10-K

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

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
	Part I
Item 1 and 2.	Our Business and Properties	1
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	25
Item 3.	Legal Proceedings	25
Item 4.	Mine Safety Disclosures	25
	Part II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	25
Item 6.	Selected Financial Data	26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 8.	Financial Statements and Supplementary Data	35
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	68
Item 9A.	Controls and Procedures	68
Item 9B.	Other Information	68
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	69
Item 11.	Executive Compensation	69
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	69
Item 13.	Certain Relationships and Related Transactions, and Director Independence	69
Item 14.	Principal Accounting Fees and Services	69
	Part IV
Item 15.	Exhibits, Financial Statement Schedules	70
Item 16.	Form 10-K Summary	73
Signatures		74

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

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• 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.

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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.

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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.

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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.

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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.

	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.

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	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

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• 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

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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.

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		36
Report of Independent Registered Public Accounting Firm		37
Consolidated Financial Statements:
	Consolidated Balance Sheets	39
	Consolidated Statements of Operations	40
	Consolidated Statements of Stockholders’ Equity	41
	Consolidated Statements of Cash Flows	42
	Notes to the Consolidated Financial Statements	43
Supplementary Information
	Supplemental Disclosures About Natural Gas Producing Activities (unaudited)	60
Schedule I
	Condensed Financial Information of Registrant Tellurian Inc.	64

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			—			—			—
Share-based payments	—			19,397			—			—
Net changes in working capital (Note 16)	10,520			7,433			18,338			516
Net cash used in operating activities	(103,752		)	(109,229		)	(50,430		)	(111		)
Cash flows from investing activities:
Cash received in acquisition	—			56			210			—
Acquisition and development of natural gas properties	(8,356		)	(90,099		)	—			—
Deferred engineering costs	(10,000		)	(9,000		)	—			—
Proceeds from transfer of asset	167			—			—			—
Purchase of property - land	(3,498		)	—			(9,491		)	—
Purchase of property and equipment	—			(1,114		)	(1,225		)	(268		)
Proceeds from sale of available-for-sale securities	—			4,592			—			—
Net cash used in investing activities	(21,687		)	(95,565		)	(10,506		)	(268		)
Cash flows from financing activities:
Proceeds from borrowing under term loan	59,400			—			—			—
Payments of term loan financing costs	(2,621		)	—			—			—
Proceeds from the issuance of common stock	133,800			318,204			59,015			—
Tax payments for net share settlement of equity awards (Note 16)	(5,734		)	(828		)	—			—
Proceeds from the issuance of preferred stock	—			—			25,000			—
Equity offering costs	(4,090		)	(5,707		)	(1,681		)	—
Net 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 period	128,273			21,398			—			589
Cash, cash equivalents and restricted cash, end of period	$	183,589		$	128,273		$	21,398		$	210
Supplementary disclosure of cash flow information:
Interest paid	$	(1,174	)	$	—		$	—		$	—

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

42

TELLURIAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Tellurian Inc., a Delaware corporation based in Houston, Texas (“Tellurian”), plans to develop, own and operate a global natural gas business and to deliver natural gas to customers worldwide. Tellurian has begun to establish a portfolio of natural gas production, LNG marketing, and infrastructure assets including an LNG terminal facility (the “Driftwood terminal”) and an associated pipeline (the “Driftwood pipeline”) in southwest Louisiana. Tellurian intends to develop the Driftwood pipeline as part of what we refer to as the “Pipeline Network.” In addition to the Driftwood pipeline, the Pipeline Network is expected to include two pipelines, the Haynesville Global Access Pipeline and the Permian Global Access Pipeline, both of which are currently in the early stages of development. The Driftwood terminal, the Pipeline Network and Tellurian’s existing and planned natural gas production assets are referred to collectively as the “Driftwood Project”.

On February 10, 2017 (the “Merger Date”), Tellurian Investments Inc. (“Tellurian Investments”) completed a merger (the “Merger”) with a subsidiary of Magellan Petroleum Corporation (“Magellan”). Magellan changed its corporate name to Tellurian Inc. shortly after completing the Merger. The Merger was accounted for as a “reverse acquisition,” with Tellurian Investments being treated as the accounting acquirer. As such, the historical consolidated comparative information as of and for all periods in 2016 in this report relates to Tellurian Investments and its subsidiaries. Subsequent to the Merger Date, the information relates to the consolidated entities of Tellurian Inc., with Magellan reflected as the accounting acquiree. In connection with the Merger, each issued and outstanding share of Tellurian Investments common stock was exchanged for 1.3 shares of Magellan common stock. All share and per share amounts in the Consolidated Financial Statements and related notes have been retroactively adjusted for all periods presented to give effect to this exchange, including reclassifying an amount equal to the change in par value of common stock from additional paid-in capital.

On April 9, 2016, Tellurian Investments acquired Tellurian Services LLC (“Tellurian Services”), formerly known as Parallax Services LLC (“Parallax Services”). Under the financial reporting rules of the SEC, Parallax Services (“Predecessor”) has been deemed to be the predecessor to Tellurian (“Successor”) for financial reporting purposes.

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.

Basis of Presentation

Our Consolidated Financial Statements were prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Tellurian Inc. and its wholly and majority owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

Segments

Management allocates resources and assesses financial performance on a consolidated basis. As such, for the purposes of financial reporting under GAAP during the years ended December 31, 2018, 2017 and 2016, the Company operated as a single operating segment.    

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions on a regular basis. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

The Company uses three levels of the fair value hierarchy of inputs to measure the fair value of an asset or a liability. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.

Goodwill

Goodwill resulting from a business combination is not subject to amortization. The Company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.

43

TELLURIAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenue Recognition

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), amended the previous revenue recognition guidance and required us to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted the new standard on January 1, 2018, utilizing the modified retrospective approach. We have applied the standard to all contracts as of the date of the application of the standard. We developed an accounting policy, implemented changes to the relevant business processes and the control activities within them, and evaluated the disclosure requirements as a result of the provisions of this ASU. Adoption of the ASU did not require an adjustment to the opening stockholders’ equity and did not change our amount and timing of revenues. We have elected to exclude all taxes from the measurement of transaction price.

For the sale of commodities, we consider the delivery of each unit (MMBtu) to be a separate performance obligation that is satisfied upon delivery. These contracts are either fixed price contracts or contracts with a fixed differential to an index price, both of which are considered fixed consideration. The fixed consideration is allocated to each performance obligation and represents the relative standalone selling price basis.

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “LNG sales” on the Consolidated Statements of Operations. For such LNG sales, we require payment within 10 days from delivery. Other LNG revenue represents revenue earned from sub-charter agreements and is accounted for outside of this ASU and in line with Accounting Standards Codification 840, Leases.

In our judgment, the performance obligations for the sale of natural gas and LNG are satisfied at a point in time because the customer obtains control and legal title of the asset when the natural gas or LNG is delivered to the designated sales point.

Because our performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, we have recognized amounts due from contracts with customers of $0.5 million as accounts receivable within the Consolidated Balance Sheets as of December 31, 2018.

Cash, Cash Equivalents and Restricted Cash

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents that are restricted as to withdrawal or use under the terms of certain contractual agreements are recorded in Non-current restricted cash on our Consolidated Balance Sheets.

Concentration of Cash

We maintain cash balances and restricted cash at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the criteria for and we elect the normal purchases and sales exception.

Changes in the fair value of our derivative instruments are recorded in earnings, and, at present, we have elected not to apply hedge accounting. See Note 12, Financial Instruments for additional details about our derivative instruments.

Property, Plant and Equipment

Natural gas development and production activities are accounted for using the successful efforts method of accounting. Costs incurred to acquire a property (whether unproved or proved) are capitalized when incurred. Lease rentals are expensed as incurred. Natural gas exploratory costs are expensed as incurred and costs to develop proved reserves are capitalized. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. We deplete our natural gas reserves using the units-of-production method.

Fixed assets are recorded at cost. We depreciate our property, plant and equipment, excluding land, using the straight-line depreciation method over the estimated useful life of the asset. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed, and the resulting gains or losses are recorded in our Consolidated Statements of Operations. Management tests property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of property, plant and equipment might not be recoverable.

44

TELLURIAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accounting for LNG Development Activities

As we have been in the preliminary stage of developing the Driftwood terminal, substantially all of the costs to date related to such activities have been expensed. These costs primarily include professional fees associated with FEED studies and applying to FERC for authorization to construct our terminals and other required permitting for the Driftwood Project.

Costs incurred in connection with a project to develop the Driftwood terminal shall generally be treated as development expenses until the project has reached the notice-to-proceed state (“NTP State”) and the following criteria (the “NTP Criteria”) have been achieved: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. In addition to the above, certain costs incurred prior to achieving the NTP State will be capitalized though the NTP Criteria have not been met. Costs to be capitalized prior to achieving the NTP State include land purchase costs, land improvement costs, costs associated with preparing the facility for use and any fixed structure construction costs (fence, storage areas, drainage, etc.). Furthermore, activities directly associated with detailed engineering and/or facility designs shall be capitalized.

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.

Debt

Discounts and expenses incurred with the issuance of debt are amortized over the term of the debt. These amounts are presented as a reduction of Senior secured term loan on the accompanying Consolidated Balance Sheets. See Note 13, Long-Term Borrowings, for additional details about our Senior secured term loan.

Income Taxes

We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, we determine deferred tax assets and liabilities on the basis of the differences between the financial statement and tax basis of assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to be realized or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a determination, we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. If we determine that we would be able to realize our deferred tax assets in the future in excess of their net recorded amount, we would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.

Net Loss Per Share (EPS)

Basic net loss per share excludes dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period. Diluted net loss per share reflects potential dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued and were dilutive.

NOTE 2 — MERGER AND ACQUISITION

The Merger

As discussed in Note 1, Basis of Presentation and Summary of Significant Accounting Policies, Tellurian Investments merged with a subsidiary of Magellan on February 10, 2017. The Merger has been accounted for as a “reverse acquisition,” with Tellurian Investments being treated as the accounting acquirer using the acquisition method.

The total consideration exchanged was as follows (in thousands, except share and per-share amounts):

45

TELLURIAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

Number of shares of Magellan common stock outstanding (1)	5,985,042
Price per share of Magellan common stock (2)	$	14.21
Aggregate value of Tellurian common stock issued			$	85,048
Fair value of stock options (3)			2,821
Net purchase consideration to be allocated			$	87,869
(1) The number of shares of Magellan common stock issued and outstanding as of February 9, 2017.
(2) The closing price of Magellan common stock on the NASDAQ on February 9, 2017.
(3) The estimated fair value of Magellan stock options for pre-Merger services rendered.

We utilized estimated fair values at the Merger Date for the allocation of consideration to the net tangible and intangible assets acquired and liabilities assumed. The purchase price allocation to assets acquired and liabilities assumed in the Merger was as follows (in thousands):

Fair Value of Assets Acquired:
Cash	$	56
Securities available-for-sale	1,111
Other current assets	93
Unproved properties	13,000
Wells in progress	332
Land, buildings and equipment, net	67
Other long-term assets	19
Total assets acquired	14,678
Fair Value of Liabilities Assumed:
Accounts payable and other liabilities	4,393
Notes payable	8
Total liabilities assumed	4,401
Total net assets acquired	10,277
Goodwill as a result of the Merger	$	77,592

We valued our interests acquired in unproved oil and gas properties using a market approach based on commercial negotiations and bids received for the interests (see Note 5, Property, Plant and Equipment, for more information about the properties). The fair value of other property, plant and equipment and wells in progress was determined to be the carrying value of Magellan. Securities available-for-sale were valued based on quoted market prices. The carrying values of cash, other current assets, accounts payable and accrued liabilities and other non-current assets and liabilities approximated fair value at the Merger Date. The Company has determined that such fair value measures for the overall allocation are classified as Level 3 in the fair value hierarchy.

Goodwill recognized as a result of the Merger totaled approximately $77.6 million, none of which is deductible for income tax purposes. Subsequent to the Merger, the Company determined that there is no evidence that we will recover the value of this goodwill and an impairment expense of approximately $77.6 million was recognized during the year ended December 31, 2017. For purposes of determining the goodwill impairment, we utilized qualitative factors as well as the fair values determined when allocating consideration as of the Merger Date.

Parallax Services Acquisition

On April 9, 2016, Tellurian Investments acquired Parallax Services, which was renamed Tellurian Services, with equity consideration valued at approximately $1 million. The transaction was accounted for using the acquisition method.

Pro Forma Results

The following table provides unaudited pro forma results for the year ended December 31, 2017, and 2016, as if the Merger occurred and Parallax Services had been acquired as of January 1, 2016 (in thousands, except per-share amounts):

46

TELLURIAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

	Year Ended December 31,
	2017			2016
Pro forma net loss	$	(235,201	)	$	(100,734	)
Pro forma net loss per basic share	$	(1.24	)	$	(0.98	)
Pro forma basic and diluted weighted average common shares outstanding	189,246			102,281

The unaudited pro forma results include adjustments for the historical net loss of Magellan and Parallax Services as well as an increase in compensation expense associated with the addition of three new directors. The pro forma information is provided for informational purposes only and is not necessarily indicative of what Tellurian’s results of operations would have been if the Merger and acquisition of Parallax Services had occurred on January 1, 2016. Following the Merger Date, approximately $0.8 million of net loss related to the acquired activities has been included in our Consolidated Financial Statements.

NOTE 3 — DEFERRED ENGINEERINGCOSTS

Deferred engineering costs of $69.0 million at December 31, 2018 and $18.0 million at December 31, 2017 represent detailed engineering services related to the Driftwood terminal. Such costs will be deferred until construction commences on the Driftwood terminal, at which time they will be transferred to construction in progress.

NOTE 4 — TRANSACTIONS WITH RELATED PARTIES

Accounts Receivable due from Related Parties

Tellurian’s accounts receivable due from related parties primarily consists of tax indemnities from employees who received share-based compensation in 2016.

Accounts Payable due to Related Parties

In December 2017, Tellurian and Martin Houston, a major shareholder and Vice Chairman of the Company, agreed to mutually discharge $0.3 million owed by Tellurian to entities partially owned by Mr. Houston.

Non-current Note Receivable due from Related Party

In July 2017, the $0.3 million non-current note receivable due from Mr. Houston was repaid in full, and the demand note evidencing the receivable was canceled.

Other

During the year ended December 31, 2018, the Company incurred approximately $0.1 million in legal fees to a law firm for various legal advice. During the year ended December 31, 2017, the Company incurred $0.7 million in legal fees to the same law firm for advice associated with a lawsuit that was settled in April 2017. A member of our board of directors is a partner at such law firm.

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of fixed assets and oil and natural gas properties, as shown below (in thousands):

	December 31,
	2018			2017
Land	$	13,276		$	9,491
Proved properties	101,459			90,869
Unproved properties	10,204			13,000
Wells in progress	4,660			345
Corporate and other	2,905			2,693
Total fixed assets, at cost	132,504			116,398
Accumulated depreciation and depletion	(1,924		)	(542		)
Total property, plant and equipment, net	$	130,580		$	115,856

Depreciation and depletion expense for the years ended December 31,2018, 2017 and 2016 was approximately $1.5 million, $0.5 million and $0.1 million, respectively.

47

TELLURIAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

Land

We own land in Louisiana for the purpose of constructing the Driftwood Project.

Proved Properties

We own producing and non-producing acreage in northern Louisiana. In September 2018, we identified indicators of impairment related to certain non-producing acreage that led to an impairment charge of approximately $2.7 million.

Unproved Properties

We own interests in unproved properties in the Weald Basin, United Kingdom through our holding of non-operating interests in two licenses which expire in June and September 2021. We previously held an operating interest in an exploration permit in the Bonaparte Basin, Australia; however, in May 2018, we transferred the permit to a third party for consideration of approximately $0.2 million in cash and the release of approximately $1.3 million in liabilities incurred in connection with a canceled 2017 seismic survey. As a result, we have recognized, within our Consolidated Statement of Operations, a loss on the transfer of the permit of approximately $1.0 million during the current year.

NOTE 6 — OTHER NON-CURRENT ASSETS

Other non-current assets consist of the following (in thousands):

	December 31, 2018		December 31, 2017
Land lease and purchase options	$	4,115	$	2,948
Permitting costs	12,585		4,708
Other	1,959		1,620
Total other non-current assets	$	18,659	$	9,276

Land Lease and Purchase Options

We hold lease and purchase option agreements (the “Options”) for certain tracts of land and associated river frontage that provide for four or five-year terms. In addition to the Options, the Company holds a ground lease for a port facility adjacent to a tract of land that was acquired in March 2016. The lease provides for a four-year term, subject to a 20-year extension and sixfive-year renewals. The ground lease is accounted for as an operating lease, with rental payments accounted for using the straight-line method.

Upon exercise of the Options, the leases are subject to maximum terms of 60 years (inclusive of various renewals) at the option of the Company. Lease and purchase option payments have been capitalized in other non-current assets. Costs of the Options will be amortized over the life of the lease once obtained, or capitalized into the land if purchased.

Permitting Costs

Permitting costs primarily represent the purchase of wetland credits in connection with our permit application to the USACE in 2018 and 2017. These wetland credits will be applied to our permit in accordance with the Clean Water Act and the Rivers and Harbors Act, which require us to mitigate the impact to the Louisiana wetlands caused by the construction of the Driftwood Project. If the USACE permit is secured, the permitting costs will be capitalized and depreciated with the total cost to construct the Driftwood Project.

NOTE 7 — ACCRUED LIABILITIES

The components of accrued liabilities consist of the following (in thousands):

	December 31,
	2018		2017
Project development activities	$	8,879	$	5,142
Payroll and compensation	23,286		25,833
Accrued taxes	2,507		2,764
Professional services (e.g., legal, audit)	2,423		2,806
Accrued rent and other	4,078		2,556
Total accrued liabilities	$	41,173	$	39,101

48

TELLURIAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

NOTE 8 — COMMITMENTS AND CONTINGENCIES

Litigation

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, now known as Tellurian Services) on the other hand (collectively, “Parallax”). In October 2017, Driftwood Pipeline LLC (“Driftwood Pipeline”) and Tellurian Services 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 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.

Contractual Obligations

The Company is obligated under various non-cancelable operating lease agreements for office facilities that generally provide for minimum rent payments and a proportionate share of operating expenses and property taxes and include certain renewal and expansion options. For the years ended December 31, 2018, 2017 and 2016, rent expense under these lease arrangements was $3.2 million, $2.3 million and $0.5 million, respectively.

At December 31, 2018, contractual obligations for long-term operating leases and purchase obligations are as follows (in thousands):

	2019		2020		2021		2022		2023		Thereafter		Total
Office leases	$	3,126	$	3,510	$	3,440	$	3,718	$	3,993	$	8,061	$	25,848
Land lease and purchase options	1,588		634		23		23		23		436		2,727
Other	499		499		2		—		—		—		1,000
	$	5,213	$	4,643	$	3,465	$	3,741	$	4,016	$	8,497	$	29,575

NOTE 9 — SHARE-BASED COMPENSATION

We have granted restricted stock, restricted stock units and phantom units (collectively, “Restricted Stock”), as well as unrestricted stock and stock options, to employees, directors and outside consultants (collectively, the “grantees”) under the Tellurian Inc. 2016 Omnibus Incentive Compensation Plan, as amended (the “2016 Plan”), and the Amended and Restated Tellurian Investments Inc. 2016 Omnibus Incentive Plan (the “Legacy Plan”). The maximum number of shares of Tellurian common stock authorized for issuance under the 2016 Plan is 40 million shares of common stock, and no further awards can be made under the Legacy Plan.

For the year ended December 31, 2018, share-based compensation expense related to all share-based awards totaled approximately $5.1 million. For the year ended December 31, 2017, share-based compensation expense related to all share-based awards totaled approximately $23.0 million, approximately $2 million of which was issued in settlement of bonuses accrued at December 31, 2016. For the year ended December 31, 2016, share-based compensation expense related to all share-based awards totaled approximately $24.5 million. As of December 31, 2018, unrecognized compensation expense, based on the grant date fair value, for all share-based awards totaled approximately $197.0 million.

Restricted Stock

Upon the vesting of restricted stock, shares of common stock will be released to the grantee. Upon the vesting of certain restricted stock units, the units will be converted into shares of common stock and released to the grantee. In March 2018, we began issuing phantom units that may be settled in either cash, stock or a combination thereof.As of December 31, 2018, there was no Restricted Stock that would be required to be settled in cash.

As of December 31, 2018, we had granted approximately 24.4 million shares of performance-based Restricted Stock, of which approximately 19.8 million shares will vest entirely based upon an affirmative final investment decision (“FID”) by the Company’s board of directors, as defined in the award agreements, and approximately 4.0 million shares will vest in one-third increments at FID and the first and second anniversary of FID. The remaining shares of performance-based Restricted Stock, totaling approximately 0.6 million shares, will vest based on other criteria. As of December 31, 2018, no expense had been recognized in connection with performance-based Restricted Stock.

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The fair value of the Restricted Stock was established by the market price on the date of grant and, for service-based awards, is being recognized as compensation expense ratably over the vesting term.

The following table provides a summary of our Restricted Stock transactions for the year ended December 31, 2018 (shares and units in thousands):

	Shares		Weighted-Average Grant Date Fair Value
Unvested at January 1, 2018	20,488		$	6.95
Granted (1)	4,311		11.02
Vested	(213	)	11.60
Forfeited	(202	)	11.73
Unvested at December 31, 2018	24,384		$	7.59

⁽¹⁾ The weighted-average grant date fair value of Restricted Stock granted during the years ended December 31, 2018, 2017 and 2016 was $11.02, $9.59 and $3.52, respectively.

The total grant date fair value of restricted stock vested during the years ended December 31, 2018, 2017 and 2016 was approximately $2.5 million, $3.7 million and $0.4 million, respectively.

Stock Options

The 2016 Plan participants have been granted non-qualified options to purchase shares of common stock. Stock options are granted at a price not less than the market price of the common stock on the date of grant. Stock options vest equally over a three-year period from the date of grant. Options shall be exercisable at such time and under such conditions set forth in the underlying award agreement, but in no event shall any option be exercisable later than the tenth anniversary of the date of its grant. The fair value of each stock option award is estimated using the Black-Scholes option pricing model.

The following table provides a summary of our stock option transactions for the year ended December 31, 2018 (stock options in thousands):

	Stock Options		Weighted Average Exercise Price
Outstanding at January 1, 2018	2,011		$	10.32
Granted	—		—
Exercised	—		—
Forfeited or Expired	(23	)	10.32
Outstanding at December 31, 2018	1,988		$	10.32
Exercisable at December 31, 2018	665		$	10.32

Valuation assumptions used to value stock options for the year ended December 31, 2017 (there were no stock options granted in 2018 or 2016), were as follows:

	December 31, 2017
Expected term (in years)	6.0
Expected volatility	22.13	%
Expected dividend yields	—	%
Risk-free rate	2.05	%

Due to our limited history, the Company has elected to apply the simplified method to determine the expected term. Additionally, due to our limited history, expected volatility is based on the implied volatility of the Company's peer group as identified by our board of directors. The expected dividend yield is based on historical yields on the date of grant. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

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There were no stock options granted or exercised during the year ended December 31, 2018. There were 2.0 million stock options granted during the year ended December 31, 2017, with the weighted average grant date fair value of $2.72. No stock options were exercised during the year ended December 31, 2017. There were no stock options granted or exercised during the year ended December 31, 2016.

NOTE 10 — SHARE-BASED PAYMENTS

For the year ended December 31, 2018 and 2017, Tellurian recognized approximately $0.0 million and $19.4 million as share-based expense for various third-party provided services.

In February 2017, the Company issued 409,800 shares of Tellurian common stock, valued at approximately $5.8 million, to a financial adviser in connection with the successful completion of the Merger. This cost has been included in general and administrative expenses in the Consolidated Statements of Operations. Additionally, on the Merger Date, the Company issued 90,350 shares of Tellurian common stock to settle a liability assumed in the Merger valued at approximately $1.3 million.

In March 2017, the Company’s board of directors approved the issuance of 1.0 million shares that were purchased at a discount by a commercial development consultant under the Omnibus Plan. The terms of the share purchase agreement did not contain performance obligations or similar vesting provisions; accordingly, the full amount of approximately $11.4 million, representing the aggregate difference between the purchase price of $0.50 per share and the fair value on the date of issuance of $11.88 per share, was recognized on the date of the share purchase and has been included in general and administrative expenses in the Consolidated Statements of Operations.

Also in March 2017, the Company issued 200,000 shares under a management consulting arrangement for specified services performed from March 2017 through May 2017. The services were valued at $11.34 per share on the date of issuance. The total cost of approximately $2.3 million was amortized to general and administrative expenses on a straight-line basis over the three-month service period in the Consolidated Statements of Operations.

NOTE 11 — INCOME TAXES

Income tax benefit (provision) included in our reported net loss consisted of the following (in thousands):

	Year Ended December 31,
	2018		2017			2016
Current:
Federal	$	—	$	—		$	—
State	—		—			(4		)
Foreign	190		(185		)	—
Total Current	190		(185		)	(4		)
Deferred:
Federal	—		—			170
State	—		—			—
Foreign	—		—			—
Total Deferred	—		—			170
Total income tax benefit (provision)	$	190	$	(185	)	$	166

The sources of loss from operations before income taxes were as follows (in thousands):

	Year Ended December 31,
	2018			2017			2016
Domestic	$	(115,137	)	$	(223,991	)	$	(95,739	)
Foreign	(10,798		)	(7,283		)	(1,082		)
Total loss before income taxes	$	(125,935	)	$	(231,274	)	$	(96,821	)

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:

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	Year Ended December 31,
	2018			2017			2016
Income tax benefit (provision) at U.S. statutory rate	$	26,446		$	80,946		$	33,887
Share-based compensation	—			—			(5,911		)
Impairment	—			(27,969		)	—
Change in U.S. tax rate	—			(30,562		)	—
Change in valuation allowance due to change in U.S. tax rate	—			30,562			—
U.S. state tax	7,955			—			—
Change in valuation allowance	(32,086		)	(51,030		)	(26,398		)
Other	(2,125		)	(2,132		)	(1,412		)
Total income tax benefit (provision)	$	190		$	(185	)	$	166

Significant components of our deferred tax assets and liabilities are as follows (in thousands):

	December 31,
	2018			2017
Deferred tax assets:
Capitalized engineering costs	$	6,353		$	2,812
Capitalized start-up costs	19,290			17,881
Compensation and benefits	3,862			5,465
Net operating loss carryforwards and credits:
Federal	37,822			19,423
State	4,979			522
Foreign	2,392			1,694
Other, net	8,328			3,541
Deferred tax assets	83,026			51,338
Less valuation allowance	(83,026		)	(50,942		)
Deferred tax assets, net of valuation allowance	—			396
Deferred tax liabilities	—			(396		)
Net deferred tax assets	$	—		$	—

The Tax Cuts and Jobs Act of 2017 (the “Act”) was enacted on December 22, 2017, and has several key provisions impacting the accounting for, and reporting of, income taxes. On December 22, 2017, the SEC issued Staff Accounting Bulletin No. 118, which allows companies to report the income tax effects of the Act as a provisional amount based on a reasonable estimate, which would be subject to adjustment during a reasonable measurement period, not to exceed twelve months, until the accounting and analysis under ASC 740 is complete. We incorporated the impact of the Tax Act in our results of operations and calculated provisional amounts for the tax effects of the Tax Act that could be reasonably estimated. At December 31, 2017, we recorded a $30.6 million unfavorable impact on the Company’s gross U.S. deferred tax assets and a corresponding $30.6 million favorable impact to the valuation allowance. We have not recorded an adjustment to these amounts. As of December 31, 2018, our accounting for the impact of the Tax Act was complete.

As of December 31, 2018, we had federal, state and international net operating loss (“NOL”) carryforwards of $180.1 million, $113.7 million and $13.6 million, respectively. Approximately $88.4 million of these NOLs have an indefinite carryforward period. All other NOLs will expire between 2036 and 2037.

Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal, state and international deferred tax assets as of December 31, 2018, and 2017. We will continue to evaluate the realizability of our deferred tax assets in the future. The increase in the valuation allowance was $32.1 million for the year ended December 31, 2018.

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In addition, we experienced a Section 382 ownership change in April 2017. An analysis of the annual limitation on the utilization of our NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not materially limit the use of our NOLs over the carryover period. We will continue to monitor trading activity in our shares which could cause an additional ownership change. If the Company experiences a Section 382 ownership change, it could further affect our ability to utilize our existing NOL carryforwards.

As of December 31, 2018, the Company determined that it has no uncertain tax positions, interest or penalties as defined within ASC 740-10. The Company does not have unrecognized tax benefits. The Company does not believe that it is reasonably possible that the total unrecognized benefits will significantly increase within the next 12 months.

We are subject to tax in the U.S. and various state and foreign jurisdictions. We are not currently under audit by any taxing authority. Federal and state tax returns filed with each jurisdiction remain open to examination under the normal three-year statute of limitations.

Pursuant to ASC 740-30-25-17, the Company recognizes deferred tax liabilities associated with outside basis differences on investments in foreign subsidiaries unless the difference is considered essentially permanent in duration. As of December 31, 2018, the Company has not recorded any deferred taxes on unremitted earnings as the Company has no undistributed earnings and profits. If circumstances change in the foreseeable future and it becomes apparent that some or all of the undistributed earnings and profits will not be reinvested indefinitely, or will be remitted in the foreseeable future, a deferred tax liability will be recorded for some or all of the outside basis difference.

NOTE 12 — FINANCIAL INSTRUMENTS

As discussed in Note 13, Long-Term Borrowings, as part of entering into the senior secured term loan credit agreement, we are required to enter into and maintain certain hedging transactions to remain compliant with a specific negative covenant. As a result, we use derivative financial instruments, namely over the counter (“OTC”) commodity swap instruments (collectively “commodity swaps”), to maintain compliance with this covenant. We do not hold or issue derivative financial instruments for trading purposes.

Commodity swap agreements involve payments to or receipts from counterparties based on the differential between two prices for the commodity, and also include basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices, as also required by the negative covenant of the senior secured term loan credit agreement.

The fair value of our commodity swaps is classified as Level 2 in the fair value hierarchy and is based on standard industry income approach models that use significant observable inputs, including but not limited to New York Mercantile Exchange (NYMEX) natural gas forward curves and basis forward curves, all of which are validated to external sources, at least monthly.

The Company recognizes all derivative instruments as either assets or liabilities at fair value on a net basis as they are with a single counterparty and subject to a master netting arrangement. These derivative instruments are reported as either current or non-current assets or current or non-current liabilities, based on their maturity dates. The Company can net settle its derivative instruments at any time. As of December 31, 2018, we had a current liability of $0.2 million, net, with respect to the fair value of the current portion of our commodity swaps. In addition, as of December 31, 2018, we had a non-current asset of $0.3 million, net, with respect to the fair value of the non-current portion of our commodity swaps. The current liability and the non-current asset are classified within Accrued liabilities and Other non-current assets, respectively, on the Consolidated Balance Sheets. Gross current asset and current liability amounts are $0.4 million and $0.6 million, respectively. Gross non-current asset and non-current liability amounts are $0.6 million and $0.3 million, respectively.

We do not apply hedge accounting for our commodity swaps; therefore, all changes in fair value of the Company’s derivative instruments are recognized within Other income, net, in the Consolidated Statements of Operations. For the year ended December 31, 2018, we recognized a realized loss of $0.1 million and an unrealized gain of $0.1 million related to the changes in fair value of the commodity swaps in our Consolidated Statements of Operations. Derivative contracts which result in physical delivery of a commodity expected to be used or sold by the Company in the normal course of business are designated as normal purchases and sales and are exempt from derivative accounting. OTC arrangements require settlement in cash. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Consolidated Statements of Cash Flows. 

With respect to the commodity swaps, the Company hedged portions of expected sales of equity production and portions of its basis exposure cover approximately 19.3 Bcf and 19.3 Bcf of natural gas, respectively, as of December 31, 2018. The open positions at December 31, 2018 had maturities extending through September 2021. 

For additional details, refer to Note 13, Long-Term Borrowings.

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NOTE 13 — LONG-TERM BORROWINGS

On September 28, 2018 (the “Closing Date”), Tellurian Production Holdings LLC (“Production Holdings”), our wholly owned subsidiary, entered into a three-year senior secured term loan credit agreement (the “Term Loan”) in an aggregate 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. The discount and fees are being amortized over the term of the Term Loan on a straight-line basis. At December 31, 2018, the outstanding principal amount of the Term Loan was $60.0 million. In addition, the unamortized discount and deferred financing costs, as of December 31, 2018 were $3.0 million.

Our 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 is presented within non-current restricted cash on our Consolidated Balance Sheet. At December 31, 2018, unused proceeds from the Term Loan classified as non-current restricted cash were $49.6 million.

We have the right, but not the obligation, to make voluntary principal payments starting six months following the Closing Date in a minimum amount of $5.0 million or any integral multiples of $1.0 million in excess thereof. If no voluntary principal payments are made, the principal amount, together with any accrued interest, is payable at the maturity date of September 28, 2021.

The Term Loan can be terminated early with an early termination payment equal to the outstanding principal plus accrued interest. 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. 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. For the year ended December 31, 2018, our total interest expense associated with the Term Loan was $1.2 million.

Guarantors and Covenants

Amounts borrowed under the Term Loan are guaranteed by Tellurian Inc. and each of Production Holdings’ subsidiaries. The Term Loan is collateralized by a first priority lien on all assets of Production Holdings and its subsidiaries, including domestic properties described in Note 5, Property, Plant and Equipment.

The Term Loan contains specific financial covenants and as of December 31, 2018, we remained in compliance with such covenants under the Term Loan.

For details of hedging transactions, as at and for the year ended December 31, 2018, entered into for the purposes of the Term Loan, refer to Note 12, Financial Instruments.

Long-Term Borrowings Maturities

A summary of long-term borrowings maturities is as follows (in thousands):

Years Ending December 31,	Principal Payments
2019	$	—
2020	—
2021	60,000
Total	$	60,000

Fair Value

As of December 31, 2018, the carrying value of the Term Loan approximated fair value. The Term Loan is a Level 3 instrument in the fair value hierarchy. The Level 3 estimated fair value approximates the carrying value because the interest rates are variable and reflective of market rates, and the debt may be repaid, in full or in part, at any time with minimum penalty (as noted above, 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).

NOTE 14 — STOCKHOLDERS' EQUITY

At-the-Market Program

We maintain an at-the-market equity offering program pursuant to which we may sell shares of our common stock from time to time on Nasdaq through Credit Suisse Securities (USA) LLC acting as sales agent. We have availability under the at-the-market program to raise aggregate sales proceeds of up to $189.7 million.  

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Preferred Stock

In March 2018, we entered into a preferred stock purchase agreement with BDC Oil and Gas Holdings, LLC (“Bechtel Holdings”), a Delaware limited liability company and an affiliate of Bechtel Oil, Gas and Chemicals, Inc., a Delaware corporation (“Bechtel”), pursuant to which we sold to Bechtel Holdings approximately 6.1 million shares of our Series C convertible preferred stock (the “Preferred Stock”).

In exchange for the Preferred Stock, Bechtel agreed to discharge approximately $22.7 million of the outstanding liabilities associated with the detailed engineering services for the Driftwood Project, and to apply approximately $27.3 million to additional future detailed engineering services. During the year ended December 31, 2018, all of the approximately $27.3 million of future services were received and, as such, all $50.0 million have been recognized on our Consolidated Balance Sheets within deferred engineering costs. See Note 3, Deferred Engineering Costs, for further information regarding the costs associated with the detailed engineering services.

The holders of the Preferred Stock do not have dividend rights but do have a liquidation preference over holders of our common stock. The holders of the Preferred Stock may convert all or any portion of their shares into shares of our common stock on a one-for-one basis. At any time after “Substantial Completion” of “Project 1,” each as defined in and pursuant to the LSTK EPC agreement for the Driftwood LNG Phase 1 Liquefaction Facility, dated as of November 10, 2017, or at any time after March 21, 2028, we have the right to cause all of the Preferred Stock to be converted into shares of our common stock on a one-for-one basis. The Preferred Stock has been excluded from the computation of diluted loss per share because including it in the computation would have been antidilutive for the periods presented.

In March 2017, GE Oil & Gas, Inc. (now known as GE Oil & Gas, LLC) (“GE”), as the holder of all 5.5 million outstanding shares of Tellurian Investments Series A convertible preferred stock (the “Tellurian Investments Preferred Shares”), exchanged those shares into an equal number of shares of Tellurian Inc. Series B convertible preferred stock (the “Series B Preferred Stock”) pursuant to the terms of the Tellurian Investments Certificate of Incorporation (the “Preferred Share Exchange”). The terms of the Series B Preferred Stock were substantially similar to those of the Tellurian Investments Preferred Shares. The Series B Preferred Stock was exchangeable at any time into shares of the Company’s common stock on a one-for-one basis, subject to anti-dilution adjustments in certain circumstances.

The ability of GE to exchange the Tellurian Investments Preferred Shares into shares of Series B Preferred Stock or into shares of Tellurian common stock following the Merger required the fair value of such features to be bifurcated from the contract and recognized as an embedded derivative until the Merger Date.

The fair value of the embedded derivative was determined through the use of a model which utilizes certain observable inputs such as the price of Magellan common stock at various points in time and the volatility of Magellan common stock over an assumed half-year and one-year holding period from February 10, 2017 and December 31, 2016, respectively. At each valuation date, the model also included (i) unobservable inputs related to the weighted probabilities of certain Merger-related scenarios and (ii) a discount for the lack of marketability determined through the use of commonly accepted methods. We have therefore classified the fair value measurements of this embedded derivative as Level 3 inputs. On the Merger Date, the embedded derivative was reclassified to additional paid-in capital in accordance with GAAP.

The following table summarizes the changes in fair value for the embedded derivative (in thousands):

	February 10, 2017			December 31, 2016
Fair value at the beginning of period and initial fair value, respectively	$	8,753		$	5,445
(Gain) loss on exchange feature	(2,209		)	3,308
Fair value at the end of the period and year, respectively	$	6,544		$	8,753

In June 2017, GE, as the holder of all 5.5 million outstanding shares of Series B Preferred Stock, exercised its right to convert all such shares of Series B Preferred Stock into 5.5 million shares of Tellurian common stock pursuant to and in accordance with the terms of the Series B Preferred Stock.

Public Equity Offerings and Exercise of Overallotment

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

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In December 2017, we issued 10.0 million shares of common stock for proceeds of approximately $94.8 million, net of approximately $5.2 million in fees and commissions. The underwriters were granted an option to purchase up to an additional 1.5 million shares of common stock within 30 days. In January 2018, the underwriters exercised their option to purchase an additional 1.5 million shares of our common stock for proceeds of approximately $14.5 million, net of approximately $0.5 million in fees and commissions.

TOTAL Investment

In January 2017, pursuant to a common stock purchase agreement dated as of December 19, 2016, between Tellurian Investments and TOTAL Delaware, Inc. (“TOTAL”), TOTAL purchased, and Tellurian Investments sold and issued to TOTAL, approximately 35.4 million shares of Tellurian Investments common stock for an aggregate purchase price of $207 million, net of offering costs. In connection with the Merger, the shares purchased by TOTAL were exchanged for approximately 46 million shares of Tellurian common stock.

In May 2017, Tellurian and TOTAL entered into a pre-emptive rights agreement pursuant to which TOTAL was granted a right to purchase its pro rata portion of any new equity securities that Tellurian may issue to a third party on the same terms and conditions as such equity securities are offered and sold to such party, subject to certain excepted offerings (the “Pre-emptive Rights Agreement”). Pursuant to the common stock purchase agreement dated as of December 19, 2016, between Tellurian Investments and TOTAL, the terms and conditions of the Pre-emptive Rights Agreement are similar to those contained in the pre-emptive rights agreement dated as of January 3, 2017, between Tellurian Investments and TOTAL, but the Pre-emptive Rights Agreement is subject to additional excepted offerings.

Retirement of Treasury Stock

In December 2017, the Company retired approximately 1.3 million shares of treasury stock. These retired shares are now included in the Company’s pool of authorized unissued shares.

NOTE 15 — LOSS PER SHARE

The following table summarizes the computation of basic and diluted loss per share (in thousands, except per-share amounts):

	Year Ended December 31,
	2018			2017			2016
Net loss	$	(125,745	)	$	(231,459	)	$	(96,655	)
Basic weighted average common shares outstanding	211,574			188,536			95,795
Loss per share:
Basic and diluted	$	(0.59	)	$	(1.23	)	$	(1.01	)

As of December 31, 2018, 2017 and 2016, the effect of 24.4 million, 19.9 million and 11.5 million, respectively, of unvested restricted stock awards that could potentially dilute basic EPS in the future were not included in the computation of diluted EPS because to do so would have been antidilutive for the periods presented. In addition, as of December 31, 2018 and 2017, the effect of 2.0 million and 2.0 million options, respectively, and, as of December 31, 2018, the effect of 6.1 million shares of the Preferred Stock, all of which could potentially dilute basic EPS in the future, were not included in the computation of diluted EPS because to do so would have been antidilutive for the periods presented. As such, basic and diluted EPS are the same for all periods presented.

NOTE 16 — SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides information regarding the net changes in working capital (in thousands):

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	Successor									Predecessor
										For the period from January 1, 2016 through April 9, 2016
	Year Ended December 31,
	2018			2017			2016
Accounts receivable	$	(958	)	$	(442	)	$	(39	)	$	1
Accounts receivable due from related parties	62			(60		)	(124		)	(32		)
Prepaids and other current assets	(431		)	(1,419		)	(1,936		)	13
Note receivable due from related party	—			251			—			—
Accounts payable and accrued expenses	23,251			11,338			22,393			281
Accounts payable due to related parties	—			—			(53		)	253
Other, net	(11,404		)	(2,235		)	(1,903		)	—
Net changes in working capital	$	10,520		$	7,433		$	18,338		$	516

The following table provides supplemental disclosure of cash flow information (in thousands):

	Successor						Predecessor
							For the period from January 1, 2016 through April 9, 2016
	Year Ended December 31,
	2018		2017		2016
Net cash paid for income taxes	$	—	$	—	$	4	$	—
Property, plant and equipment non-cash accruals	8,630		83		46		75
Non-cash settlement of withholding taxes associated with the 2017 bonus accrual and vesting of certain awards	5,733		828		—		—
Non-cash settlement of the 2017 bonus accrual	15,202		—		—		—
Asset retirement obligation additions and revisions	115		—		—		—
Equity offering cost accrual	—		65		128		—

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of such amounts shown in the Consolidated Statements of Cash Flows (in thousands):

	Successor						Predecessor
							For the period from January 1, 2016 through April 9, 2016
	Year Ended December 31,
	2018		2017		2016
Cash and cash equivalents	$	133,714	$	128,273	$	21,398	$	210
Non-current restricted cash	49,875		—		—		—
Total cash, cash equivalents and restricted cash in the statement of cash flows	$	183,589	$	128,273	$	21,398	$	210

NOTE 17 — INTERIM FINANCIAL INFORMATION (UNAUDITED)

Amounts presented are in thousands, except, per share amounts (certain amounts may not recalculate exactly due to rounding):

57

TELLURIAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year Ended December 31, 2018
Total revenue	$	6,801		$	813		$	799		$	1,872
Loss from operations	(25,392		)	(36,658		)	(34,384		)	(31,287		)
Net loss	(25,184		)	(35,854		)	(33,191		)	(31,516		)
Net loss per common share - basic and diluted	(0.12		)	(0.17		)	(0.15		)	(0.14		)
Weighted average shares outstanding - basic and diluted	204,772			206,531			217,380			217,408
Year Ended December 31, 2017
Total revenue	$	—		$	—		$	—		$	5,441
Loss from operations	(143,721		)	(32,899		)	(26,095		)	(35,852		)
Net loss	(141,349		)	(32,523		)	(22,864		)	(34,723		)
Net loss per common share - basic and diluted	(0.92		)	(0.17		)	(0.12		)	(0.18		)
Weighted average shares outstanding - basic and diluted	154,213			186,102			192,405			194,978

NOTE 18 — RECENT ACCOUNTING STANDARDS

The following table provides a description of recent accounting standards that had not been adopted by the Company as of December 31, 2018:

58

TELLURIAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This standard may be early adopted and must be adopted using a modified retrospective approach with certain available practical expedients, one of which is an option of applying the requirements of the standard either (1) retrospectively to each prior comparative reporting period presented or (2) retrospectively at the beginning of the period of adoption.	January 1, 2019	The Company has adopted the standard on January 1, 2019, and will apply it at the beginning of the period of adoption. Therefore, upon adoption, financial information and disclosures will not be updated for comparative reporting periods under the new standard. Additionally, the Company has elected the transition package of practical expedients upon adoption which, among other things, allows an entity to not reassess the historical lease classification. The Company utilized a combination of a bottom-up and top-down approach to identify and analyze its lease portfolio. The analysis included reviewing all forms of leases, performing a completeness assessment over the lease population, assessing the policy elections offered by the standard and evaluating its business processes and internal controls to meet the ASU's accounting, reporting and disclosure requirements. The Company’s adoption of the standard has an impact on the Consolidated Balance Sheet. The Company’s adoption of the standard does not impact the Consolidated Statements of Operations or the Consolidated Statements of Cash Flows. The most significant effect of the new standard on the Consolidated Balance Sheet relates to the recognition of right-of-use assets and lease liabilities for the Company’s real estate portfolio, which the Company expects to be between $15 million and $25 million. The Company will also be providing new disclosures for its leasing activities under the new standard in the first quarter of 2019.

There were no recent accounting standards that were adopted by the Company during the reporting period that had a significant effect on our Consolidated Financial Statements.

NOTE 19 — SUBSEQUENT EVENTS

On January 18, 2019, we received our final environmental impact statement (“EIS”) from FERC for the Driftwood terminal and pipeline. The final EIS was prepared in compliance with the requirements of the National Environmental Policy Act (“NEPA”), the Council on Environmental Quality regulations for implementing NEPA, and FERC regulations.

59

TELLURIAN INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES    

In accordance with FASB and SEC disclosure requirements for natural gas producing activities, this section provides supplemental information on Tellurian’s natural gas producing activities in six separate tables. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on the Company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves and changes in estimated discounted future net cash flows. The Company had no activities related to natural gas producing activities during the year ended December 31, 2016.

Table I — Capitalized Costs Related to Natural Gas Producing Activities

Capitalized costs related to Tellurian’s natural gas and condensate producing activities are summarized as follows (in thousands):

	December 31, 2018			December 31, 2017
Proved properties	$	101,459		$	90,869
Unproved properties	10,204			13,000
Gross capitalized costs	111,663			103,869
Accumulated DD&A	(1,335		)	(149		)
Net capitalized costs	$	110,328		$	103,720

Table II — Costs Incurred in Exploration, Property Acquisitions and Development

Costs incurred in natural gas property acquisition, exploration and development activities are summarized as follows (in thousands):

	December 31, 2018		December 31, 2017
Property acquisitions:
Proved	$	13,261	$	90,869
Unproved	204		13,000
Exploration costs	—		—
Development	2,104		949
Costs incurred	$	15,569	$	104,818

Table III — Results of Operations for Natural Gas & Condensate Producing Activities

The following table includes revenues and expenses directly associated with our natural gas and condensate producing activities. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas operations. Tellurian's results of operations from natural gas and condensate producing activities for the periods presented are as follows (in thousands):

	December 31, 2018			December 31, 2017
Natural gas sales	$	4,423		$	503
Operating costs	11,251			1,668
Depreciation, depletion and amortization	1,228			115
Impairment charge	2,699			—
Total operating costs and expenses	15,178			1,783
Results of operations	$	(10,755	)	$	(1,280	)

Table IV — Natural Gas & Condensate Reserve Quantity Information

Our estimated proved reserves are located in Louisiana. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the natural gas and condensate reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in these estimates. The estimates of our

60

TELLURIAN INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

proved reserves as of December 31, 2018 and 2017 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants.

The condensate volumes shown include crude oil and condensate.

	Gas (MMcf)		Condensate (Mbbl)		Gas Equivalent (MMcfe)
Proved reserves:
December 31, 2016	—		—		—
Extensions, discoveries and other additions	—		—		—
Revisions of previous estimates	—		—		—
Production	(190	)	—		(191	)
Sale of reserves-in-place	—		—		—
Purchases of reserves-in-place	327,308		10		327,371
December 31, 2017	327,118		10		327,180
Extensions, discoveries and other additions	22,481		—		22,481
Revisions of previous estimates	(84,061	)	(2	)	(84,072	)
Production	(1,399	)	(1	)	(1,405	)
Sale of reserves-in-place	—		—		—
Purchases of reserves-in-place	715		—		715
December 31, 2018	264,854		7		264,899
Proved developed reserves:
December 31, 2016	—		—		—
December 31, 2017	5,720		10		5,782
December 31, 2018	17,522		7		17,567
Proved undeveloped reserves:
December 31, 2016	—		—		—
December 31, 2017	321,398		—		321,398
December 31, 2018	247,332		—		247,332

2016 to 2017 Changes

• Acquired 327 Bcfe of reserves in a series of transactions.

2017 to 2018 Changes

• Added approximately 22 Bcfe of proved reserves, comprised primarily of 19 Bcfe from additional proved undeveloped locations as a result of a more detailed analysis from an updated development plan and 3 Bcfe from drilling activities.

• Had negative revisions of approximately 85 Bcfe, comprised primarily of 59 Bcfe as a result of newly acquired 3D seismic data indicating additional geological faulting risks, which led to a reduction in proved undeveloped locations and some lateral lengths, 14 Bcfe, net, from changes in estimating lateral lengths of proved undeveloped locations as a result of more detailed analysis from an updated development plan, and 12 Bcfe due to loss of leases.

• Recorded positive revisions of approximately 1 Bcfe due to an increase in commodity prices.

• Acquired approximately 1 Bcfe of proved reserves through minor interest acquisitions.

Table V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas & Condensate Reserves

ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Tellurian has followed these guidelines, which are briefly discussed below.

61

TELLURIAN INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Future cash inflows and future production and development costs as of December 31, 2018 and 2017 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of natural gas and condensate to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates, including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the FASB and do not necessarily reflect our expectations of actual revenue to be derived from those reserves or their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth our future net cash flows relating to proved natural gas and condensate reserves based on the standardized measure (in thousands):

	December 31, 2018			December 31, 2017
Future cash inflows	$	676,454		$	777,711
Future production costs	(105,341		)	(144,991		)
Future development costs	(264,239		)	(331,297		)
Future income tax provisions	(54,564		)	(52,212		)
Future net cash flows	252,310			249,211
Less effect of a 10% discount factor	(106,499		)	(161,009		)
Standardized measure of discounted future net cash flows	$	145,811		$	88,202

Table VI — Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas & Condensate Reserves

The following table sets forth the changes in the standardized measure of discounted future net cash flows (in thousands):

62

TELLURIAN INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2016	$	—
Sales and transfers of gas and condensate produced, net of production costs	(265		)
Net changes in prices and production costs	—
Extensions, discoveries, additions and improved recovery, net of related costs	—
Development costs incurred	—
Revisions of estimated development costs	—
Revisions of previous quantity estimates	—
Accretion of discount	—
Net change in income taxes	(22,921		)
Purchases of reserves in place	111,388
Sales of reserves in place	—
Changes in timing and other	—
December 31, 2017	$	88,202
Sales and transfers of gas and condensate produced, net of production costs	(1,773		)
Net changes in prices and production costs	27,530
Extensions, discoveries, additions and improved recovery, net of related costs	13,334
Development costs incurred	545
Revisions of estimated development costs	9,663
Revisions of previous quantity estimates	12,991
Accretion of discount	11,112
Net change in income taxes	(9,472		)
Purchases of reserves in place	844
Sales of reserves in place	—
Changes in timing and other	(7,165		)
December 31, 2018	$	145,811

63

SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
TELLURIAN INC.
PARENT COMPANY BALANCE SHEETS
(in thousands, except share and per share)
	December 31,
	2018			2017
ASSETS
Cash and cash equivalents	$	—		$	—
Prepaids and other	72			25
Investments in subsidiaries	289,802			212,846
Property, plant and equipment, net	10,000			13,000
Total assets	$	299,874		$	225,871
LIABILITIES AND EQUITY
Liabilities:
Accounts payable	$	114		$	148
Accrued liabilities	1,826			1,836
Total liabilities	1,940			1,984
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	$	299,874		$	225,871

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

64

SCHEDULE I (Continued)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
TELLURIAN INC.
PARENT COMPANY STATEMENTS OF OPERATIONS
(in thousands)
	Year Ended December 31,
	2018			2017			2016
Total revenues	$	—		$	—		$	—
Operating costs and expenses:
Cost of sales	93			15			—
Development expenses	2,487			320			21
General and administrative expenses	4,618			594			25,084
Goodwill impairment	—			77,592			—
Total operating costs and expenses	7,198			78,521			25,105
Loss on preferred stock exchange feature	—			—			3,308
Interest expense	2			—			—
Loss from operations before income taxes and equity in losses of subsidiaries	(7,200		)	(78,521		)	(28,413		)
Income tax benefit (provision)	—			(4		)	170
Net loss from operations before equity in losses of subsidiaries	$	(7,200	)	$	(78,525	)	$	(28,243	)
Equity in losses of subsidiaries, net of tax	$	(118,545	)	$	(152,934	)	$	(68,412	)
Net loss	$	(125,745	)	$	(231,459	)	$	(96,655	)

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

65

SCHEDULE I (Continued)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
TELLURIAN INC.
PARENT COMPANY STATEMENTS OF CASH FLOWS
(in thousands)
	Year Ended December 31,
	2018			2017			2016
Net cash used in operating activities	(123,976		)	(312,553		)	(60,532		)
Cash flows from investing activities:
Cash received in acquisition	—			56			210
Cash used for acquisition	—			—			(1,190		)
Net cash received (used) in investing activities	—			56			(980		)
Cash flows from financing activities:
Proceeds from the issuance of common stock	133,800			318,204			59,015
Tax payments for net share settlement of equity awards	(5,734		)	—			—
Proceeds from the issuance of preferred stock	—			—			25,000
Equity offering costs	(4,090		)	(5,707		)	(1,681		)
Net cash provided by financing activities	123,976			312,497			82,334
Net increase (decrease) in cash and cash equivalents	—			—			20,822
Cash and cash equivalents, beginning of period	—			—			—
Cash and cash equivalents, end of period	$	—		$	—		$	20,822

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

66

SCHEDULE I — CONTINUED

TELLURIAN INC.

NOTES TO PARENT COMPANY FINANCIAL STATEMENTS

NOTE 1 — BASIS OF PRESENTATION

Tellurian Inc. is a Delaware corporation based in Houston, Texas (“Tellurian”), which wholly owns Tellurain Investments Inc. (“Tellurian Investments”), which in turn wholly owns Tellurian Production Holdings LLC (“Production Holdings”), Tellurian Investment’s primary operating company.

On February 10, 2017 (the “Merger Date”), Tellurian Investments Inc. (“Tellurian Investments”) completed a merger (the “Merger”) with a subsidiary of Magellan Petroleum Corporation (“Magellan”). Magellan changed its corporate name to Tellurian Inc. shortly after completing the Merger. The Merger was accounted for as a “reverse acquisition,” with Tellurian Investments being treated as the accounting acquirer. As such, the historical consolidated comparative information as of and for all periods in 2016 in this Schedule I relates to Tellurian Investments. Subsequent to the Merger Date, the information relates to the consolidated entities of Tellurian Inc., with Magellan reflected as the accounting acquiree. In connection with the Merger, each issued and outstanding share of Tellurian Investments common stock was exchanged for 1.3 shares of Magellan common stock. All share amounts in the Condensed Financial Information and related notes have been retroactively adjusted for all periods presented to give effect to this exchange, including reclassifying an amount equal to the change in par value of common stock from additional paid-in capital.

On April 9, 2016, Tellurian Investments acquired Tellurian Services LLC (“Tellurian Services”), formerly known as Parallax Services LLC (“Parallax Services”). Under the financial reporting rules of the SEC, Parallax Services (“Predecessor”) has been deemed to be the predecessor to Tellurian (“Successor”) for financial reporting purposes. Predecessor financial statements have been included in Tellurian’s Consolidated Financial Statements in this report.

These condensed parent company financial statements reflect the activity of Tellurian as the parent company to Production Holdings and have been prepared in accordance with Rule 12-04, Schedule 1 of Regulation S-X, as the restricted net assets of Production Holdings exceed 25% of the consolidated net assets of Tellurian. This information should be read in conjunction with the consolidated financial statements of Tellurian included in this report under the caption Item 8, “Financial Statements and Supplementary Data.”

NOTE 2 — PROPERTY, PLANT AND EQUIPMENT

The amounts included in Tellurian’s parent-only financial statements related to property, plant and equipment represent unproved properties in the United Kingdom and Australia, as disclosed in Note 5, Property, Plant and Equipment, to Tellurian’s Consolidated Financial Statements included in this report under the caption Item 8, “Financial Statements and Supplementary Data.” 

NOTE 3 — GOODWILL IMPAIRMENT

For details regarding the goodwill impairment included in Tellurian’s parent-only financial statements, refer to Note 2, Merger and Acquisition — The Merger, to Tellurian’s Consolidated Financial Statements included in this report under the caption Item 8, “Financial Statements and Supplementary Data.” 

NOTE 4 — CONTINGENCIES

For details regarding the contingencies related to Tellurian Investments litigation, refer to Note 8, Commitments and Contingencies, to Tellurian’s Consolidated Financial Statements included in this report under the caption Item 8, “Financial Statements and Supplementary Data.” 

67

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

As previously disclosed, (i) upon the closing of the Merger, our audit committee replaced EKS&H LLLP (“EKS&H”) as the Company’s independent registered accounting firm with Deloitte & Touche LLP and (ii) there were no “disagreements” with EKS&H or “reportable events” (as those terms are defined in Item 304 of SEC Regulation S-K) during the fiscal years ended June 30, 2015 or 2016 and the subsequent period through February 13, 2017.  

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Meg A. Gentle, the Company’s Chief Executive Officer and President, in her capacity as principal executive officer, and Antoine J. Lafargue, the Company’s Senior Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2018, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information we are required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We made no changes in our internal control over financial reporting during the year ended December 31, 2018, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the U.S. We make modifications to improve the design and effectiveness of our disclosure controls and may take other corrective action if our reviews identify deficiencies or weaknesses in our controls.

Management’s Annual Report on Internal Control Over Financial Reporting; Report of Independent Registered Public Accounting Firm

The management report called for by Item 308(a) of Regulation S-K is set forth in Item 8 of Part II of this Annual Report on Form 10-K.

The independent auditors report called for by Item 308(b) of Regulation S-K is set forth in Item 8 of Part II of this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting during the quarter ended December 31, 2018, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Pursuant to Section 13(r) of the Exchange Act, if during the year ended December 31, 2018, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our annual report on Form 10-K as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (the “ITRSHRA”). Disclosure is generally required even if the activities were conducted outside the U.S. by non-U.S. entities in compliance with applicable law. During the year ended December 31, 2018, we did not engage in any transactions with Iran or with persons or entities related to Iran.

TOTAL Delaware, Inc. (“TOTAL”) and TOTAL S.A. have beneficial ownership of approximately 19% of the outstanding Tellurian common stock. TOTAL has the right to designate for election one member of Tellurian’s board of directors, and Eric Festa is the current TOTAL designee. TOTAL will retain this right for so long as its percentage ownership of Tellurian voting stock is at least 10%. On March 16, 2018, TOTAL S.A. included information in its Annual Report on Form 20-F for the year ended December 31, 2017 (the “TOTAL 2017 Annual Report”) regarding activities during 2017 that require disclosure under the ITRSHRA. The relevant disclosures were reproduced in Exhibit 99.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, filed with the SEC on May 9, 2018 and are incorporated by reference herein. On May 16, 2018, TOTAL S.A. announced its intent to discontinue the South Pars 11 project in Iran and to unwind related operations, disclosure of which was included in Exhibit 99.9 to the TOTAL S.A. report on Form 6-K filed with the SEC on June 1, 2018 and under the heading “US withdrawal from the JCPOA: TOTAL’s position related to the South Pars 11 project in Iran” in Exhibit 99.2 to the TOTAL S.A. report on Form 6-K filed with the SEC on July 27, 2018. We have no involvement in or control over such activities, and we have not independently verified or participated in the preparation of the disclosures made in the TOTAL 2017 Annual Report or the TOTAL S.A. reports on Form 6-K.

68

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this Item is incorporated by reference from Tellurian's Definitive Proxy Statement with respect to its 2019 Annual Meeting of Stockholders to be filed not later than April 30, 2019.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference from Tellurian's Definitive Proxy Statement with respect to its 2019 Annual Meeting of Stockholders to be filed not later than April 30, 2019.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTER

The information required by this Item with respect to security ownership of certain beneficial owners and management is incorporated by reference from Tellurian's Definitive Proxy Statement with respect to its 2019 Annual Meeting of Stockholders to be filed not later than April 30, 2019.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item is incorporated by reference from Tellurian's Definitive Proxy Statement with respect to its 2019 Annual Meeting of Stockholders to be filed not later than April 30, 2019.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item is incorporated by reference from Tellurian's Definitive Proxy Statement with respect to its 2019 Annual Meeting of Stockholders to be filed not later than April 30, 2019.

69

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following financial statements, financial statement schedules and exhibits are filed as part of this report:

1. Financial Statements. Tellurian’s consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.

2. Financial Statement Schedules. Our financial statement schedules filed herewith are set forth in Part II, Item 8 of this report as follows: (1) Tellurian Inc. — Schedule I — Condensed Financial Information of Registrant. All valuation and qualifying accounts schedule were omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedule.

3. Exhibits. The exhibits listed below are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.

Exhibit No.	Description
1.1	Distribution Agency Agreement, dated as of March 15, 2017, by and between Tellurian Inc. and Credit Suisse Securities (USA) LLC (incorporated by reference to Exhibit 1.1 to the Company’s Current Report on Form 8-K filed on March 15, 2017)
2.1††	Agreement and Plan of Merger, dated as of August 2, 2016, by and among Magellan Petroleum Corporation, Tellurian Investments Inc., and River Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on August 3, 2016), as amended by First Amendment to Agreement and Plan of Merger, dated as of November 23, 2016 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on November 29, 2016) and Second Amendment to Agreement and Plan of Merger, dated as of December 19, 2016 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on December 21, 2016)
2.2††	Purchase and Sale Agreement, dated as of September 6, 2017, by and between Rockcliff Energy Operating LLC and Tellurian Production LLC (incorporated by reference to Exhibit 2.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017)
3.1	Amended and Restated Certificate of Incorporation of Tellurian Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on September 22, 2017)
3.1.1	Certificate of Designations of Series C Convertible Preferred Stock of Tellurian Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on March 21, 2018)
3.2	Amended and Restated Bylaws of Tellurian Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on September 22, 2017)
10.1	Voting Agreement, dated as of January 3, 2017, by and among Magellan Petroleum Corporation, Tellurian Investments Inc., TOTAL Delaware, Inc., Charif Souki, the Souki Family 2016 Trust and Martin Houston (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on January 5, 2017)
10.2	Pre-emptive Rights Agreement, dated as of May 10, 2017, by and between Tellurian Inc. and TOTAL Delaware, Inc. (incorporated by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017)
10.3	Registration Rights Agreement, dated as of June 28, 2017, by and between Tellurian Inc. and GE Oil & Gas, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 3, 2017)
10.4	Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Driftwood LNG Phase 1 Liquefaction Facility, dated as of November 10, 2017, by and between Driftwood LNG LLC and Bechtel Oil, Gas and Chemicals, Inc. (portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 13, 2017)
10.4.1	Change Order CO-001, dated as of June 12, 2018, to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Driftwood LNG Phase 1 Liquefaction Facility, dated as of November 10, 2017, by and between Driftwood LNG LLC and Bechtel Oil, Gas and Chemicals, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018)
10.5	Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Driftwood LNG Phase 2 Liquefaction Facility, dated as of November 10, 2017, by and between Driftwood LNG LLC and Bechtel Oil, Gas and Chemicals, Inc. (portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on November 13, 2017)

70

Exhibit No.	Description
10.5.1	Change Order CO-001, dated as of June 12, 2018, to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Driftwood LNG Phase 2 Liquefaction Facility, dated as of November 10, 2017, by and between Driftwood LNG LLC and Bechtel Oil, Gas and Chemicals, Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018)
10.6	Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Driftwood LNG Phase 3 Liquefaction Facility, dated as of November 10, 2017, by and between Driftwood LNG LLC and Bechtel Oil, Gas and Chemicals, Inc. (portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on November 13, 2017)
10.6.1	Change Order CO-001, dated as of June 12, 2018, to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Driftwood LNG Phase 3 Liquefaction Facility, dated as of November 10, 2017, by and between Driftwood LNG LLC and Bechtel Oil, Gas and Chemicals, Inc. (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018)
10.7	Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Driftwood LNG Phase 4 Liquefaction Facility, dated as of November 10, 2017, by and between Driftwood LNG LLC and Bechtel Oil, Gas and Chemicals, Inc. (portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on November 13, 2017)
10.7.1	Change Order CO-001, dated as of June 12, 2018, to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Driftwood LNG Phase 4 Liquefaction Facility, dated as of November 10, 2017, by and between Driftwood LNG LLC and Bechtel Oil, Gas and Chemicals, Inc. (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018)
10.8	Credit Agreement, dated as of September 28, 2018, by and among Tellurian Production Holdings LLC, as borrower, the lender parties thereto, Goldman Sachs Lending Partners LLC, as administrative agent, and J. Aron & Company LLC, as collateral agent (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018)
10.8.1*	Omnibus Amendment and Consent, dated as of November 29, 2018, by and among Tellurian Production Holdings LLC, as borrower, the lender parties thereto, Goldman Sachs Lending Partners LLC, as administrative agent, and J. Aron & Company LLC, as collateral agent and initial swap counterparty
10.9	Parent Guaranty, dated as of September 28, 2018, by and between Tellurian Inc., as guarantor, and J. Aron & Company LLC, as collateral agent (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018)
10.10†	Employment Letter Agreement by and between Tellurian Investments Inc. and Meg A. Gentle, dated as of August 31, 2016 (incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-4/A filed on November 8, 2016)
10.11†	Employment Letter Agreement by and between Tellurian Investments Inc. and R. Keith Teague, dated as of September 23, 2016 (incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-4/A filed on November 8, 2016)
10.12†	Employment Letter Agreement by and between Tellurian Services LLC and Daniel A. Belhumeur, dated as of September 23, 2016 (incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-4/A filed on November 8, 2016)
10.13†	Employment Agreement, dated as of February 9, 2017, by and between Tellurian Services LLC and Antoine Lafargue (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 13, 2017)
10.14†	Employment Letter Agreement, by and between Tellurian Services LLC and Khaled Sharafeldin, dated as of January 9, 2017 (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017)
10.15†	Form of Indemnification Agreement (Officers) (incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017)
10.16†	Form of Indemnification Agreement (Directors) (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 28, 2017)
10.17†	Amended and Restated Tellurian Inc. 2016 Omnibus Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 22, 2017)
10.17.1†	Form of Stock Award Agreement pursuant to the Tellurian Inc. 2016 Omnibus Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 28, 2017)
10.17.2†	Form of Stock Award Agreement pursuant to the Tellurian Inc. 2016 Omnibus Incentive Compensation Plan (Directors) (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017)

71

Exhibit No.	Description
10.17.3†	Restricted Stock Agreement pursuant to the Tellurian Inc. 2016 Omnibus Incentive Compensation Plan, dated as of February 13, 2017, by and between Tellurian Inc. and Antoine Lafargue (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 13, 2017)
10.17.4†	Form of Restricted Stock Agreement pursuant to the Tellurian Inc. 2016 Omnibus Incentive Compensation Plan (Directors) (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017)
10.17.5†	Form of Restricted Stock Agreement pursuant to the Amended and Restated Tellurian Inc. 2016 Omnibus Incentive Compensation Plan (U.S. Selected Senior Management) (Time-Based Vesting) (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017)
10.17.6†	Form of Restricted Stock Agreement pursuant to the Amended and Restated Tellurian Inc. 2016 Omnibus Incentive Compensation Plan (U.S. Selected Senior Management) (Milestone-Based Vesting) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2018)
10.17.7†*	Form of Restricted Stock Agreement pursuant to the Amended and Restated Tellurian Inc. 2016 Omnibus Incentive Compensation Plan (Directors)
10.17.8†	Form of Stock Option Agreement pursuant to the Amended and Restated Tellurian Inc. 2016 Omnibus Incentive Compensation Plan (U.S. Selected Senior Management) (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017)
10.18†	Amended and Restated Tellurian Investments Inc. 2016 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on February 13, 2017)
10.18.1†	Form of Restricted Stock Amendment Letter regarding the Amended and Restated Tellurian Investments Inc. 2016 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on February 13, 2017)
10.18.2†	Form of Notice of Grant and Restricted Stock Award Agreement pursuant to the 2016 Tellurian Investments Omnibus Incentive Plan (Milestone-Based Vesting) (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on February 13, 2017)
10.18.3†	Form of Amendment to Restricted Stock Agreement pursuant to the Amended and Restated Tellurian Investments Inc. 2016 Omnibus Incentive Plan (Employees) (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017)
10.19†	Form of Construction Incentive Award Agreement (U.S. Selected Senior Management) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 23, 2018)
10.20†*	Form of Construction Incentive Award Agreement (U.S. Employees)
14.1	Code of Business Conduct and Ethics (incorporated by reference to Exhibit 14.1 to the Company’s Current Report on Form 8-K filed on December 6, 2018)
21.1*	Subsidiaries of Tellurian Inc.
23.1*	Consent of Deloitte & Touche LLP
23.2*	Consent of Netherland, Sewell & Associates, Inc.
31.1*	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Section 13(r) Disclosure (incorporated by reference to Exhibit 99.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2018)
99.2*	Summary Reserves Report of Netherland, Sewell & Associates, Inc.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

72

*	Filed herewith.
**	Furnished herewith.
†	Management contract or compensatory plan or arrangement.
††	Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules and similar attachments have been omitted. The registrant hereby agrees to furnish supplementally a copy of any omitted schedule or attachment to the Securities and Exchange Commission upon request.

ITEM 16. FORM 10-K SUMMARY

None.

73

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		TELLURIAN INC.
Date:	February 27, 2019	By:	/s/ Antoine J. Lafargue
			Antoine J. Lafargue
			Senior Vice President and Chief Financial Officer
			(as Principal Financial Officer)
			Tellurian Inc.
Date:	February 27, 2019	By:	/s/ Khaled A. Sharafeldin
			Khaled A. Sharafeldin
			Chief Accounting Officer
			(as Principal Accounting Officer)
			Tellurian Inc.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ Meg A. Gentle	Date:	February 27, 2019
Meg A. Gentle, Director, President and Chief Executive Officer, Tellurian Inc. (as Principal Executive Officer)
/s/ Antoine J. Lafargue	Date:	February 27, 2019
Antoine J. Lafargue, Senior Vice President and Chief Financial Officer, Tellurian Inc. (as Principal Financial Officer)
/s/ Khaled A. Sharafeldin	Date:	February 27, 2019
Khaled A. Sharafeldin, Chief Accounting Officer, Tellurian Inc. (as Principal Accounting Officer)
/s/ Charif Souki	Date:	February 27, 2019
Charif Souki, Director and Chairman, Tellurian Inc.
/s/ Martin J. Houston	Date:	February 27, 2019
Martin J. Houston, Director and Vice Chairman, Tellurian Inc.
/s/ Diana Derycz-Kessler	Date:	February 27, 2019
Diana Derycz-Kessler, Director, Tellurian Inc.
/s/ Dillon J. Ferguson	Date:	February 27, 2019
Dillon J. Ferguson, Director, Tellurian Inc.
/s/ Eric P. Festa	Date:	February 27, 2019
Eric P. Festa, Director, Tellurian Inc.
/s/ Brooke A. Peterson	Date:	February 27, 2019
Brooke A. Peterson, Director, Tellurian Inc.
/s/ Don A. Turkleson	Date:	February 27, 2019
Don A. Turkleson, Director, Tellurian Inc.

74

EX-10.8.1

Exhibit 10.8.1

OMNIBUS AMENDMENT AND CONSENT

This omnibus amendment and consent (this “Agreement”) is entered into as of November 29, 2018 (the “Effective Date”), by and among TELLURIAN PRODUCTION HOLDINGS LLC, a Delaware limited liability company (“Borrower”), the Lenders (defined below) party hereto, GOLDMAN SACHS LENDING PARTNERS LLC, as the administrative agent (in such capacity, including any successors or assigns in such capacity, “Administrative Agent”), J. ARON & COMPANY LLC, as the collateral agent (in such capacity, including any successors or assigns in such capacity, “Collateral Agent”), and, for the purpose of Section 3 below only, J. ARON & COMPANY LLC, as the initial swap counterparty under the Intercreditor Agreement (the “InitialSwap Counterparty”).

WITNESSETH:

WHEREAS, Borrower, Administrative Agent, Collateral Agent and the financial institutions party thereto as lenders (the “Lenders”, and together with Administrative Agent and Collateral Agent, the “Lender Parties”), have entered into that certain Credit Agreement dated as of September 28, 2018 (as amended, restated, supplemented or otherwise modified (including by this Agreement), the “Credit Agreement”);

WHEREAS, Borrower has requested that the Lender Parties amend the Credit Agreement and grant a consent under the Credit Agreement with respect to the Specified Expenditures (defined below), in each case, as herein provided;

WHEREAS, the Administrative Agent, the Collateral Agent and the Initial Swap Counterparty have agreed to amend the Intercreditor Agreement as herein provided; and

WHEREAS, subject to the terms and conditions hereinafter set forth, the Lender Parties and the Initial Swap Counterparty, as applicable, have agreed to amend the Credit Agreement and the Intercreditor Agreement as herein provided and grant a consent under the Credit Agreement as set forth herein with respect to the Specified Expenditures.

NOW, THEREFORE, for and in consideration of the mutual covenants and agreements and to the conditions precedent set forth herein, the parties to this Agreement hereby agree as follows:

SECTION 1.Terms Defined in the Credit Agreement

As used in this Agreement, except as may otherwise be provided herein, all capitalized terms defined in the Credit Agreement shall have the same meaning herein as therein, all of such terms and their definitions being incorporated herein by reference.

SECTION 2.Amendments to Credit Agreement.

(a)The definition of “Projected Production” in Section 1.1 of the Credit Agreement is hereby amended and restated as follows:

“Projected Production” as of any time means the projected production of Proved Developed Producing Oil and Gas Properties (measured by volume unit or BTU equivalent, not sales price), for the term of the contracts or a particular month, as applicable, as such production has been projected in the Reserve Report most recently delivered to the Lenders, as updated by any Return Certificate (or as otherwise approved by the Administrative Agent in its sole discretion), provided that “Projected Production” shall include pro forma proved developed producing reserves for any well a Credit Party is seeking to drill and that is the subject of a Return Certificate.”

(b)The first sentence of Section 2.2(b)(v) of the Credit Agreement is hereby amended and restated as follows:

“(v)The Collateral Agent shall owe to Borrower for each calendar month interest on the Margin Balance at the Federal Funds Rate, and the Collateral Agent shall deliver such interest payments to the Borrower by wire transfers to a Controlled Account designated by the Borrower within five (5) Business Days after the end

of such calendar month; provided, that all interest owing by the Collateral Agent to Borrower for the period starting September 28, 2018 through October 31, 2018 shall be delivered to the Borrower within five (5) Business Days after November 30, 2018.”

(c)Section 7.1(b) of the Credit Agreement is hereby amended and restated as follows:

“Monthly Reports. (i) As soon as available and in any event within forty-five (45) days after the end of each calendar month, a report summarizing, as requested by Administrative Agent or any Lender, (A) the gross volume of sales and actual production during such month from all of the Oil and Gas Properties of the Credit Parties and current prices being received for such production, (B) detailed determinations of costs and such other information as may be reasonably requested by Administrative Agent or any Lender, and (C) lease operating expenses (separated by category of expense) and Permitted Expenditures paid or incurred during such month; and (ii) on or before the last day of each month (beginning with the month ending December 31, 2018), the Projections for the immediately following month.

(d)Section 7.15(a) of the Credit Agreement is hereby amended and restated as follows:

“Minimum Hedging. Within five (5) Business Days after (i) prior to the APOD Completion Date, the approval of a Return Certificate for the drilling of a well that will be operated by a Credit Party pursuant to the APOD, (ii) prior to the APOD Completion Date, notice from the operator of a well that is not operated by a Credit Party that sales of Hydrocarbons from such well have commenced and (iii) from and after the APOD Completion Date, the delivery of each Reserve Report hereunder (each such date, the “Hedging Transaction Date”), the Credit Parties shall enter into and thereafter maintain their position in one or more Acceptable Commodity Hedging Transactions consisting of fixed price swaps or collars and covering aggregate notional volumes of not less than 75% of Projected Production for each month following the Hedging Transaction Date through the later of (x) the date twenty-seven (27) months after the date such well commences production and (y) the Maturity Date. Any swaps or collars utilized to comply with this Section 7.15 must have a fixed price paid to the Credit Parties (for swaps) or floor price paid to the Credit Parties (for collars) that would satisfy the internal rate of return set forth in the Return Certificate or that is otherwise acceptable to the Administrative Agent in its sole discretion. Within five (5) Business Days after each Hedging Transaction Date, the Credit Parties shall enter into and thereafter maintain their position in one or more Acceptable Commodity Hedging Transactions consisting of basis differential hedges covering aggregate notional volumes of not less than 75% of Projected Production for each month following the Hedging Transaction Date on a rolling 12-month basis through the later of (x) the date twenty-seven (27) months after the date such well commences production and (y) the Maturity Date.”

SECTION 3.Amendments to Intercreditor Agreement.

(a)Clause (ii) of Section 4.02(a) of the Intercreditor Agreement is hereby amended and restated as follows:

“(ii) during the existence of a Triggering Event, all such amounts received by any Creditor or the Collateral Agent (other than (x) amounts received by any Creditor as a result of the exercise of netting or set-off rights permitted pursuant to the provisos set forth in Section 2.02, which shall be for the sole benefit of such Creditor, (y) amounts received by J. Aron in respect of any collateral pledged or posted to J. Aron under the J. Aron ISDA in accordance with the terms thereof, which shall be for the sole benefit of J. Aron or (z) the Margin Balance, which shall be for the sole benefit of the Lenders) shall be treated as if constituting Proceeds, shall be turned over to the Collateral Agent, and shall be applied by the Collateral Agent in accordance with Section 4.02(c) below.”

(b)The language before the colon in Section 4.02(c) of the Intercreditor Agreement is hereby amended and restated as follows:

“(c) All Collateral or Proceeds received by the Collateral Agent or any Creditor during the existence of a Triggering Event or otherwise in connection with any Enforcement Action (other than (x) amounts received by any Creditor as a result of the exercise of netting or set-off rights permitted pursuant to the provisos set forth in Section 2.02, which shall be for the sole benefit of such Creditor, (y) amounts received by J. Aron in

respect of any collateral pledged or posted to J. Aron under the J. Aron ISDA in accordance with the terms thereof, which shall be for the sole benefit of J. Aron or (z) the Margin Balance, which shall be for the sole benefit of the Lenders) shall be applied in the following order”.

SECTION 4.Consent

(a)Borrower has advised the Lender Parties that it desires to make the payments described on Schedule I hereto (the “Specified Expenditures”), which payments, if made in the absence of this Agreement, would violate Sections 2.2(a), 8.2 and 8.25 of the Credit Agreement.

(b)Subject to the satisfaction or waiver in writing of the conditions precedent set forth in Section 5 hereof, and in accordance with Section 12.12 of Credit Agreement, the Lender Parties hereby consent to the Borrower making the Specified Expenditures (the “Consent”). Other than the Consent, nothing in this Agreement shall be deemed to be (i) a consent to the deviation by any Credit Party from strict compliance with the terms and conditions of the Loan Documents, (ii) a waiver of any Default or Event of Default, or (iii) a waiver of (or an agreement to forbear from exercising) any rights or remedies that the Lender Parties have pursuant to the Credit Agreement and applicable law by reason of any Default or Event of Default.

SECTION 5.Conditions of Effectiveness

This Agreement shall become effective on the Effective Date upon fulfillment of the following conditions precedent:

(a)Borrower shall have delivered to Administrative Agent a duly executed counterpart of this Agreement; and

(b)Parent Guarantor and each Subsidiary Guarantor shall have delivered to Administrative Agent a duly executed counterpart of the Ratification Agreement substantially in the form attached hereto as Exhibit A (the “Ratification Agreement”).

SECTION 6.Representations and Warranties

Borrower represents and warrants to the Lender Parties, with full knowledge that the Lender Parties are relying on the following representations and warranties in executing this Agreement, as follows:

(a)The execution, delivery and performance of this Agreement and the Ratification Agreement by Borrower and each Guarantor party thereto and the consummation of the transactions contemplated hereby and thereby have been duly authorized by all necessary company action on the part of Borrower and such Guarantor.

(b)This Agreement, the Ratification Agreement, the Credit Agreement, the Loan Documents and each and every other document executed and delivered in connection herewith constitute legal, valid, and binding obligations of Borrower and each Guarantor party thereto, enforceable against such Person in accordance with their respective terms, except as may be limited by equitable principles or Debtor Relief Laws.

(c)The execution, delivery, and performance by Borrower of this Agreement and each Guarantor of the Ratification Agreement, and the consummation of the transactions contemplated hereby and thereby do not and will not (i) violate or conflict with, or result in a breach of, or require any consent under, or other action to, with or by (A) the Constituent Documents of such Person, (B) any applicable Law, rule, or regulation or any order, writ, injunction, or decree of any Governmental Authority or arbitrator where such violation or conflict would reasonably be expected to result in a Material Adverse Event, or (C) any other agreement or instrument to which such Person is a party or by which it or any of its Properties is bound or subject which could reasonably be expected to result in a Material Adverse Event, or (ii) constitute a default under any such agreement or instrument which could reasonably be expected to result in a Material Adverse Event, or result in the creation or imposition of any Lien upon any of the revenues or assets of such Person.

(d)The execution, delivery and performance by Borrower of this Agreement and each Guarantor of the Ratification Agreement, and the consummation of the transactions contemplated hereby and thereby do not and will not require any registration with, consent or approval of, or notice to, or other action to, with or by, any Governmental Authority.

(e)As of the date of this Agreement, the Credit Parties, taken as a whole, are Solvent and have not entered into any transaction with the intent to hinder, delay or defraud a creditor.

(f)(i) No Default has occurred and is continuing, and (ii) all of the representations and warranties contained in Article 6 of the Credit Agreement and in the other Loan Documents are true and correct in all material respects (other than any representations or warranties subject to a Material Adverse Event qualification or any other qualification as to materiality, which are true and correct in all respects) on and as of the Effective Date, in each case with the same force and effect as if such representations and warranties had been made on and as of such date, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they were true and correct in all material respects (other than any representations or warranties subject to a Material Adverse Event qualification or any other qualification as to materiality, which were true and correct in all respects) as of such earlier date.

SECTION 7.Reference to and Effect on the Loan Documents

Upon the effectiveness hereof, on and after the date hereof, (i) each reference in the Credit Agreement or the Intercreditor Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” or words of like import and (ii) each reference in any other Loan Document to “the Credit Agreement” or “the Intercreditor Agreement”, shall, in each case, mean and be a reference to the Credit Agreement or the Intercreditor Agreement, as applicable, after giving effect to this Agreement.

SECTION 8.Cost and Expenses

Borrower agrees to pay all reasonable and documented out-of-pocket costs and expenses of the Lender Parties and their Related Parties connection with this Agreement, including, without limitation, the reasonable and documented out-of-pocket fees and expenses of legal counsel for the Lender Parties and their Related Parties in connection herewith.

SECTION 9.Extent of Consent

Except as otherwise expressly provided herein, none of the Credit Agreement, the Intercreditor Agreement or any of the other Loan Documents are amended, modified or affected by this Agreement. Borrower hereby ratifies and confirms that: (a) all of the terms, conditions, covenants, representations, warranties and all other provisions of the Credit Agreement remain in full force and effect; (b) each of the other Loan Documents are and remain in full force and effect in accordance with their respective terms; (c) the Collateral is unimpaired by this Agreement; and (d) any and all Liens, security interests and other security or Collateral now or hereafter held by the Lender Parties as security for payment and performance of the Secured Obligations are hereby renewed and carried forth to secure payment and performance of all of the Secured Obligations.

SECTION 10.Waiver and Release

In consideration of the Consent provided herein and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, Borrower hereby waives, releases, and forever discharges each Lender Party, its predecessors and its successors, assigns, affiliates, shareholders, directors, officers, accountants, attorneys, employees, agents, representatives, and servants (collectively, the “Released Parties”) of, from and against any and all claims, actions, causes of action, suits, proceedings, contracts, judgments, damages, accounts, reckonings, executions, and liabilities whatsoever of every name and nature, whether known or unknown, whether or not well founded in fact or in law, and whether in law, at equity, or otherwise, which such Person ever had or now has for or by reason of any matter, cause, or anything whatsoever to this date relating to or arising out of the Loans, this Agreement, or any of the Loan Documents, including without limitation any actual or alleged act or omission of any of the Released Parties with respect to the Loans or any of the Loan Documents, or any Liens or Collateral in connection therewith, or the enforcement of any of the Lender Parties’ rights or remedies thereunder. The terms of this waiver and release shall survive the termination of this Agreement, the Loans, the Credit Agreement and the Loan Documents and shall remain in full force and effect after the termination of this Agreement.

SECTION 11.Claims

As additional consideration of the execution, delivery, and performance of this Agreement by the parties hereto and to induce the Lender Parties to enter into this Agreement, Borrower represents and warrants that it does not know of any defenses, counterclaims or rights of setoff to the payment of any Secured Obligations to any Secured Party.

SECTION 12.Counterparts

This Agreement may be executed in one or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

SECTION 13.Severability

Any provision of this Agreement held by a court of competent jurisdiction to be invalid or unenforceable shall not impair or invalidate the remainder of this Agreement and the effect thereof shall be confined to the provision held to be invalid or illegal. Furthermore, in lieu of such invalid or unenforceable provision there shall be added as a part of this Agreement a provision as similar in terms to such illegal, invalid or unenforceable provision as may be possible and be legal, valid and enforceable.

SECTION 1.GOVERNING LAW; VENUE; SERVICE OF PROCESS; WAIVER OF JURY TRIAL

The provisions of Section 12.13 of the Credit Agreement are hereby incorporated herein mutatis mutandis.

SECTION 14.Headings

The headings, captions, and arrangements used in this Agreement are for convenience only and shall not affect the interpretation of this Agreement.

SECTION 15.NOTICE OF FINAL AGREEMENT

THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES HERETO RELATING TO THE SUBJECT MATTER HEREOF AND THEREOF AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES HERETO. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES HERETO.

[Remainder of Page Left Blank; Signature Pages to Follow]

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized.

BORROWER:

TELLURIAN PRODUCTION HOLDINGS LLC, a Delaware limited liability company

By:/s/ Graham McArthur

Name: Graham McArthur

Title: Treasurer

Signature Page Omnibus Amendment and Consent

ADMINISTRATIVE AGENT:

GOLDMAN SACHS LENDING PARTNERS LLC, as Administrative Agent

By:/s/ Simon Collier

Name: Simon Collier

Title: Authorized Signatory

COLLATERAL AGENT:

J. ARON & COMPANY LLC, as Collateral Agent

By:/s/ Simon Collier

Name: Simon Collier

Title: Attorney-In-Fact

LENDERS:

J. ARON & COMPANY LLC, as a Lender

By:/s/ Simon Collier

Name: Simon Collier

Title: Attorney-In-Fact

For purposes of Section 3 only, INITIAL SWAP COUNTERPARTY:

J. ARON & COMPANY LLC, as Initial Swap Counterparty under the Intercreditor Agreement

By:/s/ Simon Collier

Name: Simon Collier

Title: Attorney-In-Fact

Signature Page Omnibus Amendment and Consent

EXHIBIT A

FORM OF RATIFICATION AGREEMENT

November 29, 2018

Reference is made to that certain (i) Credit Agreement dated as of September 28, 2018 (as amended, restated, supplemented or otherwise modified (including by the Amendment referred to below), the “Credit Agreement”), by and among TELLURIAN PRODUCTION HOLDINGS LLC, a Delaware limited liability company (“Borrower”), the lenders party thereto, GOLDMAN SACHS LENDING PARTNERS LLC, as the administrative agent (in such capacity, including any successors or assigns in such capacity, “Administrative Agent”), and J. ARON & COMPANY LLC, as the collateral agent (in such capacity, including any successors or assigns in such capacity, “Collateral Agent”), (ii) the Intercreditor Agreement dated as of September 28, 2018 (as amended, restated, supplemented or otherwise modified (including by the Amendment referred to below), by an among Borrower and the other Credit Parties party thereto, Administrative Agent, Collateral Agent and J. Aron & Company LLC, as initial swap counterparty (“Initial Swap Counterparty”), and (iii) the Omnibus Amendment and Consent dated as of the date hereof (the “Amendment”), among Borrower, Administrative Agent, Collateral Agent, the lenders party thereto and Initial Swap Counterparty. Capitalized terms used herein have the meanings given to such terms in the Credit Agreement.

Each of the undersigned Guarantors hereby (a) acknowledges the terms of the Amendment; and (b) ratifies, confirms and agrees that, following the effectiveness of the Amendment on the Effective Date referred to therein, (i) the Loan Documents to which such Guarantor is a party shall remain in full force and effect on such date, including without limitation the Guaranty Agreement and the Security Documents to which such Guarantor is a party and (ii) the applicable Security Documents shall continue to secure the Secured Obligations, in the manner and to the extent provided therein, without defense, set off, counterclaim, discount or charge of any kind as of the date hereof. Without limiting the foregoing, each Guarantor that is a Subsidiary of Borrower hereby agrees to the amendments to the Intercreditor Agreement set forth in Section 3 of the Amendment in accordance with Section 5.10 of the Intercreditor Agreement.

This Ratification Agreement may be executed in one or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

THIS RATIFICATION AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER (INCLUDING, WITHOUT LIMITATION, ANY CLAIMS SOUNDING IN CONTRACT LAW OR TORT LAW ARISING OUT OF THE SUBJECT MATTER HEREOF AND ANY DETERMINATIONS WITH RESPECT TO POST-JUDGMENT INTEREST) SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK WITHOUT REGARD TO CONFLICT OF LAWS PRINCIPLES THEREOF THAT WOULD RESULT IN THE APPLICATION OF ANY LAW OTHER THAN THE LAW OF THE STATE OF NEW YORK.

[Signature Pages Follow]

Exhibit A to Omnibus Amendment and Consent

IN WITNESS WHEREOF, the parties hereto have caused this Ratification Agreement to be duly executed on the date first above written.

TELLURIAN INC.

By:

Name:

Title:

TELLURIAN PRODUCTION LLC

By:

Name:

Title:

TELLURIAN OPERATING LLC

By:

Name:

Title:

Exhibit A to Omnibus Amendment and Consent

SCHEDULE I

Specified Expenditures

The following categories of expenses relating to the SCOTT, formerly known as NIXON, 25X36 14 10 HC 1-ALT well, which is set forth on the APOD, in an aggregate amount not to exceed $100,000: (a) Land Services & Expenses, (b) Legal Fees & Expenses, and (c) Permits, Surveys & Regulatory Expenses.

Schedule I to Omnibus Amendment and Consent

EX-10.17.7

Exhibit 10.17.7

Director Form - A&R 2016 Plan 2018 Awards

TELLURIAN INC.

RESTRICTED STOCK AGREEMENT

PURSUANT TO THE

TELLURIAN INC.

AMENDED AND RESTATED 2016 OMNIBUS INCENTIVE COMPENSATION PLAN

This RESTRICTED STOCK AGREEMENT (“Agreement”) is effective as of [___], 2018 (the “Grant Date”), between Tellurian Inc., a Delaware corporation (the “Company”), and [INSERT NAME] (the “Participant”).

Terms and Conditions

The Participant is hereby granted, as an eligible Directorof the Company or a Subsidiary, as of the Grant Date, pursuant to the Amended and Restated Tellurian Inc. 2016 Omnibus Incentive Compensation Plan (as it may be amended and/or restated from time to time, the “Plan”), the number ofShares of the Company’s Common Stock set forth in Section 1 below. Except as otherwise indicated, any capitalized term used but not defined herein shall have the meaning ascribed to such term in the Plan. A copy of the Plan and the prospectus with regard to the shares under an effective registration on Form S-8 have been delivered or made available to the Participant. By signing and returning this Agreement, the Participant acknowledges having received and read a copy of the Plan and the prospectus and agrees to comply with the Plan, this Agreement and all applicable laws and regulations.

Accordingly, the parties hereto agree as follows:

1.Grant of Shares. Subject in all respects to the Plan and the terms and conditions set forth herein and therein, effective as of the Grant Date, the Company hereby awards to the Participant [_______] shares of its Common Stock (the “Shares”). Such Shares are subject to certain vesting and forfeiture restrictions set forth in Section 2 hereof, which restrictions shall lapse at the times provided under Section 2 hereof. For the period during which such restrictions are in effect, the Shares subject to such restrictions are referred to herein as the “Restricted Stock.” The Restricted Stock, in the sole discretion of the Plan Administrator, shall be evidenced by a certificate or be credited to a book entry account maintained by the Company (or its designee) on behalf of the Participant and such certificate or book entry (as applicable) shall be noted appropriately to record the restrictions on the Restricted Stock imposed hereby.

2.Restricted Stock.

(a)Rights as a Stockholder. The Participant shall have the rights of a stockholder with respect to the shares of Restricted Stock as, and only as, set forth in Section 10.4 of the Plan and herein. Solely with respect to unvested shares of Restricted Stock, (i) dividends or other distributions (collectively, “dividends”) on such unvested shares of Restricted Stock shall be withheld, in each case, while such unvested shares of Restricted Stock are subject to restrictions, and (ii) in no event shall dividends or other distributions payable thereunder be paid unless and until such unvested shares of Restricted Stock to which they relate no longer are subject to a risk of forfeiture hereunder. Dividends that are not paid currently shall be credited to bookkeeping accounts on the Company’s records for purposes of the Plan and shall not accrue interest. Such dividends shall be paid to the Participant in the same form as paid on the Common Stock promptly upon the lapse of the restrictions.

(b)Vesting. Subject to Sections 2(c) and 2(d) below, the Restricted Stock shall only vest, and the forfeiture restrictions shall lapse, as to the number of shares set forth below, on the respective vesting dates set forth below:

Vesting Date	Number of Shares
September 6, 2018	_____________
December 6, 2018	_____________
March 6, 2019	_____________
June 6, 2019	_____________

There shall be no proportionate or partial vesting in the periods prior to the applicable vesting date(s) and all vesting shall occur only on the applicable vesting date(s), subject to the Participant’s continued service as Director of the Company or any Subsidiary through the applicable vesting, as explained in Section 2(c) below.

(c)Termination of Directorship.In the event the Participant experiences a Termination of Directorship, any Shares of Restricted Stock not then vested shall not vest (except as otherwise provided herein) and shall be forfeited back to the Company without compensation as of the date of such Termination of Directorship; provided, however, that any such Shares of Restricted Stock not then vested shall fully vest upon the death or Disability of the Participant, or upon a Termination of Directorship by the Company without Cause.

(d)Change of Control. In the event of a Change of Control (as defined in the Plan), all outstanding and unvested Shares of Restricted Stock shall immediately vest in full and all forfeiture restrictions thereon shall lapse as of the date of such Change of Control.

(e)Section 83(b). If the Participant properly elects (as permitted by Section 83(b) of the Code) within thirty (30) days after the issuance of the Restricted Stock to include in gross income for federal income tax purposes in the year of issuance the fair market value of such Restricted Stock, the Participant shall deliver to the Company a signed copy of such election within 10 days after the making of such election, and shall pay to the Company or make arrangements satisfactory to the Company to pay to the Company upon such election, any federal, state, local or other taxes of any kind that the Company is required to withhold with respect to the Restricted Stock. The Participant acknowledges that it is his or her sole responsibility, and not the Company’s, to file timely and properly the election under Section 83(b) of the Code and any corresponding provisions of state tax laws if he or she elects to utilize such election.

(f)Certificates. If, after the Grant Date, certificates are issued with respect to the shares of Restricted Stock, such issuance and delivery of certificates shall be made in accordance with the applicable terms of the Plan.

3.Delivery Delay. The delivery of any certificate representing the Restricted Stock may be postponed by the Company for such period as may be required for it to comply with any applicable foreign, federal, state or provincial securities law, or any national securities exchange listing requirements and the Company is not obligated to issue or deliver any securities if, in the opinion of counsel for the Company, the issuance of such Shares shall constitute a violation by the Participant or the Company of any provisions of any applicable foreign, federal, state or provincial law or of any regulations of any governmental authority or any national securities exchange. If the Participant is currently a resident or is likely to become a resident in the United Kingdom at any time during the period that the Shares are subject to restriction, the Participant acknowledges and understands that the Company intends to meet its delivery obligations in Common Stock with respect to the shares of Restricted Stock, except as may be prohibited by law or described in this Agreement or supplementary materials.

4.Certain Legal Restrictions. The Plan, this Agreement, the granting and vesting of the Restricted Stock, and any obligations of the Company under the Plan and this Agreement, shall be subject to all applicable federal, state and local laws, rules and regulations, and to such approvals by any regulatory or governmental agency as may be required, and to any rules or regulations of any exchange on which the Common Stock is listed.

5.Withholding of Taxes. The Company shall have the right to deduct from any payment to be made pursuant to this Agreement and the Plan, or to otherwise require, prior to the issuance, delivery or vesting of any shares of Common Stock, payment by the Participant of, any federal, state or local taxes required by law to be withheld.

6.Provisions of Plan Control. This Agreement is subject to all the terms, conditions and provisions of the Plan, including, without limitation, the amendment provisions thereof, and to such rules, regulations and

interpretations relating to the Plan as may be adopted by the Plan Administrator and as may be in effect from time to time. The Plan is incorporated herein by reference. If and to the extent that any provision of this Agreement conflicts or is inconsistent with the terms set forth in the Plan, the Plan shall control, and this Agreement shall be deemed to be modified accordingly.

7.Restrictions on Transfer. The Participant shall not sell, transfer, pledge, hypothecate, assign or otherwise dispose of the Shares, except as permitted in the Plan or Agreement. Any attempted sale, transfer, pledge, hypothecation, assignment or other disposition of the Shares in violation of the Plan or this Agreement shall be void and of no effect and the Company shall have the right to disregard the same on its books and records and to issue “stop transfer” instructions to its transfer agent.

8.Recoupment Policy. The Participant acknowledges and agrees that the Restricted Stock shall be subject to the terms and provisions of any “clawback” or recoupment policy that may be adopted by the Company from time to time or as may be required by any applicable law (including, without limitation, the Dodd-Frank Wall Street Reform and Consumer Protection Act and rules and regulations thereunder).

9.No Right to Continued Service. This Agreement is not an agreement for continued service. None of this Agreement, the Plan or the grant of the Restricted Stock hereunder shall (a) guarantee that the Company will retain the Participant’s services as Director for any specific time period or (b) modify or limit in any respect the Company’s right to terminate or modify the Participant’s service arrangement or compensation. Moreover, this Agreement is not intended to and does not amend any existing service contract between the Participant and the Company or any of its Affiliates.

10.Section 409A. Subject to and without limitation on Section 19.3 of the Plan, it is intended that the Restricted Stock comply with or be exempt from Code Section 409A, and this Agreement shall be construed and interpreted in accordance with such intent. In no event whatsoever will Company be liable for any additional tax, interest or penalties that may be imposed on the Participant under Code Section 409A or any damages for failing to comply with Code Section 409A.

11.Notices. Any notice or communication given hereunder shall be in writing or by electronic means and, if in writing, shall be deemed to have been duly given: (a) when delivered in person or by electronic means; (b) three days after being sent by United States mail; or (c) on the first business day following the date of deposit if delivered by a nationally recognized overnight delivery service, in each case, to the appropriate party at the following address (or such other address as the party shall from time to time specify): (i) if to the Company, to Tellurian Inc. at its then current headquarters; and (ii) if to the Participant, to the address on file with the Company.

12.Mode of Communications. The Participant agrees, to the fullest extent permitted by applicable law, in lieu of receiving documents in paper format, to accept electronic delivery of any documents that the Company or any of its Affiliates may deliver in connection with this grant of Restricted Stock and any other grants offered by the Company, including, without limitation, prospectuses, grant notifications, account statements, annual or quarterly reports, and other communications. The Participant further agrees that electronic delivery of a document may be made via the Company’s email system or by reference to a location on the Company’s intranet or website or the online brokerage account system.

13.Governing Law. All matters arising out of or relating to this Agreement and the transactions contemplated hereby, including its validity, interpretation, construction, performance and enforcement, shall be governed by and construed in accordance with the internal laws of the State of Delaware, without giving effect to principles of conflict of laws which would result in the application of the laws of any other jurisdiction.

14.Successors. The Company will require any successors or assigns to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession or assignment had taken place. The terms of this Agreement and all of the rights of the parties hereunder will be binding upon, inure to the benefit of, and be enforceable by, the Participant’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees.

15.WAIVER OF JURY TRIAL. EACH PARTY TO THIS AGREEMENT, FOR ITSELF AND ITS AFFILIATES, HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW ANY RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM (WHETHER BASED ON CONTRACT, TORT OR OTHERWISE) ARISING OUT OF OR RELATING TO THE ACTIONS OF THE PARTIES HERETO OR THEIR RESPECTIVE AFFILIATES PURSUANT TO THIS AGREEMENT OR IN THE NEGOTIATION, ADMINISTRATION, PERFORMANCE OR ENFORCEMENT OF THIS AGREEMENT.

16.Construction. All section titles and captions in this Agreement are for convenience only, shall not be deemed part of this Agreement, and in no way shall define, limit, extend or describe the scope or intent of any provisions of this Agreement. Wherever any words are used in this Agreement in the masculine gender they shall be construed as though they were also used in the feminine gender in all cases where they would so apply. As used herein, (a) “or” shall mean “and/or” and (b) “including” or “include” shall mean “including, without limitation.” Any reference herein to an agreement in writing shall be deemed to include an electronic writing to the extent permitted by applicable law.

17.Severability of Provisions. If at any time any of the provisions of this Agreement shall be held invalid or unenforceable, or are prohibited by the laws of the jurisdiction where they are to be performed or enforced, by reason of being vague or unreasonable as to duration or geographic scope or scope of the activities restricted, or for any other reason, such provisions shall be considered divisible and shall become and be immediately amended to include only such restrictions and to such extent as shall be deemed to be reasonable and enforceable by the court or other body having jurisdiction over this Agreement, and the Company and the Participant agree that the provisions of this Agreement, as so amended, shall be valid and binding as though any invalid or unenforceable provisions had not been included.

18.No Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach or any other covenant, duty, agreement or condition.

19.Entire Agreement. This Agreement, together with the Plan, contains the entire understanding of the parties with respect to the subject matter hereof and supersedes any prior agreements between the Company and the Participant with respect to the subject matter hereof.

20.Data Protection. By accepting this Agreement (whether by electronic means or otherwise), the Participant hereby consents to the holding and processing of personal data provided by him to the Company for all purposes necessary for the operation of the Plan. These include, but are not limited to administering and maintaining Participant records; providing information to any registrars, brokers or third party administrators of the Plan; and providing information to future purchasers of the Company or the business in which the Participant works.

21.Acceptance. To accept the grant of the Restricted Stock, the Participant must execute and return the Agreement by [______] (the “Acceptance Deadline”). By accepting this grant, the Participant will have agreed to the terms and conditions set forth in this Agreement and the terms and conditions of the Plan. The grant of the Restricted Stock will be considered null and void, and acceptance thereof will be of no effect, if the Participant does not execute and return the Agreement by the Acceptance Deadline.

22.Counterparts. This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one instrument. Execution and delivery of this Agreement by facsimile or other electronic signature is legal, valid and binding for all purposes.

[Remainder of Page Left Intentionally Blank]

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date and year first above written.

TELLURIAN INC.

By:

Name:

Title:

PARTICIPANT

By:

Name: [INSERT NAME]

[Signature Page to Restricted Stock Agreement]

EX-10.20

Exhibit 10.20

US Employees (Double-Trigger)    

Construction Incentive Plan (NTP)

To: [INSERT NAME AND ADDRESS OF GRANTEE]

(“you” or the “Grantee”)

CONSTRUCTION INCENTIVE AWARD AGREEMENT

Congratulations! Tellurian Services LLC (the “Employer”) hereby awards you the opportunity to participate in a cash incentive award with respect to the development by Driftwood Holdings LLC and its subsidiaries and successors (collectively, the “Partnership”) of the Driftwood LNG Liquefaction Facility, a liquefied natural gas production and export terminal on the west bank of the Calcasieu River, Louisiana, USA (the “Driftwood Project”), on the terms and subject to the conditions (including the vesting restrictions) set out in this Construction Incentive Award Agreement (this “Agreement”). Tellurian Inc. (the “Company”) is a party to this Agreement solely for the purpose of providing the guarantee set out below under “Guarantee”.

All capitalized words used in this Agreement that are not defined in the main body of this Agreement are defined in the Glossary at the end of this Agreement.

Grant Date: [____] (the “Grant Date”)

Cash Award: The aggregate amount of the award shall be $[____], which shall be payable to you by the Employer in cash on the occurrence of certain milestones (as described below) on the terms, and subject to the conditions, set out in this Agreement (the “Cash Award”).

The Cash Award shall be allocated among Phases 1 to 4 of the Driftwood Project under the Driftwood EPC Contracts (each, a “Phase”), as follows:

Phase	Allocation (% of total Cash Award)	Allocation ($)
Phase 1	40%	$[____]
Phase 2	20%	$[____]
Phase 3	20%	$[____]
Phase 4	20%	$[____]

Vesting: Subject to the other provisions contained herein, the portion of the Cash Award allocated to any Phase of the Driftwood Project shall vest and become payable to you as follows:

• 25% of the Cash Award allocated to such Phase shall vest and become payable on the first anniversary of the NTP Date applicable to such Phase;

• 25% of the Cash Award allocated to such Phase shall vest and become payable on the second anniversary of the applicable NTP Date;

• 25% of the Cash Award allocated to such Phase shall vest and become payable on the third anniversary of the applicable NTP Date; and

• 25% of the Cash Award allocated to such Phase shall vest and become payable on the fourth anniversary of the applicable NTP Date (the “Vesting Schedule”).

There shall be no proportionate or partial vesting in the periods prior to the applicable vesting date(s) and all vesting shall occur only on the applicable vesting date(s), subject to your continued employment or other service to the Employer, the Company, any of their Subsidiaries or the Partnership on the applicable vesting date.

Expiration: This Cash Award shall expire on the ten (10) year anniversary of the Grant Date (the “Expiration Date”). To the extent that by the Expiration Date the NTP Date for any Phase has not occurred, your entitlement to the Cash Award allocated to such Phase shall immediately lapse and be forfeited by you, without any right to compensation, and the Employer shall not be liable to pay any amount to you in respect thereof. However, for the avoidance of doubt, if the NTP Date for a Phase has occurred on or before the Expiration Date, the associated portion of the Cash Award for such Phase shall (subject to the provisions of this Agreement) vest in accordance with the Vesting Schedule.

Payment: Each portion of the Cash Award shall be paid to you in cash on or as soon as administratively practicable following the date on which such portion vests, and in any event not later than thirty (30) days after the date of vesting. All payments in settlement of any portion of the Cash Award shall be subject to applicable tax withholding, as set forth in greater detail below.

Termination of Service (Generally): Except as otherwise provided herein, in the event of your Termination of Service for any reason (whether notice of termination is given by you or the Company, the Employer, one of their Subsidiaries or the Partnership), you shall not be entitled to receive and shall forfeit, without any right to compensation, any rights in respect of any portion of the Cash Award that is unvested as of the date of such Termination of Service.

Termination of Service Due to Disability: If you experience a Termination of Service by reason of Disability prior to the occurrence of the NTP Date for a particular Phase, then any portion of the Cash Award allocated to any Phase for which the applicable NTP Date occurs within one (1) year following the date of such Termination of Service shall vest and become payable to you immediately as of such NTP Date. If you experience a Termination of Service by reason of Disability on or following the occurrence of the NTP Date for a particular Phase, any unvested portion of the Cash Award allocated to such Phase shall vest and become payable to you immediately on the date of the Termination of Service. Your entitlement to any portion of the Cash Award allocated to a Phase for which the applicable NTP Date does not occur within a one (1) year period following the date of the Termination of Service by reason of Disability shall immediately lapse and be forfeited on the first (1st) anniversary of such Termination of Service.

Termination of Service Due to Death: If you die prior to the occurrence of the NTP Date for a particular Phase, then any portion of the Cash Award allocated to such Phase shall remain outstanding and eligible to become vested in full subject to and upon the occurrence of the applicable NTP Date on or before the Expiration Date, without regard to the continued service condition. If you die on or after the occurrence of the NTP Date for a particular Phase, then any unvested portion of the Cash Award allocated to such Phase shall vest and become payable to your estate immediately on the date of your death.

Termination Without Cause: If you experience a Termination Without Cause prior to the occurrence of the NTP Date for a particular Phase, then any portion of the Cash Award allocated to such Phase shall not immediately lapse and instead shall remain outstanding and vest in accordance with the Vesting Schedule, without regard to the continued service condition, subject to and conditioned upon: (A) the occurrence of the applicable NTP Date on or before the Expiration Date; (B) your continued compliance with the Restrictive Covenants; and (C) your timely execution and delivery (without revocation) to the Employer of the Release within twenty-one (21) days (or such longer period as may be required by law) after delivery of the form of Release by the Employer. If you experience a Termination Without Cause on or after the occurrence of the NTP Date for a particular Phase, then any portion of the Cash Award allocated to such Phase that is unvested as of the date of such Termination Without Cause shall not immediately lapse and instead shall remain outstanding and vest in accordance with the Vesting Schedule, without regard to the requirement of your continued employment or service on the scheduled vesting date(s), subject to and conditioned upon: (A) your continued compliance with the Restrictive Covenants; and (B) your timely execution and delivery (without revocation) to the Employer of the Release within twenty-one (21) days (or such longer period as may be required by law) after delivery of the form of Release by the Employer.

Change of Control: If you experience a Termination Without Cause within one (1) year following a Change of Control while any portion of the Cash Award is unvested, such unvested portion of the Cash Award shall immediately vest and become payable in full as of the date of such Termination Without Cause, subject to and conditioned upon: (A) your continued compliance with the Restrictive Covenants; and (B) your timely execution and delivery (without revocation) to the Employer of a Release within twenty-one (21) days (or such longer period as may be required by law) after delivery of the form of Release by the Employer.

Withholding of Taxes: Amounts payable in respect of the Cash Award shall be subject to withholding and deductions for federal, state and/or local taxes, and the Employer shall have the right to withhold such amounts from any amounts otherwise payable to you in respect of the Cash Award or to otherwise require, prior to the grant, vesting or payment of the Cash Award, payment by you of any federal, state or local taxes required by law to be withheld. To the extent permitted under Code Section 409A, the Employer shall have the right, in its sole discretion, to accelerate the vesting and payment of any portion of the Cash Award in its sole discretion in order to pay any income and/or employment taxes required in respect of the Cash Award prior to payment (provided that you shall have no discretion, and may not be given a direct or indirect election, with respect to whether the Employer exercises such discretion to accelerate).

Code Section 409A: It is intended that the Cash Award will comply with or be exempt from Code Section 409A, and this Agreement will be construed and interpreted in accordance with such intent. A termination of employment (or other service, as the case may be) shall not be deemed to have occurred for purposes of any provision of this Agreement providing for the payment of any amounts or benefits upon or following a termination of employment (or other service, as the case may be) unless such termination is also a “separation from service” within the meaning of Code Section 409A and, for purposes of any such provision of this Agreement, references to a “termination,” “termination of employment” or like terms shall mean “separation from service.” For purposes of Code Section 409A, a right to receive any installment payments pursuant to the Cash Award shall be treated as a right to receive a series of separate and distinct payments. Whenever a payment under the Cash Award specifies a payment period with reference to a number of days (e.g., “payment shall be made within thirty (30) days”), the actual date of payment within the specified period shall be within the sole discretion of the Employer. Notwithstanding anything herein to the contrary, the following shall apply, if and to the extent required by Code Section 409A, in the event that (A) you are deemed to be a “specified employee” within the meaning of Code Section 409A(a)(2)(B)(i) and (B) amounts or benefits under the Cash Award or any other program, plan or arrangement of the Employer or a controlled group affiliate thereof are due or payable on account of “separation from service” within the meaning of Treasury Regulations Section 1.409A-1(h): No such payments that are “nonqualified deferred compensation” subject to Code Section 409A shall be made prior to the date that is six (6) months after the date of separation from service or, if earlier, the date of death; following any applicable six (6) month delay, all such delayed payments will be paid in a single lump sum (without interest) on the earliest permissible payment date. Notwithstanding anything herein to the contrary, to the extent that the Cash Award is (i) subject to Code Section 409A and (ii) a Change of Control would accelerate the timing of payment thereunder, the payment of such Cash Award shall not occur until the earliest of (I) the Change of Control if such Change of Control constitutes a “change in the ownership of the corporation,” a “change in the effective control of the corporation” or a “change in the ownership of a substantial portion of the assets of the corporation,” within the meaning of Code Section 409A(2)(A)(v), (II) the date such Cash Award would otherwise be settled pursuant to the terms of this Agreement and (III) your “separation of service” within the meaning of Code Section 409A.

No Right to Employment or Consultancy Service: Nothing in this Agreement shall confer upon you any right with respect to continuation as an employee, consultant or director with the Company, the Employer, any of their Subsidiaries or the Partnership, nor shall it interfere with or restrict in any way the right of the Company, the Employer, any of their Subsidiaries or the Partnership, which is hereby expressly reserved, to remove, terminate or discharge you at any time for any reason whatsoever, with or without Cause and with or without advance notice. This Agreement is not intended to and does not amend any existing employment or consultancy contract between you and the Company, the Employer, any of their Subsidiaries or the Partnership.

No Shareholder Rights: The grant of the Cash Award hereunder shall not make you, nor give you any of the rights of privileges of, a shareholder of the Company or any of its Affiliates (including the Employer).

Unsecured Obligation: Except as otherwise provided below under “Guarantee”, the obligations of the Company and the Employer with respect to the Cash Award is an unfunded and unsecured promise, and ultimately your right to receive the payments contemplated by the Cash Award shall be no greater than the rights of any other unsecured general creditor of the Company or the Employer.

Restrictions on Transfer: You shall not sell, transfer, pledge, hypothecate, assign or otherwise dispose of the Cash Award or any rights or interest therein, including without limitation any rights under this Agreement or any amounts payable in settlement of the Cash Award, prior to payment hereunder. Any attempted sale, transfer, pledge, hypothecation, assignment or other disposition of the Cash Award in violation of this provision shall be void and of no effect.

Guarantee: The Company guarantees to the Grantee the due and punctual performance, observance and discharge by the Employer of all the Guaranteed Obligations if and when they become performable or due under this Agreement. If the Employer defaults in the payment when due of any amount that is a Guaranteed Obligation the Company shall, immediately on demand by the Grantee, pay that amount to the Grantee in the manner prescribed by this Agreement. The Company as principal obligor and as a separate and independent obligation and liability from its obligations and liabilities, agrees to indemnify and keep indemnified the Grantee in full and on demand from and against all and any losses, costs, claims, liabilities, damages, demands and expenses suffered or incurred by the Grantee arising out of, or in connection with, the Guaranteed Obligations not being recoverable for any reason, or the Company's failure to perform or discharge any of the Guaranteed Obligations. This guarantee shall at all times be a continuing security and shall cover the ultimate balance of all monies payable by the Company to the Grantee in respect of the Guaranteed Obligations, irrespective of any intermediate payment or discharge in full or in part of the Guaranteed Obligations. The Company irrevocably appoints the Employer as its agent to receive on its behalf service of any proceedings arising out of or in connection with this Agreement. Such service shall be deemed completed on delivery to the agent (whether or not it is forwarded to or received by its principal). If for any reason the agent ceases to be able to act as agent or no longer has an address in the United States, the Company shall immediately appoint a substitute and give notice to you of the new agent’s name and address. Nothing in this Agreement shall affect the right to serve process in any manner permitted by law.

Severability: If any provision of this Agreement (or part of any provision) is found by any court or other authority of competent jurisdiction to be invalid, illegal or unenforceable, that provision or part-provision shall, to the extent required, be deemed not to form part of this agreement, and the validity and enforceability of the other provisions of this agreement shall not be affected.

Counterparts: This Agreement may be executed in one or more counterparts but shall not be effective until each party has executed at least one counterpart. Each such counterpart shall constitute an original of this Agreement but all the counterparts shall together constitute the same instrument.

Governing Law: All matters arising out of or relating to this Agreement and the transactions contemplated hereby, including its validity, interpretation, construction, performance and enforcement, shall be governed by and construed in accordance with the internal laws of the State of Delaware, without giving effect to principles of conflict of laws which would result in the application of the laws of any other jurisdiction. The Cash Award and any payments in settlement thereof shall be subject to all applicable federal, state and local laws, rules and regulations, and to such approvals by any regulatory or governmental agency as may be required, if any.

Data Protection: By accepting the Cash Award (whether by electronic means or otherwise), you hereby consent to the holding and processing of personal data provided by you to the Company and the Employer for all purposes necessary for the operation of this Agreement and the Cash Award. This includes, but is not limited to, administering and maintaining records regarding you; providing information to third party administrators of benefit plans and awards; and providing information to future purchasers of the Company, the Employer or the business in which you work. You are hereby advised and directed to refer to any Employer data protection policy and/or notice from time to time in place for more details about how your personal data is used.

Successors and Assigns: The Employer may require any successors or assigns to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Employer would be required to perform it if no such succession or assignment had taken place. All obligations of the Employer granted hereunder shall be binding on the Employer and its successors and assigns.

Waiver: No failure or delay by a party to exercise any right or remedy provided under this Agreement or by law shall constitute a waiver of that or any other right or remedy, nor shall it preclude or restrict the further exercise of that or any other right or remedy. No single or partial exercise of any right or remedy provided under this Agreement shall preclude or restrict the further exercise of that or any other right or remedy.

Entire Agreement: This Agreement contains the entire understanding of the parties with respect to the subject matter hereof and supersedes any prior agreements between you and the Company or the Employer with respect to the subject matter hereof. No party has been induced to enter into this Agreement in reliance upon, nor have they been given, any warranty, representation, statement, assurance, covenant, agreement, undertaking, indemnity or commitment of any nature whatsoever other than as are expressly set out in this Agreement and, to the extent that any of them have been,

they unconditionally and irrevocably waive any claims, rights or remedies which any of them might otherwise have had in relation thereto.

By your signature, the signature of the Employer’s representative and the signature of the Company’s representative below, you, the Employer and the Company hereby acknowledge that you have been issued the right to participate in the Cash Award with effect from the Grant Date on the terms and conditions of this Agreement. Further, you acknowledge your agreement to be bound to the terms of this Agreement in connection with your acceptance of the Cash Award issued hereby through procedures, including electronic procedures, provided by or on behalf of the Employer.

To accept the Cash Award, execute this form and return an executed copy to [___] (the “Designated Recipient”) by [___]. Failure to return the executed copy to the Designated Recipient by such date will render this award invalid.

EMPLOYER

Tellurian Services LLC

By: _____________________     

Name: [____]

Title: [____]

COMPANY

Tellurian Inc.

By: _____________________

Name: [____]

Title: [____]

GRANTEE

Accepted by:

_____________________

[NAME]

Date: _____________________

GLOSSARY

(a) “Affiliate” shall mean any person that directly or indirectly controls, is controlled by or is under common control with the Company. The term “control” (including, with correlative meaning, the terms “controlled by” and “under common control with”), as applied to any person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such person, whether through the ownership of voting or other securities, by contract or otherwise.

(b)“Board” shall mean the Board of Directors of the Company.

(c)“Cause” shall mean a Termination of Service resulting from (a) your indictment for, conviction of, or pleading of guilty or nolo contendere to, any felony or any crime involving fraud, dishonesty or moral turpitude; (b) your gross negligence with regard to the Company or any Affiliate (including the Employer) in respect of your duties for the Company or any Affiliate (including the Employer); (c) your willful misconduct having or, which in the good faith discretion of the Board could have, an adverse impact on the Company or any Affiliate (including the Employer) economically or reputation-wise; (d) your material breach of this Agreement, or any employment, consulting or similar agreement between you and the Company or one of its Affiliates (including the Employer) or material breach of any code of conduct or ethics or any other policy of the Company or any Affiliate (including the Employer), which breach (if curable in the good faith discretion of the Board) has remained uncured for a period of ten (10) days following delivery of written notice to you specifying the manner in which the agreement or policy has been materially breached; or (e) your continued or repeated failure to perform your duties or responsibilities to the Company or any Affiliate (including the Employer) at a level and in a manner satisfactory to the applicable party in its sole discretion (including by reason of your habitual absenteeism or due to your insubordination), which failure has not been cured to the satisfaction of the applicable party following notice to you. Whether you have been terminated for Cause will be determined by the Company’s Chief Executive Officer (or his or her designee) in his or her sole discretion or, if you are or are reasonably expected to become subject to the requirements of Section 16 of the Exchange Act, by the Board in its sole discretion. To the extent you are terminated as a member of the Board of the Company or the board of directors of any Subsidiary, “Cause” shall include a termination of such directorship for “cause” as determined in accordance with the provisions of Section 141(k) of the Delaware General Corporation Law. In addition to the foregoing, if you are an employee or other service provider of the Partnership at the time of your Termination of Service, then a termination by the Partnership for any act or omission by you that, if done (or not done) with respect to the Company or an Affiliate would be grounds for “Cause” hereunder or in any applicable employment, consulting or similar agreement between you and the Partnership that is then in-effect, then such termination shall be deemed to be a Termination of Service for Cause for purposes of this Agreement.

(d)“Change of Control” shall mean the occurrence of any of the following after the Grant Date:

(i)any individual, entity, or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) acquires beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 50% or more of either (A) the then outstanding shares of Common Stock of the Company (the “Outstanding Company Common Stock”) or (B) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that for purposes of this subsection (i), the following acquisitions shall not constitute a Change of Control: (1) any acquisition directly from the Company or any Subsidiary or Affiliate, (2) any acquisition by the Company or any Subsidiary or Affiliate, (3) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any entity controlled by the Company, (4) any acquisition pursuant to a transaction which complies with clauses (A) and (B) of Section d(iii) of this Glossary, below, or (5) any acquisition of additional securities by any Person who, as of the Grant Date, held 15% or more of either (x) the Outstanding Company Common Stock or (y) the Outstanding Company Voting Securities;

(ii)individuals who, as of the Grant Date, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the Grant Date whose election, or nomination for election by the Company’s

stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a person other than the Board;

(iii)consummation by the Company of a reorganization, merger, or consolidation, or sale or other disposition of all or substantially all of the assets of the Company, or the acquisition of assets of another entity (a “Business Combination”), in each case, unless, following such Business Combination, (A) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of the then outstanding shares of Common Stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the entity resulting from such Business Combination (including, without limitation, an entity which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, and (B) at least a majority of the members of the board of directors (or equivalent governing authority) of the entity resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination. For the avoidance of doubt and notwithstanding anything in the foregoing to the contrary, a sale or other disposition of the Partnership or the Company’s interest in the Partnership shall not constitute a sale or other disposition of all or substantially all of the assets of the Company or any other Change of Control for purposes of this Agreement; or

(iv)approval by the stockholders of the Company of a complete liquidation or dissolution of the Company.

(e)“Code” shall mean The U.S. Internal Revenue Code of 1986, as amended from time to time, and any successor thereto, the Treasury Regulations thereunder and other relevant interpretive guidance issued by the Internal Revenue Service or the Treasury Department. Reference to any specific section of the Code shall be deemed to include such regulations and guidance, as well as any successor provision of the Code.

(f)“Common Stock” shall mean the Common Stock of the Company, $0.01 par value per share.

(g)“Disability” shall mean you have experienced a “permanent and total disability” within the meaning of Code Section 22(e)(3). The determination of whether you have experienced a Disability shall be determined under procedures established by the Compensation Committee of the Board. Notwithstanding the foregoing, for a Cash Award that constitutes “non-qualified deferred compensation” pursuant to Code Section 409A, the foregoing definition shall apply for purposes of vesting of such Cash Award, provided that for purposes of payment of such Cash Award, such Cash Award shall not be paid until the earliest of: (A) your “disability” within the meaning of Code Section 409A(a)(2)(C)(i) or (ii), (B) your “separation from service” within the meaning of Code Section 409A and (C) the date your Cash Award would otherwise be paid pursuant to the terms of this Agreement.

(h)“Driftwood” means Driftwood LNG LLC.

(i)“Driftwood EPC Contracts” means the Engineering, Procurement and Construction contracts, dated as of November 10, 2017, between Driftwood and Bechtel Oil, Gas and Chemicals, Inc., each, as amended, restated, modified, extended or supplemented, or any successor contract or arrangement with respect to the engineering, procurement and construction of the Driftwood Project (in whole or in part).

(j)“Exchange Act” shall mean U.S. Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

(k)“Guaranteed Obligations” shall mean all present and future obligations and liabilities of the Employer under this Agreement, including all money and liabilities of any nature from time to time due, owing or incurred by the Employer under this Agreement.

(l)“Notice to Proceed” shall mean a notice to proceed or any similar action or authorization issued and delivered by Driftwood under a Driftwood EPC Contract to commence the performance of work on the applicable Phase of the Driftwood Project.

(m)“NTP Date” shall mean the date on which Notice to Proceed is issued for the applicable Phase.

(n)“Release” means a general release of all claims of any kind that you have or may have (including but not limited to contractual and statutory rights for unfair dismissal and unlawful discrimination arising out of your employment and/or its termination) against the Company and its Affiliates (including the Employer) and their respective affiliates, officers, directors, employees, shareholders, agents and representatives, in a form satisfactory to the Employer.

(o)“Restrictive Covenants” means all confidentiality obligations and post-termination provisions and restrictive covenants to which you are subject under your contract of employment or otherwise.

(p) “Subsidiary” shall mean a corporation, partnership, joint venture, limited liability company, limited liability partnership, or other entity in which the Company owns directly or indirectly, fifty percent (50%) or more of the voting power or profit interests, or as to which the Company or one of its Affiliates serves as general or managing partner or in a similar capacity.

(q)“Termination of Service” means the termination of your employment or consultancy service with the Company, the Employer or any of their Subsidiaries (or the Partnership, if applicable) for any reason (and whether such termination results from notice from you, the Company, the Employer, one of their Subsidiaries or the Partnership); provided, however, that notwithstanding the foregoing, a Termination of Service will not be deemed to occur for purposes of this Agreement if you become an employee or other service provider of the Partnership immediately following a Termination of Service with the Company, the Employer or any of their Subsidiaries (or if you become an employee or other service provider of the Company, the Employer or any of their Subsidiaries immediately following a Termination of Service with the Partnership), or if your employment or other service with the Company, the Employer or any of their Subsidiaries is transferred, assigned or seconded to the Partnership (or if your employment or other service with the Partnership is transferred, assigned or seconded to the Company, the Employer or any of their Subsidiaries), it being understood that in such cases, continuous employment or other service with the Company, the Employer, any of their Subsidiaries and/or the Partnership shall be treated as continuous service with the Company for purposes of the Cash Award, and Termination of Service shall be deemed to occur upon the cessation of all employment or other service to the Company, the Employer, any of their Subsidiaries and the Partnership.

(r)“Termination Without Cause” shall mean a Termination of Service by the Company, the Employer or any of their Subsidiaries (or the Partnership, if applicable) other than (i) for Cause or (ii) as a result of your death or Disability. If you incur a Termination of Service by the Company, the Employer or any of their Subsidiaries (or the Partnership, if applicable) after rejecting an offer of employment or other service with any entity for which such employment or other service would be credited as continued service with the Company or a Subsidiary for purposes of the vesting of the Cash Award, there will be no deemed Termination Without Cause.

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF THE REGISTRANT

Below is a list of all direct and indirect subsidiaries of Tellurian Inc. as of December 31, 2018:    

Subsidiary	State or Other Jurisdiction of Incorporation or Organization	Ownership
Tellurian Inc. owns the following subsidiaries directly:
Tellurian Investments LLC (formerly known as Tellurian Investments Inc.)	Delaware	100.0%
Magellan Petroleum (UK) Investment Holdings Limited	United Kingdom	100.0%
Magellan Petroleum Australia Pty Ltd	Queensland, Australia	70.0% (1)
Tellurian Investments LLC owns the following subsidiaries directly:
Driftwood Holdings LLC	Delaware	100.0%
Tellurian LandCo LLC (formerly known as Parallax LNG LandCo LLC and MBTU LandCo LLC)	Delaware	100.0%
Tellurian LNG LLC (formerly known as Parallax LNG LLC)	Delaware	100.0%
Tellurian Midstream Holdings LLC	Delaware	100.0%
Tellurian Production Holdings LLC	Delaware	100.0%
Tellurian Services LLC (formerly known as Parallax Services LLC)	Delaware	100.0%
Tellurian Supply & Trade LLC	Delaware	100.0%
Tellurian International Holdings Ltd	United Kingdom	100.0%
Tellurian LNG UK Ltd	United Kingdom	100.0%
Tellurian LNG Singapore Pte. Ltd.	Singapore	100.0%
Tellurian International Holdings Ltd owns the following subsidiary directly:
Tellurian Trading UK Ltd	United Kingdom	100%
Driftwood Holdings LLC owns the following subsidiary directly:
Tellurian Management Services LLC (formerly known as Tellurian O&M LLC and Driftwood Operating LLC)	Delaware	100.0%
Tellurian LNG LLC owns the following subsidiaries directly:
Driftwood LNG LLC	Delaware	100.0%
Driftwood LNG Tug Services LLC	Delaware	100.0%
Driftwood Pipeline LLC (formerly known as Driftwood LNG Pipeline LLC)	Delaware	100.0%
Tellurian Midstream Holdings LLC owns the following subsidiary directly:
Tellurian Pipeline LLC	Delaware	100.0%
Tellurian Pipeline LLC owns the following subsidiaries directly:
Haynesville Global Access Pipeline LLC	Delaware	100.0%
Permian Global Access Pipeline LLC	Delaware	100.0%
Tellurian Production Holdings LLC owns the following subsidiaries directly:
Tellurian Operating LLC	Delaware	100.0%
Tellurian Production LLC	Delaware	100.0%
Magellan Petroleum (UK) Investment Holdings Limited owns the following subsidiary directly:
Magellan Petroleum (UK) Limited	United Kingdom	100.0%
Magellan Petroleum Australia Pty Ltd owns the following subsidiaries directly:
Magellan Petroleum (Offshore) Pty Ltd	Queensland, Australia	100.0%

(1) Tellurian Inc. directly owns 70% of Magellan Petroleum Pty Ltd (“MPA”), and the remaining 30% of MPA is directly owned by Magellan Petroleum (UK) Limited, a wholly owned subsidiary of Magellan Petroleum (UK) Investment Holdings Limited.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements Nos. 333-216013 and 333-216011 on Form S-3ASR and Registration Statement Nos. 333-220641, 333-216010, 333-189614, 333-171149, 333-162668 and 333-70567 on Form S-8 of our reports dated February 27, 2019, relating to the consolidated financial statements and financial statement schedule of Tellurian Inc. and subsidiaries, and the effectiveness of Tellurian Inc. and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Tellurian Inc. for the year ended December 31, 2018.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2019

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 of Tellurian Inc. (No. 333-216013 and No. 333-216011) and to the incorporation by reference in the Registration Statements on Form S-8 of Tellurian Inc. (No. 333-220641, No. 333-216010, No. 333-189614, No. 333-171149, No. 333-162668 and No. 333-70567) of all references to our firm and information from our reserves report dated January 30, 2019 included in or made a part of Tellurian Inc.’s Annual Report on Form 10-K for the year ended December 31, 2018, and our summary report attached as Exhibit 99.2 to the Annual Report on Form 10-K.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Danny D. Simmons
	Danny D. Simmons, P.E.
	President and Chief Operating Officer

Houston, Texas

February 27, 2019

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Meg A. Gentle, certify that:

1. I have reviewed this annual report on Form 10-K of Tellurian Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 27, 2019

/s/ Meg A. Gentle

Meg A. Gentle

Chief Executive Officer

(as Principal Executive Officer)

Tellurian Inc.

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Antoine J. Lafargue, certify that:

1. I have reviewed this annual report on Form 10-K of Tellurian Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 27, 2019

/s/ Antoine J. Lafargue

Antoine J. Lafargue

Senior Vice President and Chief Financial Officer

(as Principal Financial Officer)

Tellurian Inc.

EX-32.1

Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Tellurian Inc. (the “Company”) on Form 10-K for the year ended December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Meg A. Gentle, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 27, 2019

/s/ Meg A. Gentle

Meg A. Gentle

Chief Executive Officer

(as Principal Executive Officer)

Tellurian Inc.

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Tellurian Inc. (the “Company”) on Form 10-K for the year ended December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Antoine J. Lafargue, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 27, 2019

/s/ Antoine J. Lafargue

Antoine J. Lafargue

Senior Vice President and Chief Financial Officer

(as Principal Financial Officer)

Tellurian Inc.

EX-99.2

Exhibit 99.2

January 30, 2019

Ms. Ami Arief

Tellurian Production LLC

1201 Louisiana Street, Suite 3100

Houston, Texas 77002

Dear Ms. Arief:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2018, to the Tellurian Production LLC (Tellurian) interest in certain oil and gas properties located in Louisiana. We completed our evaluation on or about January 18, 2019. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Tellurian. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Tellurian Inc.'s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Tellurian interest in these properties, as of December 31, 2018, to be:

	Net Reserves			Future Net Revenue (M$)
	Gas	Oil	Gas Equivalent		Present Worth
Category	(MMCF)	(MBBL)	(MMCFE)	Total	at 10%
Proved Developed Producing	17,007.3	7.5	17,052.1	26,146.8	23,084.1
Proved Developed Non-Producing	514.8	0.0	514.8	1,096.3	894.5
Proved Undeveloped	247,332.0	0.0	247,332.0	279,631.7	154,225.5
Total Proved	264,854.1	7.5	264,898.9	306,874.8	178,204.1

Totals may not add because of rounding.

Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas equivalent volumes are expressed in millions of cubic feet equivalent (MMCFE), determined using the ratio of 6 MCF of gas to 1 barrel of liquids.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

Gross revenue is Tellurian's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Tellurian's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2018. For gas volumes, the average Henry Hub spot price of $3.100 per MMBTU is adjusted for energy content, transportation fees, and market differentials. The fees associated with Tellurian's transportation contracts are included as a deduction to gas revenue. For oil volumes, the average West Texas Intermediate spot price of $65.56 per barrel is adjusted for quality, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $2.552 per MCF of gas and $60.39 per barrel of oil.

Operating costs used in this report are based on operating expense records of Tellurian. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into project-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Tellurian are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Tellurian and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and any production equipment necessary to connect the wells to sales. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Tellurian's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Tellurian interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Tellurian receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Tellurian, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas

evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Tellurian, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Richard B. Talley, Jr., a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2004 and has over 5 years of prior industry experience. Zachary R. Long, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2007 and has over 2 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

	/s/ C.H. (Scott) Rees III
By:
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer

	/s/ Richard B. Talley, Jr.		/s/ Zachary R. Long
By:		By:
	Richard B. Talley, Jr., P.E. 102425		Zachary R. Long, P.G. 11792
	Senior Vice President		Vice President
Date Signed:	January 30, 2019	Date Signed:	January 30, 2019

SDC:TTS

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:

Developed Producing Reserves - Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves - Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by

Definitions - Page 2 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

Definitions - Page 3 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used

Definitions - Page 4 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Definitions - Page 5 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a.	Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.	Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a.	Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.	Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.	Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.	Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e.	Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.	Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Definitions - Page 6 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
•	The company's level of ongoing significant development activities in the area to be developed ( for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
•	The company's historical record at completing development of comparable long-term projects;
•	The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
•	The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
•	The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 7 of 7

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Document and Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Feb. 15, 2019	Jun. 29, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	TELL
Entity Registrant Name	TELLURIAN INC. /DE/
Entity Central Index Key	0000061398
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Voluntary Filers	No
Entity Common Stock, Shares Outstanding		240,460,607
Entity Public Float			$ 766,390
Entity Well Known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
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	0
Other non-current assets	18,659	9,276
Total assets	408,548	276,823
Current liabilities:
Accounts payable	11,597	11,462
Accrued liabilities	41,173	39,101
Other current liabilities	0	1,735
Total current liabilities	52,770	52,298
Senior secured term loan	57,048	0
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	0
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

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Preferred stock, par value (in usd per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares outstanding	6,123,782	0
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares, outstanding	240,655,607	222,749,220

XML

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended	12 Months Ended
	Apr. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Total revenue		$ 10,286	$ 5,441	$ 0
Related party		0	0	0
Operating costs and expenses:
Cost of sales		6,115	7,565	0
Development expenses		44,034	59,498	47,146
Depreciation, depletion and amortization		1,567	479	69
General and administrative expenses		81,777	98,874	46,515
Impairment charge and loss on transfer of assets	$ 0	4,513	0	0
Goodwill impairment		0	77,592	0
Total operating costs and expenses		138,006	244,008	93,730
Loss from operations		(127,720)	(238,567)	(93,730)
Gain (loss) on preferred stock exchange feature		0	2,209	(3,308)
Interest income, net	0	1,574	1,022	0
Other income, net		211	4,062	217
Loss before income taxes		(125,935)	(231,274)	(96,821)
Income tax benefit (provision)		190	(185)	166
Net loss		$ (125,745)	$ (231,459)	$ (96,655)
Net loss per common share:
Basic and diluted (in dollars per share)		$ (0.59)	$ (1.23)	$ (1.01)
Weighted average shares outstanding:
Basic and diluted (in shares)		211,574	188,536	95,795
Predecessor
Revenues:
Total revenue	31
Related party	31
Operating costs and expenses:
Cost of sales	0
Development expenses	44
Depreciation, depletion and amortization	8
General and administrative expenses	617
Impairment charge and loss on transfer of assets	0
Goodwill impairment	0
Total operating costs and expenses	669
Loss from operations	(638)
Gain (loss) on preferred stock exchange feature	0
Other income, net	0
Loss before income taxes	(638)
Income tax benefit (provision)	0
Net loss	(638)
Natural gas sales
Revenues:
Total revenue		$ 4,423	$ 503	$ 0
Natural gas sales | Predecessor
Revenues:
Total revenue	0
LNG sales
Revenues:
Total revenue		2,689	3,273	0
LNG sales | Predecessor
Revenues:
Total revenue	0
Other LNG revenue
Revenues:
Total revenue		$ 3,174	$ 1,665	$ 0
Other LNG revenue | Predecessor
Revenues:
Total revenue	$ 0

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Consolidated Statement of Stockholders' Equity - USD ($) $ in Thousands		Total	Common Stock	Series A Preferred Stock	Series B Preferred Stock	Series C Preferred Stock	Exchange from Series B to common stock	Common Stock	Common Stock Common Stock	Common Stock Exchange from Series B to common stock	Treasury Stock	Preferred Stock	Preferred Stock Series A Preferred Stock	Preferred Stock Convertible Preferred Stock	Preferred Stock Series B Preferred Stock	Preferred Stock Series C Preferred Stock	Preferred Stock Exchange from Series B to common stock	Additional Paid-in Capital	Additional Paid-in Capital Common Stock	Additional Paid-in Capital Series A Preferred Stock	Additional Paid-in Capital Series B Preferred Stock	Additional Paid-in Capital Series C Preferred Stock	Accumulated Deficit
Beginning balance at Dec. 31, 2015		$ 0						$ 0			$ 0	$ 0		$ 0				$ 0					$ 0
Beginning balance, shares at Dec. 31, 2015								0			0	0		0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common stock issued for acquisition		1,000						$ 1										999
Common stock issued for acquisition, shares								500,000
Issuance of stock			$ 57,374	$ 19,385					$ 98				$ 5						$ 57,276	$ 19,380
Issuance of stock, shares									98,356,000				5,468,000
Share-based compensation		$ 24,495						$ 2										24,493
Share-based compensation, shares								10,753,000
Share-based payments, shares		0
Net loss		$ (96,655)																					(96,655)
Ending balance at Dec. 31, 2016		5,599						$ 101			$ 0	$ 0		$ 5				102,148					(96,655)
Ending balance, shares at Dec. 31, 2016								109,609,000			0	0		5,468,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common stock issued for acquisition		87,923						$ 1,390										86,533
Common stock issued for acquisition, shares								51,540,000			(1,209,000)
Issuance of stock		311,924						$ 465		$ 5,468			$ (5,468)		$ 5,468		$ (5,468)	311,459
Issuance of stock, shares								46,373,000
Share-based compensation		23,019						$ 16										23,003
Share-based compensation, shares								9,350,000
Share-based payments		$ 21,165						$ 17										21,148
Share-based payments, shares		2,000,000						1,700,000
Exchange from/to preferred stock				$ (5)	$ 5		$ 0			$ 55			$ (5)		$ 55		$ (55)				$ (50)
Net loss		$ (231,459)																					(231,459)
Reclass of embedded derivative		6,544																6,544
Treasury stock		(828)									$ (828)
Treasury stock, shares											(82,000)
Retirement of treasury stock, shares								(1,291,000)			1,291,000
Retirement of treasury stock, par value								$ (1)
Retirement of treasury stock, cost		0									$ 828							(827)
Ending balance at Dec. 31, 2017		223,887						$ 2,043			$ 0	$ 0		$ 0				549,958					(328,114)
Ending balance, shares at Dec. 31, 2017								222,749,000			0	0		0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of stock			$ 129,710			$ 49,966			$ 135							$ 61			$ 129,575			$ 49,905
Issuance of stock, shares									13,500,000							6,124,000
Share-based compensation	[1]	$ 20,116						$ 17										20,099
Share-based compensation, shares	[1]							4,407,000
Share-based payments, shares		0
Net loss		$ (125,745)																					(125,745)
Ending balance at Dec. 31, 2018		$ 297,934						$ 2,195			$ 0	$ 61		$ 0				$ 749,537					$ (453,859)
Ending balance, shares at Dec. 31, 2018								240,656,000			0	6,124,000		0

[1] Includes settlement of 2017 bonus that was accrued for in December 2017.

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Apr. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net loss		$ (125,745)	$ (231,459)	$ (96,655)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		1,567	479	69
Goodwill impairment		0	77,592	0
Loss on disposal of assets		0	0	185
Provision for income tax benefit		0	0	(170)
Amortization of debt issuance costs		267	0	0
(Gain) loss on Series A convertible preferred stock exchange feature		0	(2,209)	3,308
Gain on sale of securities		0	(3,481)	0
Share-based compensation		5,126	23,019	24,495
Impairment charge and loss on transfer of assets	$ 0	4,513	0	0
Share-based payments		0	19,397	0
Net changes in working capital (Note 16)		10,520	7,433	18,338
Net cash used in operating activities		(103,752)	(109,229)	(50,430)
Cash flows from investing activities:
Cash received in acquisition		0	56	210
Acquisition and development of natural gas properties		(8,356)	(90,099)	0
Deferred engineering costs		(10,000)	(9,000)	0
Proceeds from transfer of asset		167	0	0
Purchase of property - land		(3,498)	0	(9,491)
Purchase of property and equipment		0	(1,114)	(1,225)
Proceeds from sale of available-for-sale securities		0	4,592	0
Net cash used in investing activities		(21,687)	(95,565)	(10,506)
Cash flows from financing activities:
Proceeds from borrowing under term loan		59,400	0	0
Payments of term loan financing costs		(2,621)	0	0
Proceeds from the issuance of common stock		133,800	318,204	59,015
Tax payments for net share settlement of equity awards (Note 16)		(5,734)	(828)	0
Proceeds from the issuance of preferred stock		0	0	25,000
Equity offering costs		(4,090)	(5,707)	(1,681)
Net 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
Cash, cash equivalents and restricted cash, beginning of period	0	128,273	21,398	0
Cash, cash equivalents and restricted cash, end of period	210	183,589	128,273	21,398
Supplementary disclosure of cash flow information:
Interest paid		$ (1,174)	$ 0	0
Predecessor
Cash flows from operating activities:
Net loss	(638)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization	8
Goodwill impairment	0
Loss on disposal of assets	3
Provision for income tax benefit	0
Amortization of debt issuance costs	0
(Gain) loss on Series A convertible preferred stock exchange feature	0
Gain on sale of securities	0
Share-based compensation	0
Impairment charge and loss on transfer of assets	0
Share-based payments	0
Net changes in working capital (Note 16)	516
Net cash used in operating activities	(111)
Cash flows from investing activities:
Cash received in acquisition	0
Acquisition and development of natural gas properties	0
Deferred engineering costs	0
Proceeds from transfer of asset	0
Purchase of property - land	0
Purchase of property and equipment	(268)
Proceeds from sale of available-for-sale securities	0
Net cash used in investing activities	(268)
Cash flows from financing activities:
Proceeds from borrowing under term loan	0
Payments of term loan financing costs	0
Proceeds from the issuance of common stock	0
Tax payments for net share settlement of equity awards (Note 16)	0
Proceeds from the issuance of preferred stock	0
Equity offering costs	0
Net cash provided by financing activities	0
Net increase (decrease) in cash, cash equivalents and restricted cash	(379)
Cash, cash equivalents and restricted cash, beginning of period	589			$ 589
Cash, cash equivalents and restricted cash, end of period	210
Supplementary disclosure of cash flow information:
Interest paid	$ 0

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Basis of Presentation and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Basis of Presentation and Summary of Significant Accounting Policies

NOTE 1 — BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Tellurian Inc., a Delaware corporation based in Houston, Texas (“Tellurian”), plans to develop, own and operate a global natural gas business and to deliver natural gas to customers worldwide. Tellurian has begun to establish a portfolio of natural gas production, LNG marketing, and infrastructure assets including an LNG terminal facility (the “Driftwood terminal”) and an associated pipeline (the “Driftwood pipeline”) in southwest Louisiana. Tellurian intends to develop the Driftwood pipeline as part of what we refer to as the “Pipeline Network.” In addition to the Driftwood pipeline, the Pipeline Network is expected to include two pipelines, the Haynesville Global Access Pipeline and the Permian Global Access Pipeline, both of which are currently in the early stages of development. The Driftwood terminal, the Pipeline Network and Tellurian’s existing and planned natural gas production assets are referred to collectively as the “Driftwood Project”.

On February 10, 2017 (the “Merger Date”), Tellurian Investments Inc. (“Tellurian Investments”) completed a merger (the “Merger”) with a subsidiary of Magellan Petroleum Corporation (“Magellan”). Magellan changed its corporate name to Tellurian Inc. shortly after completing the Merger. The Merger was accounted for as a “reverse acquisition,” with Tellurian Investments being treated as the accounting acquirer. As such, the historical consolidated comparative information as of and for all periods in 2016 in this report relates to Tellurian Investments and its subsidiaries. Subsequent to the Merger Date, the information relates to the consolidated entities of Tellurian Inc., with Magellan reflected as the accounting acquiree. In connection with the Merger, each issued and outstanding share of Tellurian Investments common stock was exchanged for 1.3 shares of Magellan common stock. All share and per share amounts in the Consolidated Financial Statements and related notes have been retroactively adjusted for all periods presented to give effect to this exchange, including reclassifying an amount equal to the change in par value of common stock from additional paid-in capital.

On April 9, 2016, Tellurian Investments acquired Tellurian Services LLC (“Tellurian Services”), formerly known as Parallax Services LLC (“Parallax Services”). Under the financial reporting rules of the SEC, Parallax Services (“Predecessor”) has been deemed to be the predecessor to Tellurian (“Successor”) for financial reporting purposes.

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.

Basis of Presentation

Our Consolidated Financial Statements were prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Tellurian Inc. and its wholly and majority owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

Segments

Management allocates resources and assesses financial performance on a consolidated basis. As such, for the purposes of financial reporting under GAAP during the years ended December 31, 2018, 2017 and 2016, the Company operated as a single operating segment.    

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions on a regular basis. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

The Company uses three levels of the fair value hierarchy of inputs to measure the fair value of an asset or a liability. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.

Goodwill

Goodwill resulting from a business combination is not subject to amortization. The Company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.

Revenue Recognition

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), amended the previous revenue recognition guidance and required us to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted the new standard on January 1, 2018, utilizing the modified retrospective approach. We have applied the standard to all contracts as of the date of the application of the standard. We developed an accounting policy, implemented changes to the relevant business processes and the control activities within them, and evaluated the disclosure requirements as a result of the provisions of this ASU. Adoption of the ASU did not require an adjustment to the opening stockholders’ equity and did not change our amount and timing of revenues. We have elected to exclude all taxes from the measurement of transaction price.

For the sale of commodities, we consider the delivery of each unit (MMBtu) to be a separate performance obligation that is satisfied upon delivery. These contracts are either fixed price contracts or contracts with a fixed differential to an index price, both of which are considered fixed consideration. The fixed consideration is allocated to each performance obligation and represents the relative standalone selling price basis.

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “LNG sales” on the Consolidated Statements of Operations. For such LNG sales, we require payment within 10 days from delivery. Other LNG revenue represents revenue earned from sub-charter agreements and is accounted for outside of this ASU and in line with Accounting Standards Codification 840, Leases.

In our judgment, the performance obligations for the sale of natural gas and LNG are satisfied at a point in time because the customer obtains control and legal title of the asset when the natural gas or LNG is delivered to the designated sales point.

Because our performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, we have recognized amounts due from contracts with customers of $0.5 million as accounts receivable within the Consolidated Balance Sheets as of December 31, 2018.

Cash, Cash Equivalents and Restricted Cash

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents that are restricted as to withdrawal or use under the terms of certain contractual agreements are recorded in Non-current restricted cash on our Consolidated Balance Sheets.

Concentration of Cash

We maintain cash balances and restricted cash at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the criteria for and we elect the normal purchases and sales exception.

Changes in the fair value of our derivative instruments are recorded in earnings, and, at present, we have elected not to apply hedge accounting. See Note 12, Financial Instruments for additional details about our derivative instruments.

Property, Plant and Equipment

Natural gas development and production activities are accounted for using the successful efforts method of accounting. Costs incurred to acquire a property (whether unproved or proved) are capitalized when incurred. Lease rentals are expensed as incurred. Natural gas exploratory costs are expensed as incurred and costs to develop proved reserves are capitalized. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. We deplete our natural gas reserves using the units-of-production method.

Fixed assets are recorded at cost. We depreciate our property, plant and equipment, excluding land, using the straight-line depreciation method over the estimated useful life of the asset. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed, and the resulting gains or losses are recorded in our Consolidated Statements of Operations. Management tests property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of property, plant and equipment might not be recoverable.

Accounting for LNG Development Activities

As we have been in the preliminary stage of developing the Driftwood terminal, substantially all of the costs to date related to such activities have been expensed. These costs primarily include professional fees associated with FEED studies and applying to FERC for authorization to construct our terminals and other required permitting for the Driftwood Project.

Costs incurred in connection with a project to develop the Driftwood terminal shall generally be treated as development expenses until the project has reached the notice-to-proceed state (“NTP State”) and the following criteria (the “NTP Criteria”) have been achieved: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. In addition to the above, certain costs incurred prior to achieving the NTP State will be capitalized though the NTP Criteria have not been met. Costs to be capitalized prior to achieving the NTP State include land purchase costs, land improvement costs, costs associated with preparing the facility for use and any fixed structure construction costs (fence, storage areas, drainage, etc.). Furthermore, activities directly associated with detailed engineering and/or facility designs shall be capitalized.

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.

Debt

Discounts and expenses incurred with the issuance of debt are amortized over the term of the debt. These amounts are presented as a reduction of Senior secured term loan on the accompanying Consolidated Balance Sheets. See Note 13, Long-Term Borrowings, for additional details about our Senior secured term loan.

Income Taxes

We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, we determine deferred tax assets and liabilities on the basis of the differences between the financial statement and tax basis of assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to be realized or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a determination, we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. If we determine that we would be able to realize our deferred tax assets in the future in excess of their net recorded amount, we would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.

Net Loss Per Share (EPS)

Basic net loss per share excludes dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period. Diluted net loss per share reflects potential dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued and were dilutive.

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Merger and Acquisition

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Merger and Acquisition

NOTE 2 — MERGER AND ACQUISITION

The Merger

As discussed in Note 1, Basis of Presentation and Summary of Significant Accounting Policies, Tellurian Investments merged with a subsidiary of Magellan on February 10, 2017. The Merger has been accounted for as a “reverse acquisition,” with Tellurian Investments being treated as the accounting acquirer using the acquisition method.

The total consideration exchanged was as follows (in thousands, except share and per-share amounts):

Number of shares of Magellan common stock outstanding (1)	5,985,042
Price per share of Magellan common stock (2)	$	14.21
Aggregate value of Tellurian common stock issued			$	85,048
Fair value of stock options (3)			2,821
Net purchase consideration to be allocated			$	87,869
(1) The number of shares of Magellan common stock issued and outstanding as of February 9, 2017.
(2) The closing price of Magellan common stock on the NASDAQ on February 9, 2017.
(3) The estimated fair value of Magellan stock options for pre-Merger services rendered.

We utilized estimated fair values at the Merger Date for the allocation of consideration to the net tangible and intangible assets acquired and liabilities assumed. The purchase price allocation to assets acquired and liabilities assumed in the Merger was as follows (in thousands):

Fair Value of Assets Acquired:
Cash	$	56
Securities available-for-sale	1,111
Other current assets	93
Unproved properties	13,000
Wells in progress	332
Land, buildings and equipment, net	67
Other long-term assets	19
Total assets acquired	14,678
Fair Value of Liabilities Assumed:
Accounts payable and other liabilities	4,393
Notes payable	8
Total liabilities assumed	4,401
Total net assets acquired	10,277
Goodwill as a result of the Merger	$	77,592

We valued our interests acquired in unproved oil and gas properties using a market approach based on commercial negotiations and bids received for the interests (see Note 5, Property, Plant and Equipment, for more information about the properties). The fair value of other property, plant and equipment and wells in progress was determined to be the carrying value of Magellan. Securities available-for-sale were valued based on quoted market prices. The carrying values of cash, other current assets, accounts payable and accrued liabilities and other non-current assets and liabilities approximated fair value at the Merger Date. The Company has determined that such fair value measures for the overall allocation are classified as Level 3 in the fair value hierarchy.

Goodwill recognized as a result of the Merger totaled approximately $77.6 million, none of which is deductible for income tax purposes. Subsequent to the Merger, the Company determined that there is no evidence that we will recover the value of this goodwill and an impairment expense of approximately $77.6 million was recognized during the year ended December 31, 2017. For purposes of determining the goodwill impairment, we utilized qualitative factors as well as the fair values determined when allocating consideration as of the Merger Date.

Parallax Services Acquisition

On April 9, 2016, Tellurian Investments acquired Parallax Services, which was renamed Tellurian Services, with equity consideration valued at approximately $1 million. The transaction was accounted for using the acquisition method.

Pro Forma Results

The following table provides unaudited pro forma results for the year ended December 31, 2017, and 2016, as if the Merger occurred and Parallax Services had been acquired as of January 1, 2016 (in thousands, except per-share amounts):

	Year Ended December 31,
	2017			2016
Pro forma net loss	$	(235,201	)	$	(100,734	)
Pro forma net loss per basic share	$	(1.24	)	$	(0.98	)
Pro forma basic and diluted weighted average common shares outstanding	189,246			102,281

The unaudited pro forma results include adjustments for the historical net loss of Magellan and Parallax Services as well as an increase in compensation expense associated with the addition of three new directors. The pro forma information is provided for informational purposes only and is not necessarily indicative of what Tellurian’s results of operations would have been if the Merger and acquisition of Parallax Services had occurred on January 1, 2016. Following the Merger Date, approximately $0.8 million of net loss related to the acquired activities has been included in our Consolidated Financial Statements.

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Deferred Engineering Costs

12 Months Ended

Dec. 31, 2018

Deferred Costs [Abstract]

Deferred Engineering Costs

NOTE 3 — DEFERRED ENGINEERINGCOSTS

Deferred engineering costs of $69.0 million at December 31, 2018 and $18.0 million at December 31, 2017 represent detailed engineering services related to the Driftwood terminal. Such costs will be deferred until construction commences on the Driftwood terminal, at which time they will be transferred to construction in progress.

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Transaction with Related Parties

12 Months Ended

Dec. 31, 2018

Related Party Transactions [Abstract]

Transaction with Related Parties

NOTE 4 — TRANSACTIONS WITH RELATED PARTIES

Accounts Receivable due from Related Parties

Tellurian’s accounts receivable due from related parties primarily consists of tax indemnities from employees who received share-based compensation in 2016.

Accounts Payable due to Related Parties

In December 2017, Tellurian and Martin Houston, a major shareholder and Vice Chairman of the Company, agreed to mutually discharge $0.3 million owed by Tellurian to entities partially owned by Mr. Houston.

Non-current Note Receivable due from Related Party

In July 2017, the $0.3 million non-current note receivable due from Mr. Houston was repaid in full, and the demand note evidencing the receivable was canceled.

Other

During the year ended December 31, 2018, the Company incurred approximately $0.1 million in legal fees to a law firm for various legal advice. During the year ended December 31, 2017, the Company incurred $0.7 million in legal fees to the same law firm for advice associated with a lawsuit that was settled in April 2017. A member of our board of directors is a partner at such law firm.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of fixed assets and oil and natural gas properties, as shown below (in thousands):

	December 31,
	2018			2017
Land	$	13,276		$	9,491
Proved properties	101,459			90,869
Unproved properties	10,204			13,000
Wells in progress	4,660			345
Corporate and other	2,905			2,693
Total fixed assets, at cost	132,504			116,398
Accumulated depreciation and depletion	(1,924		)	(542		)
Total property, plant and equipment, net	$	130,580		$	115,856

Depreciation and depletion expense for the years ended December 31,2018, 2017 and 2016 was approximately $1.5 million, $0.5 million and $0.1 million, respectively.

Land

We own land in Louisiana for the purpose of constructing the Driftwood Project.

Proved Properties

We own producing and non-producing acreage in northern Louisiana. In September 2018, we identified indicators of impairment related to certain non-producing acreage that led to an impairment charge of approximately $2.7 million.

Unproved Properties

We own interests in unproved properties in the Weald Basin, United Kingdom through our holding of non-operating interests in two licenses which expire in June and September 2021. We previously held an operating interest in an exploration permit in the Bonaparte Basin, Australia; however, in May 2018, we transferred the permit to a third party for consideration of approximately $0.2 million in cash and the release of approximately $1.3 million in liabilities incurred in connection with a canceled 2017 seismic survey. As a result, we have recognized, within our Consolidated Statement of Operations, a loss on the transfer of the permit of approximately $1.0 million during the current year.

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Other Non-Current Assets

12 Months Ended

Dec. 31, 2018

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other Non-Current Assets

NOTE 6 — OTHER NON-CURRENT ASSETS

Other non-current assets consist of the following (in thousands):

	December 31, 2018		December 31, 2017
Land lease and purchase options	$	4,115	$	2,948
Permitting costs	12,585		4,708
Other	1,959		1,620
Total other non-current assets	$	18,659	$	9,276

Land Lease and Purchase Options

We hold lease and purchase option agreements (the “Options”) for certain tracts of land and associated river frontage that provide for four or five-year terms. In addition to the Options, the Company holds a ground lease for a port facility adjacent to a tract of land that was acquired in March 2016. The lease provides for a four-year term, subject to a 20-year extension and sixfive-year renewals. The ground lease is accounted for as an operating lease, with rental payments accounted for using the straight-line method.

Upon exercise of the Options, the leases are subject to maximum terms of 60 years (inclusive of various renewals) at the option of the Company. Lease and purchase option payments have been capitalized in other non-current assets. Costs of the Options will be amortized over the life of the lease once obtained, or capitalized into the land if purchased.

Permitting Costs

Permitting costs primarily represent the purchase of wetland credits in connection with our permit application to the USACE in 2018 and 2017. These wetland credits will be applied to our permit in accordance with the Clean Water Act and the Rivers and Harbors Act, which require us to mitigate the impact to the Louisiana wetlands caused by the construction of the Driftwood Project. If the USACE permit is secured, the permitting costs will be capitalized and depreciated with the total cost to construct the Driftwood Project.

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Accrued Liabilities

12 Months Ended

Dec. 31, 2018

Payables and Accruals [Abstract]

Accrued Liabilities

NOTE 7 — ACCRUED LIABILITIES

The components of accrued liabilities consist of the following (in thousands):

	December 31,
	2018		2017
Project development activities	$	8,879	$	5,142
Payroll and compensation	23,286		25,833
Accrued taxes	2,507		2,764
Professional services (e.g., legal, audit)	2,423		2,806
Accrued rent and other	4,078		2,556
Total accrued liabilities	$	41,173	$	39,101

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

NOTE 8 — COMMITMENTS AND CONTINGENCIES

Litigation

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, now known as Tellurian Services) on the other hand (collectively, “Parallax”). In October 2017, Driftwood Pipeline LLC (“Driftwood Pipeline”) and Tellurian Services 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 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.

Contractual Obligations

The Company is obligated under various non-cancelable operating lease agreements for office facilities that generally provide for minimum rent payments and a proportionate share of operating expenses and property taxes and include certain renewal and expansion options. For the years ended December 31, 2018, 2017 and 2016, rent expense under these lease arrangements was $3.2 million, $2.3 million and $0.5 million, respectively.

At December 31, 2018, contractual obligations for long-term operating leases and purchase obligations are as follows (in thousands):

	2019		2020		2021		2022		2023		Thereafter		Total
Office leases	$	3,126	$	3,510	$	3,440	$	3,718	$	3,993	$	8,061	$	25,848
Land lease and purchase options	1,588		634		23		23		23		436		2,727
Other	499		499		2		—		—		—		1,000
	$	5,213	$	4,643	$	3,465	$	3,741	$	4,016	$	8,497	$	29,575

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Share-Based Compensation

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

NOTE 9 — SHARE-BASED COMPENSATION

We have granted restricted stock, restricted stock units and phantom units (collectively, “Restricted Stock”), as well as unrestricted stock and stock options, to employees, directors and outside consultants (collectively, the “grantees”) under the Tellurian Inc. 2016 Omnibus Incentive Compensation Plan, as amended (the “2016 Plan”), and the Amended and Restated Tellurian Investments Inc. 2016 Omnibus Incentive Plan (the “Legacy Plan”). The maximum number of shares of Tellurian common stock authorized for issuance under the 2016 Plan is 40 million shares of common stock, and no further awards can be made under the Legacy Plan.

For the year ended December 31, 2018, share-based compensation expense related to all share-based awards totaled approximately $5.1 million. For the year ended December 31, 2017, share-based compensation expense related to all share-based awards totaled approximately $23.0 million, approximately $2 million of which was issued in settlement of bonuses accrued at December 31, 2016. For the year ended December 31, 2016, share-based compensation expense related to all share-based awards totaled approximately $24.5 million. As of December 31, 2018, unrecognized compensation expense, based on the grant date fair value, for all share-based awards totaled approximately $197.0 million.

Restricted Stock

Upon the vesting of restricted stock, shares of common stock will be released to the grantee. Upon the vesting of certain restricted stock units, the units will be converted into shares of common stock and released to the grantee. In March 2018, we began issuing phantom units that may be settled in either cash, stock or a combination thereof.As of December 31, 2018, there was no Restricted Stock that would be required to be settled in cash.

As of December 31, 2018, we had granted approximately 24.4 million shares of performance-based Restricted Stock, of which approximately 19.8 million shares will vest entirely based upon an affirmative final investment decision (“FID”) by the Company’s board of directors, as defined in the award agreements, and approximately 4.0 million shares will vest in one-third increments at FID and the first and second anniversary of FID. The remaining shares of performance-based Restricted Stock, totaling approximately 0.6 million shares, will vest based on other criteria. As of December 31, 2018, no expense had been recognized in connection with performance-based Restricted Stock.

The fair value of the Restricted Stock was established by the market price on the date of grant and, for service-based awards, is being recognized as compensation expense ratably over the vesting term.

The following table provides a summary of our Restricted Stock transactions for the year ended December 31, 2018 (shares and units in thousands):

	Shares		Weighted-Average Grant Date Fair Value
Unvested at January 1, 2018	20,488		$	6.95
Granted (1)	4,311		11.02
Vested	(213	)	11.60
Forfeited	(202	)	11.73
Unvested at December 31, 2018	24,384		$	7.59

⁽¹⁾ The weighted-average grant date fair value of Restricted Stock granted during the years ended December 31, 2018, 2017 and 2016 was $11.02, $9.59 and $3.52, respectively.

The total grant date fair value of restricted stock vested during the years ended December 31, 2018, 2017 and 2016 was approximately $2.5 million, $3.7 million and $0.4 million, respectively.

Stock Options

The 2016 Plan participants have been granted non-qualified options to purchase shares of common stock. Stock options are granted at a price not less than the market price of the common stock on the date of grant. Stock options vest equally over a three-year period from the date of grant. Options shall be exercisable at such time and under such conditions set forth in the underlying award agreement, but in no event shall any option be exercisable later than the tenth anniversary of the date of its grant. The fair value of each stock option award is estimated using the Black-Scholes option pricing model.

The following table provides a summary of our stock option transactions for the year ended December 31, 2018 (stock options in thousands):

	Stock Options		Weighted Average Exercise Price
Outstanding at January 1, 2018	2,011		$	10.32
Granted	—		—
Exercised	—		—
Forfeited or Expired	(23	)	10.32
Outstanding at December 31, 2018	1,988		$	10.32
Exercisable at December 31, 2018	665		$	10.32

Valuation assumptions used to value stock options for the year ended December 31, 2017 (there were no stock options granted in 2018 or 2016), were as follows:

	December 31, 2017
Expected term (in years)	6.0
Expected volatility	22.13	%
Expected dividend yields	—	%
Risk-free rate	2.05	%

Due to our limited history, the Company has elected to apply the simplified method to determine the expected term. Additionally, due to our limited history, expected volatility is based on the implied volatility of the Company's peer group as identified by our board of directors. The expected dividend yield is based on historical yields on the date of grant. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

There were no stock options granted or exercised during the year ended December 31, 2018. There were 2.0 million stock options granted during the year ended December 31, 2017, with the weighted average grant date fair value of $2.72. No stock options were exercised during the year ended December 31, 2017. There were no stock options granted or exercised during the year ended December 31, 2016.

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Share-Based Payments

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Payments

NOTE 10 — SHARE-BASED PAYMENTS

For the year ended December 31, 2018 and 2017, Tellurian recognized approximately $0.0 million and $19.4 million as share-based expense for various third-party provided services.

In February 2017, the Company issued 409,800 shares of Tellurian common stock, valued at approximately $5.8 million, to a financial adviser in connection with the successful completion of the Merger. This cost has been included in general and administrative expenses in the Consolidated Statements of Operations. Additionally, on the Merger Date, the Company issued 90,350 shares of Tellurian common stock to settle a liability assumed in the Merger valued at approximately $1.3 million.

In March 2017, the Company’s board of directors approved the issuance of 1.0 million shares that were purchased at a discount by a commercial development consultant under the Omnibus Plan. The terms of the share purchase agreement did not contain performance obligations or similar vesting provisions; accordingly, the full amount of approximately $11.4 million, representing the aggregate difference between the purchase price of $0.50 per share and the fair value on the date of issuance of $11.88 per share, was recognized on the date of the share purchase and has been included in general and administrative expenses in the Consolidated Statements of Operations.

Also in March 2017, the Company issued 200,000 shares under a management consulting arrangement for specified services performed from March 2017 through May 2017. The services were valued at $11.34 per share on the date of issuance. The total cost of approximately $2.3 million was amortized to general and administrative expenses on a straight-line basis over the three-month service period in the Consolidated Statements of Operations.

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Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 11 — INCOME TAXES

Income tax benefit (provision) included in our reported net loss consisted of the following (in thousands):

	Year Ended December 31,
	2018		2017			2016
Current:
Federal	$	—	$	—		$	—
State	—		—			(4		)
Foreign	190		(185		)	—
Total Current	190		(185		)	(4		)
Deferred:
Federal	—		—			170
State	—		—			—
Foreign	—		—			—
Total Deferred	—		—			170
Total income tax benefit (provision)	$	190	$	(185	)	$	166

The sources of loss from operations before income taxes were as follows (in thousands):

	Year Ended December 31,
	2018			2017			2016
Domestic	$	(115,137	)	$	(223,991	)	$	(95,739	)
Foreign	(10,798		)	(7,283		)	(1,082		)
Total loss before income taxes	$	(125,935	)	$	(231,274	)	$	(96,821	)

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:

	Year Ended December 31,
	2018			2017			2016
Income tax benefit (provision) at U.S. statutory rate	$	26,446		$	80,946		$	33,887
Share-based compensation	—			—			(5,911		)
Impairment	—			(27,969		)	—
Change in U.S. tax rate	—			(30,562		)	—
Change in valuation allowance due to change in U.S. tax rate	—			30,562			—
U.S. state tax	7,955			—			—
Change in valuation allowance	(32,086		)	(51,030		)	(26,398		)
Other	(2,125		)	(2,132		)	(1,412		)
Total income tax benefit (provision)	$	190		$	(185	)	$	166

Significant components of our deferred tax assets and liabilities are as follows (in thousands):

	December 31,
	2018			2017
Deferred tax assets:
Capitalized engineering costs	$	6,353		$	2,812
Capitalized start-up costs	19,290			17,881
Compensation and benefits	3,862			5,465
Net operating loss carryforwards and credits:
Federal	37,822			19,423
State	4,979			522
Foreign	2,392			1,694
Other, net	8,328			3,541
Deferred tax assets	83,026			51,338
Less valuation allowance	(83,026		)	(50,942		)
Deferred tax assets, net of valuation allowance	—			396
Deferred tax liabilities	—			(396		)
Net deferred tax assets	$	—		$	—

The Tax Cuts and Jobs Act of 2017 (the “Act”) was enacted on December 22, 2017, and has several key provisions impacting the accounting for, and reporting of, income taxes. On December 22, 2017, the SEC issued Staff Accounting Bulletin No. 118, which allows companies to report the income tax effects of the Act as a provisional amount based on a reasonable estimate, which would be subject to adjustment during a reasonable measurement period, not to exceed twelve months, until the accounting and analysis under ASC 740 is complete. We incorporated the impact of the Tax Act in our results of operations and calculated provisional amounts for the tax effects of the Tax Act that could be reasonably estimated. At December 31, 2017, we recorded a $30.6 million unfavorable impact on the Company’s gross U.S. deferred tax assets and a corresponding $30.6 million favorable impact to the valuation allowance. We have not recorded an adjustment to these amounts. As of December 31, 2018, our accounting for the impact of the Tax Act was complete.

As of December 31, 2018, we had federal, state and international net operating loss (“NOL”) carryforwards of $180.1 million, $113.7 million and $13.6 million, respectively. Approximately $88.4 million of these NOLs have an indefinite carryforward period. All other NOLs will expire between 2036 and 2037.

Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal, state and international deferred tax assets as of December 31, 2018, and 2017. We will continue to evaluate the realizability of our deferred tax assets in the future. The increase in the valuation allowance was $32.1 million for the year ended December 31, 2018.

In addition, we experienced a Section 382 ownership change in April 2017. An analysis of the annual limitation on the utilization of our NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not materially limit the use of our NOLs over the carryover period. We will continue to monitor trading activity in our shares which could cause an additional ownership change. If the Company experiences a Section 382 ownership change, it could further affect our ability to utilize our existing NOL carryforwards.

As of December 31, 2018, the Company determined that it has no uncertain tax positions, interest or penalties as defined within ASC 740-10. The Company does not have unrecognized tax benefits. The Company does not believe that it is reasonably possible that the total unrecognized benefits will significantly increase within the next 12 months.

We are subject to tax in the U.S. and various state and foreign jurisdictions. We are not currently under audit by any taxing authority. Federal and state tax returns filed with each jurisdiction remain open to examination under the normal three-year statute of limitations.

Pursuant to ASC 740-30-25-17, the Company recognizes deferred tax liabilities associated with outside basis differences on investments in foreign subsidiaries unless the difference is considered essentially permanent in duration. As of December 31, 2018, the Company has not recorded any deferred taxes on unremitted earnings as the Company has no undistributed earnings and profits. If circumstances change in the foreseeable future and it becomes apparent that some or all of the undistributed earnings and profits will not be reinvested indefinitely, or will be remitted in the foreseeable future, a deferred tax liability will be recorded for some or all of the outside basis difference.

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Financial Instruments

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Financial Instruments

NOTE 12 — FINANCIAL INSTRUMENTS

As discussed in Note 13, Long-Term Borrowings, as part of entering into the senior secured term loan credit agreement, we are required to enter into and maintain certain hedging transactions to remain compliant with a specific negative covenant. As a result, we use derivative financial instruments, namely over the counter (“OTC”) commodity swap instruments (collectively “commodity swaps”), to maintain compliance with this covenant. We do not hold or issue derivative financial instruments for trading purposes.

Commodity swap agreements involve payments to or receipts from counterparties based on the differential between two prices for the commodity, and also include basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices, as also required by the negative covenant of the senior secured term loan credit agreement.

The fair value of our commodity swaps is classified as Level 2 in the fair value hierarchy and is based on standard industry income approach models that use significant observable inputs, including but not limited to New York Mercantile Exchange (NYMEX) natural gas forward curves and basis forward curves, all of which are validated to external sources, at least monthly.

The Company recognizes all derivative instruments as either assets or liabilities at fair value on a net basis as they are with a single counterparty and subject to a master netting arrangement. These derivative instruments are reported as either current or non-current assets or current or non-current liabilities, based on their maturity dates. The Company can net settle its derivative instruments at any time. As of December 31, 2018, we had a current liability of $0.2 million, net, with respect to the fair value of the current portion of our commodity swaps. In addition, as of December 31, 2018, we had a non-current asset of $0.3 million, net, with respect to the fair value of the non-current portion of our commodity swaps. The current liability and the non-current asset are classified within Accrued liabilities and Other non-current assets, respectively, on the Consolidated Balance Sheets. Gross current asset and current liability amounts are $0.4 million and $0.6 million, respectively. Gross non-current asset and non-current liability amounts are $0.6 million and $0.3 million, respectively.

We do not apply hedge accounting for our commodity swaps; therefore, all changes in fair value of the Company’s derivative instruments are recognized within Other income, net, in the Consolidated Statements of Operations. For the year ended December 31, 2018, we recognized a realized loss of $0.1 million and an unrealized gain of $0.1 million related to the changes in fair value of the commodity swaps in our Consolidated Statements of Operations. Derivative contracts which result in physical delivery of a commodity expected to be used or sold by the Company in the normal course of business are designated as normal purchases and sales and are exempt from derivative accounting. OTC arrangements require settlement in cash. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Consolidated Statements of Cash Flows. 

With respect to the commodity swaps, the Company hedged portions of expected sales of equity production and portions of its basis exposure cover approximately 19.3 Bcf and 19.3 Bcf of natural gas, respectively, as of December 31, 2018. The open positions at December 31, 2018 had maturities extending through September 2021. 

For additional details, refer to Note 13, Long-Term Borrowings.

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Long-term Borrowings

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Long-term Borrowings

NOTE 13 — LONG-TERM BORROWINGS

On September 28, 2018 (the “Closing Date”), Tellurian Production Holdings LLC (“Production Holdings”), our wholly owned subsidiary, entered into a three-year senior secured term loan credit agreement (the “Term Loan”) in an aggregate 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. The discount and fees are being amortized over the term of the Term Loan on a straight-line basis. At December 31, 2018, the outstanding principal amount of the Term Loan was $60.0 million. In addition, the unamortized discount and deferred financing costs, as of December 31, 2018 were $3.0 million.

Our 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 is presented within non-current restricted cash on our Consolidated Balance Sheet. At December 31, 2018, unused proceeds from the Term Loan classified as non-current restricted cash were $49.6 million.

We have the right, but not the obligation, to make voluntary principal payments starting six months following the Closing Date in a minimum amount of $5.0 million or any integral multiples of $1.0 million in excess thereof. If no voluntary principal payments are made, the principal amount, together with any accrued interest, is payable at the maturity date of September 28, 2021.

The Term Loan can be terminated early with an early termination payment equal to the outstanding principal plus accrued interest. 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. 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. For the year ended December 31, 2018, our total interest expense associated with the Term Loan was $1.2 million.

Guarantors and Covenants

Amounts borrowed under the Term Loan are guaranteed by Tellurian Inc. and each of Production Holdings’ subsidiaries. The Term Loan is collateralized by a first priority lien on all assets of Production Holdings and its subsidiaries, including domestic properties described in Note 5, Property, Plant and Equipment.

The Term Loan contains specific financial covenants and as of December 31, 2018, we remained in compliance with such covenants under the Term Loan.

For details of hedging transactions, as at and for the year ended December 31, 2018, entered into for the purposes of the Term Loan, refer to Note 12, Financial Instruments.

Long-Term Borrowings Maturities

A summary of long-term borrowings maturities is as follows (in thousands):

Years Ending December 31,	Principal Payments
2019	$	—
2020	—
2021	60,000
Total	$	60,000

Fair Value

As of December 31, 2018, the carrying value of the Term Loan approximated fair value. The Term Loan is a Level 3 instrument in the fair value hierarchy. The Level 3 estimated fair value approximates the carrying value because the interest rates are variable and reflective of market rates, and the debt may be repaid, in full or in part, at any time with minimum penalty (as noted above, 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).

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Stockholders' Equity

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Stockholders' Equity

NOTE 14 — STOCKHOLDERS' EQUITY

At-the-Market Program

We maintain an at-the-market equity offering program pursuant to which we may sell shares of our common stock from time to time on Nasdaq through Credit Suisse Securities (USA) LLC acting as sales agent. We have availability under the at-the-market program to raise aggregate sales proceeds of up to $189.7 million.  

Preferred Stock

In March 2018, we entered into a preferred stock purchase agreement with BDC Oil and Gas Holdings, LLC (“Bechtel Holdings”), a Delaware limited liability company and an affiliate of Bechtel Oil, Gas and Chemicals, Inc., a Delaware corporation (“Bechtel”), pursuant to which we sold to Bechtel Holdings approximately 6.1 million shares of our Series C convertible preferred stock (the “Preferred Stock”).

In exchange for the Preferred Stock, Bechtel agreed to discharge approximately $22.7 million of the outstanding liabilities associated with the detailed engineering services for the Driftwood Project, and to apply approximately $27.3 million to additional future detailed engineering services. During the year ended December 31, 2018, all of the approximately $27.3 million of future services were received and, as such, all $50.0 million have been recognized on our Consolidated Balance Sheets within deferred engineering costs. See Note 3, Deferred Engineering Costs, for further information regarding the costs associated with the detailed engineering services.

The holders of the Preferred Stock do not have dividend rights but do have a liquidation preference over holders of our common stock. The holders of the Preferred Stock may convert all or any portion of their shares into shares of our common stock on a one-for-one basis. At any time after “Substantial Completion” of “Project 1,” each as defined in and pursuant to the LSTK EPC agreement for the Driftwood LNG Phase 1 Liquefaction Facility, dated as of November 10, 2017, or at any time after March 21, 2028, we have the right to cause all of the Preferred Stock to be converted into shares of our common stock on a one-for-one basis. The Preferred Stock has been excluded from the computation of diluted loss per share because including it in the computation would have been antidilutive for the periods presented.

In March 2017, GE Oil & Gas, Inc. (now known as GE Oil & Gas, LLC) (“GE”), as the holder of all 5.5 million outstanding shares of Tellurian Investments Series A convertible preferred stock (the “Tellurian Investments Preferred Shares”), exchanged those shares into an equal number of shares of Tellurian Inc. Series B convertible preferred stock (the “Series B Preferred Stock”) pursuant to the terms of the Tellurian Investments Certificate of Incorporation (the “Preferred Share Exchange”). The terms of the Series B Preferred Stock were substantially similar to those of the Tellurian Investments Preferred Shares. The Series B Preferred Stock was exchangeable at any time into shares of the Company’s common stock on a one-for-one basis, subject to anti-dilution adjustments in certain circumstances.

The ability of GE to exchange the Tellurian Investments Preferred Shares into shares of Series B Preferred Stock or into shares of Tellurian common stock following the Merger required the fair value of such features to be bifurcated from the contract and recognized as an embedded derivative until the Merger Date.

The fair value of the embedded derivative was determined through the use of a model which utilizes certain observable inputs such as the price of Magellan common stock at various points in time and the volatility of Magellan common stock over an assumed half-year and one-year holding period from February 10, 2017 and December 31, 2016, respectively. At each valuation date, the model also included (i) unobservable inputs related to the weighted probabilities of certain Merger-related scenarios and (ii) a discount for the lack of marketability determined through the use of commonly accepted methods. We have therefore classified the fair value measurements of this embedded derivative as Level 3 inputs. On the Merger Date, the embedded derivative was reclassified to additional paid-in capital in accordance with GAAP.

The following table summarizes the changes in fair value for the embedded derivative (in thousands):

	February 10, 2017			December 31, 2016
Fair value at the beginning of period and initial fair value, respectively	$	8,753		$	5,445
(Gain) loss on exchange feature	(2,209		)	3,308
Fair value at the end of the period and year, respectively	$	6,544		$	8,753

In June 2017, GE, as the holder of all 5.5 million outstanding shares of Series B Preferred Stock, exercised its right to convert all such shares of Series B Preferred Stock into 5.5 million shares of Tellurian common stock pursuant to and in accordance with the terms of the Series B Preferred Stock.

Public Equity Offerings and Exercise of Overallotment

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

In December 2017, we issued 10.0 million shares of common stock for proceeds of approximately $94.8 million, net of approximately $5.2 million in fees and commissions. The underwriters were granted an option to purchase up to an additional 1.5 million shares of common stock within 30 days. In January 2018, the underwriters exercised their option to purchase an additional 1.5 million shares of our common stock for proceeds of approximately $14.5 million, net of approximately $0.5 million in fees and commissions.

TOTAL Investment

In January 2017, pursuant to a common stock purchase agreement dated as of December 19, 2016, between Tellurian Investments and TOTAL Delaware, Inc. (“TOTAL”), TOTAL purchased, and Tellurian Investments sold and issued to TOTAL, approximately 35.4 million shares of Tellurian Investments common stock for an aggregate purchase price of $207 million, net of offering costs. In connection with the Merger, the shares purchased by TOTAL were exchanged for approximately 46 million shares of Tellurian common stock.

In May 2017, Tellurian and TOTAL entered into a pre-emptive rights agreement pursuant to which TOTAL was granted a right to purchase its pro rata portion of any new equity securities that Tellurian may issue to a third party on the same terms and conditions as such equity securities are offered and sold to such party, subject to certain excepted offerings (the “Pre-emptive Rights Agreement”). Pursuant to the common stock purchase agreement dated as of December 19, 2016, between Tellurian Investments and TOTAL, the terms and conditions of the Pre-emptive Rights Agreement are similar to those contained in the pre-emptive rights agreement dated as of January 3, 2017, between Tellurian Investments and TOTAL, but the Pre-emptive Rights Agreement is subject to additional excepted offerings.

Retirement of Treasury Stock

In December 2017, the Company retired approximately 1.3 million shares of treasury stock. These retired shares are now included in the Company’s pool of authorized unissued shares.

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Loss Per Share

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Loss Per Share

NOTE 15 — LOSS PER SHARE

The following table summarizes the computation of basic and diluted loss per share (in thousands, except per-share amounts):

	Year Ended December 31,
	2018			2017			2016
Net loss	$	(125,745	)	$	(231,459	)	$	(96,655	)
Basic weighted average common shares outstanding	211,574			188,536			95,795
Loss per share:
Basic and diluted	$	(0.59	)	$	(1.23	)	$	(1.01	)

As of December 31, 2018, 2017 and 2016, the effect of 24.4 million, 19.9 million and 11.5 million, respectively, of unvested restricted stock awards that could potentially dilute basic EPS in the future were not included in the computation of diluted EPS because to do so would have been antidilutive for the periods presented. In addition, as of December 31, 2018 and 2017, the effect of 2.0 million and 2.0 million options, respectively, and, as of December 31, 2018, the effect of 6.1 million shares of the Preferred Stock, all of which could potentially dilute basic EPS in the future, were not included in the computation of diluted EPS because to do so would have been antidilutive for the periods presented. As such, basic and diluted EPS are the same for all periods presented.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

NOTE 16 — SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides information regarding the net changes in working capital (in thousands):

	Successor									Predecessor
										For the period from January 1, 2016 through April 9, 2016
	Year Ended December 31,
	2018			2017			2016
Accounts receivable	$	(958	)	$	(442	)	$	(39	)	$	1
Accounts receivable due from related parties	62			(60		)	(124		)	(32		)
Prepaids and other current assets	(431		)	(1,419		)	(1,936		)	13
Note receivable due from related party	—			251			—			—
Accounts payable and accrued expenses	23,251			11,338			22,393			281
Accounts payable due to related parties	—			—			(53		)	253
Other, net	(11,404		)	(2,235		)	(1,903		)	—
Net changes in working capital	$	10,520		$	7,433		$	18,338		$	516

The following table provides supplemental disclosure of cash flow information (in thousands):

	Successor						Predecessor
							For the period from January 1, 2016 through April 9, 2016
	Year Ended December 31,
	2018		2017		2016
Net cash paid for income taxes	$	—	$	—	$	4	$	—
Property, plant and equipment non-cash accruals	8,630		83		46		75
Non-cash settlement of withholding taxes associated with the 2017 bonus accrual and vesting of certain awards	5,733		828		—		—
Non-cash settlement of the 2017 bonus accrual	15,202		—		—		—
Asset retirement obligation additions and revisions	115		—		—		—
Equity offering cost accrual	—		65		128		—

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of such amounts shown in the Consolidated Statements of Cash Flows (in thousands):

	Successor						Predecessor
							For the period from January 1, 2016 through April 9, 2016
	Year Ended December 31,
	2018		2017		2016
Cash and cash equivalents	$	133,714	$	128,273	$	21,398	$	210
Non-current restricted cash	49,875		—		—		—
Total cash, cash equivalents and restricted cash in the statement of cash flows	$	183,589	$	128,273	$	21,398	$	210

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Interim Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Interim Financial Information (Unaudited)

NOTE 17 — INTERIM FINANCIAL INFORMATION (UNAUDITED)

Amounts presented are in thousands, except, per share amounts (certain amounts may not recalculate exactly due to rounding):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year Ended December 31, 2018
Total revenue	$	6,801		$	813		$	799		$	1,872
Loss from operations	(25,392		)	(36,658		)	(34,384		)	(31,287		)
Net loss	(25,184		)	(35,854		)	(33,191		)	(31,516		)
Net loss per common share - basic and diluted	(0.12		)	(0.17		)	(0.15		)	(0.14		)
Weighted average shares outstanding - basic and diluted	204,772			206,531			217,380			217,408
Year Ended December 31, 2017
Total revenue	$	—		$	—		$	—		$	5,441
Loss from operations	(143,721		)	(32,899		)	(26,095		)	(35,852		)
Net loss	(141,349		)	(32,523		)	(22,864		)	(34,723		)
Net loss per common share - basic and diluted	(0.92		)	(0.17		)	(0.12		)	(0.18		)
Weighted average shares outstanding - basic and diluted	154,213			186,102			192,405			194,978

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Recent Accounting Standards

12 Months Ended

Dec. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards

NOTE 18 — RECENT ACCOUNTING STANDARDS

The following table provides a description of recent accounting standards that had not been adopted by the Company as of December 31, 2018:

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This standard may be early adopted and must be adopted using a modified retrospective approach with certain available practical expedients, one of which is an option of applying the requirements of the standard either (1) retrospectively to each prior comparative reporting period presented or (2) retrospectively at the beginning of the period of adoption.	January 1, 2019	The Company has adopted the standard on January 1, 2019, and will apply it at the beginning of the period of adoption. Therefore, upon adoption, financial information and disclosures will not be updated for comparative reporting periods under the new standard. Additionally, the Company has elected the transition package of practical expedients upon adoption which, among other things, allows an entity to not reassess the historical lease classification. The Company utilized a combination of a bottom-up and top-down approach to identify and analyze its lease portfolio. The analysis included reviewing all forms of leases, performing a completeness assessment over the lease population, assessing the policy elections offered by the standard and evaluating its business processes and internal controls to meet the ASU's accounting, reporting and disclosure requirements. The Company’s adoption of the standard has an impact on the Consolidated Balance Sheet. The Company’s adoption of the standard does not impact the Consolidated Statements of Operations or the Consolidated Statements of Cash Flows. The most significant effect of the new standard on the Consolidated Balance Sheet relates to the recognition of right-of-use assets and lease liabilities for the Company’s real estate portfolio, which the Company expects to be between $15 million and $25 million. The Company will also be providing new disclosures for its leasing activities under the new standard in the first quarter of 2019.

There were no recent accounting standards that were adopted by the Company during the reporting period that had a significant effect on our Consolidated Financial Statements.

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Subsequent Events

12 Months Ended

Dec. 31, 2018

Subsequent Events [Abstract]

Subsequent Events

NOTE 19 — SUBSEQUENT EVENTS

On January 18, 2019, we received our final environmental impact statement (“EIS”) from FERC for the Driftwood terminal and pipeline. The final EIS was prepared in compliance with the requirements of the National Environmental Policy Act (“NEPA”), the Council on Environmental Quality regulations for implementing NEPA, and FERC regulations.

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Supplemental Disclosures About Natural Gas Producing Activities

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Supplemental Disclosures About Natural Gas Producing Activities

SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES    

In accordance with FASB and SEC disclosure requirements for natural gas producing activities, this section provides supplemental information on Tellurian’s natural gas producing activities in six separate tables. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on the Company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves and changes in estimated discounted future net cash flows. The Company had no activities related to natural gas producing activities during the year ended December 31, 2016.

Table I — Capitalized Costs Related to Natural Gas Producing Activities

Capitalized costs related to Tellurian’s natural gas and condensate producing activities are summarized as follows (in thousands):

	December 31, 2018			December 31, 2017
Proved properties	$	101,459		$	90,869
Unproved properties	10,204			13,000
Gross capitalized costs	111,663			103,869
Accumulated DD&A	(1,335		)	(149		)
Net capitalized costs	$	110,328		$	103,720

Table II — Costs Incurred in Exploration, Property Acquisitions and Development

Costs incurred in natural gas property acquisition, exploration and development activities are summarized as follows (in thousands):

	December 31, 2018		December 31, 2017
Property acquisitions:
Proved	$	13,261	$	90,869
Unproved	204		13,000
Exploration costs	—		—
Development	2,104		949
Costs incurred	$	15,569	$	104,818

Table III — Results of Operations for Natural Gas & Condensate Producing Activities

The following table includes revenues and expenses directly associated with our natural gas and condensate producing activities. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas operations. Tellurian's results of operations from natural gas and condensate producing activities for the periods presented are as follows (in thousands):

	December 31, 2018			December 31, 2017
Natural gas sales	$	4,423		$	503
Operating costs	11,251			1,668
Depreciation, depletion and amortization	1,228			115
Impairment charge	2,699			—
Total operating costs and expenses	15,178			1,783
Results of operations	$	(10,755	)	$	(1,280	)

Table IV — Natural Gas & Condensate Reserve Quantity Information

Our estimated proved reserves are located in Louisiana. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the natural gas and condensate reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in these estimates. The estimates of our proved reserves as of December 31, 2018 and 2017 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants.

The condensate volumes shown include crude oil and condensate.

	Gas (MMcf)		Condensate (Mbbl)		Gas Equivalent (MMcfe)
Proved reserves:
December 31, 2016	—		—		—
Extensions, discoveries and other additions	—		—		—
Revisions of previous estimates	—		—		—
Production	(190	)	—		(191	)
Sale of reserves-in-place	—		—		—
Purchases of reserves-in-place	327,308		10		327,371
December 31, 2017	327,118		10		327,180
Extensions, discoveries and other additions	22,481		—		22,481
Revisions of previous estimates	(84,061	)	(2	)	(84,072	)
Production	(1,399	)	(1	)	(1,405	)
Sale of reserves-in-place	—		—		—
Purchases of reserves-in-place	715		—		715
December 31, 2018	264,854		7		264,899
Proved developed reserves:
December 31, 2016	—		—		—
December 31, 2017	5,720		10		5,782
December 31, 2018	17,522		7		17,567
Proved undeveloped reserves:
December 31, 2016	—		—		—
December 31, 2017	321,398		—		321,398
December 31, 2018	247,332		—		247,332

2016 to 2017 Changes

• Acquired 327 Bcfe of reserves in a series of transactions.

2017 to 2018 Changes

• Added approximately 22 Bcfe of proved reserves, comprised primarily of 19 Bcfe from additional proved undeveloped locations as a result of a more detailed analysis from an updated development plan and 3 Bcfe from drilling activities.

• Had negative revisions of approximately 85 Bcfe, comprised primarily of 59 Bcfe as a result of newly acquired 3D seismic data indicating additional geological faulting risks, which led to a reduction in proved undeveloped locations and some lateral lengths, 14 Bcfe, net, from changes in estimating lateral lengths of proved undeveloped locations as a result of more detailed analysis from an updated development plan, and 12 Bcfe due to loss of leases.

• Recorded positive revisions of approximately 1 Bcfe due to an increase in commodity prices.

• Acquired approximately 1 Bcfe of proved reserves through minor interest acquisitions.

Table V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas & Condensate Reserves

ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Tellurian has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs as of December 31, 2018 and 2017 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of natural gas and condensate to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates, including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the FASB and do not necessarily reflect our expectations of actual revenue to be derived from those reserves or their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth our future net cash flows relating to proved natural gas and condensate reserves based on the standardized measure (in thousands):

	December 31, 2018			December 31, 2017
Future cash inflows	$	676,454		$	777,711
Future production costs	(105,341		)	(144,991		)
Future development costs	(264,239		)	(331,297		)
Future income tax provisions	(54,564		)	(52,212		)
Future net cash flows	252,310			249,211
Less effect of a 10% discount factor	(106,499		)	(161,009		)
Standardized measure of discounted future net cash flows	$	145,811		$	88,202

Table VI — Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas & Condensate Reserves

The following table sets forth the changes in the standardized measure of discounted future net cash flows (in thousands):

December 31, 2016	$	—
Sales and transfers of gas and condensate produced, net of production costs	(265		)
Net changes in prices and production costs	—
Extensions, discoveries, additions and improved recovery, net of related costs	—
Development costs incurred	—
Revisions of estimated development costs	—
Revisions of previous quantity estimates	—
Accretion of discount	—
Net change in income taxes	(22,921		)
Purchases of reserves in place	111,388
Sales of reserves in place	—
Changes in timing and other	—
December 31, 2017	$	88,202
Sales and transfers of gas and condensate produced, net of production costs	(1,773		)
Net changes in prices and production costs	27,530
Extensions, discoveries, additions and improved recovery, net of related costs	13,334
Development costs incurred	545
Revisions of estimated development costs	9,663
Revisions of previous quantity estimates	12,991
Accretion of discount	11,112
Net change in income taxes	(9,472		)
Purchases of reserves in place	844
Sales of reserves in place	—
Changes in timing and other	(7,165		)
December 31, 2018	$	145,811

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT

12 Months Ended

Dec. 31, 2018

Condensed Financial Information Disclosure [Abstract]

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
TELLURIAN INC.
PARENT COMPANY BALANCE SHEETS
(in thousands, except share and per share)
	December 31,
	2018			2017
ASSETS
Cash and cash equivalents	$	—		$	—
Prepaids and other	72			25
Investments in subsidiaries	289,802			212,846
Property, plant and equipment, net	10,000			13,000
Total assets	$	299,874		$	225,871
LIABILITIES AND EQUITY
Liabilities:
Accounts payable	$	114		$	148
Accrued liabilities	1,826			1,836
Total liabilities	1,940			1,984
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	$	299,874		$	225,871

SCHEDULE I (Continued)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
TELLURIAN INC.
PARENT COMPANY STATEMENTS OF OPERATIONS
(in thousands)
	Year Ended December 31,
	2018			2017			2016
Total revenues	$	—		$	—		$	—
Operating costs and expenses:
Cost of sales	93			15			—
Development expenses	2,487			320			21
General and administrative expenses	4,618			594			25,084
Goodwill impairment	—			77,592			—
Total operating costs and expenses	7,198			78,521			25,105
Loss on preferred stock exchange feature	—			—			3,308
Interest expense	2			—			—
Loss from operations before income taxes and equity in losses of subsidiaries	(7,200		)	(78,521		)	(28,413		)
Income tax benefit (provision)	—			(4		)	170
Net loss from operations before equity in losses of subsidiaries	$	(7,200	)	$	(78,525	)	$	(28,243	)
Equity in losses of subsidiaries, net of tax	$	(118,545	)	$	(152,934	)	$	(68,412	)
Net loss	$	(125,745	)	$	(231,459	)	$	(96,655	)

SCHEDULE I (Continued)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
TELLURIAN INC.
PARENT COMPANY STATEMENTS OF CASH FLOWS
(in thousands)
	Year Ended December 31,
	2018			2017			2016
Net cash used in operating activities	(123,976		)	(312,553		)	(60,532		)
Cash flows from investing activities:
Cash received in acquisition	—			56			210
Cash used for acquisition	—			—			(1,190		)
Net cash received (used) in investing activities	—			56			(980		)
Cash flows from financing activities:
Proceeds from the issuance of common stock	133,800			318,204			59,015
Tax payments for net share settlement of equity awards	(5,734		)	—			—
Proceeds from the issuance of preferred stock	—			—			25,000
Equity offering costs	(4,090		)	(5,707		)	(1,681		)
Net cash provided by financing activities	123,976			312,497			82,334
Net increase (decrease) in cash and cash equivalents	—			—			20,822
Cash and cash equivalents, beginning of period	—			—			—
Cash and cash equivalents, end of period	$	—		$	—		$	20,822

NOTE 1 — BASIS OF PRESENTATION

Tellurian Inc. is a Delaware corporation based in Houston, Texas (“Tellurian”), which wholly owns Tellurain Investments Inc. (“Tellurian Investments”), which in turn wholly owns Tellurian Production Holdings LLC (“Production Holdings”), Tellurian Investment’s primary operating company.

On February 10, 2017 (the “Merger Date”), Tellurian Investments Inc. (“Tellurian Investments”) completed a merger (the “Merger”) with a subsidiary of Magellan Petroleum Corporation (“Magellan”). Magellan changed its corporate name to Tellurian Inc. shortly after completing the Merger. The Merger was accounted for as a “reverse acquisition,” with Tellurian Investments being treated as the accounting acquirer. As such, the historical consolidated comparative information as of and for all periods in 2016 in this Schedule I relates to Tellurian Investments. Subsequent to the Merger Date, the information relates to the consolidated entities of Tellurian Inc., with Magellan reflected as the accounting acquiree. In connection with the Merger, each issued and outstanding share of Tellurian Investments common stock was exchanged for 1.3 shares of Magellan common stock. All share amounts in the Condensed Financial Information and related notes have been retroactively adjusted for all periods presented to give effect to this exchange, including reclassifying an amount equal to the change in par value of common stock from additional paid-in capital.

On April 9, 2016, Tellurian Investments acquired Tellurian Services LLC (“Tellurian Services”), formerly known as Parallax Services LLC (“Parallax Services”). Under the financial reporting rules of the SEC, Parallax Services (“Predecessor”) has been deemed to be the predecessor to Tellurian (“Successor”) for financial reporting purposes. Predecessor financial statements have been included in Tellurian’s Consolidated Financial Statements in this report.

These condensed parent company financial statements reflect the activity of Tellurian as the parent company to Production Holdings and have been prepared in accordance with Rule 12-04, Schedule 1 of Regulation S-X, as the restricted net assets of Production Holdings exceed 25% of the consolidated net assets of Tellurian. This information should be read in conjunction with the consolidated financial statements of Tellurian included in this report under the caption Item 8, “Financial Statements and Supplementary Data.”

NOTE 2 — PROPERTY, PLANT AND EQUIPMENT

The amounts included in Tellurian’s parent-only financial statements related to property, plant and equipment represent unproved properties in the United Kingdom and Australia, as disclosed in Note 5, Property, Plant and Equipment, to Tellurian’s Consolidated Financial Statements included in this report under the caption Item 8, “Financial Statements and Supplementary Data.”

NOTE 3 — GOODWILL IMPAIRMENT

For details regarding the goodwill impairment included in Tellurian’s parent-only financial statements, refer to Note 2, Merger and Acquisition — The Merger, to Tellurian’s Consolidated Financial Statements included in this report under the caption Item 8, “Financial Statements and Supplementary Data.”

NOTE 4 — CONTINGENCIES

For details regarding the contingencies related to Tellurian Investments litigation, refer to Note 8, Commitments and Contingencies, to Tellurian’s Consolidated Financial Statements included in this report under the caption Item 8, “Financial Statements and Supplementary Data.”

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Basis of Presentation and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

Our Consolidated Financial Statements were prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Tellurian Inc. and its wholly and majority owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

Segments

Segments

Management allocates resources and assesses financial performance on a consolidated basis. As such, for the purposes of financial reporting under GAAP during the years ended December 31, 2018, 2017 and 2016, the Company operated as a single operating segment.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions on a regular basis. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair Value

The Company uses three levels of the fair value hierarchy of inputs to measure the fair value of an asset or a liability. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.

Goodwill

Goodwill

Goodwill resulting from a business combination is not subject to amortization. The Company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.

Revenue Recognition

Revenue Recognition

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), amended the previous revenue recognition guidance and required us to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted the new standard on January 1, 2018, utilizing the modified retrospective approach. We have applied the standard to all contracts as of the date of the application of the standard. We developed an accounting policy, implemented changes to the relevant business processes and the control activities within them, and evaluated the disclosure requirements as a result of the provisions of this ASU. Adoption of the ASU did not require an adjustment to the opening stockholders’ equity and did not change our amount and timing of revenues. We have elected to exclude all taxes from the measurement of transaction price.

For the sale of commodities, we consider the delivery of each unit (MMBtu) to be a separate performance obligation that is satisfied upon delivery. These contracts are either fixed price contracts or contracts with a fixed differential to an index price, both of which are considered fixed consideration. The fixed consideration is allocated to each performance obligation and represents the relative standalone selling price basis.

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “LNG sales” on the Consolidated Statements of Operations. For such LNG sales, we require payment within 10 days from delivery. Other LNG revenue represents revenue earned from sub-charter agreements and is accounted for outside of this ASU and in line with Accounting Standards Codification 840, Leases.

In our judgment, the performance obligations for the sale of natural gas and LNG are satisfied at a point in time because the customer obtains control and legal title of the asset when the natural gas or LNG is delivered to the designated sales point.

Cash, Cash Equivalents and Restricted Cash

Cash, Cash Equivalents and Restricted Cash

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents that are restricted as to withdrawal or use under the terms of certain contractual agreements are recorded in Non-current restricted cash on our Consolidated Balance Sheets.

Concentration of Cash

Concentration of Cash

We maintain cash balances and restricted cash at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

Derivative Instruments

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the criteria for and we elect the normal purchases and sales exception.

Changes in the fair value of our derivative instruments are recorded in earnings, and, at present, we have elected not to apply hedge accounting.

Property, Plant and Equipment Cost Basis

Property, Plant and Equipment

Natural gas development and production activities are accounted for using the successful efforts method of accounting. Costs incurred to acquire a property (whether unproved or proved) are capitalized when incurred. Lease rentals are expensed as incurred. Natural gas exploratory costs are expensed as incurred and costs to develop proved reserves are capitalized. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. We deplete our natural gas reserves using the units-of-production method.

Fixed assets are recorded at cost. We depreciate our property, plant and equipment, excluding land, using the straight-line depreciation method over the estimated useful life of the asset. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed, and the resulting gains or losses are recorded in our Consolidated Statements of Operations. Management tests property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of property, plant and equipment might not be recoverable.

Accounting for LNG Development Activities

Accounting for LNG Development Activities

As we have been in the preliminary stage of developing the Driftwood terminal, substantially all of the costs to date related to such activities have been expensed. These costs primarily include professional fees associated with FEED studies and applying to FERC for authorization to construct our terminals and other required permitting for the Driftwood Project.

Costs incurred in connection with a project to develop the Driftwood terminal shall generally be treated as development expenses until the project has reached the notice-to-proceed state (“NTP State”) and the following criteria (the “NTP Criteria”) have been achieved: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. In addition to the above, certain costs incurred prior to achieving the NTP State will be capitalized though the NTP Criteria have not been met. Costs to be capitalized prior to achieving the NTP State include land purchase costs, land improvement costs, costs associated with preparing the facility for use and any fixed structure construction costs (fence, storage areas, drainage, etc.). Furthermore, activities directly associated with detailed engineering and/or facility designs shall be capitalized.

Share-Based Compensation

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.

Debt

Debt

Discounts and expenses incurred with the issuance of debt are amortized over the term of the debt. These amounts are presented as a reduction of Senior secured term loan on the accompanying Consolidated Balance Sheets.

Income Taxes

Income Taxes

We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, we determine deferred tax assets and liabilities on the basis of the differences between the financial statement and tax basis of assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to be realized or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a determination, we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. If we determine that we would be able to realize our deferred tax assets in the future in excess of their net recorded amount, we would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.

Net Loss Per Share (EPS)

Net Loss Per Share (EPS)

Basic net loss per share excludes dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period. Diluted net loss per share reflects potential dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued and were dilutive.

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Merger and Acquisition (Tables)

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Schedule of Total Consideration Exchanged

The total consideration exchanged was as follows (in thousands, except share and per-share amounts):

Number of shares of Magellan common stock outstanding (1)	5,985,042
Price per share of Magellan common stock (2)	$	14.21
Aggregate value of Tellurian common stock issued			$	85,048
Fair value of stock options (3)			2,821
Net purchase consideration to be allocated			$	87,869
(1) The number of shares of Magellan common stock issued and outstanding as of February 9, 2017.
(2) The closing price of Magellan common stock on the NASDAQ on February 9, 2017.
(3) The estimated fair value of Magellan stock options for pre-Merger services rendered.

Schedule of Preliminary Purchase Price Allocation to Assets Acquired and Liabilities Assumed in Transaction

The purchase price allocation to assets acquired and liabilities assumed in the Merger was as follows (in thousands):

Fair Value of Assets Acquired:
Cash	$	56
Securities available-for-sale	1,111
Other current assets	93
Unproved properties	13,000
Wells in progress	332
Land, buildings and equipment, net	67
Other long-term assets	19
Total assets acquired	14,678
Fair Value of Liabilities Assumed:
Accounts payable and other liabilities	4,393
Notes payable	8
Total liabilities assumed	4,401
Total net assets acquired	10,277
Goodwill as a result of the Merger	$	77,592

Schedule of Unaudited Pro Forma Results

The following table provides unaudited pro forma results for the year ended December 31, 2017, and 2016, as if the Merger occurred and Parallax Services had been acquired as of January 1, 2016 (in thousands, except per-share amounts):

	Year Ended December 31,
	2017			2016
Pro forma net loss	$	(235,201	)	$	(100,734	)
Pro forma net loss per basic share	$	(1.24	)	$	(0.98	)
Pro forma basic and diluted weighted average common shares outstanding	189,246			102,281

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Summary of Property, Plant and Equipment Comprised of Fixed Assets and Oil and Gas Properties

Property, plant and equipment is comprised of fixed assets and oil and natural gas properties, as shown below (in thousands):

	December 31,
	2018			2017
Land	$	13,276		$	9,491
Proved properties	101,459			90,869
Unproved properties	10,204			13,000
Wells in progress	4,660			345
Corporate and other	2,905			2,693
Total fixed assets, at cost	132,504			116,398
Accumulated depreciation and depletion	(1,924		)	(542		)
Total property, plant and equipment, net	$	130,580		$	115,856

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Other Non-Current Assets (Tables)

12 Months Ended

Dec. 31, 2018

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other Non-Current Assets

Other non-current assets consist of the following (in thousands):

	December 31, 2018		December 31, 2017
Land lease and purchase options	$	4,115	$	2,948
Permitting costs	12,585		4,708
Other	1,959		1,620
Total other non-current assets	$	18,659	$	9,276

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Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Payables and Accruals [Abstract]

Schedule of Components of Accrued Liabilities

The components of accrued liabilities consist of the following (in thousands):

	December 31,
	2018		2017
Project development activities	$	8,879	$	5,142
Payroll and compensation	23,286		25,833
Accrued taxes	2,507		2,764
Professional services (e.g., legal, audit)	2,423		2,806
Accrued rent and other	4,078		2,556
Total accrued liabilities	$	41,173	$	39,101

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of Contractual Obligations

At December 31, 2018, contractual obligations for long-term operating leases and purchase obligations are as follows (in thousands):

	2019		2020		2021		2022		2023		Thereafter		Total
Office leases	$	3,126	$	3,510	$	3,440	$	3,718	$	3,993	$	8,061	$	25,848
Land lease and purchase options	1,588		634		23		23		23		436		2,727
Other	499		499		2		—		—		—		1,000
	$	5,213	$	4,643	$	3,465	$	3,741	$	4,016	$	8,497	$	29,575

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Restricted Stock Transactions

The following table provides a summary of our Restricted Stock transactions for the year ended December 31, 2018 (shares and units in thousands):

	Shares		Weighted-Average Grant Date Fair Value
Unvested at January 1, 2018	20,488		$	6.95
Granted (1)	4,311		11.02
Vested	(213	)	11.60
Forfeited	(202	)	11.73
Unvested at December 31, 2018	24,384		$	7.59

Summary of Stock Option Transactions

The following table provides a summary of our stock option transactions for the year ended December 31, 2018 (stock options in thousands):

	Stock Options		Weighted Average Exercise Price
Outstanding at January 1, 2018	2,011		$	10.32
Granted	—		—
Exercised	—		—
Forfeited or Expired	(23	)	10.32
Outstanding at December 31, 2018	1,988		$	10.32
Exercisable at December 31, 2018	665		$	10.32

Schedule of Stock Option Valuation Assumptions

Valuation assumptions used to value stock options for the year ended December 31, 2017 (there were no stock options granted in 2018 or 2016), were as follows:

	December 31, 2017
Expected term (in years)	6.0
Expected volatility	22.13	%
Expected dividend yields	—	%
Risk-free rate	2.05	%

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Benefit (Provision)

Income tax benefit (provision) included in our reported net loss consisted of the following (in thousands):

	Year Ended December 31,
	2018		2017			2016
Current:
Federal	$	—	$	—		$	—
State	—		—			(4		)
Foreign	190		(185		)	—
Total Current	190		(185		)	(4		)
Deferred:
Federal	—		—			170
State	—		—			—
Foreign	—		—			—
Total Deferred	—		—			170
Total income tax benefit (provision)	$	190	$	(185	)	$	166

Schedule of Income before Income Tax, Domestic and Foreign

The sources of loss from operations before income taxes were as follows (in thousands):

	Year Ended December 31,
	2018			2017			2016
Domestic	$	(115,137	)	$	(223,991	)	$	(95,739	)
Foreign	(10,798		)	(7,283		)	(1,082		)
Total loss before income taxes	$	(125,935	)	$	(231,274	)	$	(96,821	)

Summary of Effective Income Tax Rate Reconciliation

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:

	Year Ended December 31,
	2018			2017			2016
Income tax benefit (provision) at U.S. statutory rate	$	26,446		$	80,946		$	33,887
Share-based compensation	—			—			(5,911		)
Impairment	—			(27,969		)	—
Change in U.S. tax rate	—			(30,562		)	—
Change in valuation allowance due to change in U.S. tax rate	—			30,562			—
U.S. state tax	7,955			—			—
Change in valuation allowance	(32,086		)	(51,030		)	(26,398		)
Other	(2,125		)	(2,132		)	(1,412		)
Total income tax benefit (provision)	$	190		$	(185	)	$	166

Schedule of Deferred Tax Assets and Liabilities

Significant components of our deferred tax assets and liabilities are as follows (in thousands):

	December 31,
	2018			2017
Deferred tax assets:
Capitalized engineering costs	$	6,353		$	2,812
Capitalized start-up costs	19,290			17,881
Compensation and benefits	3,862			5,465
Net operating loss carryforwards and credits:
Federal	37,822			19,423
State	4,979			522
Foreign	2,392			1,694
Other, net	8,328			3,541
Deferred tax assets	83,026			51,338
Less valuation allowance	(83,026		)	(50,942		)
Deferred tax assets, net of valuation allowance	—			396
Deferred tax liabilities	—			(396		)
Net deferred tax assets	$	—		$	—

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Long-term Borrowings (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Summary of Long-term Borrowings Maturities

A summary of long-term borrowings maturities is as follows (in thousands):

Years Ending December 31,	Principal Payments
2019	$	—
2020	—
2021	60,000
Total	$	60,000

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Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Summary of Changes in Fair Value for Embedded Derivative

The following table summarizes the changes in fair value for the embedded derivative (in thousands):

	February 10, 2017			December 31, 2016
Fair value at the beginning of period and initial fair value, respectively	$	8,753		$	5,445
(Gain) loss on exchange feature	(2,209		)	3,308
Fair value at the end of the period and year, respectively	$	6,544		$	8,753

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Loss Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Schedule of Loss Per Share, Basic and Diluted

The following table summarizes the computation of basic and diluted loss per share (in thousands, except per-share amounts):

	Year Ended December 31,
	2018			2017			2016
Net loss	$	(125,745	)	$	(231,459	)	$	(96,655	)
Basic weighted average common shares outstanding	211,574			188,536			95,795
Loss per share:
Basic and diluted	$	(0.59	)	$	(1.23	)	$	(1.01	)

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2018

Supplemental Cash Flow Information [Abstract]

Net Changes in Components of Operating Assets and Liabilities

The following table provides information regarding the net changes in working capital (in thousands):

	Successor									Predecessor
										For the period from January 1, 2016 through April 9, 2016
	Year Ended December 31,
	2018			2017			2016
Accounts receivable	$	(958	)	$	(442	)	$	(39	)	$	1
Accounts receivable due from related parties	62			(60		)	(124		)	(32		)
Prepaids and other current assets	(431		)	(1,419		)	(1,936		)	13
Note receivable due from related party	—			251			—			—
Accounts payable and accrued expenses	23,251			11,338			22,393			281
Accounts payable due to related parties	—			—			(53		)	253
Other, net	(11,404		)	(2,235		)	(1,903		)	—
Net changes in working capital	$	10,520		$	7,433		$	18,338		$	516

Supplemental Disclosure of Cash Flow Information

The following table provides supplemental disclosure of cash flow information (in thousands):

	Successor						Predecessor
							For the period from January 1, 2016 through April 9, 2016
	Year Ended December 31,
	2018		2017		2016
Net cash paid for income taxes	$	—	$	—	$	4	$	—
Property, plant and equipment non-cash accruals	8,630		83		46		75
Non-cash settlement of withholding taxes associated with the 2017 bonus accrual and vesting of certain awards	5,733		828		—		—
Non-cash settlement of the 2017 bonus accrual	15,202		—		—		—
Asset retirement obligation additions and revisions	115		—		—		—
Equity offering cost accrual	—		65		128		—

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of such amounts shown in the Consolidated Statements of Cash Flows (in thousands):

	Successor						Predecessor
							For the period from January 1, 2016 through April 9, 2016
	Year Ended December 31,
	2018		2017		2016
Cash and cash equivalents	$	133,714	$	128,273	$	21,398	$	210
Non-current restricted cash	49,875		—		—		—
Total cash, cash equivalents and restricted cash in the statement of cash flows	$	183,589	$	128,273	$	21,398	$	210

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Interim Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Interim Financial Information

Amounts presented are in thousands, except, per share amounts (certain amounts may not recalculate exactly due to rounding):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year Ended December 31, 2018
Total revenue	$	6,801		$	813		$	799		$	1,872
Loss from operations	(25,392		)	(36,658		)	(34,384		)	(31,287		)
Net loss	(25,184		)	(35,854		)	(33,191		)	(31,516		)
Net loss per common share - basic and diluted	(0.12		)	(0.17		)	(0.15		)	(0.14		)
Weighted average shares outstanding - basic and diluted	204,772			206,531			217,380			217,408
Year Ended December 31, 2017
Total revenue	$	—		$	—		$	—		$	5,441
Loss from operations	(143,721		)	(32,899		)	(26,095		)	(35,852		)
Net loss	(141,349		)	(32,523		)	(22,864		)	(34,723		)
Net loss per common share - basic and diluted	(0.92		)	(0.17		)	(0.12		)	(0.18		)
Weighted average shares outstanding - basic and diluted	154,213			186,102			192,405			194,978

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Recent Accounting Standards (Tables)

12 Months Ended

Dec. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Description of Recent Accounting Standards, Not been Adopted

The following table provides a description of recent accounting standards that had not been adopted by the Company as of December 31, 2018:

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This standard may be early adopted and must be adopted using a modified retrospective approach with certain available practical expedients, one of which is an option of applying the requirements of the standard either (1) retrospectively to each prior comparative reporting period presented or (2) retrospectively at the beginning of the period of adoption.	January 1, 2019	The Company has adopted the standard on January 1, 2019, and will apply it at the beginning of the period of adoption. Therefore, upon adoption, financial information and disclosures will not be updated for comparative reporting periods under the new standard. Additionally, the Company has elected the transition package of practical expedients upon adoption which, among other things, allows an entity to not reassess the historical lease classification. The Company utilized a combination of a bottom-up and top-down approach to identify and analyze its lease portfolio. The analysis included reviewing all forms of leases, performing a completeness assessment over the lease population, assessing the policy elections offered by the standard and evaluating its business processes and internal controls to meet the ASU's accounting, reporting and disclosure requirements. The Company’s adoption of the standard has an impact on the Consolidated Balance Sheet. The Company’s adoption of the standard does not impact the Consolidated Statements of Operations or the Consolidated Statements of Cash Flows. The most significant effect of the new standard on the Consolidated Balance Sheet relates to the recognition of right-of-use assets and lease liabilities for the Company’s real estate portfolio, which the Company expects to be between $15 million and $25 million. The Company will also be providing new disclosures for its leasing activities under the new standard in the first quarter of 2019.

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Supplemental Disclosures About Natural Gas Producing Activities (Tables)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure

Capitalized costs related to Tellurian’s natural gas and condensate producing activities are summarized as follows (in thousands):

	December 31, 2018			December 31, 2017
Proved properties	$	101,459		$	90,869
Unproved properties	10,204			13,000
Gross capitalized costs	111,663			103,869
Accumulated DD&A	(1,335		)	(149		)
Net capitalized costs	$	110,328		$	103,720

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure

Costs incurred in natural gas property acquisition, exploration and development activities are summarized as follows (in thousands):

	December 31, 2018		December 31, 2017
Property acquisitions:
Proved	$	13,261	$	90,869
Unproved	204		13,000
Exploration costs	—		—
Development	2,104		949
Costs incurred	$	15,569	$	104,818

Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure

The following table includes revenues and expenses directly associated with our natural gas and condensate producing activities. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas operations. Tellurian's results of operations from natural gas and condensate producing activities for the periods presented are as follows (in thousands):

	December 31, 2018			December 31, 2017
Natural gas sales	$	4,423		$	503
Operating costs	11,251			1,668
Depreciation, depletion and amortization	1,228			115
Impairment charge	2,699			—
Total operating costs and expenses	15,178			1,783
Results of operations	$	(10,755	)	$	(1,280	)

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

The condensate volumes shown include crude oil and condensate.

	Gas (MMcf)		Condensate (Mbbl)		Gas Equivalent (MMcfe)
Proved reserves:
December 31, 2016	—		—		—
Extensions, discoveries and other additions	—		—		—
Revisions of previous estimates	—		—		—
Production	(190	)	—		(191	)
Sale of reserves-in-place	—		—		—
Purchases of reserves-in-place	327,308		10		327,371
December 31, 2017	327,118		10		327,180
Extensions, discoveries and other additions	22,481		—		22,481
Revisions of previous estimates	(84,061	)	(2	)	(84,072	)
Production	(1,399	)	(1	)	(1,405	)
Sale of reserves-in-place	—		—		—
Purchases of reserves-in-place	715		—		715
December 31, 2018	264,854		7		264,899
Proved developed reserves:
December 31, 2016	—		—		—
December 31, 2017	5,720		10		5,782
December 31, 2018	17,522		7		17,567
Proved undeveloped reserves:
December 31, 2016	—		—		—
December 31, 2017	321,398		—		321,398
December 31, 2018	247,332		—		247,332

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure

The following summary sets forth our future net cash flows relating to proved natural gas and condensate reserves based on the standardized measure (in thousands):

	December 31, 2018			December 31, 2017
Future cash inflows	$	676,454		$	777,711
Future production costs	(105,341		)	(144,991		)
Future development costs	(264,239		)	(331,297		)
Future income tax provisions	(54,564		)	(52,212		)
Future net cash flows	252,310			249,211
Less effect of a 10% discount factor	(106,499		)	(161,009		)
Standardized measure of discounted future net cash flows	$	145,811		$	88,202

The following table sets forth the changes in the standardized measure of discounted future net cash flows (in thousands):

December 31, 2016	$	—
Sales and transfers of gas and condensate produced, net of production costs	(265		)
Net changes in prices and production costs	—
Extensions, discoveries, additions and improved recovery, net of related costs	—
Development costs incurred	—
Revisions of estimated development costs	—
Revisions of previous quantity estimates	—
Accretion of discount	—
Net change in income taxes	(22,921		)
Purchases of reserves in place	111,388
Sales of reserves in place	—
Changes in timing and other	—
December 31, 2017	$	88,202
Sales and transfers of gas and condensate produced, net of production costs	(1,773		)
Net changes in prices and production costs	27,530
Extensions, discoveries, additions and improved recovery, net of related costs	13,334
Development costs incurred	545
Revisions of estimated development costs	9,663
Revisions of previous quantity estimates	12,991
Accretion of discount	11,112
Net change in income taxes	(9,472		)
Purchases of reserves in place	844
Sales of reserves in place	—
Changes in timing and other	(7,165		)
December 31, 2018	$	145,811

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Basis of Presentation and Summary of Significant Accounting Policies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) Segment	Dec. 31, 2017 Segment	Dec. 31, 2016 Segment
Business Description And Basis Of Presentation [Line Items]
Number of operating segments | Segment	1	1	1
Recognized amounts due from contracts with customer | $	$ 0.5

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Merger and Acquisition - Schedule of Total Consideration Exchanged (Detail) - USD ($) $ / shares in Units, $ in Thousands	Feb. 10, 2017	Feb. 09, 2017
Business Combinations [Abstract]
Number of shares of Magellan common stock outstanding		5,985,042
Price per share of Magellan common stock		$ 14.21
Aggregate value of Tellurian common stock issued	$ 85,048
Fair value of stock options	2,821
Net purchase consideration to be allocated	$ 87,869

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Merger And Acquisition - Schedule of Preliminary Purchase Price Allocation to Assets Acquired and Liabilities Assumed in Transaction (Detail) $ in Thousands	Feb. 10, 2017 USD ($)
Fair Value of Assets Acquired:
Cash	$ 56
Securities available-for-sale	1,111
Other current assets	93
Unproved properties	13,000
Wells in progress	332
Land, buildings and equipment, net	67
Other long-term assets	19
Total assets acquired	14,678
Fair Value of Liabilities Assumed:
Accounts payable and other liabilities	4,393
Notes payable	8
Total liabilities assumed	4,401
Total net assets acquired	10,277
Goodwill as a result of the Merger	$ 77,592

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Merger and Acquisition - Additional Information (Detail) - USD ($)			3 Months Ended								9 Months Ended	12 Months Ended
	Feb. 10, 2017	Apr. 09, 2016	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Goodwill	$ 77,592,000
Goodwill deductible for income tax purposes	0
Goodwill impairment												$ 0	$ 77,592,000	$ 0
Equity consideration valued	$ 87,869,000
Net loss			$ (31,516,000)	$ (33,191,000)	$ (35,854,000)	$ (25,184,000)	$ (34,723,000)	$ (22,864,000)	$ (32,523,000)	$ (141,349,000)		$ (125,745,000)	$ (231,459,000)	$ (96,655,000)
Parallax Services
Business Acquisition [Line Items]
Equity consideration valued		$ 1,000,000
Net loss											$ 800,000

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Merger and Acquisition - Schedule of Unaudited Pro Forma Results (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Combinations [Abstract]
Pro forma net loss	$ (235,201)	$ (100,734)
Pro forma net loss per basic share	$ (1.24)	$ (0.98)
Pro forma basic and diluted weighted average common shares outstanding	189,246	102,281

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Deferred Engineering Costs - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred Costs [Abstract]
Deferred engineering costs	$ 69.0	$ 18.0

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Transaction with Related Parties - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Jul. 31, 2017
Houston
Related Party Transaction [Line Items]
Discharge from related party debt	$ 0.3
Note receivable due from related party				$ 0.3
Law Firm
Related Party Transaction [Line Items]
Legal fees		$ 0.1	$ 0.7

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Property, Plant and Equipment - Summary of Property, Plant and Equipment Comprised of Fixed Assets and Oil and Gas Properties (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 132,504	$ 116,398
Proved properties	101,459	90,869
Unproved properties	10,204	13,000
Accumulated depreciation and depletion	(1,924)	(542)
Total property, plant and equipment, net	130,580	115,856
Land
Property, Plant and Equipment [Line Items]
Property, plant and equipment	13,276	9,491
Wells in progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment	4,660	345
Corporate and other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 2,905	$ 2,693

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Property, Plant and Equipment - Additional Information (Detail) $ in Millions	1 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2018 USD ($)	May 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2018 license	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Property, Plant and Equipment [Line Items]
Depreciation and depletion expense					$ 1.5	$ 0.5	$ 0.1
Write-off of non-producing acreage	$ 2.7
Cash consideration from transfer of permit		$ 0.2
Decrease in liabilities from transfer of permit		$ 1.3
Loss on transfer of permit			$ 1.0
United Kingdom
Property, Plant and Equipment [Line Items]
Number of non-operating interest in licenses | license				2

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Other Non-Current Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) option	Dec. 31, 2017 USD ($)
Operating Leased Assets [Line Items]
Land lease and purchase options	$ 4,115	$ 2,948
Permitting costs	12,585	4,708
Other	1,959	1,620
Total other non-current assets	$ 18,659	$ 9,276
Term of lease (in years)	4 years
Extension term (in years)	20 years
Number of renewal terms | option	6
Renewal term (in years)	5 years
Maximum terms (in years)	60 years
Minimum
Operating Leased Assets [Line Items]
Term of lease (in years)	4 years
Maximum
Operating Leased Assets [Line Items]
Term of lease (in years)	5 years

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Accrued Liabilities - Schedule of Components of Accounts Payable and Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Payables and Accruals [Abstract]
Project development activities	$ 8,879	$ 5,142
Payroll and compensation	23,286	25,833
Accrued taxes	2,507	2,764
Professional services (e.g., legal, audit)	2,423	2,806
Accrued rent and other	4,078	2,556
Total accrued liabilities	$ 41,173	$ 39,101

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Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Rent expense	$ 3.2	$ 2.3	$ 0.5

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Commitments and Contingencies - Schedule of Contractual Obligations (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Office leases
Office leases, 2019	$ 3,126
Office leases, 2020	3,510
Office leases, 2021	3,440
Office leases, 2022	3,718
Office leases, 2023	3,993
Office leases, Thereafter	8,061
Office leases, Total	25,848
Land lease and purchase options
Land lease and purchase options, 2019	1,588
Land lease and purchase options, 2020	634
Land lease and purchase options, 2021	23
Land lease and purchase options, 2022	23
Land lease and purchase options, 2023	23
Land lease and purchase options, Thereafter	436
Land lease and purchase options, Total	2,727
Other
Other, 2019	499
Other, 2020	499
Other, 2021	2
Other, 2022	0
Other, 2023	0
Other, Thereafter	0
Other, Total	1,000
Total
2019	5,213
2020	4,643
2021	3,465
2022	3,741
2023	4,016
Thereafter	8,497
Total	$ 29,575

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Share-Based Compensation - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in dollars per share)		$ 11.02	$ 9.59	$ 3.52
Share-based compensation		$ 5,126,000	$ 23,019,000	$ 24,495,000
Settlement of bonuses accrued				$ 2,000,000
Unrecognized compensation expense		$ 197,000,000
Share-based payments, shares		0	2,000,000	0
Weighted average grant date fair value (in dollars per share)			$ 2.72
Exercised (in shares)		0	0
Granted (in shares)		4,311,000
Vested (in shares)		213,000
Restricted Stock, Restricted Stock Units (RSUs), and Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation		$ 0
Total grant date fair value of restricted stock vested		$ 2,500,000	$ 3,700,000	$ 400,000
Granted (in shares)		24,400,000
Vested (in shares)		600,000
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		3 years
Omnibus Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common stock authorized for issuance		40,000,000
Granted (in dollars per share)	$ 11.88
First anniversary of FID | Restricted Stock, Restricted Stock Units (RSUs), and Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in shares)		19,800,000
Second anniversary of FID | Restricted Stock, Restricted Stock Units (RSUs), and Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in shares)		4,000,000

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Share-Based Compensation - Summary of Restricted Stock Transactions (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Shares
Unvested at January 1, 2018	20,488
Granted (in shares)	4,311
Vested (in shares)	(213)
Forfeited (in shares)	(202)
Unvested at December 31, 2018	24,384	20,488
Weighted-Average Grant Date Fair Value
Unvested (in dollars per share)	$ 7.59	$ 6.95
Granted (in dollars per share)	11.02	$ 9.59	$ 3.52
Vested (in dollars per share)	11.60
Forfeited (in dollars per share)	$ 11.73

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Share-Based Compensation - Summary of Stock Option Transactions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, beginning balance (in shares)	2,011,000	0
Granted (in shares)	0	2,000,000	0
Exercised (in shares)	0	0
Forfeited or Expired (in shares)	(23,000)
Outstanding, ending balance (in shares)	1,988,000	2,011,000	0
Exercisable (in shares)	665,000
Weighted Average Exercise Price
Outstanding, beginning balance (in dollars per share)	$ 10.32
Granted (in dollars per share)	0.00
Exercised (in dollars per share)	0.00
Forfeited or Expired (in dollars per share)	10.32
Outstanding, ending balance (in dollars per share)	10.32	$ 10.32
Exercisable (in dollars per share)	$ 10.32

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Share-Based Compensation - Schedule of Valuation Assumptions of Stock Options (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option outstanding	2,011,000	1,988,000	0
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)	6 years
Expected volatility	22.13%
Expected dividend yields	0.00%
Risk-free rate	2.05%

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Share-Based Payments - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended		2 Months Ended	12 Months Ended
	Feb. 10, 2017	Mar. 31, 2017	Feb. 28, 2017	May 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense for vendors					$ 0	$ 19,397	$ 0
Common stock shares issued on merger, value						87,923	$ 1,000
Shares issued for specified services		200,000
Share issued for services, price per share		$ 11.34
Cost of shares issued for specified services				$ 2,300
Vendors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense for vendors					$ 0	$ 19,400
Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock shares issued on merger	90,350		409,800			51,540,000	500,000
Common stock shares issued on merger, value	$ 1,300		$ 5,800			$ 1,390	$ 1
Omnibus Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant		1,000,000
Aggregate difference between purchase price and fair value		$ 11,400
Purchase price per share		$ 0.50
Closing share price on the date of issuance per share		$ 11.88

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Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Unfavorable impact to gross U.S. deferred tax assets		$ 30,600,000
Increase in valuation allowance	$ 32,100,000	$ 30,600,000
Federal	180,100,000
State	113,700,000
Foreign	13,600,000
NOLs with indefinite carryforward period	88,400,000
Undistributed earnings and profits	$ 0

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Income Taxes - Schedule of Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current:
Federal	$ 0	$ 0	$ 0
State	0	0	(4)
Foreign	190	(185)	0
Total Current	190	(185)	(4)
Deferred:
Federal	0	0	170
State	0	0	0
Foreign	0	0	0
Total Deferred	0	0	170
Total income tax benefit (provision)	$ 190	$ (185)	$ 166

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Income Taxes - Schedule of Income before Income Tax, Domestic and Foreign (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Domestic	$ (115,137)	$ (223,991)	$ (95,739)
Foreign	(10,798)	(7,283)	(1,082)
Loss before income taxes	$ (125,935)	$ (231,274)	$ (96,821)

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Income Taxes - Summary of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income tax benefit (provision) at U.S. statutory rate	$ 26,446	$ 80,946	$ 33,887
Share-based compensation	0	0	(5,911)
Impairment	0	(27,969)	0
Change in U.S. tax rate	0	(30,562)	0
Change in valuation allowance due to change in U.S. tax rate	0	30,562	0
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	(7,955)	0	0
Change in valuation allowance	(32,086)	(51,030)	(26,398)
Other	(2,125)	(2,132)	(1,412)
Total income tax benefit (provision)	$ 190	$ (185)	$ 166

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Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Capitalized engineering costs	$ 6,353	$ 2,812
Capitalized start-up costs	19,290	17,881
Compensation and benefits	3,862	5,465
Federal	37,822	19,423
State	4,979	522
Foreign	2,392	1,694
Other, net	8,328	3,541
Deferred tax assets	83,026	51,338
Less valuation allowance	(83,026)	(50,942)
Deferred tax assets, net of valuation allowance	0	396
Deferred tax liabilities	0	(396)
Net deferred tax assets	$ 0	$ 0

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Financial Instruments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) Bcf
Not Designated as Hedging Instrument | Non-current asset
Derivatives, Fair Value [Line Items]
Derivative asset	$ 0.6
Not Designated as Hedging Instrument | Current asset
Derivatives, Fair Value [Line Items]
Derivative asset	0.4
Not Designated as Hedging Instrument | Current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability	0.6
Not Designated as Hedging Instrument | Non-current liability
Derivatives, Fair Value [Line Items]
Derivative liability	$ 0.3
Basis Swap
Derivatives, Fair Value [Line Items]
Hedged portions of expected sales of equity production | Bcf	19.3
Commodity swaps
Derivatives, Fair Value [Line Items]
Hedged portions of expected sales of equity production | Bcf	19.3
Commodity swaps | Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Loss on derivative	$ 0.1
Unrealized gain derivatives	0.1
Level 2 | Commodity swaps | Not Designated as Hedging Instrument | Accrued liabilities
Derivatives, Fair Value [Line Items]
Derivative liability	0.2
Level 2 | Commodity swaps | Not Designated as Hedging Instrument | Non-current asset
Derivatives, Fair Value [Line Items]
Derivative asset	$ 0.3

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Long-term Borrowings - Additional Information (Details) - USD ($)		12 Months Ended
	Sep. 28, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Apr. 09, 2016
Debt Instrument [Line Items]
Outstanding principal amount		$ 60,000
Unamortized discount and deferred financing costs		3,000,000
Non-current restricted cash		49,875,000	$ 0	$ 0	$ 0
Voluntary principal payment, minimum amount		5,000,000
Voluntary principal payment, integral multiples in excess thereof		$ 1,000,000
Early termination premium (as a percentage)		1.00%
LIBOR
Debt Instrument [Line Items]
Basis on variable rate, first year (as a percentage)		5.00%
Basis on variable rate, second year (as a percentage)		7.00%
Basis on variable rate, thereafter (as a percentage)		8.00%
Term Loan
Debt Instrument [Line Items]
Debt term (in years)	3 years
Principal amount	$ 60,000,000.0
Principal amount as a percentage of par amount	99.00%
Discount	$ 600,000
Fees	$ 2,600,000
Outstanding principal amount		$ 60,000,000
Non-current restricted cash		49,600,000
Interest expense		$ 1,200,000

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Long-term Borrowings - Summary of Long-term Borrowings Maturities (Details)	Dec. 31, 2018 USD ($)
Debt Disclosure [Abstract]
2019	$ 0
2020	0
2021	60,000
Total	$ 60,000

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Stockholders' Equity - Additional Information (Detail) $ in Thousands	1 Months Ended				12 Months Ended
	Jun. 30, 2018 USD ($) shares	Jan. 31, 2018 USD ($) shares	Dec. 31, 2017 USD ($) shares	Jan. 31, 2017 USD ($) shares	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Mar. 31, 2018 USD ($) shares	Jun. 30, 2017 shares	Mar. 31, 2017 shares
Class of Stock [Line Items]
Option to purchase additional shares of common stock	12,000,000		10,000,000
Proceeds from sale of common stock, net of fees and commissions | $	$ 115,200		$ 94,800
Fees and commissions | $	$ 3,600		$ 5,200		$ 4,090	$ 5,707	$ 1,681
Conversion ratio					1
Treasury shares retired			1,300,000
Over-allotment Option
Class of Stock [Line Items]
Option to purchase additional shares of common stock		1,500,000.0
Proceeds from sale of common stock, net of fees and commissions | $		$ 14,500
Fees and commissions | $		$ 500
Option to purchase shares (up to)	1,800,000		1,500,000
At-the-Market Program
Class of Stock [Line Items]
Aggregate sales proceeds (up to) | $					$ 189,700
Convertible Preferred Stock
Class of Stock [Line Items]
Convertible preferred stock, shares issued								6,100,000
Discharge of liability outstanding | $					27,300			$ 22,700
Amount applied to future services | $								$ 27,300
TOTAL Delaware Inc
Class of Stock [Line Items]
Option to purchase additional shares of common stock				35,400,000
Proceeds from sale of common stock, net of fees and commissions | $				$ 207,000
Shares exchanged for issue of common stock				46,000,000
GE Oil & Gas, Inc.
Class of Stock [Line Items]
Number of shares converted									5,500,000
GE Oil & Gas, Inc. | Series A Preferred Stock
Class of Stock [Line Items]
Number of shares converted										5,500,000
GE Oil & Gas, Inc. | Series B Preferred Stock
Class of Stock [Line Items]
Number of shares converted									5,500,000
Non-current asset
Class of Stock [Line Items]
Deferred engineering costs | $					$ 50,000

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Stockholders' Equity - Summary of Changes in Fair Value for Embedded Derivative (Detail) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Feb. 10, 2017	Dec. 31, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value at the beginning of period and initial fair value, respectively	$ 8,753	$ 5,445
(Gain) loss on exchange feature	(2,209)	3,308
Fair value at the end of the period and year, respectively	$ 6,544	$ 8,753

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Loss Per Share - Schedule of Earnings Per Share, Basic and Diluted (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Net loss	$ (31,516)	$ (33,191)	$ (35,854)	$ (25,184)	$ (34,723)	$ (22,864)	$ (32,523)	$ (141,349)	$ (125,745)	$ (231,459)	$ (96,655)
Basic and diluted (in shares)	217,408	217,380	206,531	204,772	194,978	192,405	186,102	154,213	211,574	188,536	95,795
Loss per share:
Basic and diluted (in dollars per share)	$ (0.14)	$ (0.15)	$ (0.17)	$ (0.12)	$ (0.18)	$ (0.12)	$ (0.17)	$ (0.92)	$ (0.59)	$ (1.23)	$ (1.01)

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Loss Per Share - Additional Information (Detail) - shares shares in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share amount	24.4	19.9	11.5
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share amount	2.0	2.0
Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share amount	6.1

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Supplemental Cash Flow Information - Net Change in Components of Operating Assets and Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Apr. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounts receivable		$ (958)	$ (442)	$ (39)
Accounts receivable due from related parties		62	(60)	(124)
Prepaids and other current assets		(431)	(1,419)	(1,936)
Note receivable due from related party		0	251	0
Accounts payable and accrued expenses		23,251	11,338	22,393
Accounts payable due to related parties		0	0	(53)
Other, net		(11,404)	(2,235)	(1,903)
Net changes in working capital		$ 10,520	$ 7,433	$ 18,338
Predecessor
Accounts receivable	$ 1
Accounts receivable due from related parties	(32)
Prepaids and other current assets	13
Note receivable due from related party	0
Accounts payable and accrued expenses	281
Accounts payable due to related parties	253
Other, net	0
Net changes in working capital	$ 516

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Apr. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 210	$ 133,714	$ 128,273	$ 21,398
Net cash paid for income taxes	0	0	0	4
Property, plant and equipment non-cash accruals	75	8,630	83	46
Non-cash settlement of withholding taxes associated with the 2017 bonus accrual and vesting of certain awards	0	5,733	828	0
Non-cash settlement of the 2017 bonus accrual	0	15,202	0	0
Asset retirement obligation additions and revisions	0	115	0	0
Equity offering cost accrual	0	0	65	128
Non-current restricted cash	0	49,875	0	0
Total cash, cash equivalents and restricted cash in the statement of cash flows	$ 210	$ 183,589	$ 128,273	$ 21,398	$ 0

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Interim Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Total revenue	$ 1,872	$ 799	$ 813	$ 6,801	$ 5,441	$ 0	$ 0	$ 0	$ 10,286	$ 5,441	$ 0
Loss from operations	(31,287)	(34,384)	(36,658)	(25,392)	(35,852)	(26,095)	(32,899)	(143,721)	(127,720)	(238,567)	(93,730)
Net loss	$ (31,516)	$ (33,191)	$ (35,854)	$ (25,184)	$ (34,723)	$ (22,864)	$ (32,523)	$ (141,349)	$ (125,745)	$ (231,459)	$ (96,655)
Basic and diluted (in dollars per share)	$ (0.14)	$ (0.15)	$ (0.17)	$ (0.12)	$ (0.18)	$ (0.12)	$ (0.17)	$ (0.92)	$ (0.59)	$ (1.23)	$ (1.01)
Weighted average shares outstanding - basic and diluted (in shares)	217,408	217,380	206,531	204,772	194,978	192,405	186,102	154,213	211,574	188,536	95,795

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Recent Accounting Standards - Description of Recent Accounting Standards, Not been Adopted (Detail) - Accounting Standards Update 2016-02 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Description	This standard requires a lessee to recognize leases on its balance sheet by recording a liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This standard may be early adopted and must be adopted using a modified retrospective approach with certain available practical expedients, one of which is an option of applying the requirements of the standard either (1) retrospectively to each prior comparative reporting period presented or (2) retrospectively at the beginning of the period of adoption.
Date of Adoption	Jan. 01, 2019
Effect on our Consolidated Financial Statements or Other Significant Matters	The Company has adopted the standard on January 1, 2019, and will apply it at the beginning of the period of adoption. Therefore, upon adoption, financial information and disclosures will not be updated for comparative reporting periods under the new standard. Additionally, the Company has elected the transition package of practical expedients upon adoption which, among other things, allows an entity to not reassess the historical lease classification. The Company utilized a combination of a bottom-up and top-down approach to identify and analyze its lease portfolio. The analysis included reviewing all forms of leases, performing a completeness assessment over the lease population, assessing the policy elections offered by the standard and evaluating its business processes and internal controls to meet the ASU's accounting, reporting and disclosure requirements. The Company’s adoption of the standard has an impact on the Consolidated Balance Sheet. The Company’s adoption of the standard does not impact the Consolidated Statements of Operations or the Consolidated Statements of Cash Flows. The most significant effect of the new standard on the Consolidated Balance Sheet relates to the recognition of right-of-use assets and lease liabilities for the Company’s real estate portfolio, which the Company expects to be between $15 million and $25 million. The Company will also be providing new disclosures for its leasing activities under the new standard in the first quarter of 2019.
Scenario, Forecast | Subsequent Event | Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use assets		$ 15
Lease liabilities		15
Scenario, Forecast | Subsequent Event | Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use assets		25
Lease liabilities		$ 25

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Supplemental Disclosures About Natural Gas Producing Activities - Capitalized Costs Related to Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Extractive Industries [Abstract]
Proved properties	$ 101,459	$ 90,869
Unproved properties	10,204	13,000
Gross capitalized costs	111,663	103,869
Accumulated DD&A	(1,335)	(149)
Net capitalized costs	$ 110,328	$ 103,720

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Supplemental Disclosures About Natural Gas Producing Activities - Costs Incurred in Exploration, Property Acquisitions and Development (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property acquisitions:
Proved	$ 13,261,000	$ 90,869,000
Unproved	204,000	13,000,000
Exploration costs	0	0
Development	2,104,000	949,000
Costs incurred	$ 15,569,000	$ 104,818,000

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Supplemental Disclosures About Natural Gas Producing Activities - Results of Operations for Natural Gas & Condensate Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Extractive Industries [Abstract]
Natural gas sales	$ 4,423	$ 503
Operating costs	11,251	1,668
Depreciation, depletion and amortization	1,228	115
Impairment charge	2,699	0
Total operating costs and expenses	15,178	1,783
Results of operations	$ (10,755)	$ (1,280)

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Supplemental Disclosures About Natural Gas Producing Activities - Natural Gas & Condensate Reserve Quantity Information (Details) MMcf in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2018 Bcf MBbls MMcf	Dec. 31, 2017 Bcf MBbls MMcf	Dec. 31, 2016 MBbls MMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Extensions, discoveries and other additions | Bcf	22
Purchases of reserves-in-place | Bcf		327
Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning balance	327,118	0
Extensions, discoveries and other additions	22,481	0
Revisions of previous estimates	(84,061)	0
Production	(1,399)	(190)
Sale of reserves-in-place	0	0
Purchases of reserves-in-place	715	327,308
Proved reserves, ending balance	264,854	327,118
Proved developed reserves:	17,522	5,720	0
Proved undeveloped reserves:	247,332	321,398	0
Condensate
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning balance | MBbls	10	0
Extensions, discoveries and other additions | MBbls	0	0
Revisions of previous estimates | MBbls	(2)	0
Production | MBbls	(1)	0
Sale of reserves-in-place | MBbls	0	0
Purchases of reserves-in-place | MBbls	0	10
Proved reserves, ending balance | MBbls	7	10
Proved developed reserves: | MBbls	7	10	0
Proved undeveloped reserves: | MBbls	0	0	0
Gas Equivalent
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves, beginning balance	327,180	0
Extensions, discoveries and other additions	22,481	0
Revisions of previous estimates	(84,072)	0
Production	(1,405)	(191)
Sale of reserves-in-place	0	0
Purchases of reserves-in-place	715	327,371
Proved reserves, ending balance	264,899	327,180
Proved developed reserves:	17,567	5,782	0
Proved undeveloped reserves:	247,332	321,398	0

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Supplemental Disclosures About Natural Gas Producing Activities - Additional Information (Details) - Bcf	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Extractive Industries [Abstract]
Acquired reserves (in Bcfe)		327
Extensions, discoveries and other additions (in Bcfe)	22
Additional proved undeveloped locations, detailed analysis (in Bcfe)	19
Additional proved undeveloped locations, drilling activities (in Bcfe)	3
Negative revisions (in Bcfe)	85
Negative revisions, previous estimates (in Bcfe)	59
Negative revisions, revision of previous estimates (in Bcfe)	14
Negative revisions, due to loss of leases (in Bcfe)	12
Positive revisions, increase in commodity prices (in Bcfe)	1
Acquisition of proved reserves through minor interest acquired (in Bcfe)	1

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Supplemental Disclosures About Natural Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas & Condensate Reserves (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Future cash inflows	$ 676,454	$ 777,711
Future production costs	(105,341)	(144,991)
Future development costs	(264,239)	(331,297)
Future income tax provisions	(54,564)	(52,212)
Future net cash flows	252,310	249,211
Less effect of a 10% discount factor	(106,499)	(161,009)
Standardized measure of discounted future net cash flows	$ 145,811	$ 88,202	$ 0

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Supplemental Disclosures About Natural Gas Producing Activities - Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas & Condensate Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning balance	$ 88,202	$ 0
Sales and transfers of gas and condensate produced, net of production costs	(1,773)	(265)
Net changes in prices and production costs	27,530	0
Extensions, discoveries, additions and improved recovery, net of related costs	13,334	0
Development costs incurred	545	0
Revisions of estimated development costs	9,663	0
Revisions of previous quantity estimates	12,991	0
Accretion of discount	11,112	0
Net change in income taxes	(9,472)	(22,921)
Purchases of reserves in place	844	111,388
Sales of reserves in place	0	0
Changes in timing and other	(7,165)
Ending balance	$ 145,811	$ 88,202

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT - PARENT COMPANY BALANCE SHEETS (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Apr. 09, 2016	Dec. 31, 2015
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	$ 133,714	$ 128,273	$ 21,398	$ 210
Prepaids and other	3,906	3,458
Property, plant and equipment, net	130,580	115,856
Total assets	408,548	276,823
Accounts payable	11,597	11,462
Accrued liabilities	41,173	39,101
Total long-term liabilities	57,844	638
Preferred stock, $0.01 par value, 100,000,000 authorized: 6,123,782 and zero shares outstanding, respectively	61	0
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	5,599		$ 0
Total liabilities and stockholders’ equity	408,548	276,823
Parent [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	0	0	$ 0
Prepaids and other	72	25
Investments in subsidiaries	289,802	212,846
Property, plant and equipment, net	10,000	13,000
Total assets	299,874	225,871
Accounts payable	114	148
Accrued liabilities	1,826	1,836
Total long-term liabilities	1,940	1,984
Preferred stock, $0.01 par value, 100,000,000 authorized: 6,123,782 and zero shares outstanding, respectively	61	0
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	$ 299,874	$ 225,871

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT - PARENT COMPANY BALANCE SHEETS (Parenthetical) (Details) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Preferred stock, par value (in usd per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares outstanding	6,123,782	0
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares, outstanding	240,655,607	222,749,220

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT - PARENT COMPANY STATEMENTS OF OPERATIONS (Details) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Apr. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Income Statements, Captions [Line Items]
Total revenue	$ 1,872	$ 799	$ 813	$ 6,801	$ 5,441	$ 0	$ 0	$ 0		$ 10,286	$ 5,441	$ 0
Cost of sales										6,115	7,565	0
Development expenses										44,034	59,498	47,146
General and administrative expenses										81,777	98,874	46,515
Goodwill impairment										0	77,592	0
Total operating costs and expenses										138,006	244,008	93,730
Loss on preferred stock exchange feature										0	(2,209)	3,308
Interest expense									$ 0	1,574	1,022	0
Income tax benefit (provision)										190	(185)	166
Parent [Member]
Condensed Income Statements, Captions [Line Items]
Total revenue										0	0	0
Cost of sales										93	15	0
Development expenses										2,487	320	21
General and administrative expenses										4,618	594	25,084
Goodwill impairment										0	77,592	0
Total operating costs and expenses										7,198	78,521	25,105
Loss on preferred stock exchange feature										0	0	3,308
Interest expense										2	0	0
Loss from operations before income taxes and equity in losses of subsidiaries										(7,200)	(78,521)	(28,413)
Income tax benefit (provision)										0	(4)	170
Net loss from operations before equity in losses of subsidiaries										(7,200)	(78,525)	(28,243)
Equity in losses of subsidiaries, net of tax										(118,545)	(152,934)	(68,412)
Net loss										$ (125,745)	$ (231,459)	$ (96,655)

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT - PARENT COMPANY STATEMENTS OF CASH FLOWS (Details) - USD ($) $ in Thousands	1 Months Ended		3 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Apr. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Cash Flow Statements, Captions [Line Items]
Net cash used in operating activities				$ (103,752)	$ (109,229)	$ (50,430)
Cash flows from investing activities:
Cash received in acquisition				0	56	210
Net cash used in investing activities				(21,687)	(95,565)	(10,506)
Cash flows from financing activities:
Proceeds from the issuance of common stock				133,800	318,204	59,015
Tax payments for net share settlement of equity awards				(5,734)	(828)	0
Proceeds from the issuance of preferred stock				0	0	25,000
Equity offering costs	$ (3,600)	$ (5,200)		(4,090)	(5,707)	(1,681)
Net cash provided by financing activities				180,755	311,669	82,334
Cash and cash equivalents, beginning of period				128,273	21,398
Cash and cash equivalents, end of period		128,273	$ 210	133,714	128,273	21,398
Parent [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash used in operating activities				(123,976)	(312,553)
Cash flows from investing activities:
Cash received in acquisition				0	56
Acquisition and development of natural gas properties				0	0
Net cash used in investing activities				0	56
Cash flows from financing activities:
Proceeds from the issuance of common stock				133,800	318,204
Tax payments for net share settlement of equity awards				(5,734)	0
Proceeds from the issuance of preferred stock				0	0
Equity offering costs				(4,090)	(5,707)
Net cash provided by financing activities				123,976	312,497
Net increase (decrease) in cash and cash equivalents				0	0
Cash and cash equivalents, beginning of period				0	0
Cash and cash equivalents, end of period		$ 0		$ 0	0	0
Tellurian Investments, Inc. [Member] | Parent [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash used in operating activities						(60,532)
Cash flows from investing activities:
Cash received in acquisition						210
Acquisition and development of natural gas properties						(1,190)
Net cash used in investing activities						(980)
Cash flows from financing activities:
Proceeds from the issuance of common stock						59,015
Tax payments for net share settlement of equity awards						0
Proceeds from the issuance of preferred stock						25,000
Equity offering costs						(1,681)
Net cash provided by financing activities						82,334
Net increase (decrease) in cash and cash equivalents						20,822
Cash and cash equivalents, beginning of period			$ 0		$ 20,822	0
Cash and cash equivalents, end of period						$ 20,822

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Basis of Presentation (Details)	Dec. 31, 2018
Parent [Member] | Merger Agreement
Business Acquisition [Line Items]
Exchange of shares, conversion ratio	1.3