8-K

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): June 12, 2018

Tellurian Inc.

(Exact name of registrant as specified in its charter)

Delaware	001-5507	06-0842255
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)
1201 Louisiana Street, Suite 3100, Houston, TX		77002
(Address of principal executive offices)		(Zip Code)

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:

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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.  ☐

Item 7.01 Regulation FD Disclosure.

On June 12, 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.

Item 9.01 Financial Statements and Exhibits.

(d)    Exhibits.

Exhibit No.	Description
99.1	Tellurian Inc. Corporate Presentation dated June 2018

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.

TELLURIAN INC.
By:	/s/ Antoine J. Lafargue
Name: Title:	Antoine J. Lafargue Senior Vice President and Chief Financial Officer

Date: June 12, 2018

EX-99.1

Corporate presentation June 2018 Exhibit 99.1

Disclaimer

Business model Driftwood assets Market fundamentals Additional detail Contents

Global call on U.S. natural gas Business model U.S. supply push… …and global demand pull Source: Wood Mackenzie, Tellurian Research. Notes:(1) Includes the Permian, Haynesville, Utica, Marcellus, Anadarko, Eagle Ford. (2) Based on a demand growth estimate of 4.5% post-2020. (3) Capacity required to meet demand growth post-2020. 51 71 20 46 75 Bcf/d Output from selected shale basins(1) mtpa Global LNG production capacity mtpa Takeaway infrastructure Required Under construction Other U.S. Supply infrastructure Required(3) 29 (2) 150 Under construction 221

Building a low-cost global gas business Business model Pipeline Liquefaction Marketing Upstream 11,620 acres in the Haynesville with 1.4 Tcf resource ~$7 billion(1) of pipeline infrastructure projects in development ~$15 billion of liquefaction infrastructure in development International delivery of LNG cargoes started in 2017 Driftwood Holdings partnership – integrated, low-cost Note: (1) HGAP and PGAP projects are in early stages and remain under review.

Tellurian’s differentiating factors Business model Management track record at Cheniere and BG Group 45% 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 permits will be received by January 2019 Integrated: Upstream reserves Pipeline network LNG terminal LNG delivered FOB U.S. Gulf Coast at $3.00/mmBtu World class partners Fixed cost EPC contract Regulatory certainty Experienced management Unique business model

Tellurian will offer equity interest in Driftwood Holdings Driftwood Holdings will consist of a Production Company, a Pipeline Network and an 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) Business model Tellurian Marketing Pipeline Network Production Company Equity ownership ~40% ~16 mtpa ~12 mtpa Customer/Partner ~60% Customers 100% Business model Nasdaq: TELL LNG Terminal Tellurian will retain ~12 mtpa and ~40% of the assets Estimated ~$2 billion annual cash flow to Tellurian Driftwood Holdings

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) Pipeline asset funding to be reviewed following results of open season; illustrative financials include Driftwood pipeline only. (4) For Phase 1, drilling capital expenditures of $3.4 billion, net of $2.2 billion of gas sales. Scenario Phase 1(1) Full development(1) Capacity (mtpa) 11.0 27.6 Upstream resource need(2), Tcf ~15 ~40 Investment ($ billions) Terminal $ 7.6 $ 15.2 Pipeline(3) $ 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)(4) $ 1.2 $ 2.5 Total $ 12.0 $ 24.0 Transaction price ($ per tonne) $1,500 $1,500 Capacity split mtpa % mtpa % Partner 8.0 72% 16.0 58% Tellurian 3.0 28% 11.6 42% Business model Driftwood Holdings’ construction budget

Driftwood Holdings’ operating costs Business model Total cost of ~$3/mmBtu locks in low cost of supply 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 to market. Upstream cost $/mmBtu Liquefaction cost (1) (2)

Margins and price signals Business model Netback prices to the Gulf Coast(1) Sources: Platts, CME, Tellurian Research. Notes: (1) Forward prices for 2018 assuming $1.79/mmBtu shipping cost from USGC to East Asia using Platts JKM. (2) Platts Gulf Coast Marker. 2018 JKM forward prices up $3.40 since September 2017 Avg. 2018 JKM price up 54% since Sept-17 July 2018 GCM(2) 5 June 2018: $8.41/mmBtu 2013 2014 2015 2016 2017 2018 Q1 Q2 Q3 Q4 2018 $/mmBtu $/mmBtu

Returns to Driftwood Holdings’ partners(1) Business model U.S. Gulf Coast netback price ($/mmBtu) $6.00 $10.00 $15.00 Driftwood LNG, FOB U.S. Gulf Coast $(3.00) $(3.00) $(3.00) Margin ($/mmBtu) 3.00 7.00 12.00 Annual partner cash flow ($ millions)(2) 156 364 624 Cash on cash return 10% 24% 42% Payback (years)(3) 10 4 2 Unlevered IRR(4) 9% 18% 26% Notes:(1) 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. (2) Annual partner cash flow equals the margin multiplied by 52 mmBtu per tonne. (3) Payback period begins at substantial completion of Driftwood LNG terminal. (4) 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% based on a $1.5 billion investment in exchange for 1 mtpa of capacity.

Value to Tellurian Inc. Business model Notes: (1) $3.00/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) Includes Seaport Global, Stifel, Cowen and Tuohy Brothers estimates. (4) Calculated by multiplying total capacity retained by Tellurian in each phase by $1,500 per tonne, discounting at a rate of 10% for one year and dividing by total number of shares outstanding (228 million as of May 4, 2018 plus 6 million preferred shares). (5) As of June 5, 2018. USGC netback ($/mmBtu) Margin(1) ($/mmBtu) Phase 1(2) Full development(2) Annual cash flows ($ millions) $ 6.00 $10.00 $15.00 $ 3.00 $ 7.00 $12.00 $ 470 $1,090 $1,870 $1,810 $4,220 $7,240 Analyst estimates, NAV and trading range Cash flow analysis (5) (4) (3) Phase 1 Full development $ per share

Marketing process – Driftwood Holdings Business model Activity 2018 Q1 Q2 Q3 Q4 Launch marketing Narrow candidates Negotiate agreements ~25 customer/partners in data room Feb 15 Commercialize Phase 1 by Q3 or Q4 2018

A global LNG demand pull has coincided with a supply push from the U.S., signaling the need for additional liquefaction capacity Tellurian’s business model provides investors with access to the U.S. integrated gas value chain, delivering low-cost, flexible LNG globally Experienced management and strategic partners Consistently executing on timeline of development Significant near-term equity upside Conclusions Business model

Business model Driftwood assets Market fundamentals Additional detail Contents

Driftwood LNG terminal Note:(1) Engineering, procurement and construction costs 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 EPC Cost ~$550 per tonne ~$15.2 billion(1) Artist rendition Driftwood LNG

Regulatory and cost certainty Driftwood LNG Regulatory schedule clarity Guaranteed lump sum turnkey contract with Bechtel 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 11.0 27.6 $ per tonne mtpa

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 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 net production – 4 mmcf/d Operated producing wells – 19 Identified development locations – ~178 Total net resource – ~1.4 Tcf or ~10% of total resource required for Phase 1 Upstream Objectives Current assets

>100 Tcf available resources in Haynesville Upstream Sources: IHS Enerdeq; 1Derrick; investor presentations; Tellurian research. Note: (1) Estimated resources based on acreage. 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

Pipeline network Notes: (1) Included in Driftwood Holdings. (2) Currently not included in Driftwood Holdings illustrative financials (slides 7, 8, 9, 11 and 12); commercial and regulatory in progress and financial structuring under review. Pipeline network Driftwood Pipeline(1) Capacity (Bcf/d) 4.0 Cost ($ billions) $2.2 Length (miles) 96 Diameter (inches) 48 Compression (HP) 274,000 Status FERC approval pending Haynesville Global Access Pipeline(2) Capacity (Bcf/d) 2.0 Cost ($ billions) $1.4 Length (miles) 200 Diameter (inches) 42 Compression (HP) 23,000 Status Open season: 2/21/18 Permian Global Access Pipeline(2) Capacity (Bcf/d) 2.0 Cost ($ billions) $3.7 Length (miles) 625 Diameter (inches) 42 Compression (HP) 258,000 Status Open season: 3/20/18 Bringing low-cost gas to Southwest Louisiana 1 2 3 1 2 3

Business model Driftwood assets Market fundamentals Additional detail Contents

Demand pull Global LNG Demand outlook Sources: Wood Mackenzie, Tellurian Research. Notes:(1) Assumes 85% utilization rate. (2) Based on assumption that LNG demand grows at 4.5% p.a. post-2020. 127 mtpa of new liquefaction capacity required by 2025(1) mtpa Under construction In operation Demand(2) 107 mtpa

13 Bcf/d 6 1 8 1 4 U.S. natural gas needs global market access Global LNG 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 (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 20 Total estimated 2017-2025 production growth, Bcf/d Required future investment: ~$170 billion Up to 13 Bcf/d export capacity

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. Deeper physical liquidity from infrastructure 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:751 Bcf

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

2018 Pipeline open seasons $50 million $25 million $60 million $207 million Merger $100 million Upstream acquisition LSTK April December January February June November December Feb/March March Management, friends and family invest $60 million in Tellurian GE invests $25 million in Tellurian TOTAL invests $207 million in Tellurian Merge 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 Acquire Haynesville acreage, production and ~1.4 Tcf Execute LSTK EPC contract with Bechtel for ~$15 billion Raise approximately $100 million public equity Announce open seasons for Haynesville Global Access Pipeline and Permian Global Access Pipeline Bechtel invests $50 million in Tellurian 2017 2016 Building a low-cost global gas business Additional detail

Funding and ownership Additional detail Sources (1) ($ million) Note:(1) As of April 2018. Ownership(1) (%) $467 million 228 million shares

Driftwood vs. competitors – cost per tonne Sources:Wood Mackenzie, The World Bank, Tellurian Research. Note:(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 Additional detail

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 Additional detail

Driftwood schedule Additional detail Note:(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 Months (1) (1) (1)

Key terms of EPC agreements with Bechtel Additional detail 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

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

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. 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

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