Forward looking statements
The information in this presentation includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact are forward-looking statements. The words anticipate, assume, believe, budget, estimate, expect, forecast, initial, intend, may, plan, potential, project, should, will, would, and similar expressions are intended to identify forward-looking statements. The forward-looking statements in this presentation relate to, among other things, future contracts, contract terms and margins, our business and prospects, future costs, prices, financial results, liquidity and financing, regulatory and permitting developments, future demand and supply affecting LNG and general energy markets and the closing of, and the achievement of anticipated benefits from, our natural gas property acquisition.
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to numerous known and unknown risks and uncertainties, which may cause actual results to be materially different from any future results or performance expressed or implied by the forward-looking statements. These risks and uncertainties include those described in the Risk Factors section of Exhibit 99.1 to our Current Report on Form 8-K/A filed with the Securities and Exchange Commission (the SEC) on March 15, 2017 and other filings with the SEC, which are incorporated by reference in this presentation. Many of the forward-looking statements in this presentation relate to events or developments anticipated to occur numerous years in the future, which increases the likelihood that actual results will differ materially from those indicated in such forward-looking statements. In addition, the acquisition, exploration and development of natural gas properties involve numerous risks and uncertainties, including the risks that we will assume unanticipated liabilities associated with the assets to be acquired and that the performance of the assets will not meet our expectations due to operational, geologic, regulatory, midstream or other issues. It is possible that the acquisition will not be completed on the terms or at the time expected, or at all.
The forward-looking statements made in or in connection with this presentation speak only as of the date hereof. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws.
Non-GAAP financial measures
This presentation contains information about projected EBITDA of Tellurian. EBITDA is not a financial measure determined in accordance with U.S. generally accepted accounting principles (GAAP), should not be viewed as a substitute for any financial measure determined in accordance with GAAP and is not necessarily comparable to similarly titled measures reported by other companies. It would not be possible without unreasonable efforts to reconcile the projected non-GAAP information presented herein to net income, the most directly comparable GAAP financial measure. Similarly, projected future cash flows as set forth herein may differ from cash flows determined in accordance with GAAP.
Reserves and resources
Estimates of non-proved reserves or resources are based on more limited information, and are subject to significantly greater risk of not being produced, than proved reserves.
low-cost global natural gas business
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
Announced acquisition of natural gas production and undeveloped acreage in the Haynesville
The global LNG market is in transition
Steady demand growth from non-traditional markets
Increasingly flexible commercial structures
Revocation of destination restrictions
Emerging LNG price indices
Growing gas-on-gas competition
4 Global LNG
Daily supply readily available across the globe
18 cargoes loaded every day in 2020 to satisfy 50 Bcf/d of demand
# of Atlantic Basin
# of Pacific Basin
# of Middle East
Source: Wood Mackenzie
Note: Average cargo size c. 2.9 Bcf, assuming 150,000 m3 ship.
In 2017, approximately a third of all LNG cargoes are estimated to be spot volumes.
Assumes 12% per annum. demand growth.
5 Global LNG
Global LNG on the water
# of ships Gas storage on LNG vessels Storage
# ships Total storage on water
Japan + Korea terminals: 633 Bcf
LNG vessels: 686 Bcf
LNG carrier laden LNG carrier unladen
Sources: Kpler, Maran Gas, IHS.
Note: LNG storage assumes half of fleet is in ballast, 2.9 Bcf capacity per vessel.
6 Global LNG
New liquefaction capacity required
Accelerated demand growth driven by low LNG prices
LNG demand growth (1)
2017 effective capacity(4) utilization >98%
LNG capacity utilization (2)
Emerging indices provide forward transparency Netback prices to the Gulf Coast (3)
Netback to Europe Netback to Asia Platts Gulf Coast Marker
2014 2015 20161H20172015201620172018201920202021
Sources: ICE via Marketview, (1) Kpler, (2) Wood Mackenzie, (3) Platts and Tullet Prebon, Fearnleys, Tellurian Research.
Notes: (4) Effective capacity is defined as total capacity less unplanned outages and gas constraints. Implied utilization rates assume demand growth of 12% per annum.
7 Global LNG
Building a low-cost globalgas business
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 Less than $600 per tonne
Develop suite of flexible LNG products Build out risk management and operational infrastructure LNG trade entry in 2017
Acquiring 9,200 net acres with up to 138 drilling locations in Haynesville
Delivered gas cost $2.25/mmBtu
FERC permit pending
~27.6 mtpa Driftwood LNG terminal FEED complete Fixed fee construction contract under negotiation FERC permit pending
Experienced global marketing team Offices in Houston, Washington D.C., London, and Singapore
8 Business model
New business model
Tellurian will offer equity interest in Driftwood Holdings
Driftwood Holdings will consist of Tellurian Production, Driftwood pipeline and Driftwood LNG terminal (~27.6 mtpa)
Equity will cost ~$1,500 per tonne
Investors 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 11 mtpa
Tellurian will manage and operate the project
Driftwood LNG terminal
9 Business model
Potential margin capture from new business model
Full cycle cost of gas delivered to market
Cost through the LNG plant
Cost of LNG FOB U.S. GC before equity return
$4.50 18/ mmBtu
Range of GC netbacks
Oct GCM 22nd Sept 2017: $6.60/mmBtu
$1.50 15/ mmBtu
Range of Tellurian margin capture
Oct implied margin: $3.60/mmBtu
$20 $15 $10 $5 0
10 Business model
Liquefaction capacity ~27.6 mtpa
Tellurian retained capacity ~711 mtpa
Realized price (FOB Platts Gulf Coast $6.60/mmBtu
Delivered gas cost(Gulf Coast) $3.00/mmBtu
2027 Tellurian equity cash flow ($ millions)
Tellurian Equity LNG Netback prices ($/mmBtu)
retained % (mtpa) $4.50$6.00$8.00
30% 8.2 $400$800$1,300
35% 9.6 $750$1,400$2,300
40% 11.0 $900$1,700$2,700
11 Business model
Tellurian Production objectives
Experienced upstream team joined in May 2017
Acquire and develop long life, low-cost natural gas resources
Low geological risk
Production of 1.5 Bcf/d starting in 2022
Total resources of ~15 Tcf
Low operating costs
Flexible development terms
Focused on Haynesville and Eagle Ford basins
12 Tellurian Production
Tellurian signed a PSA with a private seller to purchase 9,200 net acres in the Haynesville shale for $85.1 million
Haynesville acreage provides low development risk, favorable economics and close proximity to significant demand growth
Target is to deliver gas for $2.25/mmBtu
Located in De Soto and Red River parishes 100% HBP
92% operated 100% gas
Current production 4 mmcf/d Operated producing wells 19
Identified development locations ~138 Total net resource ~1.3 tcf
13 Tellurian Production
Haynesville type curve comparison
Comparative type curve statistics
Tellurian Peer A Peer BPeer CPeer D
Type curve detail
NLANLA core /
De Soto / North blended
Area De SotoDe Soto
Red River Louisiana development
Completion (lbs. / ft.) - 4,0003,8002,7003,000
Single well stats
Lateral length (ft.) 6,950 7,5007,5004,5009,800
Gross EUR (Bcf) 15.5 18.818.69.919.9
EUR per 1,000 ft. (Bcf) 2.2 2.502.482.202.03
Gross D&C ($ million) $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
B-Tax IRR (%)(2) 43% 60%90%+54%-
Cumulative production normalized to 7,500(3)
5.0 Peer A
0 30 60 90 120 150 180 210 240 270 300
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)).
14 Tellurian Production
Driftwood LNG terminal and pipeline
Driftwood LNG terminal Land Capacity Trains
Driftwood pipeline Size Capacity
~1,000 acres near Lake Charles, LA ~27.6 mtpa(1) Up to 20 trains of ~1.38 mtpa each Chart heat exchangers GE LM6000 PF+ compressors 3 storage tanks 235,000 m3 each 3 marine berths
~$500 600 per tonne
~4 Bcf/d avg. throughput Access ~35 Bcf/d flowing gas
Notes: (1) Estimate, subject to further engineering evaluation.
(2) Excludes owners costs, financing costs and contingencies.
15 Driftwood LNG
The cost of Gulf Coast greenfield LNG projects are amongst the lowest quartile projects globally
Cost $/tonne(1) $2,500
$2,000 $1,500 $1,000 $500 $-
~27.6 mtpa capacity
Capacity mtpa 30
25 20 15 10 5
Sources: Wood Mackenzie (Q4 2016), Tellurian Research.
Notes: (1) Includes owners costs and contingencies and excludes financing and pipeline related costs.
(2) Estimates of berth and storage/tank facilities.
(3) Estimated increase in costs tied to EPC as per 2Q17 CB&I earnings call.
16 Driftwood LNG
Plan to enter LNG Marketing business in 2017
Expect initial participation in LNG trade through short-term charter arrangements
Continue build out of risk management and operational capabilities
17 LNG Marketing
Tellurians integrated model to deliver low cost LNG globally
LNG demand is growing at 12% per annum
The U.S. is best positioned to meet these supply needs with access to abundant low-cost gas and a track record of building low-cost liquefaction
Netback LNG prices to the U.S. Gulf Coast of > $5.50/mmBtu have signaled that additional liquefaction capacity is needed
Artists rendition of Driftwood LNG
19 Artists rendition
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