Corporate Presentation

January 2021

Cautionary statements

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," "model," "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 and contract terms, margins, returns and payback periods, future cash flows, production, delivery of LNG, liquefaction and regasification capacity additions, infrastructure growth, equity values, future costs, prices, financial results, liquidity and financing, including project financing, reaching FID, future demand and supply affecting LNG and general energy markets and other aspects of our business and our prospects and those of other industry participants.

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 our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, and our other filings with the Securities and Exchange Commission, 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.

Projected future cash flows as set forth herein may differ from cash flows determined in accordance with GAAP.

We may not be able to complete the anticipated transactions described in the presentation. FID is subject to the completion of financing arrangements that may not be completed within the time frame expected or at all.

The financial information included on slides 3, 4, 5, 11, 12, 16, 17, 19 and 20 is meant for illustrative purposes only and does not purport to show estimates of actual future financial performance. The information on those slides assumes the completion of certain acquisition, financing and other transactions. Such transactions may not be completed on the assumed terms or at all. Actual commodity prices may vary materially from the commodity prices assumed for the purposes of the illustrative financial performance information.

Estimates of "resources" and other non-proved reserves are subject to substantially greater risk than are estimates of proved reserves.

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.

2

Tellurian value proposition (Nasdaq: TELL)

Developing a global natural gas business around Driftwood LNG ("DWLNG")

Our business

  • Driftwood LNG: a 27.6 mtpa LNG export terminal in Louisiana(1)
  • Haynesville gas production: current asset 1.0 Tcf of resource; production 46 mmcf/d
  • Pioneering management team that has built ~18% of global LNG capacity
  • Reduce global carbon emissions & support efforts to deal with climate change

Tellurian investment case

  • ~$2 bn of FCF at full operations of Driftwood LNG(2)
  • ~$5-7annual cash flow per share to TELL shareholders(2)
  • Implied equity value of ~$12-17/share at FID(3)

Notes:

(1)

EPC guaranteed capacity of 24.1 mtpa; expected production of 27.6 mtpa.

(2)

See assumptions discussed in notes to slide 5.

(3)

NPV of $5-7 cash flow per share at commercial operations in 2026 discounted at 15% for the 40-year life of the plant and assuming no terminal value.

3

Driftwood plans to deliver LNG < $3.50/mmBtu

Low capital cost, low operating cost, integrated JV

Fully integrated low-cost project

~$1,000/tonne including LNG terminal,

Driftwood pipeline and upstream gas

Haynesville gas is lower cost than Henry Hub

Haynesville

Gas production

< $2.00/mmBtu gas delivered to plant

Supply gas

regardless of Henry Hub market index price

Partnership model ensures interest alignment

Gillis

JV partners own their share of the LNG at cost

Driftwood Pipeline

Driftwood LNG

Houston

< $3.50/mmBtu FOB LNG price

FOB

LNG

< $2.00 gas delivery + < $0.75 opex + < $0.75 debt service

< $3.50

4

Positioned to deliver $5-7/sh of cash flow(1)

Tellurian ownership structure

Illustrative cash flow calculation to Tellurian

~11.6 mtpa(2)

Driftwood Holdings

Production

Pipeline

LNG

Company

Network

Terminal

x 52 mmBtuconversion x $3.50 margin

  • $2.1 billion annual cash flow

Notes:

(1)

Annual cash flow per share based on the following assumptions, among others: (a) projected $2.1 billion annual cash flow to Tellurian, (b) ~330 million shares outstanding, conversion of ~6.1 million shares of existing convertible preferred stock issued to Bechtel and conversion of outstanding

stock options and warrants for ~42 million shares, (c) total Driftwood LNG production at expected production capacity of 27.6 mtpa and (d) 11.6 mtpa Tellurian owned capacity in Driftwood LNG, before any additional capacity purchases are contemplated by the company.

(2)

11.6 mtpa at full development of Driftwood LNG.

5

2019 Historical price

Haynesville value rises with Henry Hub

Price volatility also shows value of upstream integration

Haynesville Shale & Tellurian acreage

U . S . Gulf Coast

= Tellurian acreage

Haynesville /

Bossier Shale

Haynesville targets have 140+ Tcf resource potential

Driftwood LNG

a s

Houston, TX

T e x

a n a i s i u o L

Rising Henry Hub prices call for additional supply

$/mmBtu

$4

$3

$2

$1

--

Tellurian holds 10,067 net acres in the Haynesville(1) ~1.0 Tcf resource base, 100+ drilling locations(1)

2018

2020

2021

2022

2023

Fwd price

Fwd price 9-months prior

46 mmcf/d current production; 71 producing wells (21 operated)

Sources:

MarketView and Tellurian Research.

Note:

(1) As of end of October 2020.

6

Higher prices supported by structural factors

China

India

Europe

Southeast Asia

  • Improved gas infrastructure penetration increases demand
  • Increased industrial demand from economic recovery
  • Government policy to support natural gas to tackle pollution issues and energy poverty
  • Increased reliance on imported gas due to domestic declines
  • Higher CO2 prices and climate action urgency boost demand
  • Fastest growing region for power demand at 5.4% in 2021
  • Limited private-sector financing for new coal projects makes LNG attractive as a baseload fuel

Global commodity prices

$/mmBtu $35

$30

$25

$20

$15

$10

$5

$0

Jan-21

Dec-20

Nov-20

Oct-20

Sep-20

Aug-20

Jul-20

Jun-20

May-20

Apr-20

Mar-20

Feb-20

Jan-20

JKM HH TTF Brent

Sources:

Platts and ICE via MarketView, SIA, IEA Electricity Market Report 2020.

7

Forward natural gas prices rise globally

Asian LNG - JKM forward curve

European natural gas - TTF forward curve

$/mmBtu

$/mmBtu

$12

$18

$12

$10

2-year forward price

$10

2-year forward price

+26% since April

+22% since April

$8

$8

$6

$6

$4

$4

$2

$2

Feb-21Aug-21Feb-22

Aug-22Feb-23Aug-23

Feb-21Aug-21Feb-22Aug-22Feb-23Aug-23

January 2021 Forwards

April 2020 Forwards

January 2021 Fowards

April 2020 Forwards

Sources: NYMEX and ICE via MarketView.

8

Asian LNG demand grew 17% y/y

China/India/JKT (Japan-Korea-Taiwan) LNG imports up 36%/11%/9%, respectively, year-over-year in December 2020

Chinese LNG imports

million tonnes/month

Indian LNG imports

million tonnes/month

JKT LNG imports

million tonnes/month

12

4

16

13.6 13.2

14.1

9

8.7

6.6

6.9

6

6.3

5.5

5.8

5.3

5.5

5.9

5.6

5.3

6.4

6.4

4.4 4.5

4.8

5.3

5.0

4.7

4.8

4.2

4.4

4.3

4.2

3

-

2019 2020

Source:

IHS Markit.

3

2.8

2.9

2.2

2.1

2.4

2.3

2.3

2.3

2.2

2.1

2.1

2.0

2.3

2

2.1

2.1

1.9

1.9

1.7

1.8

1.9

1.9

1.9

1.5 1.3

1

-

2019 2020

12

13.1

12.2

11.4

11.6

11.0

10.8

11.3

12.9

11.7

10.2

11.5

11.7

9.9

9.7

10.8

9.8 10.0 10.3

8

9.5 9.3

9.3

4

-

2019 2020

9

Entering 5-year starvation; expect rising price

Global liquefaction capacity additions (mtpa)

~30 mtpa capacity additions

~146 mtpa capacity additions

~61 mtpa capacity additions

Limited capacity additions(1)

1.6% per annum

8.3% per annum

2.5% per annum

(0.5)% per annum

40

33

27

29

27

23

20

14

13

12

4

5

8

6

9

(0)

2

--

(3)

(8)

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

JKM annual average:

$14.04

$15.12

$16.54

$13.85

$7.45

$5.73

$7.13

$9.74

$5.49

$4.38

Sources:

Wood Mackenzie, Tellurian analysis.

Note:

(1) Capacity additions for projects that have reached FID only.

10

Driftwood LNG progress & catalyst roadmap

Fully-

Major

Premier site

wrapped EPC

permits

Financing

Construction

contract

secured

Driftwood LNG is shovel

ready

2021 value creation catalysts

LNG market recovery Commercial progress Phase I FID

LNG demand

Henry Hub volatility

Announce new

recovery from

shows value of

commercial

COVID-19

upstream

agreements

JKM > $7/mmBtu

~$1,000/tonne capital

Secure project

costs for integrated

financing

project

11

Key investment highlights

Driftwood LNG is shovel ready, major permits secured

Engineering ~30% complete, >$150 mm invested in EPC

Phase I low-cost capital of ~$1,000/tonne

LNG delivered FOB U.S. Gulf Coast < $3.50/mmBtu to maximize margins in growing LNG market

Premier management team with performance track record

12

Contact us

  • Matt Phillips
    Director, Investor Relations & Finance +1 832 320 9331 matthew.phillips@tellurianinc.com
  • Johan Yokay
    Manager, Investor Relations & Finance +1 832 320 9327 johan.yokay@tellurianinc.com
  • Joi Lecznar
    EVP, Public & Government Affairs +1 832 962 4044 joi.lecznar@tellurianinc.com

Social media

@TellurianLNG

13

Appendix: Driftwood LNG Project & Financial Details

14

Driftwood LNG's ideal site for exports

Access to pipeline infrastructure

Access to power and water

Support from local communities

Site size over 1,000 acres

Insulation from surge, wind and local populations

Berth over 45' depth with access to high seas

Artist rendition

Fully permitted

30% engineering complete

EPC contract signed

Shovel ready project

15

Driftwood expects to deliver LNG FOB at < $3.50/mmBtu

Integrated operations deliver lower costs

Gas

$2.00/mmBtu

sourcing

LNG

< $0.75

/mmBtu

< $3.50/mmBtu

pipeline(1)

plant +

Average cost on the water

service(2)

< $0.75/mmBtu

Debt

Notes: (1)

Includes operating expenses for Driftwood LNG plant and Driftwood pipeline and G&A.

(2)

For phase one: ~$9.8 billion of project finance debt amortized over 20-year period.

16

Driftwood LNG and pipeline capital for Phase I

$ in billions, unless otherwise noted

Uses ($ bn)

Sources ($ bn)

Driftwood LNG terminal

$10.6

Driftwood partner equity

$6.0

Owner's cost(1)

1.8

Driftwood pipeline, upstream, &

2.6

other(2)

Cost/tonne ($/tonne)(3)

$1,042

Tellurian pre-FID work contribution

0.6

Cash flow from cargo ramp-up

0.5

Debt

9.8

Financing costs and interest

1.8

Total Uses

$16.8

Total Sources

$16.8

At ~$1,000/tonne, Driftwood is among the lowest-cost global LNG projects

Notes: (1) Owner's cost for Driftwood LNG terminal construction.

  1. Other includes pre-FID development costs and G&A during construction.
  2. Based on Phase I EPC guaranteed capacity of 14.5 mtpa EPC. (Phase I expected production is 16.6 mtpa).

17

Bechtel LSTK secures project execution

Driftwood EPC contract costs ($ per tonne)

$710

Increase from price refresh

Leading LNG EPC contractor

$500

$510

~$560

44 LNG trains delivered to 18

customers in 9 countries

$700

$390

~30% of global LNG liquefaction

capacity (>125 mtpa)

~$550

$490

$500

$380

Tellurian and Bechtel relationship

16 trains(1) delivered with Tellurian's

executive team

Stage 1

Stage 2

Stage 3

Stage 4

Total

Invested $50 million in Tellurian Inc.

Capacity

11.0

5.5

5.5

5.5

27.6

Price refresh in April 2019 resulted in ~2%

(mtpa)

Plants 1&2

Plant 3

Plant 4

Plant 5

increase after ~24 months

Sources:

Tellurian-Bechtel agreements; Bechtel website.

Note:

(1) Includes all trains from Sabine Pass LNG, Corpus Christi LNG, Atlantic LNG, QCLNG and ELNG.

18

Value to Tellurian Inc.

Every $1.00 reduction in gas costs or increase in LNG price adds $1.60/share in cash flow in 5-plant case

Base case

3 Plants

5 Plants

USGC netback

Cost of LNG(1)

Margin

Cash flows(2)(3)

($/mmBtu)

($/mmBtu)

($/mmBtu)

$ millions ($ per share)

Tellurian capacity

4.6 mtpa

11.6 mtpa

based on 27.6 mtpa

production profile

$5.00

$3.50

$1.50

$360 ($0.95)

$900 ($2.38)

$7.00

$3.50

$3.50

$840

($2.22)

$2,110 ($5.57)

$9.00

$3.50

$5.50

$1,320

($3.48)

$3,320 ($8.76)

$11.00

$3.50

$7.50

$1,790

($4.72)

$4,520 ($11.93)

Notes:

(1)

$3.50/mmBtu cost of LNG FOB Gulf Coast assumes $2.00/mmBtu cost of gas at Driftwood LNG terminal.

(b) ~330 million shares outstanding, conversion of ~6.1 million shares of existing convertible preferred stock issued to Bechtel and conversion

(2)

Annual cash flow equals the margin multiplied by 52 mmBtu per tonne; does not reflect potential impact of management fees paid to

of outstanding stock options and warrants for ~42 million shares, and (c) total Driftwood LNG production at expected production capacity

Tellurian nor G&A.

of 27.6 mtpa.

(3)

Annual cash flow per share based on the following assumptions, among others: (a) projected $2.1 billion annual cash flow to Tellurian,

19

Returns to Driftwood Holdings' partners

U.S. Gulf Coast netback price ($/mmBtu)

$5.00

$7.00

$9.00

$11.00

Driftwood LNG, FOB U.S. Gulf Coast

$(3.50)

$(3.50)

$(3.50)

$(3.50)

($/mmBtu)

Margin

$1.50

$3.50

$5.50

$7.50

($/mmBtu)

Annual partner cash flow(1)

$80

$180

$285

$390

($ millions per tonne)

Cash on cash return(2)

16%

36%

57%

78%

Payback(3)

6

3

2

1

(years)

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.

20

Unmatched LNG development experience

Tellurian's management team has >80 years of combined LNG development experience globally

Charif Souki

Executive Chairman of the Board

  • Co-founderof Tellurian
  • Founded Cheniere in 1996, Chairman and CEO until 2015

Martin Houston

Vice Chairman

  • Co-founderof Tellurian
  • 32 years at BG Group, retired as COO in 2014

Octávio Simões

President & CEO

  • Joined Tellurian in 2019 after 20 years at Sempra
  • President & CEO of Sempra LNG & Midstream

Keith Teague

EVP & COO

  • CEO of Driftwood Holdings
  • EVP - Asset Group at Cheniere

79 mtpa

Tellurian management responsible for ~18% of the LNG in production today

35 years

Tellurian management has delivered cost- leading LNG projects for >35 years

21

Appendix: LNG & ESG

22

Global energy needs require natural gas

The shifting landscape of energy consumption

Tonnes8 oil equivalent/capita

Drivers of shifting landscape

35% Non-OECD energy consumption growth rate was

7

31%

30% ~13x that of OECD's over the past decade

6

23%

2030 target for

24%

gas' share in both

5

19%

India and China's

energy mix

4

7.0

15%

15%

3

2

4.0

4.3

6%

7%

1

2.3

-

0.6

0.9

U.S.

Europe

JKT

India

China

Rest of

Asia

2018 energy consumption per capita

Gas' share of 2018 total energy mix

Sources:

BP Statistical Review of World Energy, Tellurian Research

Note:

(1) Based on total 2018 energy demand for non-OECD countries and 0.855 mtpa LNG per 1 million tonnes oil equivalent.

25%

Despite massive energy growth, natural gas is

just 22% of non-OECD's energy mix, while coal's

20%

share is 36%

15%

If gas moved to just 25%, over 200 mtpa of LNG

would be required to meet demand(1)

10%

Population and economic growth to encourage

5%

further energy consumption growth in Asia

0%

9 of 10 world's most polluted cities located in just

two Asian countries (India & China)

A drive towards cleaner energy sources will

require both natural gas and renewables

23

China & India: ~90 mtpa growth potential

LNG demand growth (2019-2025)

Key growth drivers

mtpa

46

15

India

43

21

China

Infrastructure:

~2x growth in India's pipeline grid by 2025

~2x growth in India's regas capacity by 2025

~1.5x growth in China's pipeline grid by 2025

~2x growth in China's regas capacity by 2025

Policy:

India and China's infrastructure growth allows

each to remain on track to reach their targets

of 15% for gas' share in the energy mix by 2030

Latent demand:

Based on consultant forecast(1)

Based on existing and planned infrastructure(2)

Sources:

BP Statistical Review of Energy, WoodMac, SIA, Tellurian Research.

Notes:

(1)

Based on WoodMac's LNG demand outlook for both India and China.

(2)

Based on existing, firm and likely regas capacity in addition to downstream pipeline infrastructure projects, per project sponsors.

(3)

Based on 2018 coal-fired power generation.

India and China's total latent demand for

cleaner energy is equivalent to ~885 mtpa(3)

24

India's targets suggest even higher gas use

India natural gas demand - primary sources

mtpa

Incremental supply required for 15% target(1)

153

Uncontracted LNG

Contracted LNG

Indigenous Production

75

70

48

15

28

41

7

23

15

8

19

14

32

36

19

21

2018

2020

2025

2030

India's gas demand drivers

  • Prime Minister Modi has set a target of 15% for natural gas' share of India's energy mix by 2030
  • ~$100 billion in energy infrastructure investment currently underway(2)
  • Industrial use will lead gas demand growth as India seeks food security for ~1.3 billion people
    • India seeks to become a self-reliant supplier of urea, triggering a revival of closed fertilizer plants and the conversion of naphtha-based plants to gas
  • India's build-out of city gas distribution networks is expected to connect an incremental ~35 million homes to the national gas grid

Sources:

Wood Mackenzie, BP Energy Outlook 2019 Edition.

Notes:

(1)

Based on BP Energy Outlook's estimate of India's total primary energy consumption and Prime Minister Narendra Modi's 15% target for

natural gas' share of India's total primary energy consumption by 2030; 52.17 mmBtu per tonne of LNG.

(2)

Per India Oil Minister Dharmendra Pradhan.

25

India is rapidly building out gas infrastructure

Sharp increase in LNG and gas-related infrastructure will tap into significant latent gas demand

India's emerging regas & gas transport infrastructure

India's regasification capacity buildout

mtpa

Existing

Under construction

78

Likely in-service

69

21

57

12

19

57

57

38

Today

2025

2030

Sources:

Wood Mackenzie, BP Energy Outlook 2019 Edition, Tellurian Research.

26

New Asian markets grow ~41 mtpa by 2025

Emerging markets could add the equivalent of another South Korean market by 2025

  • Bangladesh, Malaysia, Pakistan, Thailand:
    • > 32% gas market penetration, declining indigenous gas production and strong economic growth increase the call for imports
  • Philippines, Taiwan, Vietnam, Indonesia:
    • <17% gas market penetration with growing gas demand for power, especially as coal and nuclear lose favor

LNG demand by region

mtpa

600

500

400

300

200

100

-

2019 2020 2025 2030 JKT Other China + India New Asian markets

Sources:

Wood Mackenzie, FGE.

Note:

New Asian markets include: Indonesia, Malaysia, Pakistan, Philippines, Singapore, Sri Lanka, Thailand and Vietnam.

27

Environmental and social leadership

Driftwood LNG project expected to reduce lifecycle carbon emissions and support local communities

Lifecycle emission reduction

  • Provide an outlet for currently flared natural gas in the U.S.
  • Replace coal and oil in emerging markets to reduce carbon emissions and improve air quality
  • Facilitate growth of renewables by providing energy reliability

Sustainable development

  • Liquefaction facility to have near zero methane emissions
  • Use the latest equipment, technology and monitoring systems to minimize emissions
  • Conduct green completions in upstream operations

Social engagement

  • Extensive community outreach and support programs
  • Create 350 permanent and 6,400 construction jobs
  • Fund climate change research at Columbia University

28

LNG's role in the energy transition

Today: Reduce carbon intensity, improve air quality

Future: Net zero carbon emissions

Facilitates coal-to-gas

switching

Supports growth of

renewables

Cleaner heavy

transportation fuel

  • Increasingly cost-competitive with coal
  • Reduces carbon emissions by up to 50%
  • Reduces SOx, NOx and particulate matter

Carbon capture,

utilization and storage

  • Grid reliability
  • Seasonal storage
  • High-temperatureheat for industry
  • Winter heating for buildings

Carbon offsets

  • Long-haulLNG trucking in areas without electrification
  • LNG-poweredvessels support IMO 2020 compliance

29

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Tellurian Inc. published this content on 13 January 2021 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 13 January 2021 13:21:03 UTC