Exhibit 99.1

Tellurian Inc. Corporate presentation August 2023

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,” “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, the benefits of the proposed integrated structure for Driftwood, Driftwood financing matters, capital structures, future development, transfer pricing, costs, margins, cash flow, production, returns, wells, drilling and other development activities, inventory life, commodity prices and demand (including the relationship between domestic and international gas/LNG prices), funding of current and future phases, liquefaction capacity additions, construction of LNG projects, Driftwood capacity, future demand and supply affecting LNG and general energy markets, future transactions 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, 2022, 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. A full notice to proceed with construction of the Driftwood Project 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 10, 11,12,13,14 and 19 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. 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. Forward - looking statements 2

The world is critically short natural gas Demand for energy is projected to grow over 50% in the next 25 years as world population continues to grow and people strive to prosper. Global LNG demand has grown ~7% annually over the last five years. Tellurian’s integrated model aims to connect low - cost U.S. gas with the global market Tellurian will be the first integrated global gas pure - play in the U.S. with access to low - cost domestic resource and infrastructure. Sources: BP Statistical Review, BP World Energy Outlook, Wood Mackenzie, IEA. Note: Tellurian’s integrated model creates a physical hedge from upstream operations for Driftwood’s natural gas purchases. 3 Artist rendition

Tellurian executive summary 4 Driftwood Phase I is well underway with Bechtel having commenced construction in April 2022 ▪ Extended limited notice to proceed with Bechtel in 2023, continuing project work from 2022 ▪ Cleared all Phase I critical areas, drove ~45% of Phase I piles and poured all Plant 1 compressor foundations ▪ The advanced site work de - risks the project execution and timeline, a significant benefit to Driftwood partners Global demand for LNG will exceed supply without additional investment ▪ An estimated 185 mtpa of additional capacity will be needed by 2035, almost 1/3 rd of the expected LNG market size ▪ Following 2022’s record pricing & volatility, buyers remain interested in securing low - cost U.S. LNG supply ▪ Natural gas remains a key fuel for energy transition especially in developing economies Driftwood LNG progress continues with multiple milestones met in 1H23 ▪ Binding commitment for $1bn in Driftwood financing from the Real Estate platform of Blue Owl (NYSE: OWL), a $144bn AUM alternative asset manager ▪ To date, TELL has invested over $1bn and received additional commitments for $1bn of Driftwood project costs ▪ TELL upstream: forecasted 2023 average production of 180 - 190 MMcf /d, with ability to adjust quickly with prices Driftwood’s pioneering approach provides upside to all parties ▪ Best placed among remaining U.S. projects due to site, timeline, capacity and construction progress ▪ Commercial structure aligns partner interests and EPC framework mitigates risks to development process ▪ Available capacity for Phase I allows strategic investors to directly invest in low - cost U.S. LNG at the project level 1 2 3 4 Source: Tellurian analysis.

Houston Gillis Haynesville Gas production Driftwood LNG Driftwood Pipeline Tellurian: fully integrated, pure - play LNG 5 Low - cost, integrated business model : upstream gas production in Haynesville (1) , pipeline and LNG terminal in SW Louisiana Pure - play, global gas producer : monetizing U.S. domestic gas production into premium global gas markets; integration provides cost certainty of supply Bechtel EPC execution : best - in - class LNG execution; lump sum turnkey with ~30% of overall engineering complete All critical permits secured : all FERC and DOE permits secured for Driftwood LNG terminal and pipeline Proven management track record : Tellurian team has originated and executed ~79% of U.S. LNG capacity development and ~ 33 % of global LNG capacity development across four continents Critical role in energy transition : significant ESG benefits and end - to - end emissions control from owning upstream Note: (1) Tellurian’s integrated model creates a physical hedge from upstream operations for Driftwood’s natural gas purchases.

Upstream: building inventory for LNG exports Note: (1) Inventory and reserves information as of December 31, 2022 (using December 30, 2022 NYMEX strip pricing) as prepared by N eth erland, Sewell & Associates in accordance with the definitions and guidelines set forth in the 2018 Petroleum Resources Manag eme nt System (PRMS). 6 Upstream segment Production ( MMcf /d) 1Q23 2Q23 Net acreage 1Q23 2Q23 ~30,915 ~191 ~ 214 ~31,117 Acreage ~31,117 net acres primarily in DeSoto, Bossier, Caddo and Webster parishes >60% of undeveloped acreage prospective for Bossier reserves ~75% average operated working interest for operated locations Well inventory >400 undeveloped, ~50% operated Gas/ liquids mix 99+% gas Tellurian Upstream overview (1)

Driftwood LNG 11.0 mpta Phase I LNG liquefaction facility and pipeline ready to deliver gas to global markets by 2027 7 7 Driftwood LNG A Perryville HSC Gillis Henry Hub Eunice C B Acadian Extension PL Acadian PL KM Louisiana Pipeline ( KMLP ) LEAP Gas Gathering Tennessee Gas PL ( TGP ) TETCO Trunkline PL Gas Price Hub Driftwood Pipeline Haynesville + Phase I construction progress Ideal location to source gas Total capacity ~11 mtpa LNG Feedgas requirement ~550 Bcf/year

0% 5% 10% 15% 20% 25% 30% 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 U.S. Share of Global LNG Supply (%) 28% If forward Henry Hub prices exceed global pricing, ~20 - 25% of the global LNG supply could stay within the U.S. market, helping to balance global LNG supply Henry Hub will remain global gas price floor 8 Potential for international pricing / Henry Hub inversion is unsustainable due to U.S. market share on global basis Source: Wood Mackenzie, S&P, Tellurian research. Notes: Includes projects that are under construction. (1) Excludes LNG exports, includes Mexico exports. Price inversion scenario 2030 Expected Figures U.S. LNG Supply: ~21 Bcf/d % of domestic gas consumption (1) (~93 bcf/d) % of global LNG supply (~ 81 bcf/d) ~28% ~ 23 % Future Henry Hub - JKM/TTF pricing dynamics should ensure global gas markets are adequately supplied 20%

2022-2035 Demand Growth 2022-2035 Supply Growth New Supply Required LNG supply vs. demand growth ( mtpa ) LNG demand exceeds supply growth 9 Sources: Wood Mackenzie, Tellurian estimates. Notes: (1) Based on Wood Mackenzie estimates that global LNG demand will grow 5% p.a. from 2021 to 2035. (2) Includes supply from projects that have made FID, net number that includes capacity declines at legacy projects. (3) Assumes a utilization factor of 85%. (1) (2) ~282 mtpa of new LNG demand by 2035 ~185 mtpa of new LNG capacity required by 2035 (3) 126 156 282

$0 $2 $4 $6 $8 $10 $12 $14 $16 Billions How much does a USGC LNG terminal cost? 10 Example Phase I (~11mtpa) Development Cost Stack Construction Scope Owner’s Costs Financing Costs Examples of Major Cost Drivers Civil works Gas Treatment / Utilities LNG Trains LNG Tanks Marine Berths Buildings Land Acquisition Permitting/Regulatory Utility Projects Owner’s Team / G&A Legal / Consultants Cost of Debt During Development Period Approx. Normalized Cost p er tonne of Production Construction Costs : $900 Owner’s Costs : $200 Financing Costs : $200 Total: $1,300 per tonne 10

Traditional LNG project economics 11 Illustrative LNG project cost stack (~11 mtpa ) Notes: (1) Assumes 7% interest rate on $8 bn of senior project debt. (2) Assumes 11% internal rate of return on $6 bn equity investment. Needs to be reflected in offtake price to make project feasible (1) (2) Illustrative Capital Structure: • ~$6 bn of equity (~43%) • ~$8 bn of debt (~57%) Not inclusive of: • Debt amortization • Gas sourcing and fuel use • Return to developer’s equity $1.00 $4.00 $1.00 $2.00 O&M + G&A Interest Exp. ROE Full Cost $/ mmBtu

Driftwood LNG Phase I (2 - plant, ~11 mtpa) Notes: (1) Phase I EPC contract is an estimate provided by Bechtel for the price as of July 2022, subject to refresh before full notice to proceed. (2) Includes owner’s costs, terminal labor, opex prior to LNG production, management fee to Tellurian, G&A during construction and contingencies. (3) Includes first phase of Driftwood pipeline system construction plus contingency. (4) Includes interest during construction, based on secured overnight financing rates as of March 2023 as well as financial a dv isory fees and transaction costs. 12 2 - plant development costs ($ bn ) LNG terminal (1) $9.0 EPC cost/tonne ($/tonne) $815 Owner’s cost (2) 2.2 Pipeline (3) 0.9 Capital cost/ tonne ($/ tonne ) $1,100 Financing, interest and other (4) 2.4 Total development costs $14.5 Total capacity ~11 mtpa LNG Feedgas requirement ~550 Bcf /year Note: Artist rendering of full 5 - plant Driftwood LNG development

Henry Hub 115% Henry Hub 115% Henry Hub $2.60 ( $0.50 ) $2.10 Gas Sourcing Transfer Price Bank Coverage and Dividend Realized Price Contingent Equity (2) $2.5 bn Tellurian Equity (1) $1.5 bn Partner Equity $1.8 bn Lease/Mezz $2.0 bn Bank Debt $7.0 bn Driftwood capital structure & economics 13 Equity partners to sign 11 mpta of long - term offtake contracts at the transfer price to support the project financing Illustrative capital structure Transfer pricing Tellurian is seeking partners to invest 55% of equity for 6 mtpa capacity in Phase I of Driftwood Project $/ mmBtu Notes: (1) Tellurian to raise the difference between the $1+ billion development expenditure to date and Tellurian’s equity com mitment. (2) If the six months of commissioning cargoes cover the contingent equity, the contingent equity will not be funded. (3) Assumes 1.5 bcf/day of production. Illustrative Value to Driftwood Cargo (3.8 mt) as of 8/1/2023 11 mtpa Year to Date Gulf Coast Marker ($/ mmBtu ) $6.95 $10.59 115% Henry Hub + $2.10 ($/mmBtu) $5.04 $5.03 Margin ($/ mmBtu ) $1.91 $5.56 Operating cash flow (3) $7.2 mm $1.77 bn

Illustrative cash flow at 2027 LNG pricing Notes: (1) Assumes Brent parity based on 2027 IHS Markit LNG and Gas Price Forecast as of July 2023 (rounded for illustrative purposes) . (2) Assumes transportation estimate of $1.75/ mmBtu . 14 Phase I (Plants 1 - 2) Full Development (Plants 1 - 5) LNG sales price (1,2) (less transportation, $/ mmBtu ) $14.00 $14.00 Gas sourcing (1) ($/ mmBtu ) - $5.00 - $5.00 Liquefaction and transport ($/ mmBtu ) - $1.00 - $1.00 Margin ($/ mmBtu ) = $8.00 = $8.00 Annual capacity x ~550 Bcf x ~1,380 Bcf Potential annual operating cash flow to Driftwood LNG partners before land lease and interest expense = $4.4 billion = $11.0 billion Plants 3 - 5 to be funded by cash flow from Phase I

Contact us ▪ Matt Phillips VP, Investor Relations & Finance +1 832 320 9331 matthew.phillips@tellurianinc.com ▪ Joi Lecznar EVP, Public & Government Affairs +1 832 962 4044 joi.lecznar@tellurianinc.com 15 ▪ Johan Yokay Director , Investor Relations & Assistant Treasurer +1 832 320 9327 johan.yokay@tellurianinc.com

Appendix

Driftwood LNG’s ideal site for exports 17 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 1,200 acres Insulation from surge, wind and local populations Artist rendition x Fully permitted x 30% engineering complete x EPC contract signed x Under construction

Unmatched LNG development experience Tellurian’s management team has >80 years of combined LNG development experience globally 18 Charif Souki Executive Chairman of the Board Co - founder of Tellurian Founded Cheniere in 1996, Chairman and CEO until 2015 Martin Houston Vice Chairman Co - founder of Tellurian 32 years at BG Group, retired as COO in 2014 Octávio Simões President & CEO Joined Tellurian in 2019 after 20 years at Sempra Former President & CEO of Sempra LNG & Midstream 166 mtpa Tellurian management responsible for ~33% of global LNG in production today and 79% of U.S. LNG in production today 35 years Tellurian management has delivered cost - leading LNG projects for >35 years Samik Mukherjee EVP and President, Driftwood Assets Joined Tellurian in 2022 Former EVP, COO of McDermott International, Ltd.

$0 $5 $10 $15 $20 JKM & TTF Forward Curve TTF JKM Low - cost U.S. supply provides global gas arbitrage 19 Access to premium global gas market generates up to $11/ mmBtu margin (1) at current forward prices JKM (Asia benchmark) 1 - yr forward price: $17/ mmBtu TTF (European benchmark) 1 - yr forward price: $ 17 / mmBtu Sources: Wood Mackenzie, IHS Markit, Bloomberg , ICE data via Marketview , CME Group. Notes: (1) Assumes maximum netback from Asia or Europe based on 7/24/2023 12 - month strip pricing for Henry Hub, TTF, and JKM, $1 .00/ mmBtu for plant opex and G&A and $1 - $1.70/ mmBtu shipping, depending on the destination to Europe or Asia. (2) Driftwood LNG variable cost assumes $5.00/ mmBtu for gas sourcing based on 2027 IHS Markit LNG and Gas Price Forecast as of July 2023 and $1.00/ mmBtu for plant opex and G&A. Driftwood LNG Variable cost: ~ $6/ mmBtu Driftwood LNG variable cost (2) = ~$6/ mmBtu

17 4 0 6 12 27 30 29 38 26 14 13 10 11 20 45 32 27 14 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Supply fails to keep pace with demand Global liquefaction capacity additions ( mtpa ) Sources: Wood Mackenzie, Platts via Marketview . Note: Capacity additions for projects that have reached FID only. 20 JKM annual average: ~1 50 mtpa capacity additions 6.9 % per annum ~ 116 mtpa capacity additions 3.8 % per annum ~68 mtpa capacity additions 2.7% per annum ~ 38 mtpa capacity additions 2.7 % per annum $14.04 $15.12 $16.54 $13.85 $7.45 $5.73 $7.13 $9.74 $5.49 $4.38 $18.59 $33.98 $ 14.25 YTD