Exhibit 99.1


Tellurian Inc. Corporate presentation February 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, costs, margins, cash flow, EBITDA, production, returns, wells, drilling and other development activities, 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, emissions, 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 8, 10 - 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, with limited capacity additions on the horizon. 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 ▪ Progressed limited notice to proceed projects with Bechtel in 2022, continuing into 2023 ▪ In 2022, cleared all Phase I critical areas, drove ~30% of Phase I piles and pouring Plant 1 compressor foundations ▪ The advanced site work de - risks the project and provides acceleration options upon full notice to proceed Global gas market volatility showing impact of multi - year underinvestment in LNG ▪ Nearly all global capacity under construction (~135 mtpa ) is required to backfill Russian piped gas to Europe ▪ Global natural gas shortage leading to widespread geopolitical and economic impact ▪ Global CO 2 emissions and global coal consumption estimated to have reached all - time highs in 2022 (1) TELL 4Q22 results demonstrate growing upstream momentum and operating cash flow growth ▪ 4Q22 ending cash balance of ~$474mm; 4Q22 upstream segment operating profit of $47mm & adj. EBITDA of $81mm (2) ▪ Upstream QoQ : ~80% increase in production to 225 MMcf /d, ~24% increase in acreage to 27,689 net acres ▪ Forecasted average production of ~225 MMcf /d in 2023 Economic momentum for U.S. LNG to fulfill global gas needs continues to grow ▪ Integrated LNG production model allows for margins to expand to offset increased development costs ▪ Driftwood is best placed among U.S. projects due to site, timeline, capacity and construction progress ▪ Driftwood Phase I open capacity allows for strategic investors to directly invest at project level in low - cost U.S. LNG 1 2 3 4 Source: Tellurian analysis. Notes: (1) IEA World Energy Outlook 2022. (2) Non - GAAP measure – see slide 21 for a definition and a reconciliation to the most comparable GAAP measure.



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 ~36% 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: significant production growth in 4Q Notes: (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). (2) Non - GAAP measure – see slide 21 for a definition and a reconciliation to the most comparable GAAP measure. 6 Upstream segment 4Q22 growth Production ( MMcf /d) 3Q22 4Q22 Net acres Revenues Adjusted EBITDA ( 2) 3Q22 4Q22 3Q22 4Q22 3Q22 4Q22 $70mm ~22,420 $80mm 225 125 ~27,689 $81mm $103mm Acreage ~27,689 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 100% gas Tellurian Upstream overview (1)



Driftwood LNG: construction in progress Bechtel commenced construction in April 2022 and has : – Completed demolition of all existing land structures – Cleared and backfilled all critical Phase I areas – Driven over 30% of all Phase I piles – Commenced foundation work for Plant 1 compressors Substantially completed all critical Phase I owner’s projects: – Pipeline relocation – Highway and road widening – Exercised options on the remaining terminal land leases In June 2022, Tellurian awarded Baker Hughes a contract for electric - drive, zero - emission pipeline compressors Currently planning additional site work that will significantly advance piling, pouring foundations, construction of marine offloading facilities and other work throughout 2023 7 Driftwood site and construction progress Recent Driftwood development activities



If forward Henry Hub prices exceed global pricing, ~ 20 - 25 % of the global LNG supply becomes at risk of staying within the U.S. market. 20% 25% 0% 5% 10% 15% 20% 25% 30% 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 U.S. share of global LNG supply (%) Henry Hub will remain global gas price floor 8 International pricing / Henry Hub inversion is unsustainable due to U.S. market share on global basis Source: Wood Mackenzie, Tellurian research. Notes: Includes projects that are under construction, including Driftwood LNG. (1) Excludes exports. Price inversion scenario 2030 Expected Figures U.S. LNG Supply: ~19 Bcf /d % of U.S. gas consumption (1) (~91 bcf /d) % of global LNG supply (~75 bcf /d) ~25% ~21% Future Henry Hub - JKM/TTF pricing dynamics should ensure global gas markets are adequately supplied



257 79 178 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) ~260 mtpa of new LNG demand by 2035 ~210 mtpa of new LNG capacity required by 2035 (3)



$0 $2 $4 $6 $8 $10 $12 $14 $16 Billions How much does a USGC LNG terminal cost? 10 Example Phase 1 (~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 and contingencies. (3) Includes first phase of pipeline system and pipeline opex prior to LNG construction. (4) “Other” includes management fee to Tellurian and G&A during construction; “interest” reflects secured overnight financing r ates as of October 2022. 12 2 - plant development costs ($ bn ) LNG terminal (1) $9.0 EPC cost/tonne ($/tonne) $815 Owner’s cost (2) 1.7 Pipeline (3) 0.9 Capital cost/ tonne ($/ tonne ) $1,059 Financing, interest and other (4) 2.0 Total development costs $13.6 Total capacity ~11 mtpa LNG Feedgas requirement ~550 Bcf /year Note: Artist rendering of full 5 - plant Driftwood LNG development



$16.0 $6.75 Gas $5.75 $1.50 Market Price DW FOB Cost Shipping Realized Margin Opex + interest $2.00 Driftwood capital structure & economics 13 Illustrative project economics at 11.0 mtpa : $6.75/ mmBtu x ~550 milllion mmBtu = ~$3.7 bn annual free cash flow Illustrative Driftwood FOB cost (3) Partner equity to supplement Tellurian’s development expenditures to date Cash Flow Project Equity $4.5 bn Illustrative capital structure Unit economics Tellurian is seeking partners to invest 35 - 40% of equity in Phase I of Driftwood Project Notes: (1) Assumes Brent parity based on 2027 IHS Markit LNG and Gas Price Forecast as of January 2023 (rounded for illustrative purposes). (2) Assumes gas sourcing cost based on 2027 IHS Markit LNG and Gas Price Forecast as of January 2023 . Assumes Opex of $1.00 and interest expense of $1.00 (rounded for illustrative purposes), based on ~7% interest rate on project debt and bo nd s. (3) Assumes 52 mmBtu per ton of LNG. (1) (2) Project Debt $7.0 bn Project Bonds $1.5 bn $/ mmBtu



Illustrative cash flow at 2027 LNG pricing Notes: (1) Assumes Brent parity based on 2027 IHS Markit LNG and Gas Price Forecast as of January 2023 (rounded for illustrative purpose s) . (2) 50% Asia/50% Europe blend with transportation estimate of $1.50/ mmBtu . 14 Phase I (Plants 1 - 2) Full Development (Plants 1 - 5) LNG sales price (1,2) (less transportation, $/ mmBtu ) $14.50 $14.50 Gas sourcing (1) ($/ mmBtu ) - $5.75 - $5.75 Liquefaction and transport ($/ mmBtu ) - $1.00 - $1.00 Margin ($/ mmBtu ) = $7.75 = $7.75 Annual capacity x ~550 Bcf x ~1,380 Bcf Illustrative annual operating cash flow to Driftwood LNG before interest expense = $4.3 billion = $10.7 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






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 Shovel - ready project



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 ~36% of the 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.



– $5 $10 $15 $20 $25 LNG Forward Prices JKM TTF 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: $19/ mmBtu TTF (European benchmark) 1 - yr forward price: $18/ mmBtu Driftwood LNG Variable cost ~ $6.75/ mmBtu Sources: Wood Mackenzie, IHS Markit, Bloomberg and ICE data via Marketview . Notes: (1) Assumes maximum netback from Asia or Europe based on 02/07/2023 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 $5.75/ mmBtu for gas sourcing based on 2027 IHS Markit LNG and Gas Price Forecast as of January 2023 and $1.00/ mmBtu for plant opex and G&A. Driftwood LNG variable cost (2) = ~$6.75/ mmBtu



Supply fails to keep pace with demand Sources : Wood Mackenzie, Platts via MarketView , Tellurian analysis. Note: Capacity additions for projects that have reached FID only. 20 13 4 5 10 27 30 27 38 23 15 10 16 5 15 48 20 16 4 (8) 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 ~146 mtpa capacity additions 8.2% per annum ~80 mtpa capacity additions 1.4% per annum Global liquefaction capacity additions (mtpa) ~61 mtpa capacity additions 2.5% per annum ~30 mtpa capacity additions 1.6% per annum $14.04 $15.12 $16.54 $13.85 $7.45 $5.73 $7.13 $9.74 $5.49 JKM annual average: $4.38 $18.59 $19.14 YTD $33.98



The Company reports its financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”) . However, management believes that upstream segment Adjusted EBITDA may provide financial statement users with additional meaningful comparisons between current results and the results of the Company’s peers and of prior periods . Upstream segment Adjusted EBITDA excludes certain charges or expenditures . Upstream segment Adjusted EBITDA is a supplemental measure of performance and should not be viewed as a substitute for any GAAP measure . Management presents Upstream segment Adjusted EBITDA because ( i ) it is consistent with the manner in which the Company’s position and performance are measured relative to the position and performance of its peers and (ii) it is more comparable to earnings estimates provided by securities analysts . Explanation and Reconciliation of Non - GAAP Financial Measures 21 (in thousands, unaudited) Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Upstream segment Adjusted EBITDA: Upstream segment operating profit (loss) $40,071 $3,491 $83,170 $(4,542) Add back: Depreciation, depletion and amortization 12,762 3,635 22,441 8,419 Allocated corporate general and administrative 16,709 3,766 31,155 10,925 Upstream segment Adjusted EBITDA $69,542 $10,892 $136,766 $14,802 (in thousands) Three Months Ended December 31, Twelve Months Ended December 31, 2022 2021 2022 2021 Upstream segment Adjusted EBITDA: Upstream segment operating profit (loss) $47,493 $(1,109) $130,663 $(5,651) Add back: Depreciation, depletion and amortization $21,525 $2,661 $43,966 $11,080 Allocated corporate general and administrative $11,230 $11,747 $42,385 $22,672 Upstream segment Adjusted EBITDA $80,248 $13,299 $217,014 $28,101