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
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 ~$1,000/tonne, Driftwood is among the lowest-cost global LNG projects
Notes: (1) Owner's cost for Driftwood LNG terminal construction.
- Other includes pre-FID development costs and G&A during construction.
- Based on Phase I EPC guaranteed capacity of 14.5 mtpa EPC. (Phase I expected production is 16.6 mtpa).
17
Bechtel LSTK secures project execution
Driftwood EPC contract costs ($ 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