TELL

false2022FY0000061398one0.17470333.33http://fasb.org/us-gaap/2022#OtherAssetsNoncurrenthttp://fasb.org/us-gaap/2022#OtherAssetsNoncurrenthttp://fasb.org/us-gaap/2022#PropertyPlantAndEquipmentAndFinanceLeaseRightOfUseAssetAfterAccumulatedDepreciationAndAmortizationhttp://fasb.org/us-gaap/2022#PropertyPlantAndEquipmentAndFinanceLeaseRightOfUseAssetAfterAccumulatedDepreciationAndAmortizationhttp://fasb.org/us-gaap/2022#AccruedLiabilitiesCurrenthttp://fasb.org/us-gaap/2022#AccruedLiabilitiesCurrenthttp://fasb.org/us-gaap/2022#AccruedLiabilitiesCurrenthttp://fasb.org/us-gaap/2022#AccruedLiabilitiesCurrenthttp://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrenthttp://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent00000613982022-01-012022-12-310000061398us-gaap:CommonStockMember2022-01-012022-12-310000061398tell:A825SeniorNotesDue2028Member2022-01-012022-12-3100000613982022-06-30iso4217:USD00000613982023-02-07xbrli:shares00000613982022-12-3100000613982021-12-31iso4217:USDxbrli:shares0000061398us-gaap:NaturalGasMidstreamMember2022-01-012022-12-310000061398us-gaap:NaturalGasMidstreamMember2021-01-012021-12-310000061398us-gaap:NaturalGasMidstreamMember2020-01-012020-12-310000061398tell:LiquefiedNaturalGasSalesMember2022-01-012022-12-310000061398tell:LiquefiedNaturalGasSalesMember2021-01-012021-12-310000061398tell:LiquefiedNaturalGasSalesMember2020-01-012020-12-3100000613982021-01-012021-12-3100000613982020-01-012020-12-3100000613982020-12-3100000613982019-12-310000061398us-gaap:PreferredStockMember2022-12-310000061398us-gaap:PreferredStockMember2021-12-310000061398us-gaap:PreferredStockMember2020-12-310000061398us-gaap:CommonStockMember2021-12-310000061398us-gaap:CommonStockMember2020-12-310000061398us-gaap:CommonStockMember2019-12-310000061398us-gaap:CommonStockMember2022-01-012022-12-310000061398us-gaap:CommonStockMember2021-01-012021-12-310000061398us-gaap:CommonStockMember2020-01-012020-12-310000061398us-gaap:CommonStockMember2022-12-310000061398us-gaap:AdditionalPaidInCapitalMember2021-12-310000061398us-gaap:AdditionalPaidInCapitalMember2020-12-310000061398us-gaap:AdditionalPaidInCapitalMember2019-12-310000061398us-gaap:AdditionalPaidInCapitalMember2022-01-012022-12-310000061398us-gaap:AdditionalPaidInCapitalMember2021-01-012021-12-310000061398us-gaap:AdditionalPaidInCapitalMember2020-01-012020-12-310000061398us-gaap:AdditionalPaidInCapitalMember2022-12-310000061398us-gaap:RetainedEarningsMember2021-12-310000061398us-gaap:RetainedEarningsMember2020-12-310000061398us-gaap:RetainedEarningsMember2019-12-310000061398us-gaap:RetainedEarningsMember2022-01-012022-12-310000061398us-gaap:RetainedEarningsMember2021-01-012021-12-310000061398us-gaap:RetainedEarningsMember2020-01-012020-12-310000061398us-gaap:RetainedEarningsMember2022-12-31tell:Segment0000061398tell:HaynesvilleShaleMember2022-12-310000061398tell:ProvedNaturalGasPropertiesMember2022-12-310000061398tell:ProvedNaturalGasPropertiesMember2021-12-310000061398tell:WellsInProgressMember2022-12-310000061398tell:WellsInProgressMember2021-12-310000061398tell:UpstreamNaturalGasAssetsMember2022-12-310000061398tell:UpstreamNaturalGasAssetsMember2021-12-310000061398us-gaap:LandAndLandImprovementsMember2022-12-310000061398us-gaap:LandAndLandImprovementsMember2021-12-310000061398us-gaap:ConstructionInProgressMember2022-12-310000061398us-gaap:ConstructionInProgressMember2021-12-310000061398tell:BuildingsAndOtherAssetsMember2022-12-310000061398tell:BuildingsAndOtherAssetsMember2021-12-310000061398tell:DriftwoodProjectMember2022-12-310000061398tell:DriftwoodProjectMember2021-12-310000061398tell:FixedAssetsAndOtherMember2022-12-310000061398tell:FixedAssetsAndOtherMember2021-12-3100000613982022-03-310000061398us-gaap:ConstructionInProgressMember2022-01-012022-12-310000061398tell:HaynesvilleShaleMember2022-08-182022-08-180000061398tell:HaynesvilleShaleMember2022-08-18tell:well00000613982022-02-240000061398us-gaap:NotesReceivableMember2022-12-31xbrli:pureutr:Mcftell:cargo0000061398tell:NaturalGasFinancialInstrumentsMember2022-01-012022-12-310000061398tell:NaturalGasFinancialInstrumentsMember2021-01-012021-12-310000061398tell:LNGFinancialFuturesMember2022-01-012022-12-310000061398tell:LNGFinancialFuturesMember2021-01-012021-12-310000061398tell:ContingentConsiderationEmbeddedDerivativeMember2022-01-012022-12-310000061398tell:ContingentConsiderationEmbeddedDerivativeMember2021-01-012021-12-310000061398tell:NaturalGasFinancialInstrumentsMember2022-12-310000061398tell:NaturalGasFinancialInstrumentsMember2021-12-310000061398tell:LNGFinancialFuturesMember2022-12-310000061398tell:LNGFinancialFuturesMember2021-12-310000061398tell:ContingentConsiderationEmbeddedDerivativeMember2022-12-310000061398tell:ContingentConsiderationEmbeddedDerivativeMember2021-12-310000061398srt:BoardOfDirectorsChairmanMember2020-01-012020-12-310000061398srt:BoardOfDirectorsChairmanMember2021-01-012021-12-310000061398srt:BoardOfDirectorsChairmanMember2022-01-012022-12-310000061398srt:BoardOfDirectorsChairmanMembersrt:ScenarioForecastMember2023-01-012023-12-310000061398tell:A600SeniorSecuredConvertibleNotesDue2025Member2022-12-310000061398tell:A825SeniorNotesDue2028Member2022-12-310000061398tell:A825SeniorNotesDue2028Member2021-12-310000061398us-gaap:ConvertibleNotesPayableMembertell:A600SeniorSecuredConvertibleNotesDue2025Member2022-06-030000061398us-gaap:ConvertibleNotesPayableMembertell:A600SeniorSecuredConvertibleNotesDue2025Member2022-06-032022-06-03tell:pipeline0000061398us-gaap:ConvertibleNotesPayableMembertell:A600SeniorSecuredConvertibleNotesDue2025Member2022-12-310000061398tell:A825SeniorNotesDue2028Memberus-gaap:SeniorNotesMember2021-11-100000061398tell:A825SeniorNotesDue2028Memberus-gaap:SeniorNotesMember2021-11-102021-11-100000061398tell:A825SeniorNotesDue2028Memberus-gaap:SeniorNotesMember2021-12-070000061398tell:A825SeniorNotesDue2028Memberus-gaap:SeniorNotesMember2021-12-072021-12-070000061398tell:AtTheMarketDebtOfferingProgramMemberus-gaap:SeniorNotesMember2021-12-170000061398tell:AtTheMarketDebtOfferingProgramMemberus-gaap:SeniorNotesMember2022-01-012022-12-310000061398tell:A2020SeniorUnsecuredNoteMemberus-gaap:SeniorNotesMember2020-04-290000061398tell:A2019TermLoanMemberus-gaap:LoansPayableMember2019-05-230000061398tell:A2019TermLoanMemberus-gaap:LoansPayableMember2019-07-160000061398tell:A2019TermLoanMembertell:OriginalWarrantMemberus-gaap:LoansPayableMember2019-05-230000061398tell:ReplacementWarrantMembertell:A2019TermLoanMemberus-gaap:LoansPayableMember2020-03-030000061398tell:A2019TermLoanMemberus-gaap:LoansPayableMember2021-03-122021-03-120000061398tell:A2019TermLoanMemberus-gaap:LoansPayableMember2021-01-012021-12-310000061398tell:A2019TermLoanMemberus-gaap:LoansPayableMember2022-12-310000061398tell:A2018TermLoanMemberus-gaap:LoansPayableMember2018-09-282018-09-280000061398tell:A2018TermLoanMemberus-gaap:LoansPayableMember2018-09-280000061398tell:A2018TermLoanMemberus-gaap:LoansPayableMember2021-01-012021-12-310000061398us-gaap:ConvertibleNotesPayableMembertell:A600SeniorSecuredConvertibleNotesDue2025Member2022-01-012022-12-310000061398tell:TradeFinanceCreditLineMember2021-07-190000061398tell:TradeFinanceCreditLineMember2021-12-070000061398tell:TradeFinanceCreditLineMember2022-12-310000061398tell:AtTheMarketEquityOfferingProgramsMember2022-01-012022-12-310000061398tell:NewAtTheMarketEquityOfferingProgramMember2022-12-300000061398tell:NewAtTheMarketEquityOfferingProgramMember2022-12-310000061398tell:EquityOfferingInAug2021Memberus-gaap:CommonStockMember2021-08-062021-08-060000061398tell:EquityOfferingInAug2021Memberus-gaap:CommonStockMember2021-08-060000061398us-gaap:OverAllotmentOptionMemberus-gaap:CommonStockMember2021-08-312021-08-310000061398tell:A2019TermLoanMemberus-gaap:LoansPayableMember2021-03-310000061398tell:A2019TermLoanMemberus-gaap:LoansPayableMember2021-01-012021-03-310000061398us-gaap:ConvertiblePreferredStockMember2018-03-012018-03-3100000613982020-07-012020-07-31tell:numberOfInstallment0000061398tell:A2016PlanMember2022-12-310000061398tell:PerformanceBasedRestrictedStockMember2022-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheOneMembertell:PerformanceBasedRestrictedStockMember2022-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheTwoMembertell:PerformanceBasedRestrictedStockMember2022-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheThreeMembertell:PerformanceBasedRestrictedStockMember2022-12-310000061398tell:PerformanceBasedRestrictedStockMember2022-01-012022-12-310000061398us-gaap:RestrictedStockMember2022-01-012022-12-310000061398us-gaap:RestrictedStockMember2021-12-310000061398us-gaap:RestrictedStockMember2022-01-012022-12-310000061398us-gaap:RestrictedStockMember2022-12-310000061398us-gaap:RestrictedStockMember2021-01-012021-12-310000061398us-gaap:RestrictedStockMember2020-01-012020-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheOneMember2020-01-012020-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheOneMember2020-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheTwoMember2020-01-012020-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheTwoMember2020-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheThreeMember2020-01-012020-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheThreeMember2020-12-310000061398us-gaap:EmployeeStockOptionMember2020-01-012020-12-310000061398us-gaap:EmployeeStockOptionMember2022-01-012022-12-310000061398us-gaap:ShareBasedCompensationAwardTrancheTwoMembertell:PerformanceBasedRestrictedStockMember2022-01-012022-12-310000061398tell:ShortTermIncentiveAwardsMember2022-01-012022-12-310000061398tell:ShortTermIncentiveAwardsMember2021-01-012021-12-310000061398tell:LongTermIncentiveAwardsMember2022-01-012022-12-31tell:vesting_tranche0000061398tell:A2021LTIAwardMember2021-12-310000061398tell:A2021LTIAwardMember2022-01-012022-12-310000061398tell:A2021LTIAwardMember2022-12-310000061398tell:LongTermIncentiveAwardsMember2021-01-012021-12-310000061398us-gaap:OperatingSegmentsMembertell:UpstreamSegmentMember2022-01-012022-12-310000061398tell:MidstreamSegmentMemberus-gaap:OperatingSegmentsMember2022-01-012022-12-310000061398us-gaap:OperatingSegmentsMembertell:MarketingTradingSegmentMember2022-01-012022-12-310000061398us-gaap:CorporateNonSegmentMember2022-01-012022-12-310000061398us-gaap:IntersegmentEliminationMembertell:UpstreamSegmentMember2022-01-012022-12-310000061398tell:MidstreamSegmentMemberus-gaap:IntersegmentEliminationMember2022-01-012022-12-310000061398tell:MarketingTradingSegmentMemberus-gaap:IntersegmentEliminationMember2022-01-012022-12-310000061398us-gaap:IntersegmentEliminationMember2022-01-012022-12-310000061398us-gaap:OperatingSegmentsMembertell:UpstreamSegmentMember2021-01-012021-12-310000061398tell:MidstreamSegmentMemberus-gaap:OperatingSegmentsMember2021-01-012021-12-310000061398us-gaap:OperatingSegmentsMembertell:MarketingTradingSegmentMember2021-01-012021-12-310000061398us-gaap:CorporateNonSegmentMember2021-01-012021-12-310000061398us-gaap:IntersegmentEliminationMembertell:UpstreamSegmentMember2021-01-012021-12-310000061398tell:MidstreamSegmentMemberus-gaap:IntersegmentEliminationMember2021-01-012021-12-310000061398tell:MarketingTradingSegmentMemberus-gaap:IntersegmentEliminationMember2021-01-012021-12-310000061398us-gaap:IntersegmentEliminationMember2021-01-012021-12-310000061398us-gaap:OperatingSegmentsMembertell:UpstreamSegmentMember2020-01-012020-12-310000061398tell:MidstreamSegmentMemberus-gaap:OperatingSegmentsMember2020-01-012020-12-310000061398us-gaap:OperatingSegmentsMembertell:MarketingTradingSegmentMember2020-01-012020-12-310000061398us-gaap:CorporateNonSegmentMember2020-01-012020-12-310000061398us-gaap:IntersegmentEliminationMembertell:UpstreamSegmentMember2020-01-012020-12-310000061398tell:MidstreamSegmentMemberus-gaap:IntersegmentEliminationMember2020-01-012020-12-310000061398tell:MarketingTradingSegmentMemberus-gaap:IntersegmentEliminationMember2020-01-012020-12-310000061398us-gaap:IntersegmentEliminationMember2020-01-012020-12-310000061398us-gaap:OperatingSegmentsMember2022-01-012022-12-310000061398us-gaap:OperatingSegmentsMember2021-01-012021-12-310000061398us-gaap:OperatingSegmentsMember2020-01-012020-12-310000061398srt:NaturalGasReservesMember2019-12-310000061398srt:OilReservesMember2019-12-31utr:bbl0000061398srt:NaturalGasLiquidsReservesMember2019-12-31utr:Mcfe0000061398srt:NaturalGasReservesMember2020-01-012020-12-310000061398srt:OilReservesMember2020-01-012020-12-310000061398srt:NaturalGasLiquidsReservesMember2020-01-012020-12-310000061398srt:NaturalGasReservesMember2020-12-310000061398srt:OilReservesMember2020-12-310000061398srt:NaturalGasLiquidsReservesMember2020-12-310000061398srt:NaturalGasReservesMember2021-01-012021-12-310000061398srt:OilReservesMember2021-01-012021-12-310000061398srt:NaturalGasLiquidsReservesMember2021-01-012021-12-310000061398srt:NaturalGasReservesMember2021-12-310000061398srt:OilReservesMember2021-12-310000061398srt:NaturalGasLiquidsReservesMember2021-12-310000061398srt:NaturalGasReservesMember2022-01-012022-12-310000061398srt:OilReservesMember2022-01-012022-12-310000061398srt:NaturalGasLiquidsReservesMember2022-01-012022-12-310000061398srt:NaturalGasReservesMember2022-12-310000061398srt:OilReservesMember2022-12-310000061398srt:NaturalGasLiquidsReservesMember2022-12-31utr:Bcfe

FORM			10-K

☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2022

OR

☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Delaware

06-0842255

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

1201 Louisiana Street,

Suite 3100,

Houston,

TX

77002

(Address of principal executive offices)

(Zip Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading symbol

Name of each exchange on which registered

Common stock, par value $0.01 per share

TELL

NYSE

American LLC

8.25% Senior Notes due 2028

TELZ

NYSE

American LLC

Securities registered pursuant to Section 12(g) of the Act:

None

Yes			☒			No			☐

Yes			☐			No			☒

Yes			☒			No			☐

Yes			☒			No			☐

Large accelerated filer			☒			Accelerated filer			☐
Non-accelerated filer			☐			Smaller reporting company			☐
						Emerging growth company			☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Yes			☐			No			☒

563,518,417 shares of common stock were issued and outstanding as of February 7, 2023.

						Page
			Part I
Item 1 and 2.			Our Business and Properties			1
Item 1A.			Risk Factors			14
Item 1B.			Unresolved Staff Comments			28
Item 3.			Legal Proceedings			28
Item 4.			Mine Safety Disclosures			28
			Part II
Item 5.			Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities			29
Item 6.			[Reserved]			30
Item 7.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
Item 7A.			Quantitative and Qualitative Disclosures About Market Risk			36
Item 8.			Financial Statements and Supplementary Data			37
Item 9.			Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			68
Item 9A.			Controls and Procedures			68
Item 9B.			Other Information			70
Item 9C.			Disclosure Regarding Foreign Jurisdictions that Prevents Inspections			70
			Part III
Item 10.			Directors, Executive Officers and Corporate Governance			71
Item 11.			Executive Compensation			71
Item 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			71
Item 13.			Certain Relationships and Related Transactions, and Director Independence			71
Item 14.			Principal Accounting Fees and Services			71
			Part IV
Item 15.			Exhibits, Financial Statement Schedules			72
Item 16.			Form 10-K Summary			77
Signatures						78

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, that address activity, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “contemplate,” “continue,” “could,” “estimate,” “expect,” “forecast,” “initial,” “intend,” “likely,” “may,” “plan,” “possible,” “potential,” “predict,” “project,” “proposed,” “should,” “will,” “would” and similar terms, phrases, and expressions are intended to identify forward-looking statements. These forward-looking statements relate to, among other things:

•our businesses and prospects and our overall strategy;

•planned or estimated capital expenditures;

•availability of liquidity and capital resources;

•our ability to obtain financing as needed and the terms of financing transactions, including for the Driftwood Project;

•revenues and expenses;

•progress in developing our projects and the timing of that progress;

•attributes and future values of the Company’s projects or other interests, operations or rights; and

•government regulations, including our ability to obtain, and the timing of, necessary governmental permits and approvals.

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 a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that could cause actual results and performance to differ materially from any future results or performance expressed or implied by the forward-looking statements include, but are not limited to, the following:

•the uncertain nature of demand for and price of natural gas and LNG;

•risks related to shortages of LNG vessels worldwide;

•technological innovation which may render our anticipated competitive advantage obsolete;

•risks related to a terrorist or military incident involving an LNG carrier;

•changes in legislation and regulations relating to the LNG industry, including environmental laws and regulations that impose significant compliance costs and liabilities;

•governmental interventions in the LNG industry, including increases in barriers to international trade;

•uncertainties regarding our ability to maintain sufficient liquidity and attract sufficient capital resources to implement our projects;

•our limited operating history;

•our ability to attract and retain key personnel;

•risks related to doing business in, and having counterparties in, foreign countries;

•our reliance on the skill and expertise of third-party service providers;

•the ability of our vendors, customers and other counterparties to meet their contractual obligations;

•risks and uncertainties inherent in management estimates of future operating results and cash flows;

•our ability to maintain compliance with our debt arrangements;

•changes in competitive factors, including the development or expansion of LNG, pipeline and other projects that are competitive with ours;

•development risks, operational hazards and regulatory approvals;

•our ability to enter into and consummate planned financing and other transactions;

•risks related to pandemics or disease outbreaks;

•risks of potential impairment charges and reductions in our reserves; and

•risks and uncertainties associated with litigation matters.

The forward-looking statements in this report speak 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.

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. As used in this document, the terms listed below have the following meanings:

ASC			Accounting Standards Codification
Bcf			Billion cubic feet of natural gas
Bcfe			Billion cubic feet of natural gas equivalent volumes using a ratio of 6 Mcf to 1 barrel of liquid
Condensate			Hydrocarbons that exist in a gaseous phase at original reservoir temperature and pressure, but when produced, are in the liquid phase at surface pressure and temperature
DD&A			Depreciation, depletion, and amortization
DFC			Deferred financing costs
DOE/FECM			U.S. Department of Energy, Office of Fossil Energy and Carbon Management
EPC			Engineering, procurement, and construction
FASB			Financial Accounting Standards Board
FEED			Front-End Engineering and Design
FERC			U.S. Federal Energy Regulatory Commission
FID			Final investment decision as it pertains to the Driftwood Project
FTA countries			Countries with which the U.S. has a free trade agreement providing for national treatment for trade in natural gas
GAAP			Generally accepted accounting principles in the U.S.
Henry Hub			A common market pricing point for natural gas in the United States, located in Louisiana.
LNG			Liquefied natural gas
LSTK			Lump Sum Turnkey
Mcf			Thousand cubic feet of natural gas
MMBtu			Million British thermal unit
MMcf			Million cubic feet of natural gas
MMcf/d			MMcf per day
MMcfe			Million cubic feet of natural gas equivalent volumes using a ratio of 6 Mcf to 1 barrel of liquid
Mtpa			Million tonnes per annum
NGA			Natural Gas Act of 1938, as amended
Non-FTA countries			Countries with which the U.S. does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
NYMEX			New York Mercantile Exchange
NYSE American			NYSE American LLC
Oil			Crude oil and condensate
Phase 1			Plants one and two of the Driftwood terminal
PUD			Proved undeveloped reserves
SEC			U.S. Securities and Exchange Commission
SPA			Sale and purchase agreement
Train			An industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
U.K.			United Kingdom
U.S.			United States
USACE			U.S. Army Corps of Engineers

With respect to the information relating to our ownership in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

PART I

ITEM 1 AND 2. OUR BUSINESS AND PROPERTIES

Tellurian Inc. (“Tellurian,” “we,” “us,” “our,” or the “Company”), a Delaware corporation, is a Houston-based company that is developing and plans to own and operate a portfolio of natural gas, LNG marketing, and infrastructure assets that includes an LNG terminal facility (the “Driftwood terminal”), an associated pipeline (the “Driftwood pipeline”), other related pipelines, and upstream natural gas assets (collectively referred to as the “Business”). The Driftwood terminal and the Driftwood pipeline are collectively referred to as the “Driftwood Project.” As of December 31, 2022, our upstream natural gas assets consist of 27,689 net acres and interests in 143 producing wells located in the Haynesville Shale trend of northern Louisiana. Our Business may be developed in phases.

As part of our execution strategy, which includes increasing our asset base, we will consider various commercial arrangements with third parties across the natural gas value chain. We are also pursuing activities such as direct sales of LNG to global counterparties, trading of LNG, the acquisition of additional upstream acreage and drilling of new wells on our existing or newly acquired upstream acreage. We remain focused on the financing and construction of the Driftwood Project and related pipelines while managing our upstream assets.

We manage and report our operations in three reportable segments. The Upstream segment is organized and operates to produce, gather, and deliver natural gas and to acquire and develop natural gas assets. The Midstream segment is organized to develop, construct and operate LNG terminals and pipelines. The Marketing & Trading segment is organized and operates to purchase and sell natural gas produced primarily by the Upstream segment, market the Driftwood terminal’s LNG production capacity and trade LNG.

We continue to evaluate the scope and other aspects of our Business in light of the evolving economic environment, dynamics of the global political landscape, needs of potential counterparties and other factors. How we execute our Business will be based on a variety of factors, including the results of our continuing analysis, changing business conditions and market feedback.

On March 24, 2022, the Company issued a limited notice to proceed to Bechtel Energy Inc., formerly known as Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”), under our LSTK EPC agreement for Phase 1 of the Driftwood terminal dated as of November 10, 2017 (the “Phase 1 EPC Agreement”). The Company commenced construction of Phase 1 of the Driftwood terminal on April 4, 2022.

On June 3, 2022, we issued and sold $500.0 million aggregate principal amount of 6.00% Senior Secured Convertible Notes due May 1, 2025 (the “Convertible Notes”). Net proceeds from the Convertible Notes were approximately $488.7 million after deducting fees and expenses.

On August 18, 2022, the Company completed the acquisition of certain natural gas assets in the Haynesville Shale basin. The purchase price of $125.0 million was subject to customary adjustments totaling approximately $8.8 million, for an adjusted purchase price of approximately $133.8 million.

During the year ended December 31, 2021, the Company entered into a pledge with the National Forest Foundation on a five-year plan for reforestation and other forest management projects totaling $25.0 million across the United States. In 2022, the Company supported the planting of more than one million trees on 1,441 acres across the United States and bolstered nursery capacity by one million seedlings.

Our natural gas assets consist of 27,689 net acres and interests in 143 producing wells located in the Haynesville Shale trend of north Louisiana. For the year ended December 31, 2022, our average net production was approximately 129.7 MMcf/d. All of our proved reserves were associated with those properties as of December 31, 2022. Proved reserves are the estimated quantities of natural gas and condensate which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., costs as of the date the estimate is made). Proved reserves are categorized as either developed or undeveloped.

Our reserves as of December 31, 2022 were estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm, and are set forth in the following table. Per SEC rules, NSAI based its estimates on the 12-month unweighted arithmetic average of the first-day-of-the-month price of natural gas for each month from January through December 2022. Prices include consideration of changes in existing prices provided for under contractual arrangements, but not on escalations or reductions based upon future conditions. The price used for the reserve estimates as of December 31, 2022 was $6.36 per MMBtu of natural gas, adjusted for energy content, transportation fees and market differentials.

The following table shows our proved reserves as of December 31, 2022:

			Natural Gas (MMcf)
Proved reserves (as of December 31, 2022):
Developed			218,382
Undeveloped			226,511
Total proved reserves			444,893

As of December 31, 2022, the standardized measure of discounted future net cash flow from our proved reserves (the “standardized measure”) was approximately $1,036.3 million.

During the year ended December 31, 2022, the Company spent approximately $140.0 million on the conversion of our proved undeveloped reserves to proved developed reserves. The Company converted approximately 138 Bcfe of proved undeveloped to proved developed reserves, which represents a conversion rate of approximately 43%.

Refer to Supplemental Disclosures About Natural Gas Producing Activities, starting on page 63, for additional details.

Our December 31, 2022 reserve report was prepared by NSAI in accordance with guidelines established by the SEC. Reserve definitions comply with the definitions provided by Regulation S‑X of the SEC. NSAI prepared the reserve report based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provided to them. This information was reviewed by knowledgeable members of our Company for accuracy and completeness prior to submission to NSAI. A letter that identifies the professional qualifications of the individual at NSAI who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2022, has been filed as an addendum to Exhibit 99.1 to this report and is incorporated by reference herein.

Internally, a Senior Vice President is responsible for overseeing our reserves process. Our Senior Vice President has over 20 years of experience in the oil and natural gas industry, with the majority of that time in reservoir engineering and asset management. She is a graduate of Virginia Polytechnic Institute and State University with dual degrees in Chemical Engineering and French, and a graduate of the University of Houston with a Masters of Business Administration degree. During her career, she has had multiple responsibilities in technical and leadership roles, including reservoir engineering and reserves management, production engineering, planning, and asset management for multiple U.S. onshore and international projects. She is also a licensed Professional Engineer in the State of Texas.

For the years ended December 31, 2022, 2021 and 2020, we produced 47,322 MMcf, 14,302 MMcf and 16,893 MMcf of natural gas at an average sales price of $5.78, $3.52 and $1.74 per Mcf, respectively. Natural gas production and operating costs for the periods ended December 31, 2022, 2021 and 2020 were $0.37, $0.48 and $0.28 per Mcfe, respectively.

The information in the table below should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found, or economic value. A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. A productive well is an exploratory, development, or extension well that is not a dry well. Completion refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. The table below shows the number of net productive and dry development operated and non-operated wells drilled during the past three years.

						For the Year Ended December 31,
						2022						2021						2020
Development wells:
Productive						13.5						6.9						—
Dry						—						—						—
We had no exploratory wells drilled during any of the periods presented.

As of December 31, 2022, we owned working interests in 114 gross (45.6 net) productive natural gas wells. As of December 31, 2022, there were 22 gross (9.7 net) in process wells.

We have 7,982 gross (7,063 net) developed leasehold acres that are held by production. Additionally, we hold 21,650 gross (20,626 net) undeveloped leasehold acres. Of the total gross and net undeveloped acreage, 16,091 gross (15,681 net) acres are not held by production, of which 1,441 gross and net acres are set to expire in the fourth quarter of 2023 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.

As part of our acquisitions of natural gas properties, we also acquired certain gathering systems that deliver the natural gas we produce into third-party gathering systems. We believe that these systems and other available midstream facilities and services in the Haynesville Shale trend are adequate for our current operations and near-term growth.

Our operations are and will be subject to extensive federal, state and local statutes, rules, regulations, and laws that include, but are not limited to, the NGA, the Energy Policy Act of 2005 (“EPAct 2005”), the Oil Pollution Act, the National Environmental Policy Act (“NEPA”), the Clean Air Act (the “CAA”), the Clean Water Act (the “CWA”), the Resource Conservation and Recovery Act (“RCRA”), the Pipeline Safety Improvement Act of 2002 (the “PSIA”), and the Coastal Zone Management Act (the “CZMA”), as amended from time to time. These statutes cover areas related to the authorization, construction and operation of LNG facilities, natural gas pipelines and natural gas producing properties, including discharges and releases to the air, land and water, and the handling, generation, storage and disposal of hazardous materials and solid and hazardous wastes. These laws are administered and enforced by governmental agencies including but not limited to FERC, the U.S. Environmental Protection Agency (the “EPA”), DOE/FECM, the U.S. Department of Transportation (“DOT”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the Louisiana Department of Environmental Quality and the Louisiana Department of Natural Resources. Additionally, numerous other governmental and regulatory permits and

We have received regulatory permits and approvals in connection with the Driftwood terminal, Driftwood pipeline, and related pipelines, including the following:

Agency			Permit / Consultation			Approval Date (Anticipated)
FERC			Section 3 and Section 7 Application - NGA Related Pipeline - Section Related Pipeline - Section 7 Application			April 18, 2019 March 2023
DOE			Section 3 Application - NGA			FTA countries: February 28, 2017 (3968); amended December 6, 2018 (3968-A); amended December 18, 2020 (4641) Non-FTA countries: May 2, 2019 (4373); amended December 10, 2020 (4373-A); amended December 18, 2020 (4641)
USACE			Section 404 Section 10 (Rivers and Harbors Act)			May 3, 2019 May 3, 2019
			Related Pipeline - Section 404 Related Pipeline - Section 10			January 31, 2023 January 31, 2023
United States Coast Guard			Letter of Intent and Preliminary Water Suitability Assessment			June 21, 2016
			Follow-On Water Suitability Assessment and Letter of Recommendation			April 25, 2017
United States Fish and Wildlife Service			Section 7 of Endangered Species Act Consultation Related Pipeline - Section 7 of Endangered Species Act Consultation			September 19, 2017; February 7, 2019 August 11, 2021; October 27, 2021; April 26, 2022; June 30, 2022
National Oceanic and Atmospheric Administration / National Marine Fisheries Service			Section 7 of the Endangered Species Act Consultation			February 14, 2018
			Magnuson-Stevens Fishery Management and Conservation Act Essential Fish Habitat Consultation			October 3, 2017
			Marine Mammal Protection Act Consultation			October 3, 2017
State
Louisiana Department of Natural Resources- Coastal Management Division			Coastal Use Permit and Coastal Zone Consistency Permit, Joint Permit with USACE			May 21, 2020 (extension)
Louisiana Department of Environmental Quality - Air Quality Division			Air Permit for LNG Terminal Gillis Compressor Station Related Pipeline - Indian Bayou Compressor Station			June 2, 2021 (extension) July 6, 2022 (renewal) March 2023
Louisiana State Historic Preservation Office			Section 106 Consultation			Concurrence received on June 29, 2016
						Concurrence received on November 22, 2016
						Concurrence received on April 13, 2017
						Concurrence received on March 1, 2019
			Related Pipeline - Section 106 Consultation			Concurrence received on July 28, 2021
						Concurrence received on November 15, 2021
						Concurrence received on March 16, 2022
						Concurrence received on July 26, 2022

Federal Energy Regulatory Commission

The design, construction and operation of natural gas liquefaction facilities and pipelines, the export of LNG and the transportation of natural gas are highly regulated activities. In order to site, construct and operate the Driftwood Project, we obtained authorizations from FERC under Section 3 and Section 7 of the NGA as well as several other material governmental and regulatory approvals and permits as detailed in the table above. Construction of the Driftwood terminal has commenced. In order to gain regulatory certainty with respect to certain potential commercial transactions, on November 13, 2020, the Company filed a Petition with FERC requesting, among other things, a prospective limited waiver of FERC’s buy/sell

EPAct 2005 amended Section 3 of the NGA to establish or clarify FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, although except as specifically provided in EPAct 2005, nothing in the statute is intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals.

In 2002, FERC concluded that it would apply light-handed regulation to the rates, terms and conditions agreed to by parties for LNG terminalling services, such that LNG terminal owners would not be required to provide open-access service at non-discriminatory rates or maintain a tariff or rate schedule on file with FERC, as distinguished from the requirements applied to FERC-regulated interstate natural gas pipelines. Although EPAct 2005 codified FERC’s policy, those provisions expired on January 1, 2015. Nonetheless, we see no indication that FERC intends to modify its longstanding policy of light-handed regulation of LNG terminal operations.

A certificate of public convenience and necessity from FERC is required for the construction and operation of facilities used in interstate natural gas transportation, including pipeline facilities, in addition to other required governmental and regulatory approvals. In this regard, in April 2019, the Company obtained a certificate of public convenience and necessity to construct and operate the Driftwood pipeline. On June 17, 2021, the Company filed an application pursuant to Section 7(c) of the NGA in FERC Docket No. CP21-465-000, which, as amended, requests that FERC grant a certificate of public convenience and necessity and related approvals to construct, own and operate dual 42-inch diameter natural gas pipelines, an approximately 211,200 horsepower compressor station and appurtenant facilities to be located in Beauregard and Calcasieu Parishes, Louisiana, which would provide a maximum seasonal capacity of 5.7 Bcf of natural gas per day. FERC issued the final environmental impact statement for the project on September 15, 2022. The final order on the application is still pending.

FERC’s jurisdiction under the NGA generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate consumption for domestic, commercial, industrial or any other use and to natural gas companies engaged in such transportation or sale. FERC’s jurisdiction does not extend to the production, gathering, local distribution or export of natural gas.

Specifically, FERC’s authority to regulate interstate natural gas pipelines includes:

•rates and charges for natural gas transportation and related services;

•the certification and construction of new facilities;

•the extension and abandonment of services and facilities;

•the maintenance of accounts and records;

•the acquisition and disposition of facilities;

•the initiation and discontinuation of services; and

•various other matters.

In addition, FERC has the authority to approve, and if necessary set, “just and reasonable rates” for the transportation or sale of natural gas in interstate commerce. Relatedly, under the NGA, our proposed pipelines will not be permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including our own affiliates.

EPAct 2005 amended the NGA to make it unlawful for any entity, including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. EPAct 2005 also gives FERC authority to impose civil penalties for violations of the NGA or Natural Gas Policy Act of more than $1 million per day per violation.

Transportation of the natural gas we produce, and the prices we pay for such transportation, will be significantly affected by the foregoing laws and regulations.

Under the NGA, exports of natural gas to FTA countries are “deemed to be consistent with the public interest,” and authorization to export LNG to FTA countries shall be granted by the DOE/FECM “without modification or delay.” FTA countries currently capable of importing LNG include but are not limited to Canada, Chile, Colombia, Jordan, Mexico, Singapore, South Korea and the Dominican Republic. Exports of natural gas to Non-FTA countries are authorized unless the DOE/FECM “finds that the proposed exportation” “will not be consistent with the public interest.” We have authorization from the DOE/FECM to export LNG in a volume up to the equivalent of 1,415.3 Bcf per year of natural gas to FTA countries for a term of 30 years and to Non-FTA countries for a term through December 31, 2050.

The Natural Gas Pipeline Safety Act of 1968 (the “NGPSA”) authorizes DOT to regulate pipeline transportation of natural (flammable, toxic, or corrosive) gas and other gases, as well as the transportation and storage of LNG. Amendments to the NGPSA include the Pipeline Safety Act of 1979, which addresses liquids pipelines, and the PSIA, which governs the areas of testing, education, training, and communication.

PHMSA administers pipeline safety regulations for jurisdictional gas gathering, transmission, and distribution systems under minimum federal safety standards. PHMSA also establishes and enforces safety regulations for onshore LNG facilities, which are defined as pipeline facilities used for the transportation or storage of LNG subject to such safety standards. Those regulations address requirements for siting, design, construction, equipment, operations, personnel qualification and training, fire protection, and security of LNG facilities. The Driftwood terminal will be subject to such PHMSA regulations.

The Driftwood pipeline and other related pipelines will also be subject to regulation by PHMSA, including those under the PSIA. The PHMSA Office of Pipeline Safety administers the PSIA, which requires pipeline companies to perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as “high consequence areas.” Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for natural gas transportation pipelines, which requires pipeline operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline, as necessary; and implement preventive and mitigative actions.

On December 27, 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act (PIPES Act) of 2020 was signed into law as part of the Consolidated Appropriations Act of 2021. The legislation reauthorizes the PHMSA pipeline safety program through fiscal year 2023 and provides for advances to improve pipeline safety. The legislation includes a directive to PHMSA to update its current regulations for large-scale LNG facilities.

On January 11, 2021, PHMSA published a final rule in the Federal Register amending the Federal Pipeline Safety Regulations to reduce regulatory burdens and offer greater flexibility with respect to the construction, maintenance, and operation of gas transmission, distribution, and gathering pipeline systems, including updates to corrosion control requirements and test requirements for pressure vessels. Mandatory compliance with this rule started on October 1, 2021.

On November 15, 2021, PHMSA published a final rule in the Federal Register revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas gathering pipelines. The rule extends reporting requirements to all gas gathering operators and applies a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. This rule went into effect on May 16, 2022.

On April 8, 2022, PHMSA published a final rule in the Federal Register revising the Federal Pipeline Safety Regulations applicable to most newly constructed and entirely replaced onshore gas transmission, certain gas gathering, and hazardous liquid pipelines with diameters of six inches or greater. In the revised regulations, PHMSA establishes requirements for operators of these lines to install rupture-mitigation valves or alternative equivalent technologies and establishes minimum

On August 24, 2022, as subsequently corrected on October 25, 2022, PHMSA published a final rule in the Federal Register revising the Federal Pipeline Safety Regulations relating to improved safety of onshore gas transmission pipelines. The amendments in this final rule clarify certain integrity management provisions, codify a management of change process, update and bolster gas transmission pipeline corrosion control requirements, require operators to inspect pipelines following extreme weather events, strengthen integrity management assessment requirements, adjust the repair criteria for high-consequence areas, create new repair criteria for non-high consequence areas, and revise or create specific definitions related to the amendments. The rule goes into effect on May 24, 2023.

The Driftwood pipeline and other related pipelines will be subject to regulation by PHMSA, which will involve capital and operating costs for compliance-related equipment and operations. We have no reason to believe that these compliance costs will be material to our financial performance, but the significance of such costs will depend on future events and our ability to achieve and maintain compliance throughout the life of the Driftwood Project or related pipelines.

The State of Louisiana also administers certain federal pipeline safety standards under the NGPSA, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal sanctions.

The construction and operation of the Driftwood terminal and Driftwood pipeline are subject to federal permits, orders, approvals and consultations required by other federal and state agencies, including DOT, the Advisory Council on Historic Preservation, USACE, U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the EPA and the U.S. Department of Homeland Security. The necessary permits required for construction have been obtained and will be required to be maintained for the Driftwood terminal and Driftwood pipeline. Similarly, additional permits, orders, approvals and consultations will be required for other related pipelines.

Three significant permits that apply to the Driftwood terminal and Driftwood pipeline are the USACE Section 404 of the CWA/Section 10 of the Rivers and Harbors Act Permit, the CAA Title V Operating Permit and the Prevention of Significant Deterioration Permit, of which the latter two permits are issued by the Louisiana Department of Environmental Quality. Each of the Driftwood terminal and Driftwood pipeline has received its permit from the USACE, including a review and approval by the USACE of the findings and conditions set forth in an Environmental Impact Statement and Record of Decision issued for the Driftwood terminal and Driftwood pipeline pursuant to the requirements of NEPA. The Louisiana Department of Environmental Quality has issued the Prevention of Significant Deterioration permit, which is required to commence construction of the Driftwood terminal, as well as the Title V Operating Permit. These material approvals may be required for other related pipelines.

Our operations are and will be subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources, the handling, generation, storage and disposal of hazardous materials and solid and hazardous wastes and other matters. These environmental laws and regulations, which can restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment, will require significant expenditures for compliance, can affect the cost and output of operations, may impose substantial administrative, civil and/or criminal penalties for non-compliance and can result in substantial liabilities. The statutes, regulations and permit requirements imposed under environmental laws are modified frequently, sometimes retroactively. Such changes are difficult to predict or prepare for, and may impose material costs for new permits, capital investment or operational limitations or changes.

The Biden Administration has issued a number of executive orders that direct federal agencies to take actions that may change regulations and guidance applicable to our business.

For example, Executive Order 14008, “Tackling the Climate Crisis at Home and Abroad,” 86 FR 7619 (January 27, 2021), establishes a policy “promoting the flow of capital toward climate-aligned investments and away from high-carbon investments.” It also requires the heads of agencies to identify any fossil fuel subsidies provided by their respective agencies, and to seek to eliminate fossil fuel subsidies from the budget request for fiscal year 2022 and thereafter.

Relatedly, multiple states have challenged the Biden Administration’s interim values for the social cost of greenhouse gases in the federal courts and these challenges remain pending. Regulation and judicial challenges in these areas are evolving and we cannot predict their ultimate impact, but these issues could have an impact on the Company’s operations and financial condition.

NEPA. NEPA and comparable state laws and regulations require that government agencies review the environmental impacts of proposed projects. On January 9, 2023, the CEQ published interim guidance for federal agencies on the consideration of greenhouse gas (“GHG”) emissions and climate change under NEPA and is seeking public comment through March 10, 2023. The impact on us of these and future developments in NEPA regulation and guidance is not determinable at this time, especially with respect to those aspects of our operations and development projects that may require future federal approvals.

Clean Air Act. The CAA and comparable state laws and regulations restrict the emission of air pollutants from many sources and impose various monitoring and reporting requirements, among other requirements. The Driftwood Project and related pipelines include facilities and operations that are subject to the federal CAA and comparable state and local laws, including requirements to obtain pre-construction permits and operating permits. We may be required to incur capital expenditures for air pollution control equipment in connection with maintaining or obtaining permits and approvals pursuant to the CAA and comparable state laws and regulations.

In November 2021, the EPA published a proposed rule, which it then supplemented with a November 2022 update, that would create significant new requirements and standards designed to reduce air emissions (including methane and volatile organic compounds) from new and existing oil and gas operations, including oil and gas wells, controllers, pumps, storage vessels, and compressor stations, through measures such as leak detection monitoring and repair and the elimination of flaring except under limited circumstances. The impact of these proposed oil and gas regulations on the Driftwood Project and other related pipelines and any related costs and obligations are not determinable at this time.

On January 6, 2023, the EPA issued pre-publication proposed revisions to the primary (health-based) annual PM2.5 standard from its current level of 12.0 µg/m3 to a maximum within the range of 9.0 to 10.0 µg/m3. The EPA will accept public comment on the proposed revisions for 60 days following the publication of the revisions in the Federal Register. The impact of such revisions on the Driftwood Project and related pipelines cannot be predicted at this time.

In addition, under the Biden Administration, the EPA has released guidance documents intended to assist in the evaluation of environmental justice considerations in many aspects of governmental decision making. Among other things, the guidance emphasizes a focus on advancing environmental justice goals in connection with federal permitting and regulatory programs like the Clean Air Act. The impact of this guidance on us is not determinable at this time.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of GHGs are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources, including LNG terminals.

As discussed above, the Biden Administration has issued Executive Orders with respect to certain governmental actions related to climate change, and the EPA has promulgated, and may promulgate additional, regulations for sources of GHG emissions that could affect the oil and gas sector, and Congress or states may enact new GHG legislation, any of which could impose emission limits on the Driftwood Project or related pipelines or require us to implement additional pollution control technologies, pay fees related to GHG emissions or implement mitigation measures. On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA”). The IRA imposes a fee of up to $1,500 per metric ton of methane emitted above specified thresholds from onshore petroleum and natural gas production facilities, natural gas processing facilities, natural gas transmission and compression facilities, and onshore petroleum and natural gas gathering and boosting facilities, among other facilities. The fees will apply to methane emissions after January 1, 2024. The scope and effects of any new laws or regulations are difficult to predict, and the impact of such laws or regulations on the Driftwood Project or related pipelines cannot be predicted at this time.

Coastal Zone Management Act. Certain aspects of the Driftwood terminal are subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act. The Driftwood Project and related pipelines are subject to the CWA and analogous state and local laws. The CWA and analogous state and local laws regulate discharges of pollutants to waters of the United States or waters of the state, including discharges of wastewater and storm water runoff and discharges of dredged or fill material into waters of the United States, as well as spill prevention, control and countermeasure requirements. Permits must be obtained prior to discharging pollutants into state and federal waters or dredging or filling wetland and coastal areas. The CWA is administered by the EPA, the USACE and the states. Additionally, the siting and construction of the Driftwood terminal and Driftwood pipeline will impact jurisdictional wetlands, which would require appropriate federal, state and/or local permits and approval prior to impacting such wetlands. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for regulated impacts to wetlands. Although the CWA permits required for construction and operation of the Driftwood terminal and Driftwood pipeline have been obtained, other CWA permits may be required in connection with our projects that are under development and our future projects. The approval timeframe may also be longer than expected and could potentially affect project schedules.

In addition, in recent years, certain CWA regulatory programs, including the Section 404 wetlands permitting program, have been the subject of shifting agency interpretations and legal challenges, including in a case, Sackett v. EPA, currently pending before the Supreme Court of the United States. Most recently, on January 18, 2023, the EPA and USACE published a new rule defining jurisdictional waters under the CWA. This new rule is set to become effective March 30, 2023, but has been challenged in judicial proceedings. Further regulatory changes or judicial decisions in this area could affect the Driftwood terminal and Driftwood pipeline or other related pipelines in ways that cannot be predicted at this time.

Federal laws, including the CWA, require certain owners or operators of facilities that store or otherwise handle oil and produced water to prepare and implement spill prevention, control, countermeasure and response plans addressing the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) subjects owners and operators of facilities to strict and joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills, including the government’s response costs. Spills subject to the OPA may result in varying civil and criminal penalties and liabilities. The Driftwood Project incorporates appropriate equipment and operational measures to reduce the potential for spills of oil and establish protocols for responding to spills, but oil spills remain an operational risk that could adversely affect our operations and result in additional costs or fines or penalties.

Resource Conservation and Recovery Act. The federal RCRA and comparable state requirements govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. In the event such wastes are generated or used in connection with our facilities, we will be subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes and could be required to perform corrective action measures to clean up releases of such wastes.

Wastes from oil and gas activities are currently excluded from certain regulatory programs under RCRA. In response to litigation by environmental groups over the EPA’s alleged failure to periodically review existing RCRA regulations, the EPA and certain environmental groups entered into a consent decree pursuant to which the EPA was required to undertake a review of whether changes to the existing regulations were necessary. In April 2019, the EPA issued a report concluding that such revisions were unnecessary. A loss of the exclusion from RCRA coverage for oil and gas-related wastes, including drilling fluids, produced waters and related wastes in the future, could result in a significant increase in our costs to manage and dispose of waste associated with our production operations.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”). CERCLA, often referred to as Superfund, and comparable state statutes, impose liability that is generally joint and several and that is retroactive for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, for the release of a “hazardous substance” (or under state law, other specified substances) into the environment. So-called potentially responsible parties (“PRPs”) include the current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of, or transported hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the cost of such action. Liability can arise from conditions on properties where operations are conducted, even under circumstances where such operations were performed by third parties and/or from conditions at disposal facilities where materials were sent. Our operations involve the use or handling of materials that include or may be classified as hazardous substances under CERCLA or regulated under similar state statutes. We may also be the owner or operator of sites on which hazardous substances have been released and may be responsible for the investigation, management and disposal of soils or dredge spoils containing hazardous substances in connection with our operations.

Oil and natural gas exploration and production, and possibly other activities, have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties and, in certain

Hydraulic Fracturing. Hydraulic fracturing is commonly used to stimulate the production of crude oil and/or natural gas from dense subsurface rock formations. We plan to use hydraulic fracturing extensively in our natural gas development operations. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and natural gas commissions but is also subject to new and changing regulatory programs at the federal, state and local levels.

In February 2014, the EPA issued permitting guidance under the Safe Drinking Water Act (“SDWA”) for the underground injection of liquids from hydraulically fractured wells and other wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities related to the Driftwood Project.

In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act (“TSCA”) pursuant to which it collected extensive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. If the EPA regulates hydraulic fracturing fluid under TSCA in the future, such regulation may increase the cost of our natural gas development operations and the feedstock for the Driftwood terminal.

In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and natural gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and natural gas extraction facilities to publicly-owned treatment works. Certain activities of our Business are subject to the pretreatment standards, which means that we are required to use disposal methods that may require additional permits or cost more to implement than disposal at publicly-owned treatment works.

In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. In addition, the U.S. Department of Energy has investigated practices that the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These and similar studies, depending on their degree of development and the nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. If the EPA proposes additional regulations of hydraulic fracturing in the future, it could impose additional emission limits and pollution control technology requirements, which could limit our operations and revenues and potentially increase our costs of gas production or acquisition.

Endangered Species Act (“ESA”). Our operations may be restricted by requirements under the ESA. The ESA prohibits the harassment, harming or killing of certain protected species and destruction of protected habitats. Under the NEPA review process conducted by FERC, we have been and will be required to consult with federal agencies to determine limitations on and mitigation measures applicable to activities that have the potential to result in harm to threatened or endangered species of plants, animals, fish and their designated habitats. Although we have conducted studies and engaged in consultations with agencies in order to avoid harming protected species, inadvertent or incidental harm may occur in connection with the construction or operation of our properties, including the Driftwood Project or related pipelines, which could result in fines or penalties. In addition, if threatened or endangered species are found on any part of our properties, including the sites of the Driftwood Project, related pipelines, or pipeline rights of way, then we may be required to implement avoidance or mitigation measures that could limit our operations or impose additional costs.

Our natural gas operations are subject to a number of additional laws, rules and regulations that require, among other things, permits for the drilling of wells, drilling bonds and reports concerning operations. States, parishes and municipalities in which we operate may regulate, among other things:

•the location of new wells;

•the method of drilling, completing and operating wells;

•the surface use and restoration of properties upon which wells are drilled;

•the plugging and abandoning of wells;

•notice to surface owners and other third parties; and

•produced water and waste disposal.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states, including Louisiana, allow forced pooling or integration of tracts to facilitate exploration, while other states rely on the voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells and generally prohibit the venting or flaring of natural gas and require that oil and natural gas be produced in a prorated, equitable system. These laws and regulations may limit the amount of oil and natural gas that we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, most states, and some local authorities, impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas and minerals in place within their jurisdictions. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

We are subject to anti-corruption laws in various jurisdictions, such as the U.S. Foreign Corrupt Practices Act of 1977, as amended (the “FCPA”), the U.K. Bribery Act of 2010 and other anti-corruption laws. The FCPA and these other laws generally prohibit our employees, directors, officers and agents from authorizing, offering, or providing improper payments or anything else of value to government officials or other covered persons to obtain or retain business or gain an improper business advantage. We face the risk that one of our employees or agents will offer, authorize, or provide something of value that could subject us to liability under the FCPA and other anti-corruption laws. In addition, we cannot predict the nature, scope or effect of future regulatory requirements to which our international operations might be subject or the manner in which existing laws might be administered or interpreted.

We are also subject to other laws and regulations governing our international operations, including regulations administered by the U.S. Department of Commerce’s Bureau of Industry and Security, the U.S. Department of Treasury’s Office of Foreign Assets Control, and various non-U.S. government entities, including applicable export control regulations, economic sanctions on countries and persons, customs requirements, currency exchange regulations, and transfer pricing regulations (collectively, “Trade Control laws”).

We are also subject to new U.K. corporate criminal offenses for failure to prevent the facilitation of tax evasion pursuant to the Criminal Finances Act 2017, which imposes criminal liability on a company where it has failed to prevent the criminal facilitation of tax evasion by a person associated with the company.

We have instituted policies, procedures and ongoing training of employees designed to ensure that we and our employees and agents comply with the FCPA, other anti-corruption laws, Trade Control laws and the Criminal Finances Act 2017. However, there is no assurance that our efforts have been and will be completely effective in ensuring our compliance with all applicable anti-corruption laws, including the FCPA or other legal requirements. If we are not in compliance with the FCPA, other anti-corruption laws, the Trade Control laws or the Criminal Finances Act 2017, we may be subject to criminal and civil penalties, disgorgement and other sanctions and remedial measures, and legal expenses, which could have a material adverse impact on our business, financial condition, results of operations and liquidity. Likewise, any investigation of any potential violations of the FCPA, other anti-corruption laws, the Trade Control laws or the Criminal Finances Act 2017 by the U.S. or foreign authorities could have a material adverse impact on our reputation, business, financial condition and results of operations. U.S. or foreign authorities may also seek to hold us liable for successor liability for anti-corruption violations committed by companies we acquire or in which we invest (for example, by way of acquiring equity interests, participating as a joint venture partner, or acquiring assets).

We are subject to a high degree of competition in all aspects of our business. See “Item 1A — Risk Factors — Risks Relating to Our Business in General — Competition is intense in the energy industry and some of Tellurian’s competitors have greater financial, technological and other resources.”

Production & Transportation. The natural gas and oil business is highly competitive in the exploration for and acquisition of reserves, the acquisition of natural gas and oil leases, equipment and personnel required to develop and produce reserves, and the gathering, transportation and marketing of natural gas and oil. Our competitors include national oil companies, major integrated natural gas and oil companies, other independent natural gas and oil companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers, such as operators of pipelines and other midstream facilities. Many of our competitors have longer operating histories, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we currently possess.

Liquefaction. The Driftwood terminal will compete with liquefaction facilities worldwide to supply low-cost liquefaction to the market. There are a number of liquefaction facilities worldwide that we compete with for customers. Many

LNG Marketing. Tellurian competes with a variety of companies in the global LNG market, including (i) integrated energy companies that market LNG from their own liquefaction facilities, (ii) trading houses and aggregators with LNG supply portfolios, and (iii) liquefaction plant operators that market equity volumes. Many of the companies with which we compete have greater name recognition, larger staffs, greater access to the LNG market and substantially greater financial, technical, and marketing resources than we do.

With respect to our natural gas producing properties, we believe that we hold good and defensible leasehold title to substantially all of our properties in accordance with standards generally accepted in the industry. A preliminary title examination is conducted at the time the properties are acquired. Our natural gas properties are subject to royalty, overriding royalty, and other outstanding interests. We believe that we hold good title to our other properties, subject to customary burdens, liens, or encumbrances that we do not expect to materially interfere with our use of the properties.

We do not have any major customers.

Certain subsidiaries of Tellurian have entered into operating leases for office space in Houston, Texas, Washington, D.C. and London, United Kingdom. The tenors of the leases are five, eight and five years for Houston, Washington, D.C. and London, respectively.

As of December 31, 2022, Tellurian had 171 full-time employees worldwide. None of them are subject to collective bargaining arrangements. The Company’s workforce is primarily located in Houston, Texas, and we have offices in Louisiana, Washington DC, London and Singapore. Many of our employees are originally from or have extensive experience working in countries other than the United States. This reflects our overall strategy of building a natural gas business that is global in scope.

We plan to build, among other things, an LNG liquefaction facility that we believe is one of the largest energy infrastructure projects currently under development in the United States. Given the inherent challenges involved in the construction of a project of this type, in particular by a company that has limited current operations, our human resources strategy focuses on the recruitment and retention of employees who have already established relevant expertise in the industry. The execution of this strategy has resulted in us assembling what we believe to be a premier management team in the global natural gas and LNG industry. A related aspect of our human resources strategy is that the compensation structure for many of our employees is weighted towards incentive compensation that is designed to reward progress toward the development of our business, including in particular the financing and construction of the Driftwood Project.

The Company is a Delaware corporation originally formed in 1967 and formerly known as Magellan Petroleum Corporation.

We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.tellurianinc.com. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact Tellurian Inc., Investor Relations, 1201 Louisiana Street, Suite 3100, Houston, Texas 77002.

ITEM 1A. RISK FACTORS

Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Our risk factors are grouped into the following categories:

•Risks Relating to Financial Matters;

•Risks Relating to Our Common Stock;

•Risks Relating to Our LNG Business;

•Risks Relating to Our Natural Gas and Oil Operating Activities; and

•Risks Relating to Our Business in General.

Tellurian will be unable to generate any significant revenue from the Driftwood Project for multiple years, and expects cash flow from its other lines of business to be modest for an extended period as it focuses on the development and growth of these businesses. Tellurian will, therefore, need substantial amounts of additional financing to execute its business plan and to repay its indebtedness when necessary. There can be no assurance that Tellurian will be able to raise sufficient capital on acceptable terms, or at all. Tellurian’s ability to raise financing, and the terms of that financing, will depend to a significant extent on factors outside of its control such as global market conditions. Interest rates rose significantly in 2022 in response to inflationary pressures in the U.S. and world economies, and rising interest rates generally make financing more difficult to obtain as well as more expensive. If adequate financing is not available on satisfactory terms or at all, Tellurian may be required to delay, scale back or cancel the development of business opportunities, and this could adversely affect its operations and financial condition to a significant extent. Tellurian intends to pursue a variety of potential financing transactions, including project finance transactions and sales of equity and debt securities. We do not know whether, and to what extent, potential sources of financing will find the terms we propose acceptable. In addition, potential sources of financing may conclude that the terms of our commercial agreements for the sale of LNG are not attractive enough to justify an investment.

Debt or preferred equity financing, if obtained, may involve agreements that include liens or restrictions on Tellurian’s assets and covenants limiting or restricting our ability to take specific actions, such as paying dividends or making distributions, incurring additional debt, acquiring or disposing of assets and increasing expenses. Debt financing would also be required to be repaid regardless of Tellurian’s operating results. Obtaining financing through additional issuances of common stock or other equity securities would impose fewer restrictions on our future operations but would be dilutive to the interests of existing stockholders.

We have a limited operating history. Although Tellurian’s current directors, managers and officers have prior professional and industry experience, our business is in an early stage of development. Accordingly, the prior history, track record and historical financial information you may use to evaluate our prospects are limited.

Completion of construction of the Driftwood Project will require Tellurian to incur costs and expenses much greater than those it has incurred to date. The Company also expects to devote substantial amounts of capital to the growth and development of its other operations. Tellurian expects that operating losses will increase substantially in 2023 and thereafter, and expects to continue to generate negative operating cash flows for the next several years.

Our operations involve our entering into various construction, purchase and sale, hedging, supply and other transactions with numerous third parties. In such arrangements, we will be exposed to the performance and credit risks of our counterparties, including the risk that one or more counterparties fail to perform their obligations under the applicable agreement. Some of these risks may increase during periods of commodity price volatility. In some cases, we will be dependent on a single counterparty or a small group of counterparties, all of whom may be similarly affected by changes in economic and other conditions. These risks include, but are not limited to, risks related to the construction of the Driftwood terminal discussed below in “ — Risks Relating to Our LNG Business — Tellurian will be dependent on third-party contractors for the successful completion of the Driftwood terminal, and these contractors may be unable to complete the Driftwood terminal.” Defaults by suppliers and other counterparties may adversely affect our operating results, liquidity and access to financing.

As we continue to develop our LNG and natural gas marketing and natural gas operating activities, we may enter into commodity hedging arrangements in an effort to reduce our exposure to fluctuations in price and timing risk. Any hedging arrangements entered into would expose us to the risk of financial loss when (i) the counterparty to the hedging contract defaults on its contractual obligations or (ii) there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.

Also, commodity derivative arrangements may limit the benefit we would otherwise receive from a favorable change in the relevant commodity price. In addition, regulations issued by the Commodities Futures Trading Commission, the SEC and other federal agencies establishing regulation of the over-the-counter derivatives market could adversely affect our ability to manage our price risks associated with our LNG and natural gas activity and therefore have a negative impact on our operating results and cash flows.

Factors that could materially affect our future effective tax rates include but are not limited to:

•changes in the regulatory environment;

•changes in accounting and tax standards or practices;

•changes in U.S., state or foreign tax laws;

•changes in the composition of operating income by tax jurisdiction; and

•our operating results before taxes.

We are also subject to examination by the Internal Revenue Service (the “IRS”) and other tax authorities, including state revenue agencies and other foreign governments. While we regularly assess the likelihood of favorable or unfavorable outcomes resulting from examinations by the IRS and other tax authorities to determine the adequacy of our provision for income taxes, there can be no assurance that the actual outcome resulting from these examinations will not materially adversely affect our financial condition and operating results. Additionally, the IRS and several foreign tax authorities have increasingly focused attention on intercompany transfer pricing with respect to sales of products and services and the use of intangibles. Tax authorities could disagree with our cross-jurisdictional transfer pricing or other matters and assess additional taxes. If we do not prevail in any such disagreements, our profitability may be affected.

Tellurian’s directly and indirectly held assets currently consist primarily of natural gas leaseholds and related upstream development assets, cash held for certain development and operating expenses, applications for permits from regulatory agencies relating to the Driftwood Project and certain real property related to that project. Tellurian’s cash flow, and consequently its ability to distribute earnings, is solely dependent upon the cash flow its subsidiaries receive from the Driftwood Project and its other operations. Tellurian’s ability to complete the project, as discussed elsewhere in this section, is dependent upon its and its subsidiaries’ ability to obtain and maintain necessary regulatory approvals and raise the capital necessary to fund the development of the project. We expect that cash flows from our operations will be reinvested in the business rather than used to fund dividends, that pursuing our strategy will require substantial amounts of capital, and that the required capital will exceed cash flows from operations for a significant period.

Tellurian’s ability to pay dividends in the future is uncertain and will depend on a variety of factors, including limitations on the ability of it or its subsidiaries to pay dividends under applicable law and/or the terms of debt or other agreements, and the judgment of the Board of Directors or other governing body of the relevant entity.

We have issued senior notes as described in Note 10, Borrowings, of our Notes to Consolidated Financial Statements included in this report. Our ability to generate cash flows from operations or obtain refinancing capital sufficient to pay interest and principal on our indebtedness will depend on our future operating performance and financial condition and the availability of refinancing debt or equity capital, which will be affected by prevailing commodity prices and economic conditions and financial, business and other factors, many of which are beyond our control. Our inability to generate adequate cash flows from operations could adversely affect our ability to execute our overall business plan, and we could be required to sell assets, reduce our capital expenditures or seek refinancing debt or equity capital to satisfy the requirements of the debt agreements. These alternative measures may be unavailable or inadequate, in which case we could be forced into bankruptcy or liquidation, and may themselves adversely affect our overall business strategy. In addition, the indenture governing our convertible notes

contains covenants, including limitations on our ability to incur additional indebtedness and a minimum cash covenant, that could prevent us from pursuing certain business strategies or opportunities. If we are unable to comply with these covenants, amounts due under the notes could be accelerated. Further, the holder of our convertible notes may redeem up to $166 million of those notes at par, plus accrued and unpaid interest, on each of May 1, 2023 and May 1, 2024. The exercise of this redemption right could materially adversely affect our liquidity.

The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events could trigger a significant decline in the trading price of our common stock, including, among others, failure to obtain necessary permits, unfavorable changes in commodity prices or commodity price expectations, adverse regulatory developments, loss of a relationship with a partner, litigation, departures of key personnel, and failures to advance the Driftwood Project on the terms or within the time periods anticipated. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of equity securities generally could affect the price of our stock. The stock markets frequently experience price and volume volatility that affects many companies’ stock prices, often in ways unrelated to the operating performance of those companies. These fluctuations may affect the market price of our common stock. The trading price of our common stock during 2022 was as low as $1.54 per share and as high as $6.54 per share.

Sales of a substantial number of shares of our common stock in the market by us or any of our major shareholders, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares in the public market, or the possibility of such sales, could impair our ability to raise capital through the sale of additional equity securities. Our insider trading policy permits our officers and directors, some of whom own substantial percentages of our outstanding common stock, to pledge shares of stock that they own as collateral for loans subject to certain requirements. Some of our officers and directors have pledged shares of stock in accordance with this policy. Such pledges have resulted, and could result in the future, in large amounts of shares of our stock being sold in the market in a short period and corresponding declines in the trading price of the common stock.

In addition, in the future, we may issue shares of our common stock, or securities convertible into our common stock, in connection with acquisitions of assets or businesses or for other purposes. Such issuances may result in dilution to our existing stockholders and could have an adverse effect on the market value of shares of our common stock, depending on market conditions at the time, the terms of the issuance, and if applicable, the value of the business or assets acquired and our success in exploiting the properties or integrating the businesses we acquire.

Commercial development of an LNG facility takes a number of years, requires substantial capital investment and may be delayed by factors such as:

•increased construction costs;

•economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;

•decreases in the price of natural gas or LNG outside of the United States, which might decrease the expected returns relating to investments in LNG projects;

•the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;

•any renegotiation of EPC agreements that may be required in the event of delays in a final investment decision or other failures to meet specified deadlines; and

•political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns.

Our failure to execute our business plan within budget and on schedule could materially adversely affect our business, financial condition, operating results, liquidity and prospects.

Cost estimates for the Driftwood Project and other projects we may pursue are only approximations of the actual costs of construction. Cost estimates may be inaccurate and may change due to various factors, such as cost overruns, change orders, delays in construction, legal and regulatory requirements, site issues, increased component and material costs, escalation of labor costs, labor disputes, changes in commodity prices, changes in foreign currency exchange rates, increased spending to maintain Tellurian’s construction schedule and other factors. For example, new or increased tariffs on materials needed in the construction process could materially increase construction costs, as could supply chain issues affecting long lead-time items. Our estimate of the cost of construction of the Driftwood terminal is based on the prices set forth in our LSTK EPC agreements with Bechtel and those prices are subject to adjustment by change orders, including for consideration of certain increased costs. Our failure to achieve our cost estimates could materially adversely affect our business, financial condition, operating results, liquidity and prospects.

We will depend upon third-party pipelines and other facilities that will provide natural gas delivery options to our natural gas operations and our LNG facilities. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to meet our LNG sale and purchase agreement obligations and continue shipping natural gas from producing operations or regions to end markets could be restricted, thereby reducing our revenues. This could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

We have entered into a commercial arrangement with a third-party customer for the sale of LNG from Phase I of the Driftwood Project. Our ability to generate revenue from that contract will depend upon, among other factors, LNG prices and our ability to finance and complete the construction of the project. Tellurian’s business strategy may change regarding how and when the proposed Driftwood Project’s export capacity is marketed. Also, Tellurian’s business strategy may change due to an inability to enter into additional agreements with customers or based on a variety of factors, including the future price outlook, supply and demand of LNG, natural gas liquefaction capacity, and global regasification capacity. If our efforts to market the proposed Driftwood Project and the LNG it will produce are not successful, Tellurian’s business, results of operations, financial condition and prospects may be materially and adversely affected.

Under LNG sale and purchase agreements with our customers, we may be required to make available to them a specified amount of LNG at specified times. However, we may not be able to acquire or produce sufficient quantities of natural gas or LNG to satisfy those obligations, which may provide affected customers with the right to terminate their LNG sale and purchase agreements. Our failure to purchase, receive or produce sufficient quantities of natural gas or LNG in a timely manner could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The design, construction and operation of LNG export terminals is a highly regulated activity. The approval of FERC under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, is required to construct and operate an LNG terminal. Such approvals and authorizations are often subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. Tellurian and its affiliates will be

The construction of the Driftwood terminal is expected to take several years, will be confined to a limited geographic area and could be subject to delays, cost overruns, labor disputes and other factors that could adversely affect financial performance or impair Tellurian’s ability to execute its proposed business plan. Timely and cost-effective completion of the Driftwood terminal in compliance with agreed-upon specifications will be highly dependent upon the performance of Bechtel and other third-party contractors pursuant to their agreements. However, Tellurian has not yet entered into definitive agreements with all of the contractors, advisors and consultants necessary for the development and construction of the Driftwood terminal. Tellurian may not be able to successfully enter into such construction contracts on terms or at prices that are acceptable to it.

Further, faulty construction that does not conform to Tellurian’s design and quality standards may have an adverse effect on Tellurian’s business, results of operations, financial condition and prospects. For example, improper equipment installation may lead to a shortened life of Tellurian’s equipment, increased operations and maintenance costs or a reduced availability or production capacity of the affected facility. The ability of Tellurian’s third-party contractors to perform successfully under any agreements to be entered into is dependent on a number of factors, including force majeure events and such contractors’ ability to:

•design, engineer and receive critical components and equipment necessary for the Driftwood terminal to operate in accordance with specifications and address any start-up and operational issues that may arise in connection with the commencement of commercial operations;

•attract, develop and retain skilled personnel, engage and retain third-party subcontractors, and address any labor issues that may arise;

•post required construction bonds and comply with the terms thereof, and maintain their own financial condition, including adequate working capital;

•adhere to any warranties that the contractors provide in their EPC contracts; and

•respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control, and manage the construction process generally, including engaging and retaining third-party contractors, coordinating with other contractors and regulatory agencies and dealing with inclement weather conditions.

Furthermore, Tellurian may have disagreements with its third-party contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under the related contracts, resulting in a contractor’s unwillingness to perform further work on the relevant project. The risk of disagreements with contractors and other construction issues such as increased costs and delays may be exacerbated by inflation, supply chain disruptions and other market conditions. Tellurian may also face difficulties in commissioning a newly constructed facility. Any significant delays in the development of the Driftwood terminal could materially and adversely affect Tellurian’s business, results of operations, financial condition and prospects. The construction of the Driftwood pipeline or related pipelines will be required for the long-term operations of the Driftwood terminal and will be subject to similar risks.   

Siting, development and construction of the Driftwood Project and related pipelines will be subject to the risks of delay or cost overruns inherent in any construction project resulting from numerous factors, including, but not limited to, the following:

•difficulties or delays in obtaining, or failure to obtain, sufficient equity or debt financing on reasonable terms;

•failure to obtain all necessary government and third-party permits, approvals and licenses for the construction and operation of the Driftwood Project or any other proposed LNG facilities or related pipelines;

•difficulties in engaging qualified contractors necessary for the construction of the contemplated Driftwood Project or related pipelines;

•shortages of equipment, material or skilled labor;

•natural disasters and catastrophes, such as hurricanes, explosions, fires, floods, industrial accidents, pandemics and terrorism;

•unscheduled delays in the delivery of ordered materials;

•work stoppages and labor disputes;

•competition with other domestic and international LNG export terminals;

•unanticipated changes in domestic and international market demand for and supply of natural gas and LNG, which will depend in part on supplies of and prices for alternative energy sources and the discovery of new sources of natural resources;

•unexpected or unanticipated need for additional improvements; and

•adverse general economic conditions.

Delays beyond the estimated development periods, as well as cost overruns, could increase the cost of completion beyond the amounts that are currently estimated, which could require Tellurian to obtain additional sources of financing to fund its activities until the proposed Driftwood terminal is constructed and operational (which could cause further delays). Any delay in completion of the Driftwood Project may also cause a delay in the receipt of revenues projected from the Driftwood Project or cause a loss of one or more customers. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects. Similar risks may affect the construction of other facilities and projects we elect to pursue.

Tellurian’s plans and expectations regarding its business and the development of domestic LNG facilities and projects are generally based on assumptions about the future price of natural gas and LNG and the conditions of the global natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to remain in the future, volatile and subject to wide fluctuations that are difficult to predict. Such fluctuations may be caused by various factors, including, but not limited to, one or more of the following:

•competitive liquefaction capacity in North America;

•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;

•insufficient or oversupply of LNG tanker capacity;

•weather conditions;

•changes in demand for natural gas, including as a result of disruptive events such as the Russian invasion of Ukraine and the COVID-19 pandemic;

•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

•decreased oil and natural gas exploration activities, which may decrease the production of natural gas;

•cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;

•changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;

•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;

•political conditions in natural gas producing regions; and

•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects. The profitability of the LNG SPA we have entered into will depend in part on the relationship between the costs we incur in producing or purchasing natural gas and the then-current index prices when sales occur. An adverse change in that relationship, whether resulting from an increase in our costs, a decline in the index prices or both, could make sales under the agreements less profitable or could require us to sell at a loss. Similarly, part of our business involves the trading of LNG cargos from time to time. LNG trading involves risks, including the risk that commodity price changes will result in us selling cargos at a loss. These risks have increased in recent periods as higher commodity prices have resulted in cargos becoming generally more expensive, therefore increasing our exposure to potential losses.

Tellurian’s success will depend on its ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, although Tellurian plans to construct the Driftwood terminal using proven technologies that it believes provide it with certain advantages, Tellurian does not have any exclusive rights to any of the technologies that it will be utilizing. In addition, the technology Tellurian anticipates using in the Driftwood Project may be rendered obsolete or uneconomical by legal or regulatory requirements, technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of its competitors or others, which could materially and adversely affect Tellurian’s business, results of operations, financial condition, liquidity and prospects.

Operations of the Driftwood Project will be dependent upon our ability to deliver LNG supplies from the U.S., which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the U.S., which could increase the available supply of natural gas outside the U.S. and could result in natural gas in those markets being available at a lower cost than that of LNG exported to those markets.

Factors which may negatively affect potential demand for LNG from our liquefaction projects are diverse and include, among others:

•increases in worldwide LNG production capacity and availability of LNG for market supply;

•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;

•increases in the cost to supply natural gas feedstock to our liquefaction project;

•decreases in the cost of competing sources of natural gas or alternative sources of energy such as coal, heavy fuel oil, diesel, nuclear, hydroelectric, wind and solar;

•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;

•increases in capacity and utilization of nuclear power and related facilities;

•increases in the cost of LNG shipping; and

•displacement of LNG by pipeline natural gas or alternative fuels in locations where access to these energy sources is not currently available.

Political instability in foreign countries that import natural gas, or strained relations between such countries and the U.S., may also impede the willingness or ability of LNG suppliers, purchasers and merchants in such countries to import LNG from the U.S. Furthermore, some foreign purchasers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or our competitors’ liquefaction facilities in the U.S.

As a result of these and other factors, LNG may not be a competitive source of energy internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the U.S. on a commercial basis. Any significant impediment to the ability to deliver LNG from the U.S. generally, or from the Driftwood Project specifically, could

The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability of the vessels could be delayed to the detriment of Tellurian’s business and customers due to a variety of factors, including, but not limited to, the following:

•an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;

•political or economic disturbances in the countries where the vessels are being constructed;

•changes in governmental regulations or maritime self-regulatory organizations;

•work stoppages or other labor disturbances at shipyards;

•bankruptcies or other financial crises of shipbuilders;

•quality or engineering problems;

•weather interference or catastrophic events, such as a major earthquake, tsunami, or fire; or

•shortages of or delays in the receipt of necessary construction materials.

Any of these factors could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.

We will rely on third parties for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of the Driftwood terminal. Any of our LNG facilities, when constructed, may not have the capacity ratings and performance capabilities that we intend or estimate. Failure of any of our facilities to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our current or future LNG sale and purchase agreements and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are and will be subject to extensive federal, state and local environmental and safety regulations and laws, including regulations and restrictions related to discharges and releases to the air, land and water and the handling, storage, generation and disposal of hazardous materials and solid and hazardous wastes in connection with the development, construction and operation of our LNG facilities and pipelines. Failure to comply with these regulations and laws could result in the imposition of administrative, civil and criminal sanctions.

These regulations and laws, which include the CAA, the Oil Pollution Act, the CWA and RCRA, and analogous state and local laws and regulations, will restrict, prohibit or otherwise regulate the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities. These laws and regulations, including NEPA, will require and have required us to obtain and maintain permits with respect to our facilities, prepare environmental impact assessments, provide governmental authorities with access to our facilities for inspection and provide reports related to compliance. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. Violation of these laws and regulations could lead to substantial liabilities, fines and penalties, the denial or revocation of permits necessary for our operations, governmental orders to shut down our facilities or capital expenditures related to pollution control equipment or remediation measures that could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.

As the owner and the operator of the Driftwood Project and other related assets we could be liable for the costs of investigating and cleaning up hazardous substances released into the environment and for damage to natural resources, whether caused by us or our contractors or existing at the time construction commences. Hazardous substances present in soil, groundwater and dredge spoils may need to be processed, disposed of or otherwise managed to prevent releases into the environment. Tellurian or its affiliates may be responsible for the investigation, cleanup, monitoring, removal, disposal and other remedial actions with respect to hazardous substances on, in or under properties that Tellurian owns or operates, or

Tellurian’s business will be subject to governmental laws, rules, regulations and permits that impose various restrictions and obligations that may have material effects on the results of our operations. Each of the applicable regulatory requirements and limitations is subject to change, either through new regulations enacted on the federal, state or local level, or by new or modified regulations that may be implemented under existing law. The nature and effects of these changes in laws, rules, regulations and permits may be unpredictable and may have material effects on our business. Future legislation and regulations, such as those relating to the transportation and security of LNG exported from our proposed LNG facilities through the Calcasieu Ship Channel, could cause additional expenditures, restrictions and delays in connection with the proposed LNG facilities and their construction, the extent of which cannot be predicted and which may require Tellurian to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating costs and restrictions could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.

We will face numerous risks in developing and conducting our operations. For example, the plan of operations for the proposed Driftwood Project and related assets is subject to the inherent risks associated with LNG, pipeline and upstream operations, including explosions, pollution, leakage or release of toxic substances, fires, hurricanes and other adverse weather conditions, leakage of hydrocarbons, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the proposed Driftwood Project, related pipelines, or upstream assets, or damage to persons and property. In addition, operations at the proposed Driftwood Project, related pipelines, upstream assets, and vessels or facilities of third parties on which Tellurian’s operations are dependent could face possible risks associated with acts of aggression or terrorism.

Hurricanes have damaged coastal and inland areas located in the Gulf Coast area, resulting in disruption and damage to certain LNG terminals located in the area. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Driftwood terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Driftwood terminal or other facilities. Storms, disasters and accidents could also damage or interrupt the activities of vessels that we or third parties operate in connection with our LNG business. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels. If any such effects were to occur, they could have an adverse effect on our coastal operations.

Our LNG business will face other types of risks and liabilities as well. For instance, our LNG marketing activities expose us to possible financial losses, including the risk of losses resulting from adverse changes in the index prices upon which contracts for the purchase and sale of LNG cargos are based. Our LNG marketing activities are also subject to various domestic and international regulatory and foreign currency risks.

Tellurian does not, nor does it intend to, maintain insurance against all of these risks and losses, and many risks are not insurable. Tellurian may not be able to maintain desired or required insurance in the future at rates that it considers reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on Tellurian’s business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We expect to continue to pursue acquisitions of natural gas and oil properties from time to time. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include reserves, development potential, future commodity prices, operating costs, title issues, and potential environmental and other liabilities. Such assessments are inexact, and their accuracy is inherently uncertain. In connection with our assessments, we perform due diligence that we believe is generally consistent with industry practices.

However, our due diligence activities are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition, and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface,

When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We may acquire interests in properties on an “as is” basis with limited or no remedies for breaches of representations and warranties.

Therefore, we could incur significant unknown liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks, and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire.

In addition, acquiring additional natural gas and oil properties, or businesses that own or operate such properties, when attractive opportunities arise is a significant component of our strategy, and we may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to pursue our overall strategy.

The revenues, operating results and profitability of our natural gas or oil operating activities will depend significantly on the prices we receive for the natural gas or oil we sell. We will require substantial expenditures to replace reserves, sustain production and fund our business plans. Low natural gas or oil prices can negatively affect the amount of cash available for acquisitions and capital expenditures and our ability to raise additional capital and, as a result, could have a material adverse effect on our revenues, cash flow and reserves. In addition, low natural gas or oil prices may result in write-downs of our natural gas or oil properties, such as the $81.1 million impairment charge we incurred in 2020. Conversely, any substantial or extended increase in the price of natural gas would adversely affect the competitiveness of LNG as a source of energy (as discussed above in “ — Risks Relating to Our LNG Business — Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects”. Part of our strategy involves adjusting the level of our natural gas development activities based on our judgment as to the most cost-effective manner in which to source natural gas for the Driftwood terminal. In some circumstances, making these adjustments may involve costs. For example, a decrease in our activities may result in the expiration of leases or an increase in costs on a per-unit basis.

Historically, the markets for natural gas and oil have been volatile, and they are likely to continue to be volatile. Wide fluctuations in natural gas or oil prices may result from relatively minor changes in the supply of or demand for natural gas or oil, market uncertainty and other factors that are beyond our control. The volatility of the energy markets makes it extremely difficult to predict future natural gas or oil price movements, and we will be unable to fully hedge our exposure to natural gas or oil prices.

Our planned development and acquisition activities will require substantial capital expenditures. We intend to fund our capital expenditures for our natural gas and oil operating activities through cash on hand and financing transactions that may include public or private equity or debt offerings or borrowings under additional debt agreements. Our ability to generate operating cash flow in the future will be subject to a number of risks and variables, such as the level of production from existing wells, the price of natural gas or oil, our success in developing and producing new reserves and the other risk factors discussed in this section. If we are unable to fund our capital expenditures for natural gas or oil operating activities as planned, we could experience a curtailment of our development activity and a decline in our natural gas or oil production, and that could affect our ability to pursue our overall strategy.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could

Natural gas and oil operations are subject to many risks, including well blowouts, explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, leakages or releases of hydrocarbons, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks. For our non-operated properties, we will be dependent on the operator for regulatory compliance and for the management of these risks.

These risks could materially and adversely affect our revenues and expenses by reducing production from wells, causing wells to be shut in or otherwise negatively impacting our projected economic performance. If any of these risks occurs, we could sustain substantial losses as a result of:

•injury or loss of life;

•severe damage to or destruction of property, natural resources or equipment;

•pollution or other environmental damage;

•facility or equipment malfunctions and equipment failures or accidents;

•clean-up responsibilities;

•regulatory investigations and administrative, civil and criminal penalties; and

•injunctions resulting in limitation or suspension of operations.

Any of these events could expose us to liabilities, monetary penalties or interruptions in our business operations. In addition, certain of these risks are greater for us than for many of our competitors in that some of the natural gas we produce has a high sulphur content (sometimes referred to as “sour” gas), which increases its corrosiveness and the risk of an accidental release of hydrogen sulfide gas, exposure to which can be fatal. We may not maintain insurance against such risks, and some risks are not insurable. Even when we are insured, our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future, we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which we are not fully insured may expose us to liabilities.

Drilling for natural gas and oil may involve unprofitable efforts from wells that are either unproductive or productive but do not produce sufficient commercial quantities to cover drilling, completion, operating and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. Natural gas and oil reserve engineering requires estimates of underground accumulations of hydrocarbons and assumptions concerning future prices, production rates and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect. Our estimates of proved reserves are determined based in part on costs at the date of the estimate. Any significant variance from these costs could greatly affect our estimates of reserves. At December 31, 2022, approximately 51% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to reclassify to probable or possible any PUDs that are not developed within this five-year time frame.

Our natural gas operating activities and properties are (and to the extent that we acquire oil producing properties, these properties will be) subject to numerous federal, regional, state and local laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:

•conduct of drilling, completion, production and midstream activities;

•amounts and types of emissions and discharges;

•generation, management, and disposal of hazardous substances and waste materials;

•reclamation and abandonment of wells and facility sites; and

•remediation of contaminated sites.

In addition, these laws and regulations may result in substantial liabilities for our failure to comply or for any contamination resulting from our operations, including the assessment of administrative, civil and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area.

Environmental laws and regulations change frequently, and these changes are difficult to predict or anticipate. Future environmental laws and regulations imposing further restrictions on the emission of pollutants into the air, discharges into state or U.S. waters, wastewater disposal and hydraulic fracturing, or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our natural gas or oil production. We cannot predict the actions that future regulation will require or prohibit, but our business and operations could be subject to increased operating and compliance costs if certain regulatory proposals are adopted. In addition, such regulations may have an adverse impact on our ability to develop and produce our reserves.

Laws or regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations are proposed from time to time at the federal, state and local levels. Regulatory bodies and others from time to time assess, among other things, the risks of groundwater contamination and earthquakes caused by hydraulic fracturing and other exploration and production activities. Depending on the outcome of these assessments, federal and state legislatures and agencies may seek to further regulate or even ban such activities, as some state and local governments have already done. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions. Among other things, this could adversely affect the cost to produce natural gas, either by us or by third-party suppliers, and therefore LNG, and this could adversely affect the competitiveness of LNG relative to other sources of energy.

Our management team has identified certain well locations on our natural gas properties. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these factors, we do not know if the well locations we have identified will ever be drilled or if we will be able to produce natural gas from these or any other potential locations.

The demand for qualified and experienced field and technical personnel to conduct our operations can fluctuate significantly, often in correlation with hydrocarbon prices. The price of services and equipment may increase in the future and availability may decrease.

In addition, it is possible that oil prices could increase without a corresponding increase in natural gas prices, which could lead to increased demand and prices for equipment, facilities and personnel without an increase in the price at which we

Our natural gas and oil production activities rely on third parties to meet our needs for midstream infrastructure and services. Capital constraints and public opposition to projects could limit the construction of new infrastructure by us and third parties. In addition, increased production from us and other operators could lead to capacity constraints. We may experience delays in producing and selling natural gas or oil from time to time when adequate midstream infrastructure and services are not available. Such an event could reduce our production or result in other adverse effects on our business.

We plan to develop, own and operate a global natural gas business and to deliver natural gas to customers worldwide. We may not be successful in executing our strategy in the near future, or at all. Our management will be required to understand and manage a diverse set of business opportunities, which may distract their focus and make it difficult to be successful in increasing value for shareholders.

Tellurian may engage in operations or make substantial commitments and investments, or enter into agreements with counterparties, located outside the U.S., which would expose Tellurian to political, governmental, and economic instability, foreign currency exchange rate fluctuations and corruption risk.

Any disruption caused by these factors could harm Tellurian’s business, results of operations, financial condition, liquidity and prospects. Risks associated with operations, commitments and investments outside of the U.S. include but are not limited to risks of:

•currency fluctuations;

•war or terrorist attack;

•expropriation or nationalization of assets;

•renegotiation or nullification of existing contracts;

•changing political conditions;

•changing laws and policies affecting trade, taxation, and investment;

•multiple taxation due to different tax structures;

•general hazards associated with the assertion of sovereignty over areas in which operations are conducted; and

•the unexpected credit rating downgrade of countries in which Tellurian’s LNG customers are based.

Because Tellurian’s reporting currency is the U.S. dollar, any of the operations conducted outside the U.S. or denominated in foreign currencies would face additional risks of fluctuating currency values and exchange rates, hard currency shortages and controls on currency exchange. In addition, Tellurian would be subject to the impact of foreign currency fluctuations and exchange rate changes on its financial reports when translating the value of its assets, liabilities, revenues and expenses from operations outside of the U.S. into U.S. dollars at then-applicable exchange rates. These translations could result in changes to the results of operations from period to period.

Many scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as higher sea levels, increased frequency and severity of storms, droughts, floods, and other climatic events. Such effects could adversely affect our facilities and operations, and have an adverse effect on our financial condition and results of operations. Further, adverse weather events may accelerate changes in laws and regulations aimed at reducing GHG emissions, which could result in declining demand for natural gas and LNG, and could adversely affect our business generally. In addition, many customers are focusing more on sustainability and the environmental impacts of operations of companies. An inability to respond to potential customer demands with respect to these issues could have an impact on our financial results. Furthermore, some governmental or business entities have set voluntary carbon emissions targets or are otherwise subject to regulatory limits on their carbon emissions. Any of these developments could result in less demand for our products and, in turn, affect our financial results.

For additional information on recent regulatory changes relating to climate change, please refer to Item 1, Governmental Regulations.

Tellurian is subject to extensive federal, state and local health and safety regulations and laws. Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, penalties for non-compliance with relevant laws and regulations or litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

A terrorist or military incident could disrupt our business. For example, an incident involving an LNG carrier or LNG facility may result in delays in, or cancellation of, construction of new LNG facilities, including our proposed LNG facilities, which would increase our costs and decrease our cash flows. A terrorist incident may also result in the temporary or permanent closure of Tellurian facilities or operations, which could increase costs and decrease cash flows, depending on the duration of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas or oil that could adversely affect Tellurian’s business and customers, including by impairing the ability of Tellurian’s suppliers or customers to satisfy their respective obligations under Tellurian’s commercial agreements.

We depend on digital technology in many aspects of our business, including the processing and recording of financial and operating data, analysis of information, and communications with our employees and third parties. Cyber-attacks on our systems and those of third-party vendors and other counterparties occur frequently and have grown in sophistication. A successful cyber-attack on us or a vendor or other counterparty could have a variety of adverse consequences, including theft of proprietary or commercially sensitive information, data corruption, interruption in communications, disruptions to our existing or planned activities or transactions, and damage to third parties, any of which could have a material adverse impact on us. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks.

The success of Tellurian’s business relies heavily on key personnel such as its Executive Chairman, Vice Chairman and Chief Executive Officer. Should such persons be unable to perform their duties on behalf of Tellurian, or should Tellurian be unable to retain or attract other members of management, Tellurian’s business, results of operations, financial condition, liquidity and prospects could be materially impacted.

Additionally, we are dependent upon an available labor pool of skilled employees. We will compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and to provide our customers with the highest quality service. A shortage of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, or increases in the amounts we are obligated to pay our contractors, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.

Tellurian plans to operate in various aspects of the natural gas and oil business and will face intense competition in each area. Depending on the area of operations, competition may come from independent, technology-driven companies, large, established companies and others.

For example, many competing companies have secured access to, or are pursuing the development or acquisition of, LNG facilities to serve the North American natural gas market, including other proposed liquefaction facilities in North America. Tellurian may face competition from major energy companies and others in pursuing its proposed business strategy to provide liquefaction and export products and services at its proposed Driftwood terminal. In addition, competitors have developed and are developing additional LNG terminals in other markets, which will also compete with our proposed LNG facilities.

As another example, our business will face competition in, among other things, buying and selling reserves and leases and obtaining goods and services needed to operate properties and market natural gas and oil. Competitors include multinational oil companies, independent production companies and individual producers and operators.

Many of our competitors have longer operating histories, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than Tellurian currently possesses. The superior resources that some of these competitors have available for deployment could allow them to compete successfully against Tellurian, which could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.

ITEM 1B. UNRESOLVED STAFF COMMENTS    

None.

ITEM 3. LEGAL PROCEEDINGS

None.

ITEM 4. MINE SAFETY DISCLOSURE

None.

PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock trades on the NYSE American under the symbol “TELL.” As of February 7, 2023, there were 563,518,417 million shares outstanding held by 793 record holders of Tellurian’s common stock. The Company does not intend to pay cash dividends on its common stock in the foreseeable future.

The information contained in this Stock Performance Graph section shall not be deemed to be “soliciting material” or “filed” or incorporated by reference in future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act or the Exchange Act. The following graph compares the cumulative total shareholder return, calculated on a dividend reinvested basis, on $100.00 invested at the closing of the market on December 31, 2017, through and including the market close on December 31, 2022, with the cumulative total return for the same time period of the same amount invested in the Russell 2000 index and a peer group index. The peer group was selected based on a review of publicly available information about these companies and our determination that they met one or more of the following criteria: (i) comparable industries, (ii) similar market capitalization and (iii) similar operational characteristics, capital intensity, business and operating risks. Our peer group index consists of the following companies:

Peer group
APA Corporation (APA)			NextDecade Corporation (NEXT)
Cheniere Energy, Inc. (LNG)			NuStar Energy L.P. (NS)
Chesapeake Energy Corporation (CHK)			ONEOK, Inc. (OKE)
Continental Resources, Inc. (CLR)			Range Resources Corporation (RRC)
Enterprise Products Partners L.P. (EPD)			Southwestern Energy Company (SWN)
EQT Corporation (EQT)			Targa Resources Corp. (TRGP)
Gibson Energy Inc. (GEI)			The Williams Companies, Inc. (WMB)
Kinder Morgan, Inc. (KMI)

															Year Ended December 31,
															2017						2018						2019						2020						2021						2022
Tellurian Inc.															100						71						75						13						32						17
Russell 2000															100						88						109						129						146						115
Peer group															100						78						84						60						92						124

ITEM 6. [Reserved]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past development activities, current financial condition and outlook for the future organized as follows:

•Our Business

•Overview of Significant Events

•Liquidity and Capital Resources

•Capital Development Activities

•Results of Operations

•Commitments and Contingencies

•Summary of Critical Accounting Estimates

•Recent Accounting Standards

Our Business

Tellurian Inc. (“Tellurian,” “we,” “us,” “our,” or the “Company”), a Delaware corporation, is a Houston-based company that is developing and plans to operate a portfolio of natural gas, LNG marketing, and infrastructure assets that includes an LNG terminal facility (the “Driftwood terminal”), an associated pipeline (the “Driftwood pipeline”), other related pipelines, and upstream natural gas assets (collectively referred to as the “Business”). The Driftwood terminal and the Driftwood pipeline are collectively referred to as the “Driftwood Project.” As of December 31, 2022, our upstream natural gas assets consist of 27,689 net acres and interests in 143 producing wells located in the Haynesville Shale trend of northern Louisiana. Our Business may be developed in phases.

As part of our execution strategy, which includes increasing our asset base, we will consider various commercial arrangements with third parties across the natural gas value chain. We are also pursuing activities such as direct sales of LNG to global counterparties, trading of LNG, the acquisition of additional upstream acreage and drilling of new wells on our existing or newly acquired upstream acreage. We remain focused on the financing and construction of the Driftwood Project and related pipelines while managing our upstream assets.

We manage and report our operations in three reportable segments. The Upstream segment is organized and operates to produce, gather, and deliver natural gas and to acquire and develop natural gas assets. The Midstream segment is organized to develop, construct and operate LNG terminals and pipelines. The Marketing & Trading segment is organized and operates to purchase and sell natural gas produced primarily by the Upstream segment, market the Driftwood terminal’s LNG production capacity and trade LNG.

Overview of Significant Events

On March 24, 2022, the Company issued a limited notice to proceed to Bechtel Energy Inc., formerly known as Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”), under our LSTK EPC agreement for Phase 1 of the Driftwood terminal dated as of November 10, 2017 (the “Phase 1 EPC Agreement”). The Company commenced construction of Phase 1 of the Driftwood terminal on April 4, 2022.

On June 3, 2022, we issued and sold $500.0 million aggregate principal amount of 6.00% Senior Secured Convertible Notes due May 1, 2025 (the “Convertible Notes”). Net proceeds from the Convertible Notes were approximately $488.7 million after deducting fees and expenses.

On August 18, 2022, the Company completed the acquisition of certain natural gas assets in the Haynesville Shale basin. The purchase price of $125.0 million was subject to customary adjustments totaling approximately $8.8 million, for an adjusted purchase price of approximately $133.8 million.

During the year ended December 31, 2021, the Company entered into a pledge with the National Forest Foundation on a five-year plan for reforestation and other forest management projects totaling $25.0 million across the United States. In 2022, the Company supported the planting of more than one million trees on 1,441 acres across the United States and bolstered nursery capacity by 1 million seedlings.

Liquidity and Capital Resources

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We are currently funding our operations, development activities and general working capital needs through our cash on hand and cash generated from our upstream natural gas sales. Our current capital resources consist of approximately $474.2 million of cash and cash equivalents as of December 31, 2022 on a consolidated basis. We currently maintain an at-the-market equity offering program pursuant to which we may sell our common stock from time to time. As of the date of this filing, we have availability to raise aggregate gross sales proceeds of $500.0 million under this at-the-market equity offering program.

As of December 31, 2022, we had total indebtedness of approximately $557.7 million, of which approximately $166.7 million is subject to redemption at the sole discretion of holders of the Convertible Notes on May 1, 2023. The holders of the Convertible Notes may also redeem up to an additional $166.7 million on May 1, 2024. We also had contractual obligations associated with our finance and operating leases totaling $215.8 million, of which $7.7 million is scheduled to be paid within the next twelve months.

The Company has sufficient cash on hand and available liquidity to satisfy its obligations and fund its working capital needs for at least twelve months following the date of issuance of the consolidated financial statements. The Company has the ability to generate additional proceeds from various potential financing transactions. We remain focused on the financing and construction of the Driftwood Project and related pipelines while managing our upstream assets.

The following table summarizes the sources and uses of our cash and cash equivalents and costs and expenses for the periods presented (in thousands):

						Year Ended December 31,
						2022						2021
Cash used in operating activities						$	(22,534)					$	(61,560)
Cash used in investing activities						(565,571)						(57,865)
Cash provided by financing activities						789,299						344,962
Net increase in cash, cash equivalents and restricted cash						201,194						225,537
Cash, cash equivalents and restricted cash, beginning of the period						307,274						81,737
Cash, cash equivalents and restricted cash, end of the period						$	508,468					$	307,274
Net working capital						$	276,750					$	238,920

Cash used in operating activities for the year ended December 31, 2022 decreased by approximately $39.0 million compared to the same period in 2021 due primarily to a decrease in our consolidated Net loss of approximately $49.8 million for the year ended December 31, 2022, compared to a Net loss of approximately $114.7 million in 2021. The decrease in our consolidated Net loss was partially offset by an overall increase in disbursements in the normal course of business.

Cash used in investing activities for the year ended December 31, 2022 increased by approximately $507.7 million compared to the same period in 2021. This increase was primarily due to increased spending on natural gas acquisition and development activities of approximately $344.8 million in the current period, as compared to approximately $32.4 million in the prior period. This increase was also due to the funding of Driftwood Project construction activities of approximately $175.8 million and Driftwood Project land purchases and land improvements of approximately $23.5 million in the current period.

See Note 4, Property, plant and equipment, of our Notes to the Consolidated Financial Statements for additional information about our investing activities.

Cash provided by financing activities increased by approximately $444.3 million for the year ended December 31, 2022, as compared to the same period in 2021. This increase was primarily due to higher net proceeds from borrowing transactions of approximately $436.0 million in the current period as compared to the same period of 2021 and the absence of principal repayments of borrowings of approximately $119.7 million which were completed during the year ended December 31, 2021. The increase was partially offset by an overall decrease in net proceeds from equity issuances of $108.1 million in the current period as compared to the prior period.

See Note 10, Borrowings and Note 12, Stockholders’ Equity, of our Notes to the Consolidated Financial Statements for additional information about our financing activities.

Capital Development Activities

The activities we have proposed will require significant amounts of capital and are subject to completion risks and delays. We have received all regulatory approvals for the construction of Phase 1 of the Driftwood terminal and, as a result, our business success will depend to a significant extent upon our ability to obtain the funding necessary to construct assets on a commercially viable basis and to finance the costs of staffing, operating and expanding our company during that process. In March 2022, we issued a limited notice to proceed to Bechtel under our Phase 1 EPC Agreement and commenced the construction of Phase 1 of the Driftwood terminal in April 2022.

We currently estimate the total cost of the Driftwood Project as well as related pipelines to be approximately $25.0 billion, including owners’ costs, transaction costs and contingencies but excluding interest costs incurred during construction and other financing costs. The proposed Driftwood terminal will have a liquefaction capacity of up to approximately 27.6 Mtpa and will be situated on approximately 1,200 acres in Calcasieu Parish, Louisiana. The proposed Driftwood terminal will include up to 20 liquefaction Trains, three full containment LNG storage tanks and three marine berths.

Our strategy involves acquiring additional natural gas properties, including properties in the Haynesville shale basin. We intend to pursue potential acquisitions of such assets, or public or private companies that own such assets. We expect to use stock, cash on hand, or cash raised in financing transactions to complete an acquisition of this type.

We anticipate funding our more immediate liquidity requirements for the construction of the Driftwood terminal, natural gas activities, and general and administrative expenses through the use of cash on hand, proceeds from operations, and proceeds from completed and future issuances of securities by us. Investments in the construction of the Driftwood terminal and natural gas development are and will continue to be significant, but the size of those investments will depend on, among other things, commodity prices, Driftwood Project financing developments and other liquidity considerations, and our continuing analysis of strategic risks and opportunities. Consistent with our overall financing strategy, the Company has considered, and in some cases discussed with investors, various potential financing transactions, including issuances of debt, equity and equity-linked securities or similar transactions, to support its capital requirements. The Company will continue to evaluate its cash needs and business outlook, and it may execute one or more transactions of this type in the future.

Results of Operations    

						Year Ended December 31,
						2022						2021						2020
Natural gas sales						$	270,975					$51,499						$30,441
LNG sales						120,951						19,776						6,993
Total revenue						391,926						71,275						37,434
Operating expenses						37,886						11,693						10,230
LNG cost of sales						131,663						24,745						6,993
Total cost of sales						169,549						36,438						17,223
Development expenses						68,782						50,186						27,492
Depreciation, depletion and amortization						44,357						11,481						17,228
General and administrative expenses						126,386						85,903						47,349
Impairment charge and loss on transfer of assets						—						—						81,065
Severance and reorganization charges						—						—						6,359
Related party charges						625						—						7,357
Loss from operations						(17,773)						(112,733)						(166,639)
Interest expense, net						(13,860)						(9,378)						(43,445)
Gain on extinguishment of debt, net						—						1,422						—
Other (loss) income, net						(18,177)						5,951						(612)
Income tax benefit (provision)						—						—						—
Net loss						$	(49,810)					$	(114,738)					$	(210,696)

The most significant changes affecting our results of operations for the year ended December 31, 2022 compared to 2021, on a consolidated basis and by segment, are the following:

•Increase of approximately $219.5 million in Natural gas sales as a result of higher realized natural gas prices and production volumes attributable to the acquisition of proved natural gas properties and newly drilled and completed wells during 2022.

•Increase of approximately $26.2 million in Operating expenses primarily as a result of higher production volumes attributable to the acquisition of proved natural gas properties and newly drilled and completed wells during 2022.

•Increase of approximately $32.9 million in DD&A is primarily attributable to a higher net book value utilized in the calculation of DD&A due to the acquisition of proved natural gas assets, increased capital expenditures and higher production volumes during the current period.

Marketing & Trading

•Increase of approximately $101.2 million and approximately $106.9 million in LNG sales and LNG cost of sales, respectively, primarily as a result of increased realized sales and purchase prices of an LNG cargo sold during the first quarter of 2022, as compared to the realized price of an LNG cargo sold during the second quarter of 2021.

•Increase of approximately $24.1 million in Other (loss) income, net primarily attributable to approximately $27.2 million of realized losses on the settlement of natural gas financial instruments, which was partially offset by a $10.5 million unrealized gain on natural gas financial instruments due to changes in the fair value of the Company’s derivative instruments during the current period as compared to the same period in 2021. The net loss on natural gas financial instruments in the current period was partially offset by approximately $3.5 million of realized gain on the settlements of LNG financial instruments.

Midstream

•Increase of approximately $18.6 million in Development expenses primarily attributable to a one-time donation of $6.8 million of land and roads for public use in the state of Louisiana, an approximately $3.1 million increase in technical and engineering services associated with the Driftwood Project and pipeline development activities, and

an approximately $8.7 million increase in other development expenses associated with the Driftwood Project and related pipelines.

Consolidated

•Increase of approximately $40.5 million in General and administrative expenses primarily attributable to a $14.6 million increase in professional services, a $9.0 million increase in donations to a university to advance global energy research and an increase of $16.9 million in other expenses in the normal course of business.

•Increase of approximately $4.5 million in Interest expense, net due to increased interest charges as a result of the Company’s increase in borrowing obligations during 2022 as compared to 2021. The increase in Interest expense, net was partially offset by approximately $5.7 million of capitalized interest during 2022. For further information regarding the Company’s outstanding borrowing obligations, see Note 10, Borrowings, of our Notes to the Consolidated Financial Statements.

As a result of the foregoing, our consolidated Net loss was approximately $49.8 million for the year ended December 31, 2022, compared to a Net loss of approximately $114.7 million in 2021.

The most significant changes affecting our results of operations for the year ended December 31, 2021 compared to 2020, on a consolidated basis and by segment, are the following:

•Increase of approximately $21.1 million and approximately $1.5 million in Natural gas sales and Operating expenses, respectively, attributable to increased realized natural gas prices, partially offset by decreased production volumes, as compared to 2020.

•Absence of proved natural gas Impairment charges of approximately $81.1 million that were incurred during 2020.

•Decrease of approximately $5.7 million in DD&A expenses due to utilizing a lower net book value in the calculation of DD&A as a result of the Impairment charge that we recognized in the prior year.

Marketing & Trading

•Increase of approximately $12.8 million and approximately $17.8 million in LNG sales and LNG cost of sales, respectively, as a result of increased prices of an LNG cargo sold during the second quarter of 2021, as compared to an LNG cargo sold in the third quarter of 2020.

Midstream

•An increase of approximately $22.7 million in Development expenses primarily attributable to an $18.1 million increase in compensation expenses and a $4.6 million increase in professional services, engineering services and other development expenses associated with the Driftwood Project.

Consolidated

•Absence of Severance and reorganization charges, and Related party charges of approximately $6.4 million and $7.4 million, respectively, that were incurred during 2020.

•Decrease of approximately $34.1 million in Interest expense due to the decline in interest charges as a result of the repayment of our borrowing obligations that were outstanding at the end of 2020. For further information regarding the repayment of our borrowing obligations, see Note 10, Borrowings, of our Notes to the Consolidated Financial Statements.

•Increase of approximately $38.6 million in General and administrative expenses primarily attributable to a $32.2 million increase in compensation expenses and a $6.4 million increase in professional services.

•Increase of approximately $6.6 million in Other income (loss), net primarily attributable to an approximately $8.7 million unrealized gain on natural gas financial instruments due to changes in the fair value of the Company’s derivative instruments during the current period. The increase was partially offset by an approximately $2.5 million realized loss on the settlements of unvested warrants during the current period.

As a result of the foregoing, our consolidated Net loss was approximately $114.7 million for the year ended December 31, 2021, compared to a Net loss of approximately $210.7 million in 2020.

The information set forth in Note 11, Commitments and Contingencies, to the accompanying Consolidated Financial Statements included in Part II, Item 8 of this Form 10-K is incorporated herein by reference.

Summary of Critical Accounting Estimates

Our accounting policies are more fully described in Note 2, Summary of Significant Accounting Policies, of our Notes to Consolidated Financial Statements included in this report. As disclosed in Note 2, the preparation of financial statements requires the use of judgments and estimates. We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from these estimates. We considered the following to be our most critical accounting estimates that involve significant judgment:

When there are indicators that our proved natural gas properties carrying value may not be recoverable, we compare expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on our estimates of (and assumptions regarding) future natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the income approach in accordance with GAAP. Estimates of undiscounted future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation. In addition, such assumptions and estimates are reasonably likely to change in the future.

Proved reserves are the estimated quantities of natural gas and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, because we use the units-of-production method to deplete our natural gas properties, the quantity of reserves could significantly impact our DD&A expense. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Finally, these reserves are the basis for our supplemental natural gas disclosures. See Item 1 and 2 — Our Business and Properties for additional information on our estimate of proved reserves.

Share-based compensation transactions are measured based on the grant-date estimated fair value. For awards containing only service conditions or performance conditions deemed probable of occurring, the fair value is recognized as expense over the requisite service period using the straight-line method. We recognize compensation cost for awards with performance conditions if and when we conclude that it is probable that the performance condition will be achieved. For awards where the performance or market condition is not considered probable, compensation cost is not recognized until the performance or market condition becomes probable. We reassess the probability of vesting at each reporting period for awards with performance conditions and adjust compensation cost based on our probability assessment. We recognize forfeitures as they occur.

Recent Accounting Standards

We do not believe that any recently issued, but not yet effective, accounting standards, if currently adopted, would have a material effect on our Consolidated Financial Statements or related disclosures.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary market risk relating to our financial instruments is the volatility in market prices for our natural gas production. We use financial instruments to reduce cash flow variability due to fluctuations in the prices of natural gas. The market price risk is offset by the gain or loss recognized upon the related sale of the production that is financially protected. Refer to Note 7, Financial Instruments, of the consolidated financial statements included in this Annual Report for additional details about our financial instruments and their fair value. To quantify the sensitivity of the fair value of the Company’s financial instruments to changes in underlying commodity prices, management modeled a 10% increase and decrease in the commodity price for natural gas prices, as follows (in millions):

						As of December 31, 2022						10% Increase						10% Decrease
Natural Gas Financial Instruments						$	10,463					$	7,711					$	13,446

												Page
Report of Independent Registered Public Accounting Firm (PCAOB Firm ID No. 34)												38
Consolidated Financial Statements:
			Consolidated Balance Sheets									40
			Consolidated Statements of Operations									41
			Consolidated Statements of Stockholders’ Equity									42
			Consolidated Statements of Cash Flows									43
			Notes to Consolidated Financial Statements									44
Supplementary Information
			Supplemental Disclosures About Natural Gas Producing Activities (unaudited)									63

Opinion on the Financial Statements

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2023, expressed an unqualified opinion on the Company’s internal control over financial reporting.

•We tested the effectiveness of controls related to the Company’s estimation of natural gas properties reserve quantities, including controls relating to the natural gas prices.

◦Historical conversions of proved undeveloped reserves.

◦Third party industry sources.

◦Historical realized natural gas prices.

•We evaluated the reasonableness of capital expenditures by comparing to historical wells drilled.

•We evaluated the Company’s estimates around production volumes by evaluating wells’ past production performance to ensure it was appropriately reflected in production forecasts used in generating proved reserves.

•We evaluated the experience, qualifications and objectivity of management’s specialist, an independent reservoir engineering firm, including the methodologies and calculation procedures used to estimate natural gas reserves and performing analytical procedures on the reserve quantities.

/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 22, 2023
We have served as the Company’s auditor since 2016.

TELLURIAN INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share amounts)
						December 31,
						2022						2021
ASSETS
Current assets:
Cash and cash equivalents						$	474,205					$	305,496
Accounts receivable						76,731						9,270
Prepaid expenses and other current assets						23,355						12,952
Total current assets						574,291						327,718
Property, plant and equipment, net						789,076						150,545
Deferred engineering costs						—						110,025
Other non-current assets						63,316						33,518
Total assets						$	1,426,683					$	621,806
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable						$	4,805					$	2,852
Accrued and other liabilities						129,180						85,946
Borrowings						163,556						—
Total current liabilities						297,541						88,798
Long-term liabilities:
Borrowings						382,208						53,687
Finance lease liabilities						49,963						50,103
Other non-current liabilities						24,428						10,917
Total long-term liabilities						456,599						114,707
Commitments and Contingencies (Note 11)
Stockholders’ equity:
Preferred stock, $0.01 par value, 100,000,000 authorized: 6,123,782 and 6,123,782 shares outstanding, respectively						61						61
Common stock, $0.01 par value, 800,000,000 and 800,000,000 authorized: 564,567,568 and 500,453,575 shares outstanding, respectively						5,456						4,774
Additional paid-in capital						1,647,896						1,344,526
Accumulated deficit						(980,870)						(931,060)
Total stockholders’ equity						672,543						418,301
Total liabilities and stockholders’ equity						$	1,426,683					$	621,806

TELLURIAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
						Year Ended December 31,
						2022						2021						2020
Revenues:
Natural gas sales						$	270,975					$	51,499					$	30,441
LNG sales						120,951						19,776						6,993
Total revenue						391,926						71,275						37,434
Operating costs and expenses:
LNG Cost of sales						131,663						24,745						6,993
Operating expenses						37,886						11,693						10,230
Development expenses						68,782						50,186						27,492
Depreciation, depletion and amortization						44,357						11,481						17,228
General and administrative expenses						126,386						85,903						47,349
Impairment charges						—						—						81,065
Severance and reorganization charges						—						—						6,359
Related party charges (Note 8)						625						—						7,357
Total operating costs and expenses						409,699						184,008						204,073
Loss from operations						(17,773)						(112,733)						(166,639)
Interest expense, net						(13,860)						(9,378)						(43,445)
Gain on extinguishment of debt, net						—						1,422						—
Other (expense) income, net						(18,177)						5,951						(612)
Loss before income taxes						(49,810)						(114,738)						(210,696)
Income tax benefit (provision)						—						—						—
Net loss						$	(49,810)					$	(114,738)					$	(210,696)
Net loss per common share:
Basic and diluted						$	(0.09)					$	(0.28)					$	(0.79)
Weighted average shares outstanding:
Basic and diluted						526,946						407,615						267,615

TELLURIAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(in thousands)
									Year Ended December 31,
									2022						2021						2020
Total shareholders’ equity, beginning balance									$	418,301					$	109,090					$	166,285
Preferred stock									61						61						61
Common stock:
Beginning balance									4,774						3,309						2,211
Common stock issuance									677						1,361						808
Share-based compensation, net(1)									3						43						55
Severance and reorganization charges									—						—						22
Shared-based payments									2						1						—
Settlement of Final Payment Fee (Note 10)									—						—						110
Borrowings principal repayment (Note 10)									—						—						93
Warrants exercised									—						60						10
Ending balance									5,456						4,774						3,309
Additional paid-in capital:
Beginning balance									1,344,526						922,042						769,639
Common stock issuance									299,063						406,493						98,867
Share-based compensation, net(1)									3,631						7,892						8,589
Severance and reorganization charges									—						—						2,667
Share-based payments									676						200						561
Settlement of Final Payment Fee (Note 10)									—						—						9,036
Warrants issued in connection with Borrowings (Note 12)									—						—						17,998
Borrowings principal repayment (Note 10)									—						—						13,695
Warrants exercised									—						8,117						990
Debt extinguishment									—						(218)						—
Ending balance									1,647,896						1,344,526						922,042
Accumulated deficit:
Beginning balance									(931,060)						(816,322)						(605,626)
Net loss									(49,810)						(114,738)						(210,696)
Ending balance									(980,870)						(931,060)						(816,322)
Total shareholders’ equity, ending balance									$	672,543					$	418,301					$	109,090
(1) Includes settlement of 2019 bonuses that were accrued for in 2019.

TELLURIAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
			Year Ended December 31,
			2022						2021						2020
Cash flows from operating activities:
Net loss			$	(49,810)					$	(114,738)					$	(210,696)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization			44,357						11,481						17,228
Amortization of debt issuance costs, discounts and fees			2,424						3,102						28,741
Share-based compensation			3,633						5,950						2,699
Share-based payments			678						200						562
Severance and reorganization charges			—						—						2,689
Interest elected to be paid-in-kind			—						508						3,317
Impairment charge and loss on transfer of assets			—						—						81,065
Unrealized (gain) loss on financial instruments not designated as hedges			(9,073)						(8,693)						2,618
Net gain on extinguishment of debt			—						(1,422)						—
Other			1,210						1,035						3,378
Net changes in working capital (Note 18)			(15,953)						41,017						(1,566)
Net cash used in operating activities			(22,534)						(61,560)						(69,965)
Cash flows from investing activities:
Acquisition and development of natural gas properties			(344,800)						(32,364)						(1,307)
Driftwood Project and other related pipelines construction costs			(175,791)						(15,208)						—
Land purchases and land improvements			(23,492)						(10,293)						—
Investment in unconsolidated entities			(6,089)						—						—
Note receivable			(6,595)
Capitalized internal use software and other assets			(8,804)						—						—
Net cash used in investing activities			(565,571)						(57,865)						(1,307)
Cash flows from financing activities:
Proceeds from common stock issuances			309,021						421,809						103,664
Equity issuance costs			(9,281)						(13,955)						(3,989)
Borrowing proceeds			501,178						56,500						50,000
Borrowings issuance costs			(11,487)						(2,854)						(2,612)
Borrowings principal repayments			—						(119,725)						(60,100)
Proceeds from warrant exercise			—						8,177						1,000
Tax payments for net share settlements of equity awards (Note 18)			—						(3,064)						(1,659)
Finance lease principal payments			(132)						(1,926)						(1,777)
Net cash provided by financing activities			789,299						344,962						84,527
Net increase in cash, cash equivalents and restricted cash			201,194						225,537						13,255
Cash, cash equivalents and restricted cash, beginning of period			307,274						81,737						68,482
Cash, cash equivalents and restricted cash, end of period			508,468						307,274						81,737
Supplementary disclosure of cash flow information:
Interest paid			$	20,647					$	4,105					$	11,025

Tellurian Inc. (“Tellurian,” “we,” “us,” “our,” or the “Company”), a Delaware corporation, is a Houston-based company that is developing and plans to operate a portfolio of natural gas, LNG marketing, and infrastructure assets that includes an LNG terminal facility (the “Driftwood terminal”), an associated pipeline (the “Driftwood pipeline”), other related pipelines, and upstream natural gas assets (collectively referred to as the “Business”).

The terms “we,” “our,” “us,” “Tellurian” and the “Company” as used in this report refer collectively to Tellurian Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity associated with Tellurian Inc.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Tellurian Inc. and its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

Our Consolidated Financial Statements have been prepared in accordance with GAAP, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business as well as the Company’s ability to continue as a going concern. As of the date of the Consolidated Financial Statements, we have generated losses and negative cash flows from operations, and have an accumulated deficit. We have not yet established an ongoing source of revenues that is sufficient to cover our future operating costs and obligations as they become due during the twelve months following the issuance of the Consolidated Financial Statements.

The Company has sufficient cash on hand and available liquidity to satisfy its obligations and fund its working capital needs for at least twelve months following the date of issuance of the Consolidated Financial Statements. The Company has the ability to generate additional proceeds from various other potential financing transactions. We remain focused on the financing and construction of the Driftwood Project and related pipelines while managing our upstream assets.

Segment information is prepared on the same basis that our Chief Executive Officer, who is our Chief Operating Decision Maker, uses to manage the segments, evaluate financial results and make key operating decisions. We identified the Upstream, Midstream and Marketing & Trading components as the Company’s operating segments. These operating segments represent the Company’s reportable segments. The remainder of our business is presented as “Corporate,” and consists of corporate costs and intersegment eliminations.

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions on a regular basis. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company uses three levels of the fair value hierarchy of inputs to measure the fair value of an asset or a liability. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.

For the sale of natural gas, we consider the delivery of each unit (MMBtu) to be a separate performance obligation that is satisfied upon delivery to the designated sales point and therefore is recognized at a point in time. These contracts are either fixed price contracts or contracts with a fixed differential to an index price, both of which are deemed fixed consideration that is allocated to each performance obligation and represents the relative standalone selling price basis.

Each LNG cargo, in its entirety, is deemed to be a single performance obligation due to each molecule of LNG being distinct and substantially the same and therefore meeting the criteria for the transfer of a series of distinct goods. Accordingly, LNG sales are recognized at a point in time when the LNG has completed discharging to the customer. These are contracts with a fixed differential to an index price, which is deemed fixed consideration that is allocated to each performance obligation and represents the relative standalone selling price basis. These LNG sales are recorded on a gross basis and reported in “LNG sales” on the Consolidated Statements of Operations.

Purchases and sales of LNG inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “LNG sales” on the Consolidated Statements of Operations. For such LNG sales, we require payment within 10 days from delivery. We exclude all taxes from the measurement of the transaction price.

The Company’s receivables consist primarily of trade receivables from natural gas sales and joint interest billings due from owners on properties the Company operates. The majority of these receivables have payment terms of 30 days or less. The Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings for receivables due from joint interest owners. The Company’s historical credit losses have been de minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of the Company’s counterparties.

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents that are restricted as to withdrawal or use under the terms of certain contractual agreements are recorded in Non-current restricted cash on our Consolidated Balance Sheets. The carrying value of cash, cash equivalents and restricted cash approximates their fair value.

We maintain cash balances and restricted cash at financial institutions, which may, at times, be in excess of federally insured levels. We have not incurred losses related to these balances to date.

We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the criteria for and we elect the normal purchases and sales exception.

We have not elected and do not apply hedge accounting for our derivative instruments; therefore, all changes in fair value of the Company’s derivative instruments are recognized within Other income, net, in the Consolidated Statements of Operations. Settlements of derivative instruments are reported as a component of cash flows from operations in the Consolidated Statements of Cash Flows.

Natural gas development and production activities are accounted for using the successful efforts method of accounting. Costs incurred to acquire a property (whether proved or unproved) are capitalized when incurred. Costs to develop proved reserves are capitalized and our natural gas reserves are depleted using the units-of-production method.

Fixed assets are recorded at cost. We depreciate our property, plant and equipment, excluding land, using the straight-line depreciation method over the estimated useful life of the asset. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed, and the resulting gains or losses are recorded in our Consolidated Statements of Operations.

Management tests property, plant and equipment for impairment whenever there are indicators that the carrying amount of property, plant and equipment might not be recoverable. The carrying values of our proved natural gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. If there is an indication that the carrying amount of our proved natural gas properties may not be recoverable, we compare the estimated expected undiscounted future cash flows from our natural gas properties to the carrying values of those properties. Proved properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value.

The Company adopted Accounting Standards Update ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto (“ASC 842”) on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. We elected the transition package of practical expedients to carry-forward prior conclusions related to lease identification and classification for existing leases, combine lease and non-lease components of an arrangement for all classes of our leased assets and omit short-term leases with a term of 12 months or less from recognition on the balance sheet.

The Company determines if an arrangement is a lease at inception. Leases are recognized as either finance or operating leases on our Consolidated Balance Sheets by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. Refer to Note 17 - Leases for operating and finance right-of-use assets and lease liabilities classification within our Consolidated Balance Sheets. In the absence of a readily determinable implicitly interest rate, we discount our expected future lease payments using our incremental borrowing rate. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability, only to the extent they are reasonably certain to be exercised.

Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Lease expense for finance leases is recognized as the sum of the amortization of the right-of-use assets on a straight-line basis and the interest on lease liabilities over the lease term.

As we have been in the preliminary stage of developing the Driftwood terminal, substantially all the costs related to such activities have been expensed. These costs primarily include professional fees associated with FEED studies and complying with FERC for authorization to construct our terminal and other required permitting for the Driftwood Project.

Costs incurred in connection with a project to develop the Driftwood terminal shall generally be treated as development expenses until the project has reached the notice-to-proceed state (“NTP State”) and the following criteria (the “NTP Criteria”) have been met: (i) the necessary regulatory permits have been obtained, (ii) financing for the project has been secured and (iii) management has committed to commence construction.

In addition, certain costs incurred prior to achieving the NTP State will be capitalized although the NTP Criteria have not been met. Costs to be capitalized prior to achieving the NTP State include land purchase costs, land improvement costs, costs associated with preparing the facility for use, direct payroll and payroll benefit-related costs and any fixed structure construction costs (fence, storage areas, drainage, etc.). Furthermore, activities directly associated with detailed engineering and/or facility designs shall be capitalized. Interest is capitalized in connection with the construction of major facilities. All amounts capitalized are periodically assessed for impairment and may be impaired if indicators are present.

Prior to reaching the NTP State, costs incurred to complete construction activities necessary to proceed under our LSTK EPC agreement with Bechtel are capitalized as construction in progress when the following criteria are met: (i) costs incurred are directly identifiable, (ii) necessary regulatory permits are secured, (iii) funding for the scope of work is available, and (iv) construction activities are creditable under the LSTK EPC agreement.

Prior to reaching the NTP State, costs incurred to complete construction activities necessary to develop the Driftwood pipeline and other related pipelines are capitalized as construction in progress when the following criteria are met: (i) costs incurred are directly identifiable, (ii) necessary regulatory permits are secured, and (iii) funding for the scope of work is available.

Discounts, fees and expenses incurred with the issuance of debt are amortized over the term of the debt. These amounts are presented as a reduction of our indebtedness on the accompanying Consolidated Balance Sheets. See Note 10, Borrowings, for additional details about our loans.

We have awarded share-based compensation in the form of stock, restricted stock, restricted stock units and stock options to employees, directors and outside consultants. Share-based compensation transactions are measured based on the grant-date estimated fair value. For awards containing only service conditions or performance conditions deemed probable of occurring, the fair value is recognized as expense over the requisite service period using the straight-line method. We recognize compensation cost for awards with performance conditions if and when we conclude that it is probable that the performance condition will be achieved. For awards where the performance or market condition is not considered probable, compensation cost is not recognized until the performance or market condition becomes probable. We reassess the probability of vesting at

We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, we determine deferred tax assets and liabilities on the basis of the differences between the financial statement and tax basis of assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to be realized or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a determination, we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. If we determine that we would be able to realize our deferred tax assets in the future in excess of their net recorded amount, we will make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.

Basic net loss per share excludes dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period. Diluted net loss per share reflects potential dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued and were dilutive.

NOTE 3 — PREPAID EXPENSES AND OTHER CURRENT ASSETS

			December 31,
			2022						2021
Prepaid expenses			$	2,174					$	605
Deposits			172						2,268
Restricted cash			9,375						—
Derivative asset, net - current (Note 7)			10,463						8,693
Other current assets			1,171						1,386
Total prepaid expenses and other current assets			$	23,355					$	12,952

Deposits

Margin deposits posted with a third-party financial institution related to our financial instrument contracts were approximately $0.1 million and $2.1 million as of December 31, 2022 and December 31, 2021, respectively.

Restricted cash as of December 31, 2022 consists of approximately $9.4 million held in escrow under the terms of the purchase and sale agreement for the acquisition of certain natural gas assets in the Haynesville Shale. See Note 4, Property, Plant and Equipment, for further information.

NOTE 4 — PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following (in thousands):

			December 31,
			2022						2021
Upstream natural gas assets:
Proved properties			$	412,977					$	96,297
Wells in progress			55,374						17,653
Accumulated DD&A			(92,423)						(48,638)
Total upstream natural gas assets, net			375,928						65,312
Driftwood Project assets:
Land and land improvements			52,460						25,222
Driftwood terminal construction in progress			292,734						—
Finance lease assets, net of accumulated DD&A			56,708						57,883
Buildings and other assets, net of accumulated DD&A			340						371
Total Driftwood Project assets, net			402,242						83,476
Fixed assets and other:
Leasehold improvements and other assets			12,672						3,104
Accumulated DD&A			(1,766)						(1,347)
Total fixed assets and other, net			10,906						1,757
Total property, plant and equipment, net			$	789,076					$	150,545

Depreciation, depletion and amortization expenses for the years ended December 31, 2022, 2021 and 2020 were approximately $44.4 million, $11.5 million and $17.2 million, respectively.

Driftwood Terminal Construction in Progress

During the year ended December 31, 2021, the Company initiated certain owner construction activities necessary to proceed under our LSTK EPC agreement with Bechtel Energy Inc., formerly known as Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”), for Phase 1 of the Driftwood terminal. On March 24, 2022, the Company issued a limited notice to proceed (“LNTP”) to Bechtel under the Phase 1 EPC Agreement and commenced construction of Phase 1 of the Driftwood terminal on April 4, 2022. As the Company commenced construction activities, Deferred engineering costs and Permitting costs of approximately $110.0 million and $13.4 million, respectively, were transferred to construction in progress as of March 31, 2022. During the year ended December 31, 2022, we also capitalized approximately $169.3 million of directly identifiable project costs as construction in progress, inclusive of approximately $5.7 million in capitalized interest.

On August 18, 2022, the Company completed the acquisition of certain natural gas assets in the Haynesville Shale basin (the “Asset Acquisition”). The purchase price of $125.0 million was subject to customary adjustments totaling approximately $8.8 million, for an adjusted purchase price of approximately $133.8 million. The sellers may receive an additional cash payment of $7.5 million if the average NYMEX Henry Hub gas price for the contract delivery months beginning with August 2022 through March 2023 exceeds a specific threshold per MMBtu (the “Contingent Consideration”). See Note 7, Financial Instruments, for further information.

During the year ended December 31, 2022, we put in production 13 operated Haynesville wells and participated in four non-operated Haynesville wells that were put in production.

NOTE 5 — DEFERRED ENGINEERING COSTS

Deferred engineering costs related to the planned construction of the Driftwood terminal were transferred to construction in progress upon issuing the LNTP to Bechtel in March 2022. See Note 4, Property, Plant and Equipment, for further information.

NOTE 6 — OTHER NON-CURRENT ASSETS

Other non-current assets consist of the following (in thousands):

			December 31,
			2022						2021
Land lease and purchase options			$	300					$	6,368
Permitting costs			916						13,408
Right of use asset — operating leases			13,303						10,166
Restricted cash			24,888						1,778
Investment in unconsolidated entities			6,089						—
Note receivable			6,595
Driftwood pipeline materials and rights of way			9,136						—
Other			2,089						1,798
Total other non-current assets			$	63,316					$	33,518

During the first quarter of 2022, we exercised the final land purchase options related to the Driftwood terminal. Land purchase options held by the Company as of December 31, 2022 are related to the Driftwood pipeline.

Permitting costs primarily represent the purchase of wetland credits in connection with our permit application to the USACE in 2017, which was supplemented in 2018. The permit was issued on May 3, 2019 (the “Permit”). These wetland credits were transferred to construction in progress upon issuing the limited notice to proceed to Bechtel in March 2022. See Note 4, Property, Plant and Equipment, for further information. The purchase of these wetland credits was a condition of the Permit in accordance with the Clean Water Act and the Rivers and Harbors Act, which requires us to mitigate the potential impact to Louisiana wetlands that might be caused by the construction of the Driftwood Project.

Restricted cash as of December 31, 2022 and December 31, 2021, represents the cash collateralization of letters of credit associated with finance leases.

On February 24, 2022, the Company purchased 1.5 million ordinary shares of an unaffiliated entity that provides renewable energy services. The total cost of this investment was approximately $6.1 million. This investment does not provide the Company with a controlling financial interest in or significant influence over the operating or financial decisions of the unaffiliated entity. The Company’s investment was recorded at cost.

The Company issued an amended and restated $6.6 million promissory note due June 14, 2024 (the “Promissory Note”) to an unaffiliated entity (the “Borrower”) engaged in the development of infrastructure projects in the energy industry. The Promissory Note is collateralized by a secondary interest in the Borrower’s rights to certain land lease agreements. The Promissory Note bears interest at a rate of 6.00%, which will be capitalized into the outstanding principal balance annually.

NOTE 7 — FINANCIAL INSTRUMENTS

The primary purpose of our commodity risk management activities is to hedge our exposure to cash flow variability from commodity price risk due to fluctuations in commodity prices. The Company uses natural gas financial futures and option contracts to economically hedge the commodity price risks associated with a portion of our expected natural gas production. The Company’s open positions as of December 31, 2022 had notional volumes of approximately 9.8 Bcf, with maturities extending through October 2023.

During the year ended December 31, 2021, we entered into LNG financial futures contracts to reduce our exposure to commodity price fluctuations and to achieve more predictable cash flows relative to two LNG cargos that we were committed to purchase from and sell to unrelated third-party LNG merchants in the normal course of business in January and April 2022. As of December 31, 2022, there were no open LNG financial instrument positions.

The purchase price for the Asset Acquisition includes Contingent Consideration which was determined to be an embedded derivative and is recorded at fair value in the Consolidated Balance Sheets. Refer to Note 4, Property, Plant and Equipment, for additional information. As of the date of the acquisition, the fair value of the Contingent Consideration was approximately $3.9 million, which was recorded as part of the basis in proved natural gas properties with a corresponding embedded derivative liability. Changes in the fair value of the Contingent Consideration are recognized in the period they occur and included within Other expense, net on the Consolidated Statements of Operations.

The following table summarizes the effect of the Company’s financial instruments which are included within Other expense, net on the Consolidated Statements of Operations (in thousands):

						Year ended December 31, 2022						Year ended December 31, 2021
Natural gas financial instruments:
Realized loss						$	27,179					$	826
Unrealized gain						10,463						—
LNG financial futures contracts:
Realized gain						3,532						1,010
Unrealized (loss) gain						(5,161)						8,693
Contingent Consideration:
Unrealized gain						3,770						—

The following table presents the classification of the Company’s financial derivative assets and liabilities that are required to be measured at fair value on a recurring basis on the Company’s Consolidated Balance Sheets (in thousands):

						Year ended December 31, 2022						Year ended December 31, 2021
Current Assets:
Natural Gas Financial Instruments						$	10,463					$	—
LNG Financial Futures						—						8,693
Current liabilities:
Contingent Consideration						118						—

The Company’s natural gas and LNG financial instruments are valued using quoted prices in active exchange markets as of the balance sheet date and are classified as Level 1 within the fair value hierarchy.

The fair value of the Contingent Consideration was determined using Monte Carlo simulations including inputs such as quoted future natural gas price curves, natural gas price volatility, and discount rates. These inputs are substantially observable in active markets throughout the full term of the Contingent Consideration arrangement and are therefore designated as Level 2 within the valuation hierarchy.

NOTE 8 — RELATED PARTY TRANSACTIONS

Accounts Payable due to Related Parties

In conjunction with the dismissal of prior litigation (the “Litigation”), we agreed to reimburse the Vice Chairman of the Company’s Board of Directors, Martin Houston, for reasonable attorneys’ fees and expenses he incurred during the Litigation. During the year ended December 31, 2020, we paid approximately $5.1 million to third parties to settle outstanding amounts incurred by Mr. Houston for reasonable attorneys’ fees and expenses. During the years ended December 31, 2021 and 2020, we also paid Mr. Houston approximately $0.9 million and $1.4 million, respectively, for other expenses he incurred in connection with the Litigation. As of December 31, 2022 and 2021, all amounts owed to Mr. Houston were fully settled.

Related Party Contractor Service Fees and Expenses

The Company entered into a one-year independent contractor agreement, effective January 1, 2022, with Mr. Houston. Pursuant to the terms and conditions of this agreement, the Company paid Mr. Houston a monthly fee of $50.0 thousand plus approved expenses. In December 2022, the Company amended the independent contractor agreement to expire on the earlier of (i) termination of Mr. Houston and (ii) December 31, 2023, and to increase the monthly fee to $55.0 thousand plus approved expenses. For the year ended December 31, 2022, the Company paid Mr. Houston approximately $0.6 million, for contractor service fees and expenses. As of December 31, 2022, there were no balances due to Mr. Houston.

NOTE 9 — ACCRUED AND OTHER LIABILITIES

Accrued and other liabilities consist of the following (in thousands):

			December 31,
			2022						2021
Upstream accrued liabilities			$	71,977					$	26,421
Payroll and compensation			37,329						50,243
Accrued taxes			730						991
Driftwood Project and related pipelines development activities			4,423						435
Lease liabilities			2,875						2,279
Accrued interest			5,793						660
Other			6,053						4,917
Total accrued and other liabilities			$	129,180					$	85,946

NOTE 10 — BORROWINGS

									December 31, 2022
									Principal repayment obligation						Unamortized DFC						Carrying value
Senior Secured Convertible Notes, current									$	166,666					$	(3,110)					$	163,556
Senior Secured Convertible Notes, non-current									333,334						(6,219)						327,115
Senior Notes due 2028									57,678						(2,585)						55,093
Total borrowings									$	557,678					$	(11,914)					$	545,764

									December 31, 2021
									Principal repayment obligation						Unamortized DFC						Carrying value
Senior Notes due 2028									$	56,500					$	(2,813)					$	53,687
Total borrowings									$	56,500					$	(2,813)					$	53,687