PGAPPermian Global Access

Pipeline

Tellurian Midstream Group | April 2018

Cautionary 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.

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 resourcesEstimates 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.

Non-GAAP financial measuresForward looking statements

2

Who we are

Building a low-cost global gas business

4

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 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)

▪ Tellurian will manage and operate the project

Business model

5

Tellurian

Marketing

Pipeline

Network

Production

Company

Equity ownership ~40%

~16 mtpa

~12 mtpa

Customer/Partner

~60%

Customers

100%

Nasdaq: TELL

LNG

Terminal

Tellurian will retain ~12 mtpa

and ~40% of the assets

Driftwood Holdings

Driftwood Holdings’ operating costsTotal cost of ~$3/mmBtu locks in low cost of supply

$0.88

$0.36

$0.79

$0.22

$2.25

$0.75

$3.00

Drilling and

completion(1)

Operating Gathering,

processing and

transportation(2)

Contingency Delivered

cost

Liquefaction

cost

Total

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.

6

Upstream cost

$/mmBtu

Liquefaction cost

(1)

(2)

Tellurian Pipeline Network

7

Driftwood Pipeline

Capacity, Bcf/d 4.0Cost, $ billions $2.2 Length, miles 96

Diameter, inches 48Compression, HP 274,000Status FERC approval pending

Haynesville Global Access Pipeline

Capacity, Bcf/d 2.0Cost, $ billions $1.4Length, miles 200Diameter, inches 42Compression, HP 23,000Status Preliminary routing

Permian Global Access Pipeline

Capacity, Bcf/d 2.0Cost, $ billions $3.7Length, miles 625

Diameter, inches 42Compression, HP 258,000Status Preliminary routing

Bringing low-cost gas to Southwest Louisiana

1

2

3

1

2

3

Permian overviewWithout pipes, it’s just good rock

Permian basin: the big long

▪ Approximately 400,000 drilling locations

― Most forecasts drill no more than 30% of these

locations by 2050

▪ 20 potentially available stacked plays

▪ ~200 tcf of gas estimated produced by 2050

▪ +$40 bn/year in CAPEX by 2025

▪ Multi-generational

▪ Rock is not the constraint

▪ Economics driven by oil production and NGL

recovery

Too much of a good thing?

Sources: Berkeley Research Group (BRG), Goldman Sachs (GS)

Notes: BRG forecast assumes $55/bbl oil price, does not include Alpine High volumes; Goldman Sachs (GS) assumes WTI price of $52/bbl oil,

$3.00/mmBtu natural gas; production split of 57% oil, 23% NGLs, and 20% natural gas

9

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

2009201120132015201720192021202320252027202920312033203520372039

Bcf/d

Permian dry gas production

Midland Basin - BRG Delaware Basin - BRG

Permian Other - BRG Total production - GS

Total - BRG

“Permania”Hottest basin in the world as unconventionals not just a wildcatter’s game anymore

▪ $23 billion in CAPEX by independent E&P companies expected in Permian Basin in 2018…

▪ …but the IOCs are ramping up spending as investors clamor for resources that can respond to price signals faster than offshore projects

▪ Exxon:

― Permian mentioned 47x on Analyst Day call

― “Everyone is talking about the Permian”

― “It’s still early in the game”

― “First 3-mile lateral”

― “30 rigs this year”

▪ Chevron:

― Permian mentioned 27x on Q2 earnings call

― “Just keeps getting better”

― Production of 500,000 boepd by end of 2020, with 650,000 boepd by end of 2022

― $3.3 billion of capex in 2018 – 1/5th of overall total

▪ Shell:

― Shale is focus of “future growth opportunities”

― “It’s a big growth engine...I think we are emerging to be a strong player”

Sources: Independent E&P capex estimate from Criterion Research; Bloomberg transcripts, Houston Chronicle

10

Silver in the gold mine

▪ Natural gas does not meaningfully affect cash

flow at $3.00/Mcf

▪ Third-tier product behind oil and NGLs

▪ Current forward curves for both liquids and

natural gas mean the economics of liquids will

continue to drive drilling decisions well into the

future

― Waha basis will only make this worse

▪ As takeaway constraint tightens, natural gas

economics will not impact drilling unless shut-ins

occur

Pioneer’s situation demonstrates Permian economics driven by liquids

Source: Pioneer Natural Resources investor presentation, 3/1/2018

11

(1.00)

1.00

3.00

5.00

7.00

9.00

11.00

13.00

15.00

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Bcf/d

North Mexico East West PGAP Total active takeaway Production - GS Production - RBN Production - SocGen Production - TPH

Hurricane Permian is just gearing up...Permian producers running into takeaway constraints faster than anticipated...

Source: Goldman Sachs (GS), Wells Fargo Equity Research, RBN Energy LLC (RBN), Berkeley Research Group (BRG), Societe Generale (SocGen),

TudorPickeringHolt (TPH)

Note: Mexico active takeaway capacity assumes less than 50% utilization

Growing Mid-Continent

volumes encroached,

pushed out of Midwest by

NE production, but

takeaway options

remained

Mexico seasonal

demand increases,

but infrastructure

constraints on the

other side limit

demand pull

KMI/DCP Gulf Coast

Express comes online

and Mexico

consumption grows,

but Permian

production outpaces

takeaway growth

New pipeline needed

in 2021…but to

where?

1 2 3 4

1 2

3 4

12

Active takeaway capacity Production estimates

Waha

Hub

South LAKaty/Ship

Agua Dulce

Haynesville

Perryville

Transco St 85

Corpus

Sabine PassCameronDriftwood

?

-$0.26

-$0.25

-$0.28

$-.05

Freeport

...and will impact Texas Gulf Coast hardest2023

13

-

2.0

4.0

6.0

8.0

10.0

12.0

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Bcf/d

Local production Northern inbound Permian inbound Existing load Outbound to Mexico CCLNG 1-2 CCLNG 3

Agua Dulce is not the answerKicking the basis 400 miles south

Sources: RBN Energy, Tellurian estimates, Wells Fargo

1

2 3

1 Inbound flows from north offset

increase in demand from

Corpus Christi trains 1-2, but

market is largely dependent

on Mexican demand

2 Permian gas from Gulf Coast

Express competes with

inbound flows from Katy, HSC

and Eagle Ford production

3 Gas-on-gas competition

depresses prices, pushes gas

from Permian and legacy

pipes to the North

14

Supply Demand

Mexico will not save Waha

▪ Most analysts see exports from Agua Dulce

growing as Valley Crossing comes online

▪ More infrastructure needed to get US gas to

demand in central Mexico

― Entire country only has 10,000 miles of pipeline

capacity

― Demand will be largely seasonal due to lack

of storage

▪ Efforts to build renewables are pricing out gas

― Last renewables auction cleared at $20/MWh;

gas needs at least $45/MWh

▪ Mexican production begins to recover next

decade, as production from privatizations

comes online

Growth will continue, but not at levels meaningful to basis

Sources: RBN Energy LLC, SENER, WoodMackenzie

15

-

1.0

2.0

3.0

4.0

5.0

6.0

7.0

2018 2019 2020 2021 2022 2023

Bc

f/d

US exports to Mexico

Waha - RBN Agua Dulce - RBN All other exports Total exports - Woodmac

HSC basis moving in anticipation of PermianBackwardated market shows impact of Permian gas coming via intrastates, Agua Dulce

Source: Bloomberg as of 3/15/2018

16

-0.31

-0.28

-0.24

-0.20

-0.16

-0.12

-0.08

-0.04

-0.01

0.03

0.07

0.11

0.15

1/1

0/2

016

7/5

/201

6

12/2

8/2

016

6/2

3/2

017

12/1

6/2

017

6/1

0/2

018

12/4

/20

18

5/2

9/2

019

11/2

2/2

019

5/1

6/2

020

11/8

/20

20

$/m

mB

tu

Rolling forward curve of HOUS SHIP CHANNEL APR18

Actuals Curve as of: 28-Feb-2018 Curve as of: 29-Dec-2017

Curve as of: 30-Jun-2017 Curve as of: 30-Dec-2016 6M Moving Average as of 28-Feb-2018

-1.49

-1.36

-1.22

-1.09

-0.95

-0.82

-0.68

-0.54

-0.41

-0.27

-0.14

0.00

0.13

10-J

an-1

6

5-J

ul-16

28-D

ec-1

6

23-J

un-1

7

16-D

ec-1

7

10-J

un-1

8

4-D

ec-1

8

29-M

ay-1

9

22-N

ov-1

9

16-M

ay-2

0

8-N

ov-2

0

$/m

mB

tu

Rolling forward curve of WAHA BASIS SWAP APR18

Actuals Curve as of: 28-Feb-2018 Curve as of: 29-Dec-2017

Curve as of: 30-Jun-2017 Curve as of: 30-Dec-2016 Curve as of: 30-Jun-2016

Waha basis continues to declineTrying to catch a falling knife

Source: Bloomberg as of 3/21/18

17

1 Waha basis falling, but

curve still (just) in contango

2 Waha basis continues to drop

as investment surprises to the

upside

3 GORs, Alpine High speculation

send Cal19 basis down sharply

1

2

3

4 Strengthening WTI, NE supply

coming online lead to entire

curve shifting lower, with GCX

eventually relieving some

pressure

4

When you can’t get out, you go negative

Example

▪ Q2 and Q3 2017 AECO (Alberta hub) intraday

prices went negative on several occasions,

meaning producers paid to move their gas out

of the basin

▪ Why?

― Pipelines refused to offer IT given FT volumes at

capacity

― Condensate prices made it economic to keep

drilling

▪ End result: producers paid providers/holders of

transport as much as $2.00/mmBtu, according to

reported price data

There’s a reason Mark Papa isn’t sleeping

Sources: Platts via Marketview, Financial Post, Peyto Energy

18

-1.00

-0.50

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

$/m

mB

tu

AECO reported low price

PGAP goes directly to demandDirect access vs rate stacking

Aqua Dulce,

TX

Katy,

TX

Lake Charles,

LA

DFW,

TX

Carthage,

TX

Perryville,

LA

Station 85

Kosi

Permian

Basin

N e w M e x i c o

Key

Exiting

infrastructure

Potential

infrastructure

Permian Global

Access Pipeline M e x i c o

G u l f o f

M e x i c o

L o u i s i a n a

A r k a n s a s

M i s s i s s i p p i A l a b a m a

T e n n e s s e e

O k l a h o m a

T e x a s

19

Southwest Louisiana The Big Short

SW Louisiana: core of US gas demand2025

Notes: LNG demand includes ambient capacity; Sources: company data, drilling info, Entergy, Tellurian estimates

21

-

5.0

10.0

15.0

20.0

2018 2019 2020 2021 2022 2023 2024 2025

Bcf/d

SWLA supply & demand

Prospective demandOutbound to TXDemandSupply - new projectsSupply - existing capacity

+8.0 Bcf/d

L o u i s i a n a

T e x a s

G u l f o f M e x i c o

Driftwood LNG

Lake Charles, LA

Southwest LA: 20

Bcf/d of potential

demand

Perryville

Eunice/Station 85

Haynesville

West Inbound to SWLA

10.8 Bcf/d

Infrastructure not built for new demandYou can get to Carthage or Perryville, but where’s the demand?

Sources: EIA 2018 Annual Energy Outlook, RBN Energy; note Haynesville includes Texas production

22

Carthage

Perryville

Transco St85

FGT Z3

HSC

HHAD

411

Marcellus-Utica

24.6

33.0

2017 202574

Permian

7.3

13.0

2017 2025

Anadarko

5.6 6.1

2017 2025

23

52

Eagle Ford

5.810.2

2017 2025

112

7.3 7.9

2017 2025Haynesville

50.6

70.219.6

2017 2025 Incremental

production

Total selected basin shale

production,

Bcf/d

Resource

size, Tcf

Marcellus pipelines:

7.7 Bcf/d

Midship:

1.3 Bcf/d

KMI/DCP:

2.0 Bcf/d

SummaryBloomberg, EIA, RBN see a wall of gas that needs to find a market

▪ US dry gas production to hit 100 Bcf/d in next ten years

― Marcellus/Utica, Permian and Eagle Ford to provide growth of 18 Bcf/d

― Highly sensitive to increases in oil price

▪ Market needs at least 14-18 Bcf/d of LNG exports to balance; currently only 10 Bcf/d operating or under construction

▪ SW Louisiana is the center of US natural gas demand growth for the next decade

― Driven by LNG, favorable permitting/sites, and petrochemical growth

▪ $170 bn of infrastructure needed to bring new production to demand

▪ Even with recently built infrastructure, you still have a last mile problem: you can get close, but cannot get to market

▪ Rock and a hard place:

― Northeast, Permian production growth crowding out other production

― Basis eroding almost everywhere until infrastructure can get in place

― Getting to demand first will be key to maximizing revenue

Sources: EIA AEO 2018, Reference Case; RBN Energy, LLC; Bloomberg New Energy Finance

23

PGAPMaps & Terms

PGAP route and zones

25

PGAP receipts

26

PGAP deliveries

27

▪ Negotiated rates for higher firm transportation service

▪ Shipper classes

― Anchor: 100,000 – 499,999 mmBtu/d

― Foundation: 500,000+ mmBtu/d

▪ Term:

― Minimum: 5 years

― Maximum: 20 years

Terms

28

Thank you