Tellurian (TELZ) 8-K Regulation FD Disclosure

Exhibit 99.1

Corporate presentation January 2019

2 Disclaimer

Introduction 3 Introduction

Tellurian is capturing LNG value Introduction 4 Strong global fundamentals call for ~100 mtpa of additional U.S. LNG Tellurian developing ~$30 billion of assets to generate ~$8 cash flow per share annually Guaranteed EPC with Bechtel differentiates Tellurian and secures project execution

New LNG capacity call: ~100-250 mtpa Introduction Sources: Wood Mackenzie, Tellurian Research. Notes: (1) Assumes 85% utilization rate. (2) Assuming sustained 2015-2018 demand growth rate of ~9.6% p.a. post-2020. (3) Conservative estimate of 4.5% p.a. demand growth rate post-2020. 5 mtpa Under construction In operation Capacity required(1) 10%(2) 5%(3) ~100 mtpa ~250 mtpa 9.6% p.a. growth rate 0 100 200 300 400 500 600 700 800 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Global LNG supply outlook

$16.58 JKM TELL gas production cost: $2.25/mmbtu 2018 LNG hub price ~$10/mmBtu = JKM Introduction Sources: Platts, Tellurian research. Note: (1) Based on full development of Driftwood LNG terminal, assuming JKM price of $10/mmBtu, a shipping rate of $1.50/mmBtu and a delivered FOB cost of $3.00/mmBtu. 6 2013 2014 2015 2016 2017 2018 $13.88 $7.45 $5.72 $7.14 $9.76 Annual avg. JKM ($/mmBtu) 2018 LNG market presents opportunity for ~$8 billion of annual EBITDA for Driftwood(1) Henry Hub

Integrated model Production Company, Pipeline Network, LNG Terminal Variable and operating costs expected to be $3.00/mmBtu FOB Financing ~$8 billion in Partners’ capital through investment of $500 per tonne of LNG ~$20 billion in project finance debt equates to $1.50/mmBtu with projected interest and amortization Tellurian Tellurian will retain ~12 mpta and ~40% of the assets Estimated $2 billion annual cash flow to Tellurian(2) Tellurian projects annual ~$8 cash flow/sh(1) Tellurian Marketing Pipeline Network Production Company Equity ownership ~40% ~16 mtpa ~12 mtpa Partners (~$8 billion in equity) ~60% Partners 100% Introduction LNG Terminal Driftwood Holdings (~$20 billion in project finance debt) Notes: (1) Annual cash flow per share based on anticipated $2 billion annual cash flow to Tellurian and ~247 million shares outstanding. (2) See slide 23 for estimated annual Tellurian cash flow at various assumed U.S. Gulf Coast netback prices and margin levels. 7

Phase 1 Phase 2 Phase 3 Phase 4 Total Bechtel LSTK secures project execution Introduction Leading LNG EPC contractor 44 LNG trains delivered to 18 customers in 9 countries ~30% of global LNG liquefaction capacity (>125 mtpa) Tellurian and Bechtel relationship 16 trains(1) delivered with Tellurian’s executive team Invested $50 million in Tellurian Inc. Source: Bechtel website. Note: (1) Includes all trains from Sabine Pass LNG, Corpus Christi LNG, Atlantic LNG, QCLNG, ELNG. 8 Driftwood EPC contract costs ($ per tonne) Capacity (mtpa) 11.0 5.5 5.5 5.5 27.6

Tellurian and Vitol sign JKM-indexed MOU Introduction Tellurian to supply Vitol with 1.5 mtpa for a minimum of 15 years on an FOB basis Volumes derived from Tellurian’s retained offtake capacity at Driftwood LNG ~$430 million annual EBITDA opportunity, ~$6.5 billion over 15 years(3) Agreement aligns with evolving commoditization of the LNG industry Vitol also considering potential equity investment in Driftwood Holdings Sources: S&P Global Platts, ICE, CME. Notes: (1) Based on year-to-date swaps through exchanges through October 2018. (2) Assumes 1 lot = 10,000 mmBtu and 52 mmBtu per tonne of LNG. (3) Assuming $10/mmBtu JKM price and a $5.50/mmBtu margin. 9 Summary of MOU agreement ~186.5% CAGR ~32.0 JKM liquidity is increasing(1) Cleared JKM swaps on an LNG equivalent basis(2) 0.06 0.08 0.35 0.58 2.9 9.5 26.6 2012 2013 2014 2015 2016 2017 YTD 2018

Final Investment Decision expected 1H 2019 Introduction 10 Fully-wrapped EPC contract Draft FERC EIS Final FERC EIS Final FERC Order Final Investment Decision Notice to Proceed to Bechtel First LNG Milestone Target date November 2017 September 2018 January 2019 1H 2019 1H 2019 1H 2019 2023

Tellurian differentiated to provide value Introduction 11 Management track record at Cheniere and BG Group 43% of Tellurian owned by founders and management Guaranteed lump sum turnkey contract with Bechtel $15.2 billion for 27.6 mtpa capacity FERC scheduling notice indicates final EIS will be received by January 2019 Integrated Upstream reserves Pipeline network LNG terminal Low-cost Flexible World-class partners Fixed-cost EPC contract Regulatory certainty Experienced management Unique business model

Social media 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 12 Introduction @TellurianLNG

Project details 13 Project details

Basin 10,800 Haynesville acres 1.4 Tcf of resource Intend to acquire 15 Tcf Basis ~$7 billion of pipeline projects, providing access to Haynesville, Permian, & Appalachia supply Integrated to manage three risks Project details 14 Construction ~$15 billion liquefaction project in Louisiana

Driftwood LNG terminal Note: (1) Based on engineering, procurement, and construction agreements executed with Bechtel. 15 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 EPC Cost ~$550 per tonne ~$15.2 billion(1) Artist rendition Project details

Pipeline network Note: (1) Included in Driftwood Holdings at full development; commercial and regulatory processes in progress and financial structuring under review. 16 Project details Driftwood Pipeline(1) Capacity (Bcf/d) 4.0 Cost ($ billions) $2.2 Length (miles) 96 Diameter (inches) 48 Compression (HP) 274,000 Status FERC approval pending Haynesville Global Access Pipeline(1) Capacity (Bcf/d) 2.0 Cost ($ billions) $1.4 Length (miles) 200 Diameter (inches) 42 Compression (HP) 23,000 Status Open season completed Permian Global Access Pipeline(1) Capacity (Bcf/d) 2.0 Cost ($ billions) $3.7 Length (miles) 625 Diameter (inches) 42 Compression (HP) 258,000 Status Open season completed Bringing low-cost gas to Southwest Louisiana 1 2 3 1 2 3

>100 Tcf available resources in Haynesville Project details Sources: IHS Enerdeq; 1Derrick; investor presentations; Tellurian research. Note: (1) Estimated resources based on acreage. 17 Driftwood Holdings plans to fund and purchase 15 Tcf Potential acquisition targets: Range of resources per target (Tcf)(1): Target size: Large Medium Small 15 15 9 9 <~9 Tcf ~9 to ~15 Tcf >~15 Tcf

Expecting to eliminate HH price risk Project details Source: CME via MarketView. 18 Buy Henry Hub gas when prices are lower than $2.25 (curtail Haynesville drilling) Acquire lower priced gas in other supply basins via Tellurian pipeline network 2010 2011 2012 2013 2014 2015 2016 2017 2018 Henry Hub gas price (price index for most U.S LNG projects) $/mmBtu $2.25/mmBtu equity Haynesville gas production delivered to the Driftwood terminal Opportunities for further gas supply cost savings: $0 $1 $2 $3 $4 $5 F M A N F M A N F M A N F M A N F M A N F M A N F M A N F M A N F M A

Driftwood Holdings’ financing Project details 19 Full Development Capacity (mtpa) 27.6 Capital investment ($ billions) Liquefaction terminal(1) $ 15.2 Owners’ cost & contingency(2) $ 1.9 Driftwood pipeline(3) $ 2.2 HGAP $ 1.4 PGAP $ 3.7 Upstream $ 2.2 Fees(4) $ 0.9 Interest during construction $ 7.5 Total capital $ 35.0 Total capital ($ per tonne) $ 1,270 Debt financing(5) $ (20.0) Pre-COD cash flows(6) $ (7.0) Net partners’ capital $ 8.0 Transaction price ($ per tonne) $500 Capacity split mtpa % % Partner 16.0 58% 58% Tellurian 11.6 42% 42% Notes: (1) Based on engineering, procurement, and construction agreements executed with Bechtel. (2) Approximately half of owners’ costs represent contingency; the remaining amounts consist of cost estimates related to staffing prior to commissioning, estimated impact of inflation and foreign exchange rates, spare parts and other estimated costs. (3) Represents estimated costs of development of Driftwood pipeline in phases. (4) Preliminary estimate of certain costs associated with potential management fee to be paid by Driftwood Holdings to Tellurian and certain transaction costs. (5) Project finance debt to be borrowed by Driftwood Holdings. (6) Cash flows prior to commercial operations date of Plant 5.

Driftwood Holdings’ operating costs Project details Sources: Wood Mackenzie, 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 or to market. (3) Based on debt service cost of principal and interest related to ~$20.0 billion of project finance debt. 20 (1) (2) (3) $0.88 $2.25 $3.00 $4.50 $0.36 $0.75 $1.50 $0.79 $0.22 Drilling & completion Operating Gathering, processing & transportation Contingency Delivered Liquefaction Total variable & operating Debt FOB $/ mmBtu

Margins and price signals Project details Netback prices to the Gulf Coast(1) Sources: Platts, CME, Tellurian Research. Notes: (1) Forward prices for 2018 assuming $2.91/mmBtu shipping cost from USGC to East Asia using Platts JKM. (2) Platts Gulf Coast Marker, month-to-date as of December 20, 2018. 21 2018 JKM forward strip up $2.46 since November 2017 Avg. Cal 2018 JKM +25% since Nov-17 Dec 2018 GCM(2) 20 December 2018: $6.42/mmBtu 2013 2014 2015 2016 2017 2018 $/mmBtu ~$4.50/mmBtu $/mmBtu Nov-17 Mar-18 2018 ‘19 Dec-18 $5 $6 $7 $8 $9 $10 $11 $12 Q1 Q2 Q3 Q4 $- $5 $10 $15 $20 Jan Jul Jan Jul Jan Jul Jan Jul Jan Jul Jan Jul Jan

Returns to Driftwood Holdings’ partners Project details 22 U.S. Gulf Coast netback price ($/mmBtu) $6.00 $8.00 $10.00 $15.00 Driftwood LNG, FOB U.S. Gulf Coast ($/mmBtu) $(4.50) $(4.50) $(4.50) $(4.50) Margin ($/mmBtu) 1.50 3.50 5.50 10.50 Annual partner cash flow(1) ($ millions per tonne) 80 180 290 550 Cash on cash return(2) 16% 36% 57% 109% Payback(3) (years) 6 3 2 1 Notes: (1) Annual partner cash flow equals the margin multiplied by 52 mmBtu per tonne. (2) Based on 1 mtpa of capacity in Driftwood Holdings; all estimates before federal income tax; does not reflect potential impact of management fees paid to Tellurian. (3) Payback period based on full production.

USGC netback ($/mmBtu) Margin(1) ($/mmBtu) 2 Plants 5 Plants Annual cash flows(2) ($ millions) Cash flow per share(3) ($/share) Annual cash flows(2) ($/millions) Cash flow per share(3) ($/share) $ 6.00 $ 1.50 $ 235 $ 0.95 $ 905 $ 3.66 $ 8.00 $ 3.50 $ 545 $ 2.21 $2,110 $ 8.55 $10.00 $ 5.50 $ 860 $ 3.47 $3,320 $13.43 $15.00 $10.50 $1,640 $ 6.63 $6,335 $25.64 Value to Tellurian Inc. Project details 23 Notes: (1) $4.50/mmBtu cost of LNG FOB Gulf Coast. (2) Annual cash flow equals the margin multiplied by 52 mmBtu per tonne; does not reflect potential impact of management fees paid to Tellurian nor G&A. (3) Represents the fully diluted cash flow per share based on total outstanding shares of 241 million in common stock and 6 million shares of preferred stock as converted.

Additional detail 24 Additional detail

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. Based on line of sight supply through 2020. Global commodity requires low-cost solutions 25 Additional detail Legend LNG carrier – laden LNG carrier – unladen Bcf of LNG storage # of LNG vessels # of cargoes loaded per day LNG Storage - 2018 Japan + Korea terminals: 697 Bcf LNG vessels: 821 Bcf 15 18 2018 2020 517 609 821 967 2018 2020

Owning pipeline infrastructure mitigates basis risk Additional detail 26 Tolling model SPA model Equity model Customer incurs risk Competition between customers for pipeline access leads to hidden costs and higher cost of LNG on the water Developer incurs risk Developer consolidates pipeline transport, but still a price taker for transportation services; developer only has 5% of Henry Hub price to pay for transport Own the infrastructure True cost control and transparency from owning and managing pipeline transportation

Building a low-cost global gas business 27 Additional detail June Raise approximately $115 million in public equity March Bechtel invests $50 million in Tellurian Feb/March Announce open seasons for Haynesville Global Access Pipeline and Permian Global Access Pipeline December Raise approximately $100 million in public equity November Acquire Haynesville acreage, production and ~1.4 Tcf Execute LSTK EPC contract with Bechtel for ~$15 billion June Bechtel, Chart Industries and GE complete the front-end engineering and design (FEED) study for Driftwood LNG February Merge with Magellan Petroleum, gaining access to public markets January TOTAL invests $207 million in Tellurian December GE invests $25 million in Tellurian April Management, friends and family invest $60 million in Tellurian 2016 2017 2018 September Driftwood LNG receives Draft Environmental Impact Statement (DEIS) from FERC December Announced MOU for 1.5 mtpa for 15 years with Vitol, based on Platts JKM

Funding and ownership Sources (1) ($ millions) Notes: (1) As of December 26, 2018. (2) Excludes 6.1 million preferred shares outstanding. 28 Ownership(1)(2) (%) $576 million 241 million shares Additional detail Total 19% C. Souki 23% M. Houston 10% M. Gentle 5% Officers and directors 5% Free Float 38%

Driftwood vs. competitors – cost per tonne Sources: Wood Mackenzie, The World Bank, Tellurian Research. Note: (1) Based on full development of Driftwood Holdings, inclusive of debt service cost. (2) LNG Canada’s cost per tonne is inclusive of TransCanada’s capex estimate for Coastal GasLink . (3) 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. 29 Capacity, mtpa 14.0 27.6 31.2 10.0 16.5 9.0 15.6 9.0 8.9 LPI global ranking(3): 4.0 3.6 2.7 2.6 3.9 3.8 3.8 3.8 3.8 Additional detail (1) (2)

Integrated model prevalent internationally Source: IHS. 30 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 Additional detail

Site characteristics determine long-run costs Additional detail 31 Access to power and water Berth over 45’ depth with access to high seas Support from local communities Access to pipeline infrastructure Site size over 1,000 acres Insulated from surge, wind, and local populations Artist rendition

Key terms of EPC agreements with Bechtel Additional detail 32 Trains 8 4 4 4 20 Storage facilities 2 0 1 0 3 Berths 1 1 1 0 3 Phase 1 Phase 2 Phase 3 Phase 4 Total 11.0 5.5 5.5 5.5 27.6 Capacity $700 per tonne $490 $500 $380 ~$550

Construction budget breakdown Additional detail Notes: Based on Driftwood LNG full development. (1) Includes additional contingency by developer and staffing prior to commencement of operations. (2) Provisional sum includes escalation factor for inflation, insurance, foreign exchange, and other costs. 33 24% 24% 24% 12% 17% (2) (1)

Driftwood Holdings’ financing Additional detail 34 2-Plant Case 3-Plant Case Full Development Capacity (mtpa) 11.0 16.6 27.6 Capital investment ($ billions) Liquefaction terminal(1) $ 7.6 $ 10.3 $ 15.2 Owners’ cost & contingency(2) $ 1.1 $ 1.5 $ 1.9 Driftwood pipeline(3) $ 1.1 $ 1.5 $ 2.2 HGAP(3) $ - $ - $ 1.4 PGAP(3) $ - $ 3.7 $ 3.7 Upstream $ 2.2 $ 2.2 $ 2.2 Fees(4) $ - $ 0.9 $ 0.9 Interest during construction $ 2.5 $ 4.5 $ 7.5 Total capital $ 14.5 $ 24.6 $ 35.0 Total capital ($ per tonne) $ 1,320 $ 1,480 $ 1,270 Debt financing(5) $ (8.0) $(15.0) $ (20.0) Pre-COD cash flows(6) $ (2.5) $ (3.6) $ (7.0) Net equity $ 4.0 $ 6.0 $ 8.0 Transaction price ($ per tonne) $ 500 $ 500 $ 500 Capacity split mtpa % mtpa % mtpa % % Partner 8.0 ~73% 12.0 ~72% 16.0 ~58% 58% Tellurian 3.0 ~27% 4.6 ~28% 11.6 ~42% 42% Notes: (1) Based on engineering, procurement, and construction agreements executed with Bechtel. (2) Approximately half of owners’ costs represent contingency; the remaining amounts consist of cost estimates related to staffing prior to commissioning, estimated impact of inflation and foreign exchange rates, spare parts and other estimated costs. (3) Represents estimated costs of development of Driftwood pipeline in phases, HGAP and PGAP. (4) Preliminary estimate of certain costs associated with potential management fee to be paid by Driftwood Holdings to Tellurian and certain transaction costs. (5) Project finance debt to be borrowed by Driftwood Holdings. (6) Cash flow prior to commercial operations date of Plant 2, Plant 3, and Plant 5 in the 2-Plant, 3-Plant, and full development cases, respectively.

Corpus Christi LNG and Driftwood LNG examples Additional detail Sources: Cheniere Analyst Day presentation (2018) and Tellurian analysis. Notes: (1) Includes approximately $0.4 billion in costs for additional compression on Driftwood pipeline in 3-plant case. (2) For Corpus Christi LNG, combined owners’ costs and contingency from page 18 of Cheniere Analyst Day presentation. For Driftwood LNG, half of owner’s costs represent contingency; the remaining amounts consist of estimated costs related to staffing prior to commissioning, estimated impact of inflation and foreign exchange rates, spare parts and other estimated costs associated with the 3-plant case presented on slide 34. (3) Assuming 70% debt at 6% interest and 30% equity at a 10% return for $1,000 per tonne over 5 years. 35 ($ billions) Corpus Christi LNG Driftwood LNG T1-2 T3 T1-3 Plants 1-3 Capacity (mtpa) 9.0 4.5 13.5 16.6 EPC $7.8 $2.4 $10.2 $10.3 Pipeline $0.4 $0.0 $ 0.4 $ 1.5(1) Owners’ cost, contingency & fees(2) $1.4 $0.5 $ 1.9 $ 2.4 Total cost $9.6 $2.9 $12.5 $14.2 Unlevered cost ($ per tonne) $1,070 $645 $925 $860 Does not include G&A to manage the project Cost of financing is ~$300-$400 per tonne(3) Delays cost $150 per tonne per year

LNG projects require supply optionality Additional detail Sources: IHS, DrillingInfo, EIA, Tellurian analysis. 36 10 mtpa plant with 1.5 bcf/d feedgas requirement stresses basin supply

Production Company strategy 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 has ~10,800 net acres in the Haynesville shale Primarily located in De Soto and Red River parishes Acreage is ~90% HBP (held by production) ~85% operated 100% gas Net production – ~3.3 mmcf/d Operated producing wells – 20 Total net resource – ~1.4 Tcf or ~10% of total resource required for Phase 1 Goldman Sachs funded $60 million in September 2018 to support operated and non-operated drilling activity Additional detail Objectives Current assets(1) 37 Note: (1) As of September 30, 2018.

13 Bcf/d 4 4 7 1 3 U.S. natural gas needs global market access Additional detail 38 13 Bcf/d of incremental production; associated gas at risk of flaring without infrastructure investment Sources: EIA; ARI; Tellurian analysis. Note: (1) $1,000 per tonne average. LNG export capacity required: At least 100 mtpa: 13 Bcf/d (19 Bcf/d less ~6 under construction) ~$100 billion(1) Pipeline capacity required: Around 19 Bcf/d ~$70 billion LNG liquefaction terminal Operating/under construction Future Export capacity 19 Total estimated 2018-2025 production growth, Bcf/d Required future investment: ~$170 billion Up to 13 Bcf/d export capacity

PGAP connects constrained gas to SWLA Additional detail Takeaway constraints in the Permian Southwest Louisiana demand Sources: Company data, Goldman Sachs, Wells Fargo Equity Research, RBN Energy, Tellurian estimates. Notes: (1) LNG demand based on 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. 39 Louisiana Texas Gulf of Mexico Gillis, LA Eunice, LA Driftwood LNG Cameron LNG Sabine Pass LNG Southwest Louisiana firm demand(1)(2) (bcf/d) North Mexico East West Permian production 4 12 2017 2024