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Corporate presentation Meg Gentle, CEO Credit Suisse 23rd Annual Energy Summit Vail, Colorado February 14, 2018 Exhibit 99.1

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Disclaimer

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Strategy: Building a low-cost, global natural gas company Upstream production – 11,620 acres in the Haynesville w. ~1.4 Tcf resource Pipeline infrastructure development – ~$7 BN of pipeline projects LNG export infrastructure development – ~$15 BN of liquefaction projects LNG marketing – international delivery of LNG cargoes Differentiators Integrated business model Lowering cost for sustainable development in a commoditizing market Today’s Presentation . . . Market context . . . Asset plans . . .. Business model Introducing Tellurian (NASDAQ: TELL) Business model

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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. Global LNG market is commoditizing Global LNG 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

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Global LNG oversupply is over Global LNG Asia LNG imports Bcf/d JKM annual average prices $/mmBtu Source: Wood Mackenzie, Platts, IHS. Price signals balance the market Global LNG market Bcf/d Infrastructure constraint

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Netback prices to US Gulf Coast(2) New liquefaction capacity required Sources: ICE via Marketview, Wood Mackenzie, Platts via CME, 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; netbacks based on shipping costs based on historical and current day rates. 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 transparency LNG demand growth LNG capacity utilization

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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

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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

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Plentiful, low-cost U.S. gas endowment Implications for the U.S. Production growth and resource base from selected U.S. unconventional basins Source: EIA; Tellurian analysis 411 112 74 23 52 Resource size, Tcf Marcellus-Utica Haynesville Eagle Ford Permian Anadarko Total selected basin shale production, Bcf/d

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Ill-suited existing infrastructure Implications for the U.S. Pre-shale pipelines and import facilities did not contemplate the shale revolution Source: EIA; Tellurian analysis Traditionally, pipelines have moved gas from conventional producing regions to consuming markets in the Midwest, Northeast and West Coast Major gas transportation flows 13 13 2008 major pipeline corridor approximate capacity, Bcf/d 3 3 1 5 6 6 15

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Infrastructure first wave Implications for the U.S. Industry built new pipelines, reversed old ones and developed the first wave of LNG export projects Source: EIA; Wood Mackenzie, RBN, Tellurian analysis. 0.3 Bcf/d 5.6 Bcf/d 2.4 Bcf/d 0.7 Bcf/d 1.7 Current LNG investment: ~$60 billion 9 Bcf/d export capacity 4.8 2.6 1.3 2.6 Completed pipeline reversals and new construction, Bcf/d Pipeline reversals LNG liquefaction terminal Operating Under construction Export capacity Operating Under construction

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New infrastructure required Implications for the U.S. 13 Bcf/d of incremental production at risk of flaring without additional infrastructure investment Source: EIA; ARI; Tellurian analysis Notes: (1) $1,000/tonne average LNG export capacity required: Up to 100 mtpa: 13 Bcf/d (20 Bcf/d less ~7 under construction) ~$100 billion(1) Pipeline capacity required: Around 20 Bcf/d ~$70 billion LNG liquefaction terminal Operating/under construction Future Export capacity 13 bcf/d 6 1 8 1 Required future investment: ~$170 billion At least 7 Bcf/d export capacity 4 20 Total estimated 2017-2025 production growth, Bcf/d New pipelines required

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Permian production outpacing pipelines Tellurian Pipeline Network Takeaway constraints in the Permian Rolling forward curve of Waha basis swap – Mar 18 Source: Bloomberg, Goldman Sachs, Wells Fargo Equity Research, RBN Energy. Historical January 2018 May 2016

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Tellurian Pipeline Network Notes: (1) Included in Driftwood Holdings. (2) Currently not included in Driftwood Holdings illustrative financials (slide 24); 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

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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

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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 Mar 18 GCM(3) 12 Feb 2018: $7.56/mmBtu 2013 2014 2015 2016 2017 Netback prices to the Gulf Coast $/mmBtu $3/mmBtu supply cost

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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

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Catalysts Catalysts 2018 2019 Activity Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Regulatory Draft EIS Final EIS 10/12/18 Scheduled authorization 1/10/19 Pipelines HGAP open season PGAP open season Driftwood Driftwood equity syndication Driftwood FID

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LNG demand is growing at 11-12% 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 ~$170 Bn additional U.S. infrastructure is required to connect supply with growing global 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

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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

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2017 Additional detail

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$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 Creating Tellurian (NASDAQ: TELL) Introduction

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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

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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

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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%

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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

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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

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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

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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

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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

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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 $3.00/mcf based on NRI and returns published specific to each operator Does not include lease acquisition or corporate overhead costs. (3) 7,500’ estimated ultimate recovery (“EUR”) = original lateral length EUR + ((7,500’-original lateral length) * 0.75 * (original lateral length EUR / original lateral length)). Peer B Peer D Peer A Peer C Tellurian Tellurian Peer A Peer B Peer C Peer D Type curve detail Area De Soto / Red River North Louisiana De Soto NLA De Soto core NLA core / blended development program Completion (lbs. / ft.) - 4,000 3,800 2,700 3,000 Single well stats           Lateral length (ft.) 6,950' 7,500' 7,500' 4,500' 9,800' Gross EUR (Bcf) 15.5 18.8 18.6 9.9 19.9 EUR per 1,000' ft. (Bcf) 2.20 2.50 2.48 2.20 2.03 Gross D&C ($ 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