UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): January 8, 2018

Tellurian Inc.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (832) 962-4000

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).

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.  ☐

On January 8, 2018, Tellurian Inc. posted an updated corporate presentation to its website, www.tellurianinc.com. A copy of the corporate presentation is attached as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated herein by reference.

The information in this Current Report on Form 8-K, including the information set forth in Exhibit 99.1, is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

(d) Exhibits.

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 hereunto duly authorized.

Date: January 8, 2018

Corporate presentation January 2018 Exhibit 99.1

Disclaimer

$25 million $60 million $207 million Merger $100 million Upstream Acquisition LSTK February April August December January February June November December Charif Souki and Martin Houston establish Tellurian Management, friends and family invest $60 million Meg Gentle joins to lead the company as President & CEO GE invests $25 million in Tellurian TOTAL invests $207 million in Tellurian Merged with Magellan Petroleum, gaining access to public markets Bechtel, Chart Industries and GE complete the front-end engineering and design (FEED) study for Driftwood LNG Acquired Haynesville acreage, production and ~1.4 Tcf Executed LSTK EPC contract with Bechtel for ~$15 billion Raised approximately $100 million public equity 2017 2016 Building a low-cost global natural gas business Introduction

Netback prices to US Gulf Coast(2) New liquefaction capacity required Sources: ICE via Marketview, Wood Mackenzie, Platts and Tullett Prebon, Fearnleys, Tellurian Research. Notes: (1) Effective capacity is defined as total capacity less unplanned outages and gas constraints. Implied utilization rates assume demand growth of 11% per annum. (2) Historical prices from Platts; forward prices from Tullett Prebon Global LNG Accelerated demand growth driven by low LNG prices 2017 effective capacity(1) utilization >97% Higher prices signal need for more LNG Emerging indices provide forward transparency LNG demand growth LNG capacity utilization

Sources:Kpler, Maran Gas, IHS, Wood Mackenzie. Notes: LNG storage assumes half of fleet is in ballast, 2.9 Bcf capacity per vessel. Average cargo size ~2.9 Bcf, assuming 150,000 m3 ship. In 2017, approximately a third of all LNG cargoes are estimated to be spot volumes. Assumes 11% per annum demand growth. Daily LNG supply readily available across the globe Emergence of a liquid LNG market Bcf of LNG storage # of LNG vessels # of cargoes loaded per day Legend LNG carrier – laden LNG carrier – unladen LNG Storage - 2017 Japan + Korea terminals: 633 Bcf LNG vessels: 686 Bcf

Building a low-cost global gas business Pipeline Liquefaction Marketing Upstream Purchase low-cost gas at liquidity points or as reserves Diversify gas supply Develop pipeline solutions for constrained production basins Maximize access to supply liquidity Develop low-cost liquefaction ~$550 per tonne Develop suite of flexible LNG products Build out risk management and operational infrastructure LNG trade entry in 2017 Acquired 11,620 net acres with up to 178 drilling locations and 1.4 Tcf total net resource in Haynesville Delivered gas cost $2.25/mmBtu FERC permit pending for Driftwood Pipeline Developing Tellurian Pipeline Network ~27.6 mtpa Driftwood LNG terminal FEED complete LSTK EPC executed for $15.2 billion FERC permit pending Experienced global marketing team Offices in Houston, Washington D.C., London, and Singapore Maran Gas Mystras LNG vessel under 6 month time charter Business model

Tellurian will offer equity interest in Driftwood Holdings Driftwood Holdings will consist of Tellurian Production Company, Driftwood Pipeline Network and Driftwood LNG terminal (~27.6 mtpa) Equity will cost ~$1,500 per tonne Customer/Partner will receive equity LNG at tailgate of Driftwood LNG terminal at cost Variable and operating costs expected to be ~$3.00/mmBtu FOB (including maintenance) Tellurian will retain 7 to 12 mtpa Tellurian will manage and operate the project Business model Tellurian Marketing Driftwood Holdings Driftwood LNG Terminal Driftwood Pipeline Network Tellurian Production Company Customers Equity ownership 25% - 40% ~7-12 mtpa ~16-21 mtpa ~7-12 mtpa Customer/Partner 60% - 75% Customers 100% Business model Nasdaq: TELL

Total cost of ~$3/mmBtu locks in low cost of supply Potential margin capture from Driftwood Sources: Wood Mackenzie, Platts, Tullet Prebon, Tellurian Research. Notes: (1) Drilling and completion based on well cost of $10.2 million, 15.5 Bcf EUR, and 75.00% net revenue interest (“NRI”) (8/8ths). (2) Gathering, processing and transportation includes transportation cost to Driftwood pipeline to market. (3) Platts Gulf Coast Marker. Upstream cost $/mmBtu Liquefaction cost $3/mmBtu supply cost $1.50 – $15.00/mmBtu of margin potential Business model Feb 18 GCM(3) 4 Jan 2017: $8.75/mmBtu 2013 2014 2015 2016 2017 Netback prices to the Gulf Coast $/mmBtu $3/mmBtu supply cost

Illustrative financials Business model Notes: (1) Phase 1 of the EPC agreement reflects 2 plants, 1 berth, and 2 tanks; full development reflects 5 plants, 3 berths, and 3 tanks. (2) Resource need for 30 year period. (3) Drilling capital expenditures of $3.4 billion, net of $2.2 billion of gas sales. (4) Cash flows calculated as Tellurian capacity (3 mtpa) multiplied by 52 mmBtu per tonne multiplied by Customer margin. (5) Per share amounts based on 224 million shares outstanding as of December 15, 2017 (214 million shares as of December 7, 2017 as reported in prospectus supplement filed on December 11, 2017 and an additional 10 million shares issued in December 2017). Scenario Phase 1(1) Full development(1) Capacity, mtpa 11.0 27.6 Upstream resource need(2), Tcf ~15 ~40 Investment, $ billions Terminal and S&U $ 7.6 $ 15.2 Pipeline $ 1.1 $ 2.2 Owner's costs and other $ 1.1 $ 2.1 Upstream – acquisition $ 1.0 $ 2.0 Upstream – drilling capex (net of sales)(3) $ 1.2 $ 2.5 Total $ 12.0 $ 24.0 Transaction price, $ per tonne $1,500 $1,500 Capacity split mtpa % mtpa % Customer/Partner 8.0 72% 16.0 58% Tellurian 3.0 28% 11.6 42% LNG sale price, $/mmBtu $ 6.00 $ 10.00 $ 15.00 $ 6.00 $ 10.00 $ 15.00 Customer margin, $/mmBtu $ 3.00 $ 7.00 $ 12.00 $ 3.00 $ 7.00 $ 12.00 Tellurian annual cash flows, $ millions(4) $ 470 $ 1,090 $ 1,870 $ 1,810 $ 4,220 $ 7,240 Tellurian annual cash flows per share(5), $ $ 2.10 $ 4.90 $ 8.35 $ 8.10 $ 18.85 $ 32.30

Return on $1,500 per tonne investment Business model Payback period analysis(6) Years to recover capital $0 $(1,500) Cumulative cash flow $ millions $10/mmBtu $6/mmBtu Netback FOB U.S. Gulf Coast 4 10 Notes: (1) Equivalent to FOB price at U.S. Gulf Coast. (2) Assuming $3/mmBtu cost of LNG. (3) Assuming liquefaction capacity of 1.0 mtpa and energy conversion of 52 mmBtu per tonne. (4) Investor cashflow per tonne (from (3) above) divided by $1,500 per tonne investment. (5) IRR calculated over 20 years after investment period before federal income tax, and including a terminal value based on a cap rate of 8.0%. (6) Payback based on implied margin per unit, federal income taxes are not included; assumes $3/mmBtu cost of production and single customer investment of $1,500 million. U.S. Gulf Coast net back price(1), $/mmBtu $ 6.00 $ 10.00 $ 15.00 Driftwood LNG, FOB U.S. Gulf Coast $ (3.00) $ (3.00) $ (3.00) Margin(2), $/mmBtu $ 3.00 $ 7.00 $ 12.00 Annual Customer/Partner cashflows(3), $ per tonne $ 156 $ 364 $ 624 Cash on cash return(4) 10% 24% 42% Unlevered IRR(5) 9% 18% 26%

Driftwood vs. competitors – cost per tonne Sources:Wood Mackenzie, The World Bank, Tellurian Research. Notes:(1) The World Bank bases the Logistics Performance Index (LPI) on surveys of operators to measure logistics “friendliness “ in respective countries which is supplemented by quantitative data on the performance of components of the logistics chain. Capacity, mtpa 9.5 27.6 10.0 16.5 13.0 9.0 15.6 9.0 8.9 LPI global ranking(1): 3.6 4.0 2.7 2.6 3.9 3.8 3.8 3.8 3.8 Business model

Integrated model prevalent internationally Source:IHS. Projects include: Australasia APLNG, Darwin, GLNG, Gorgon, Ichthys, NWS, Pluto, Northwest Shelf, QCLNG, Wheatstone, PNG LNG, Tangguh, Brunei LNG, Donggi-Senoro, MLNG, Yamal LNG Mideast/Africa Angola LNG, EG LNG, Damietta, ELNG, Yemen LNG, Mozambique LNG, Coral LNG, Oman LNG, Qalhat LNG, Qatargas I-IV, RasGas I-III, ADGAS Americas Atlantic LNG, Peru LNG, LNG Canada Europe Snohvit, Yamal LNG Europe Australasia NOC IOC Business model

Driftwood LNG terminal Notes:(1) Before owners’ costs, financing costs and contingencies. Driftwood LNG terminal Land ~1,000 acres near Lake Charles, LA Capacity ~27.6 mtpa Trains Up to 20 trains of ~1.38 mtpa each Chart heat exchangers GE LM6000 PF+ compressors Storage 3 storage tanks 235,000 m3 each Marine 3 marine berths Capex ~$550 per tonne ~$15.2 billion(1) Artist rendition Driftwood LNG

Driftwood schedule Driftwood LNG Notes:(1) Projects under Environmental Assessment (EA), all other projects required an Environmental Impact Statement (EIS), which entails a longer review process with the FERC. Second wave First wave Catalyst Estimated timeline Draft Environmental Impact Statement 1H 2018 Final Environmental Impact Statement 12 October 2018 FERC order and Federal Authorization Deadline 10 January 2019 Driftwood final investment decision 1H 2019 Begin construction 1H 2019 Begin operations 2023 Months 1 1 1

Tellurian Pipeline Network Notes: (1) Included in Driftwood Holdings. (2) Currently not included in Driftwood Holdings illustrative financials (slide 9); commercial and regulatory in progress and financial structuring under review. Tellurian Pipeline Network Driftwood Pipeline1 Capacity, Bcf/d 4.0 Cost, $ billions $2.2 Length, miles 96 Diameter, inches 48 Compression, HP 274,000 Status FERC approval pending Haynesville Global Access Pipeline2 Capacity, Bcf/d 2.0 Cost, $ billions $1.4 Length, miles 200 Diameter, inches 42 Compression, HP 23,000 Status Preliminary routing Permian Global Access Pipeline2 Capacity, Bcf/d 2.0 Cost, $ billions $3.7 Length, miles 625 Diameter, inches 42 Compression, HP 258,000 Status Preliminary routing Bringing low cost gas to Southwest Louisiana 1 2 3 1 2 3

Notes:(1) LNG demand includes ambient capacity. (2) Includes: Driftwood LNG, Sabine Pass LNG T1-3, Cameron LNG T1-3, SASOL, Lake Charles CCGT, G2X Big Lake Fuels, LACC – Lotte and Westlake Chemical. Source:Company data, Tellurian estimates. Louisiana Texas Gulf of Mexico Lake Charles Petrochemical complex Gillis, LA Eunice, LA Driftwood LNG Tellurian Pipeline Network Cameron LNG Sabine Pass LNG 12 Bcf/d Southwest Louisiana firm demand(1)(2) Core of U.S. natural gas exports 12 Bcf/d Southwest Louisiana gas demand 2017 2018 2019 2020 2021 2022 2023 2024 Demand triples in 7 years

Tellurian Production Company Acquire and develop long life, low-cost natural gas resources Low geological risk Scalable position Production of ~1.5 Bcf/d starting in 2022 Total resources of ~15 Tcf for Phase 1 Operatorship Low operating costs Flexible development Initially focused on Haynesville basin; in close proximity to significant demand growth, low development risk, and favorable economics Target is to deliver gas for $2.25/mmBtu Tellurian acquired 11,620 net acres in the Haynesville shale for $87.8 million in Q4 2017 Primarily located in De Soto and Red River parishes 80% HBP 94% operated 100% gas Current production – 4 mmcf/d Operated producing wells – 19 Identified development locations – ~178 Total net resource – ~1.4 Tcf Tellurian Production Company Objectives Acquisitions

LNG demand is growing at 11% per annum Netback LNG prices to the U.S. Gulf Coast of > $8.00/mmBtu have signaled that additional liquefaction capacity is needed The U.S. is best positioned to meet global LNG supply needs with access to abundant low-cost gas and a track record of building low-cost liquefaction Additional U.S. infrastructure is required to connect stranded supply with growing demand Tellurian’s business model is designed to provide investors with access to the U.S. integrated value chain capable of providing low cost, flexible LNG globally Conclusions Source:Kpler Conclusions

Contact us Amit Marwaha Director, Investor Relations & Finance +1 832 485 2004 amit.marwaha@tellurianinc.com Joi Lecznar SVP, Public Affairs & Communication +1 832 962 4044 joi.lecznar@tellurianinc.com @TellurianLNG Contacts

2017 Additional detail

Key terms of EPC agreements with Bechtel Additional detail Phase 1 Phase 2 Phase 3 Phase 4 Total 11.0 5.5 5.5 5.5 27.6 Trains 8 4 4 4 20 Storage facilities 2 0 1 0 3 Berths 1 1 1 0 3 Capacity

Tellurian Pipeline Network Gillis Market Area KMPL TETCO Trunkline Transco Tenn Gas CTPL Cameron FGT DWPL EGAN Texas Gas Pine Prairie ANR CGT Interconnects Permian Supply Area ETC –Comanche Trail ETC – Trans-Pecos ETC – Oasis Vaquero OneOK WesTex OXY Enterprise Jal El Paso WhiteWater NGPL Northern Natural Gas TransWestern Atmos Interconnects Haynesville Supply Area Crosstex Regency (RIGS) Acadian MEP Gulf Crossing CenterPoint Tellurian Production Co. Tenn Gas ETC – Tiger Texas Gas Gulf South Interconnects Proposed pipelines DWPL DWPL interconnects Additional detail Proposed pipelines PGAP PGAP interconnects Proposed pipelines HGAP HGAP interconnects

Haynesville type curve comparison Comparative type curve statistics Cumulative production normalized to 7,500’(3) Source:Company investor presentations. Notes:(1) Assumes 75.00% net revenue interest (“NRI”) (8/8ths). (2) Assumes gas prices of $3.00/mcf based on NRI and returns published specific to each operator. (3) 7,500’ estimated ultimate recovery (“EUR”) = original lateral length EUR + ((7,500’-original lateral length) * 0.75 * (original lateral length EUR / original lateral length)). Peer B Peer D Peer A Peer C Tellurian Tellurian Peer A Peer B Peer C Peer D Type curve detail Area De Soto / Red River North Louisiana De Soto NLA De Soto core NLA core / blended development program Completion (lbs. / ft.) - 4,000 3,800 2,700 3,000 Single well stats           Lateral length (ft.) 6,950' 7,500' 7,500' 4,500' 9,800' Gross EUR (Bcf) 15.5 18.8 18.6 9.9 19.9 EUR per 1,000' ft. (Bcf) 2.20 2.50 2.48 2.20 2.03 Gross D&C ($ millions) $10.20 $10.20 $8.50 $7.70 $10.30 F&D ($/mcf)(1) $0.88 $0.73 $0.61 $1.04 $0.69 Type curve economics           Before-tax IRR (%)(2) 43% 60% 90%+ 54% - Additional detail