Corporate presentation October 2018 Exhibit 99.1
Recent updates Recent Updates
Driftwood financing update Recent updates Introducing levered structure Provides Partners with lower equity investment and non-consolidated debt Reduces equity investment to $500 per tonne Driftwood to deliver LNG to Partners for ~$3.00/mmBtu operating cost plus ~$1.50/mmBtu pass through of debt service costs Competitive & low-cost Driftwood total cost of LNG plant, 1,000 miles of pipelines, and upstream gas production: $28 billion (~$1,000 per tonne) Low-cost LNG delivery: ~$4.50/mmBtu FOB Catalyst Estimated timeline Final Environmental Impact Statement 18 January 2019 Driftwood final investment decision 1H 2019 Begin construction 1H 2019 Begin operations 2023 First LNG delivered to Partners 2024 Driftwood schedule
Driftwood Holdings’ levered structure Recent updates Notes:(1) In Equity structure case, debt service is shown net of revenue from third-party pipeline shippers. (2) FOB cost reflects $1.50/mmBtu debt service cost in Levered structure. (3) Based on assumed U.S. Gulf Coast margin of $3.32/mmBtu, TELL’s retained capacity of 11.6 mtpa, and 52 mmBtu per tonne. See slide 20 for estimated annual Tellurian cash flow at various assumed U.S. Gulf Coast netback prices and margin levels. Based on Full Development (5 plants) Equity structure Levered structure Project capacity (mtpa) 27.6 27.6 Partners’ equity ($ billion) $24 $8 Investment ($ per tonne) $1,500 $500 Project debt ($ billion) ~$3.5 ~$20 Operating & variable cost ($/mmBtu) $3.00 $3.00 Debt service ($/mmBtu)(1) $0.00 $1.50 LNG cost delivered FOB ($/mmBtu)(2) $3.00 $4.50 TELL’s interest (mtpa/%) ~12 mtpa ~40% ~12 mtpa ~40% TELL’s expected annual cash flows ($ billion)(3) $2 $2
Debt(5) Equity contribution IDC(6) Pre-COD cash flows(7) Lique- faction(1) Owner’s costs(2) Driftwood Holdings’ financing Recent updates Equity structure (previous) $ billions Levered structure (current) $ billions 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 network 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) Represents interest during construction. (7) Cash flows prior to commercial operations date of Plant 5. Equity contribution Pipelines(3) Upstream Fees(4) Full Development Lique- faction(1) Owner’s costs(2) Pipelines(3) Upstream Fees(4) Debt(5) Total capital uses: $35 billion Total capital uses: $28 billion
Core presentation Core presentation
Global call on U.S. natural gas Fundamentals U.S. supply push… …and global demand pull Source: Wood Mackenzie, Tellurian Research. Notes:(1) Includes the Permian, Haynesville, Utica, Marcellus, Anadarko, and Eagle Ford. (2) Based on an annual demand growth estimate of 4.5% post-2020 for low case and 9.6% annual growth rate for high case (same as observed 2015-2020 growth). (3) Capacity required to meet demand growth post-2020 estimated to be 107-294 mtpa. (4) Includes projects that have gone into service during 2018, including Cameroon FLNG, Cove Point LNG, Wheatstone T2, and Yamal T1. Output from selected shale basins(1) mtpa Global LNG production capacity mtpa Takeaway infrastructure Required Under construction Other U.S. Supply infrastructure 107-259 mtpa required post 2020(3) (2) 113 mtpa under construction(4) Bcf/d 51 71 20 Bcf/d 46 75-95 29-49 150 716 220-372
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 Fundamentals 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
Basin 11,620 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 Business model Construction ~$15 billion liquefaction project in Louisiana
Driftwood LNG terminal Note:(1)Based on engineering, procurement, and construction agreements executed with Bechtel. 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 ~$15.2 billion(1) Artist rendition Driftwood LNG
Pipeline network Note: (1)Included in Driftwood Holdings at full development; commercial and regulatory processes in progress and financial structuring under review. Pipeline network Driftwood Pipeline(1) Capacity (Bcf/d) 4.0 Cost ($ billions) $2.2 Length (miles) 96 Diameter (inches) 48 Compression (HP) 274,000 Status FERC approval pending Haynesville Global Access Pipeline(1) Capacity (Bcf/d) 2.0 Cost ($ 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 Upstream resource 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
Expecting to eliminate HH price risk Business model Source:CME via MarketView. 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:
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 interest and amortization Tellurian Tellurian will retain ~12 mpta and ~40% of the assets Estimated $2 billion annual cash flow to Tellurian(1) Business model Tellurian Marketing Pipeline Network Production Company Equity ownership ~40% ~16 mtpa ~12 mtpa Partners (~$8 billion in equity) ~60% Partners 100% Business model LNG Terminal Driftwood Holdings (~$20 billion in project finance debt) Note:(1)See slide 20 for estimated annual Tellurian cash flow at various assumed U.S. Gulf Coast netback prices and margin levels.
Driftwood Holdings’ financing Business model Full Development Capacity (mtpa) 27.6 Capital investment ($ 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 Business model 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. (1) (2) (3)
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 $2.91/mmBtu shipping cost from USGC to East Asia using Platts JKM. (2) Platts Gulf Coast Marker. 2018 JKM forward strip up $2.33 since November 2017 Avg. Cal 2018 JKM +38% since Nov-17 Oct 2018 GCM(2) 19 October 2018: $8.29/mmBtu 2013 2014 2015 2016 2017 Q1 Q2 Q3 Q4 2018 $/mmBtu ~$4.50/mmBtu $/mmBtu Sep-18 Nov-17 Mar-18 2018 ‘19
Returns to Driftwood Holdings’ partners Business model U.S. Gulf Coast netback price ($/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. Business model 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.
Marketing process – Driftwood Holdings Marketing process Activity 2018 Q1 Q2 Q3 Q4 Launch marketing Narrow candidates Negotiate agreements ~35 customers/partners in data room Feb 15 Commercialization by Q4 2018
Tellurian differentiated to provide value Conclusion 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 email@example.com Joi Lecznar SVP, Public Affairs & Communication +1 832 962 4044 firstname.lastname@example.org Contacts @TellurianLNG
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Demand pull Additional detail Demand outlook Sources: Wood Mackenzie, Tellurian Research. Notes:(1) Assumes 85% utilization rate. (2) Based on assumption that LNG demand grows at 4.5%-9.6% p.a. post-2020. 107-259 mtpa of new liquefaction capacity required by 2025(1) mtpa Under construction In operation Demand(2) 91-220 mtpa potential growth
Owning pipeline infrastructure mitigates basis risk Additional detail 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 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 $60 million in Tellurian 2016 2017 2018 September Driftwood LNG receives Draft Environmental Impact Statement (DEIS) from FERC
Funding and ownership Sources (1) ($ millions) Notes:(1) As of August 1, 2018. (2) Excludes 6.1 million preferred shares outstanding. Ownership(1)(2) (%) $576 million 241 million shares Additional detail
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. 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. 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 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 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
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. 24% 24% 24% 12% 17% (2) (1)
Driftwood Holdings’ financing Additional detail 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 cost estimated 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 $1,000 per tonne over 5 years. ($ 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. 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 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 Goldman Sachs funded $60 million in September 2018 to fund operated and non-operated drilling activity Additional detail Objectives Current assets
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
13 Bcf/d 4 4 7 1 3 U.S. natural gas needs global market access Additional detail 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. 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