS
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
133,714

 
$
128,273

Accounts receivable
 
1,498

 
583

Accounts receivable due from related parties
 
1,316

 
1,377

Prepaids and other
 
3,906

 
3,458

Total current assets
 
140,434

 
133,691

 
 
 
 
 
Property, plant and equipment, net
 
130,580

 
115,856

Deferred engineering costs
 
69,000

 
18,000

Non-current restricted cash
 
49,875

 

Other non-current assets
 
18,659

 
9,276

Total assets
 
$
408,548

 
$
276,823

 
 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
11,597

 
$
11,462

Accrued liabilities
 
41,173

 
39,101

Other current liabilities
 

 
1,735

Total current liabilities
 
52,770

 
52,298

 
 
 
 
 
Long-term liabilities:
 
 
 
 
Senior secured term loan
 
57,048

 

Asset retirement obligation
 
796

 
638

Total long-term liabilities
 
57,844

 
638

 
 
 
 
 
Commitments and contingencies (Note 8)
 

 
 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
Preferred stock, $0.01 par value, 100,000,000 authorized: 6,123,782 and zero shares outstanding, respectively
 
61

 

Common stock, $0.01 par value, 400,000,000 authorized: 240,655,607 and 222,749,220 shares outstanding, respectively
 
2,195

 
2,043

Additional paid-in capital
 
749,537

 
549,958

Accumulated deficit
 
(453,859
)
 
(328,114
)
Total stockholders’ equity
 
297,934

 
223,887

Total liabilities and stockholders’ equity
 
$
408,548

 
$
276,823


The accompanying notes are an integral part of these consolidated financial statements.

39


TELLURIAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
 
Predecessor
 
 
 
 
 
 
 
For the
period from
January 1,
2016 through April 9, 2016
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
 
 
 
2018
 
2017
 
2016
 
 
Revenues:
 
 
 
 
 
 
 
 
 
Natural gas sales
 
$
4,423

 
$
503

 
$

 
 
$

LNG sales
 
2,689

 
3,273

 

 
 

Other LNG revenue
 
3,174

 
1,665

 

 
 

Related party
 

 

 

 
 
31

Total revenue
 
10,286

 
5,441

 

 
 
31

 
 
 
 
 
 
 
 
 
 
Operating costs and expenses:
 
 
 
 
 
 
 
 
 
Cost of sales
 
6,115

 
7,565

 

 
 

Development expenses
 
44,034

 
59,498

 
47,146

 
 
44

Depreciation, depletion and amortization
 
1,567

 
479

 
69

 
 
8

General and administrative expenses
 
81,777

 
98,874

 
46,515

 
 
617

Impairment charge and loss on transfer of assets
 
4,513

 

 

 
 

Goodwill impairment
 

 
77,592

 

 
 

Total operating costs and expenses
 
138,006

 
244,008

 
93,730

 
 
669

 
 
 
 
 
 
 
 
 
 
Loss from operations
 
(127,720
)
 
(238,567
)
 
(93,730
)
 
 
(638
)
 
 
 
 
 
 
 
 
 
 
Gain (loss) on preferred stock exchange feature
 

 
2,209

 
(3,308
)
 
 

Interest income, net
 
1,574

 
1,022

 

 
 

Other income, net
 
211

 
4,062

 
217

 
 

 
 
 
 
 
 
 
 
 
 
Loss before income taxes
 
(125,935
)
 
(231,274
)
 
(96,821
)
 
 
(638
)
Income tax benefit (provision)
 
190

 
(185
)
 
166

 
 

Net loss
 
$
(125,745
)
 
$
(231,459
)
 
$
(96,655
)
 
 
$
(638
)
 
 
 
 
 
 
 
 
 
 
Net loss per common share:
 
 
 
 
 
 
 
 
 
Basic and diluted
 
$
(0.59
)
 
$
(1.23
)
 
$
(1.01
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average shares outstanding:
 
 
 
 
 
 
 
 
 
Basic and diluted
 
211,574

 
188,536

 
95,795

 
 
 

The accompanying notes are an integral part of these consolidated financial statements.

40


TELLURIAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)
 
 
Common Stock
 
Treasury Stock
 
Convertible Preferred Stock
 
Preferred Stock
 
 
 
 
 
 
 
 
Shares
 
Par Value Amount
 
Shares
 
Cost
 
Shares
 
Par Value Amount
 
Shares
 
Par Value Amount
 
 Additional
Paid-in Capital
 
Accumulated Deficit
 
Total Stockholders’ Equity
BALANCE AT JANUARY 1, 2016 (Successor)
 

 
$

 

 
$

 

 
$

 

 
$

 
$

 
$

 
$

Common stock issued for acquisition
 
500

 
1

 

 

 

 

 

 

 
999

 

 
1,000

Issuance of common stock
 
98,356

 
98

 

 

 

 

 

 

 
57,276

 

 
57,374

Issuance of Series A preferred stock
 

 

 

 

 
5,468

 
5

 

 

 
19,380

 

 
19,385

Share-based compensation
 
10,753

 
2

 

 

 

 

 

 

 
24,493

 

 
24,495

Net loss
 

 

 

 

 

 

 

 

 

 
(96,655
)
 
(96,655
)
BALANCE AT DECEMBER 31, 2016 (Successor)
 
109,609

 
$
101

 

 
$

 
5,468

 
$
5

 

 

 
$
102,148

 
$
(96,655
)
 
$
5,599

Merger adjustments
 
51,540

 
1,390

 
(1,209
)
 

 

 

 

 

 
86,533

 

 
87,923

Share-based compensation
 
9,350

 
16

 

 

 

 

 

 

 
23,003

 

 
23,019

Issuance of common stock
 
46,373

 
465

 

 

 

 

 

 

 
311,459

 

 
311,924

Share-based payments
 
1,700

 
17

 

 

 

 

 

 

 
21,148

 

 
21,165

Reclass of embedded derivative
 

 

 

 

 

 

 

 

 
6,544

 

 
6,544

Treasury stock
 

 

 
(82
)
 
(828
)
 

 

 

 

 

 

 
(828
)
Retirement of treasury stock
 
(1,291
)
 
(1
)
 
1,291

 
828

 

 

 

 

 
(827
)
 

 

Exchange from Series A preferred stock
 

 

 

 

 
(5,468
)
 
(5
)
 

 

 

 

 
(5
)
Exchange to Series B preferred stock
 

 

 

 

 
5,468

 
55

 

 

 
(50
)
 

 
5

Exchange from Series B to common stock
 
5,468

 
55

 

 

 
(5,468
)
 
(55
)
 

 

 

 

 

Net loss
 

 

 

 

 

 

 

 

 

 
(231,459
)
 
(231,459
)
BALANCE AT DECEMBER 31, 2017 (Successor)
 
222,749

 
$
2,043

 

 
$

 

 
$

 

 
$

 
$
549,958

 
$
(328,114
)
 
$
223,887

Issuance of common stock
 
13,500

 
135

 

 

 

 

 

 

 
129,575

 

 
129,710

Issuance of Series C preferred stock
 

 

 

 

 

 

 
6,124

 
61

 
49,905

 

 
49,966

Share-based compensation(1)
 
4,407

 
17

 

 

 

 

 

 

 
20,099

 

 
20,116

Net loss
 

 

 

 

 

 

 

 

 

 
(125,745
)
 
(125,745
)
BALANCE AT DECEMBER 31, 2018 (Successor)
 
240,656

 
$
2,195

 

 
$

 

 
$

 
6,124

 
$
61

 
$
749,537

 
$
(453,859
)
 
$
297,934

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes settlement of 2017 bonus that was accrued for in December 2017.

The accompanying notes are an integral part of these consolidated financial statements.

41


TELLURIAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
 
 
 
 
 
 
 
 
 
Successor
 
 
Predecessor
 
 
 
 
 
 
 
For the period from January 1, 2016 through April 9, 2016
 
 
Year Ended December 31,
 
 
 
 
2018
 
2017
 
2016
 
 
Cash flows from operating activities:
 
 
 
 
 
 
 
 
 
   Net loss
 
$
(125,745
)
 
$
(231,459
)
 
$
(96,655
)
 
 
$
(638
)
Adjustments to reconcile net loss to net cash used in operating activities:
 
 
 
 
 
 
 
 
 
Depreciation, depletion and amortization
 
1,567

 
479

 
69

 
 
8

Goodwill impairment
 

 
77,592

 

 
 

Loss on disposal of assets
 

 

 
185

 
 
3

Provision for income tax benefit
 

 

 
(170
)
 
 

Amortization of debt issuance costs
 
267

 

 

 
 

(Gain) loss on Series A convertible preferred stock exchange feature
 

 
(2,209
)
 
3,308

 
 

Gain on sale of securities
 

 
(3,481
)
 

 
 

Share-based compensation
 
5,126

 
23,019

 
24,495

 
 

Impairment charge and loss on transfer of assets
 
4,513

 

 
&