UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

(Mark One)

For the fiscal year ended December 31, 20192021

OR

For the transition period from to

Commission File Number 01-38497001-38497

Talos Energy Inc.

(Exact name of Registrant as specified in its Charter)

Registrant’s telephone number, including area code: (713) (713) 328-3000

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☑ NO No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ ☐NNoo☑

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☑ NO No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☑ NO No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YesYes ☐ NO  No ☑

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on the closing price of the shares of common stock on the New York Stock Exchange on June 30, 2019,2021, was $481,140,961.$703,193,887.

The number of shares of registrant’s Common Stock outstanding as of March 4, 2020February 17, 2022 was 54,204,730.81,881,477.

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GLOSSARYTable of Contents

GLOSSARY

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

Barrel or Bbl — One stock tank barrel, or 42 United States gallons liquid volume.

Boe — One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

BOEM — Bureau of Ocean Energy Management.

BSEE — Bureau of Safety and Environmental Enforcement.

Boepd — Barrels of oil equivalent per day.

Btu — British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

Completion — The installation of permanent equipment for the production of oil or natural gas.

Deepwater — Water depths of more than 600 feet.

Developed acres — The number of acres that are allocated or assignable to producing wells or wells capable of production.

Field — An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

GAAP — Accounting principles generally accepted in the United States of America.

Gross acres or gross wells — The total acres or wells in which the Company owns a working interest.

MBbls — One thousand barrels of crude oil or other liquid hydrocarbons.

MBblpd — One thousand barrels of crude oil or other liquid hydrocarbons per day.

MBoe — One thousand barrels of oil equivalent.

MBoepd — One thousand barrels of oil equivalent per day.

Mcf — One thousand cubic feet of natural gas.

Mcfpd — One thousand cubic feet of natural gas per day.

MMBoe — One million barrels of oil equivalent.

MMBtu — One million British thermal units (“Btus”).units.

MMcf — One million cubic feet of natural gas.

MMcfpd — One million cubic feet of natural gas per day.

Net acres or net wells — The sum of the fractional working interests the Company owns in gross acres or gross wells.

NGL — Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.

NYMEX — The New York Mercantile Exchange.

NYMEX Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub Index.

OPEC — Organization of Petroleum Exporting Countries.

Productive well — A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

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Proved developed reserves — In general, proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The SEC provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.

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Proved reserves — Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves — In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.

PV-10 — The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, derivatives, debt service and future income tax expense or (ii) depreciation depletion and amortization expense.

SEC — The Securities and Exchange Commission.

SEC pricing — The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for each month within the 12-month period beginning January 1, 2019 and ending December 1, 2019,prior to the end of the reporting period, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The SEC provides a complete definition of prices in “Modernization“Modernization of Oil and Gas Reporting”Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

Shelf — Water depths up to 600 feet.

Standardized Measure — The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. For the years ending December 31, 2019 and 2018 we were subject to U.S. federal and state income taxes at the entity level. For the tax year ending December 31, 2017, we were not subject to U.S. federal or state income taxes (in most states) at the entity level and thus made no provision for U.S. federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Undeveloped acreage — Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working interest — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

WTI or West Texas Intermediate — A light crude oil produced in the United States with an American Petroleum Institute (“API”) gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this reportAnnual Report on Form 10-K (this “Annual 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 fact included in this report,Annual Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report,Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about:

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We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility inflation,due to the continued impact of the coronavirus disease 2019 (“COVID-19”), including any new strains or variants and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business; the ability or willingness of OPEC and other state-controlled oil companies (“OPEC Plus”) to set and maintain oil production levels; the impact of any such actions; lack of transportation and storage capacity as a result of oversupply, government and regulations; lack of availability of drilling and production equipment and services,services; adverse weather events, including tropical storms, hurricanes and winter storms; cybersecurity threats; inflation; environmental risks,risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects,prospects; geologic risk,risk; drilling and other operating risks,risks; well control risk,risk; regulatory changes,changes; the uncertainty inherent in estimating reserves and in projecting future rates of production,production; cash flow and access to capital,capital; the timing of development expenditures,expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions,transactions; the possibility that the anticipated benefits of such business combinationour acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations, and the other risks discussed in Part I, Item 1A, “Risk Factors”1A. Risk Factors which are included herein.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this reportAnnual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.Annual Report.

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6SUMMARY RISK FACTORS

Risks Related to our Business and the Oil and Natural Gas Industry

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Risks Related to our Capital Structure and Ownership of our Common Stock

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Part I

Items 1 and 2. Business and Properties

Overview

As used in this Annual Report on Form 10-K (this “Annual Report”) and unless otherwise indicated or the context otherwise requires, references to “we,” “us,” “our,” “Talos Energy Inc.,” “Talos” and the “Company” refer to from and after the Stone Closing (as defined below), Talos Energy Inc. and its consolidated subsidiaries and prior to the Stone Closing, Talos Energy LLC and its consolidated subsidiaries.

We were incorporated on November 14, 2017 under the laws of the state of Delaware for the purpose of effecting the business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”), pursuant to which each of Talos Energy LLC and Stone became our wholly-owned subsidiary. We refer to this business combination as the “Stone Combination,” and its date of consummation, May 10, 2018, as the “Stone Closing Date.”

We are a technically driventechnically-driven independent exploration and production company focused on safely and efficiently maximizing long-term value through ourits operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico.Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage opportunities. We leverage decades of geology, geophysicstechnical and offshore operationsoperational expertise towardsin the acquisition, exploration exploitation and development of assets in key geological trends that are present in many offshore basins around the world.

We have historically focused With a focus on environmental stewardship, we also utilize our operations inexpertise to explore opportunities to reduce industrial emissions through our carbon capture and storage collaborative arrangements along the coast of the U.S. Gulf of Mexico because ofMexico.

We combine our deeptechnical experience in geology, geophysics and technicalengineering with innovative resource evaluation techniques and seismic imaging expertise in the basin, which maintains favorable geologicto discover new resources. We rely on our operational experience to safely and economic conditions, including multiple reservoir formations, comprehensive geologicresponsibly optimize production and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a large and expanding inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and joint venture opportunities, among others.

In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organicallyrecovery from our existing acreage or are acquisition or joint venture opportunities. We addassets. Finally, we leverage our commercial and corporate management experience to most effectively allocate our capital to balance risk and re- evaluatereward, grow our inventory in order to deploy capital as efficiently as possible.

Prior to the Stone Combination, Talos Energy Inc. had not conducted any material activities other than those incident to its incorporationbusiness and certain matters contemplated by that certain transaction agreement, dated as of November 21, 2017 (the “Stone Transaction Agreement”) by and among Stone, Talos Energy Inc., Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC (which was renamed to Talos Energy Inc. and converted into a Delaware corporation after the Stone Combination) and Talos Production LLC (which was converted into a Delaware corporation named Talos Production Inc. in 2019), pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of Talos Energy Inc. The Stone Combination was accounted for as a business combination in accordance with accounting principles generally accepted in the United States of America (“GAAP”), with Talos Energy LLC treated as the “acquirer” and Stone treated as the “acquired” company for financial reporting purposes. Accordingly, the reported financial condition and results of operations of the Company reflect the assets, liabilities and results of operations of Talos Energy LLC (as our predecessor) prior to the Stone Combination, and do not reflect the assets, liabilities and results of operations of Stone prior to such date. The assets, liabilities and results of operations of Talos Energy LLC have not been, and will not be, restated retrospectively to reflect the historical financial position or results of operations of Stone.

For more information on Talos Energy LLC, our predecessor for financial reporting purposes, see Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 1 — Formation and Basis of Presentation.maximize long-term stockholder value.

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Business Strategy

We intend to increase stockholder value by growing our hydrocarbon reserves, production, reserves, cash flow and backlog of future growth opportunities in a capital efficient manner.manner, while exploring potential carbon capture and sequestration (“CCS”) opportunities with aspirations to become a contributor to U.S. emissions reduction goals. Our core competencies of deep technical expertise significant library of seismic data resources and extensive offshorephysical operating experience allow us to successfully manage our hydrocarbon business asset base and consistently make attractive investments,acquisitions, thereby increasing shareholderstockholder value creation over time. Additionally, we believe these same core competencies can be utilized to develop and commercialize future CCS opportunities.

Hydrocarbon Strategy

We maintain a large and diverse in-house technical staff focused on geology, geophysics, engineering and other technical disciplines, providing many decades of exploration and production experience in the key resource trends thatin which we focus in.focus. Our significant library of seismic database,data resources, which focuses on the U.S. Gulf of Mexico and offshore Mexico, allows our technical team to apply proprietary seismic reprocessing techniques to evaluate or re-evaluate potential resources across our asset portfolio. Finally, we have deep in-house experience withacross our offshore operations, production operations, safety, facilities lease acquisitions and negotiations and other staff.business development.

Our strategic business development activities allow us to consistently identify and evaluate new opportunities through a wide range of potential avenues, including government lease sales, joint ventures and acquisitions, among others. We seek to actively participate in government lease sales to identify and acquire attractive leasehold acreage, which in many cases has not been evaluated with the latest reprocessed seismic data, resulting in an opportunity for us to identify previously unknown drilling prospects. Our proven track record of success through the drillbitorganic drilling opportunities frequently attracts potential drilling partners in projects that we operate, while in non-operated projects we leverage our core competencies to independently identify the best investment opportunities, review partner-proposed projects and be a value-added contributor. Finally, ourOur asset acquisition strategy is focused on assets with a geological setting that can benefit from our ability to use our seismic database and technical expertise to re-evaluate and improve the acquired properties. Specifically, our acquisition focus areas target a variety of potential situations and sellers that are currently commonavailable in offshore basins, including single asset acquisitions, consolidation of private companies and broader asset package transactions. We seek to actively participate in government lease sales to identify and acquire attractive leasehold acreage, which in many cases has not been evaluated with the latest reprocessed seismic data, resulting in an opportunity for us to identify previously unknown drilling prospects.

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We have historically focused our operations in the U.S. Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive asset acquisition market.

Utilizing our core competencies in conjunction with a robust and active business development effort allows us to use the following strategies to increase stockholder value:

Our asset footprint, which includes operational control of several key shallow and Deepwater facilities, allows us to invest in a diverse set of opportunities ranging from in-field development to high impact exploration projects while optimizing our facilities to lower incremental operating costs structures. We also believe our operated infrastructure can be attractive to other operators looking for a host facility for their subsea tie-back projects, which allows us either to be involved in new investment opportunities or to offset the operating cost of these facilities.

Engage

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Carbon Capture and Sequestration Strategy

PropertiesOur CCS business intends to leverage our experience and technical expertise in the U.S. Gulf of Mexico, including sub-surface engineering expertise, seismic data sets and interpretation capabilities, operational experience offshore and along the coast and a solid track record of safety and environmentally responsible operations. The U.S. Gulf of Mexico coast (“Gulf Coast”) is a critical industrial region with a large emissions footprint, while the underlying conventional geology in the area is believed by us to be ideal for carbon sequestration. We intend to provide carbon dioxide removal solutions to assist industrial partners with carbon emissions capture, transportation and injection into sequestration sites that we intend to operate in the region.

Future CCS project opportunities and the associated sequestration sites can generally be categorized into two project classifications where we intend to identify, lease and operate in order to increase stockholder value:

Hydrocarbon Properties

United States Gulf of Mexico Properties

Our area of focus in the United States is the Gulf of Mexico deepwater, which is generally considered to comprise water depths over 600 feet.Deepwater. Our strategy is focused in areas characterized by clearly defined infrastructure, well knownwell-known production history and geological well control, which reduces operational and investment risk. We believe the potential for large discoveries and increasing success rates in the sub-salt and mini-basin lower Pliocene and Miocene plays havehas resulted in increased industry focus on this area over the last decade.

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We believe our deepwaterDeepwater operations in the U.S. Gulf of Mexico provide significant potential growth opportunities through our planned drilling program. Through our technical approach of starting with known hydrocarbon systems and applying modern seismic reprocessing techniques, we have generated a substantial inventory of deepwaterDeepwater prospects that we believe are capable of delivering predictable production growth. We primarily focus our exploitation and exploration efforts around our existing infrastructure. This subsea tie-back strategy allows for better project economics and shorter periods between a discovery and production.

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As of December 31, 2019,2021, our core propertiesareas in the United States are illustrated below:

The following table sets forth a summary of certain key 2021 information regarding our core propertiesareas in the United States:

Phoenix — The Phoenix Field is comprised of six operated blocks, which include Green Canyon Blocks 236, 237, 238, 280, 281, and 282, located— Green Canyon is a Deepwater region in the deepwaters offshore Louisiana.

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There are no conventional fixed or mooredCentral U.S. Gulf of Mexico and is a key focus area both industry-wide and for our exploration activities. We operate two production platformsfacilities in the field-instead the subsea wells are tied back toregion, including a dynamically positioned floating production unit, the HP-I. The HP-I interconnects with the Phoenix Field throughHelix Producer I (“HP-I”), that is leased from Helix Energy Solutions Group, Inc. (“Helix”).

Mississippi Canyon — Mississippi Canyon is a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as during the approach of a hurricane orDeepwater region in the eventeastern portion of the Central U.S Gulf of Mexico with a mechanical problem with the dynamic positioning system. There were 11 wells contributingtrack record of prolific production and ongoing exploration success that continues to unlock new resources. We operate three production facilities in the Phoenix Field during 2019.region and are active as both an operator and non-operating partner in numerous development projects and producing fields.

Pompano — The Pompano Field is comprised of eight operated blocks, which include Viosca Knoll Blocks 989Shelf and 990, and Mississippi Canyon Blocks 26, 27, 28, 29, 72 and 73 located in the deepwaters offshore Louisiana. The Pompano Field’s three current subsea systems were tied back to a fixed leg platform with a total of 24 wells contributing to production during 2019.Gulf Coast

Ram Powell — The Ram Powell FieldU.S. Gulf of Mexico Shelf (the “Shelf”) and Gulf Coast area spans an enormous geographical area across the basin and provides diverse production from numerous operated production facilities. The Shelf area is compriseda producing region of six operated blocks which include Viosca Knoll Blocks 911, 912, 913, 955, 956the basin with attractive redevelopment and 957 located in the deepwaters offshore Louisiana. The Ram Powell Field has 10 wells contributing to production that were located on a tension leg platform in Viosca Knoll Block 956 during 2019.recovery enhancement opportunities.

Amberjack — The Amberjack Field is comprised12

Table of three operated blocks which include Mississippi Canyon Block 108, 109 and 110. The Amberjack Field had 26 wells contributing to production located on a fixed structure platform in Mississippi Canyon Block 109 during 2019.Contents

Mexico

Mexico Properties

Our areasarea of focus in Mexico are blocksis Block 7 located within the Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, respectively. We have executed Production Sharing Contractsstate. As of December 31, 2021, our core area in Mexico is illustrated below:

Block 7 — On July 15, 2015, a Talos-led consortium was awarded Block 7 (“PSCs”Block 7 Consortium”) with a term of thirty years, starting in September 2015, and extendable for two additional five-year periods. The Company’s participation interest (“PI”) in Block 7 is 35% and we are the operator. The Block 7 Consortium made a significant discovery in Block 7 after drilling the Zama-1 in 2017, less than two years after signing a production sharing contract (“PSC”) for the block with Mexico's upstream oil and gas regulator, the National HydrocarbonsHydrocarbon Commission (“CNH”),. Subsequent to the Zama-1 discovery, we drilled three additional wells to further appraise the discovery.

Upon conclusion of the three well appraisal program, we determined that the Zama Field likely extended into a nearby offshore block owned by Petróleos Mexicanos (“PEMEX”). On July 7, 2020, we received a notice from Mexico’s oilSecretaría de Energía (“Ministry of Energy” or “SENER”) instructing the Block 7 Consortium and gas regulator.PEMEX to unitize the Zama Field. The Block 7 Consortium and PEMEX engaged a third-party reservoir engineering firm to evaluate initial tract participation within the Zama reservoir, which concluded that the Block 7 Consortium holds 49.6% of the gross interest in the Zama Field and PEMEX holds 50.4%. On July 2, 2021, we were notified by SENER that it had designated PEMEX as the operator of the Zama unit. During the third quarter of 2021, we submitted Notices of Dispute (“Notices of Dispute”) to the Government of Mexico over decisions taken by SENER, including the designation of PEMEX as the operator of a yet-to-be unitized asset.

The PSC forms the basis for the Company’s exploration, development and production operations on Block 2 and7. The Block 7 PSCs — The PSC includes a cost recovery feature pursuant to which eligible costs in relation to the minimum work program activities are recoverable in-kind at a rate of 125% of costs from future production volumes. Production volumes are allocated in-kind between the consortiumBlock 7 Consortium and the United Mexican States on a monthly basis based on the contractual value of the hydrocarbons as defined in the PSC. Up to 60% of the monthly contractual value of the hydrocarbons will be allocated to the consortiumBlock 7 Consortium to recover eligible costs incurred in petroleum activities. Eligible costs exceeding 60% of the current month contractual value of the hydrocarbons will be recoverable in future periods. The amount of royalties will be determined for each type of hydrocarbons (oil, associated natural gas, non-associated natural gas and condensate) using an initial rate, adjusted thereafter for inflation. The remaining value of the hydrocarbons after the allocation for cost recovery and royalties is considered operating profit under the PSC. The allocation of operating profit to the consortiumBlock 7 Consortium after the allocation for cost recovery and royalties on Blocks 2 and 7 is 44% and 31%, respectively.. The profit for oil and gas is determined on a monthly basis using an adjustment mechanism based on the projects rate of return (“ROR”). In the event thatIf the cumulative project’s ROR in any one month exceeds 25%, the barrels of oil allocated to the consortiumBlock 7 Consortium after cost recovery are reduced on a sliding scale. Once the cumulative project’s internal ROR meets or exceeds 40%, the reduction locks in at a maximum rate. The Hydrocarbons Revenue Law provides that exploration and extraction activities are zero rated for value-added tax (“VAT”) purposes; all other activities are taxed at 16% VAT. The 0% rates only apply to agreements between the United Mexican States and state-owned enterprises or entities, and do not apply to any other agreement executed with third parties, even in the case of exploration and extraction contracts. The Mexico income tax rate is 30%.

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Block 31 PSC — The PSC includesWe own a cost recovery feature pursuant to which eligible costs in relation to the minimum work program activities are recoverable in-kind at a rate of 125% of costs from future production volumes. Production volumes are allocated in-kind between the consortium and the United Mexican States on a monthly basis based on the contractual value of the hydrocarbons as defined in the PSC. Up to 60% of the monthly contractual value of the hydrocarbons will be allocated to the consortium to recover eligible costs incurred in petroleum activities. Eligible costs exceeding 60% of the current month contractual value of the hydrocarbons will be recoverable in future periods. The amount of royalties will be determined for each type of hydrocarbons (oil, associated natural gas, non-associated natural gas and condensate) using an initial rate, adjusted thereafter for inflation. The remaining value of the hydrocarbons after the allocation for cost recovery and royalties is considered operating profit under the PSC. The allocation of operating profit to the consortium after the allocation for cost recovery and royalties on Blocks 31 is 35%. The profit for oil and gas is determined on a monthly basis using an adjustment mechanism based on the projects ROR. In the event that the cumulative project’s ROR in any one month exceeds 25%, the barrels of oil allocated to the consortium after cost recovery are reduced on a sliding scale. Once the cumulative project internal ROR meets or exceeds 40%, the reduction locks in at a maximum rate. The Hydrocarbons Revenue Law provides that exploration and extraction activities are zero rated for VAT purposes; all other activities are taxed at 16% VAT. The 0% rates only apply to agreements between the United Mexican States and state-owned enterprises or entities, and do not apply to any other agreement executed with third parties, even in the case of exploration and extraction contracts. The income tax rate is 30%.

As of December 31, 2019, our core properties in Mexico are presented in the following acreage map:

Block 7 — In July 2017, we completed drilling operations on the offshore Mexico Zama-1 exploration well, reaching a total depth of 13,480 feet. The Zama-1 well is the first offshore exploration well to be drilled in Mexico by the private sector. Well results confirmed the base of the reservoir section, with no penetration of an oil-water contact. The gross oil bearing interval is over 1,100 feet with petrophysical data indicating excellent rock properties and an oil sample with 30 degree API gravity oil. The well has been suspended as a future producer.

In the fourth quarter of 2018, we spud the Zama-2 well, the first appraisal well to be drilled in the field. The Zama-2 well confirmed the results of the original Zama-1 exploration well. In the first quarter of 2019, we drilled the second appraisal penetration, the Zama-2 ST1 well, which successfully tested the northern limits of the reservoir, acquired over 700 feet of whole core to collect detailed rock properties and performed successful well tests in several perforated intervals, reaching an unstimulated and restricted combined production rate of 8.2 MBoepd gross, of which 95% was oil.

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In the second quarter of 2019, we concluded our three well appraisal of the Zama discovery. The Zama-3 well was drilled to test the southern extent of the reservoir. Well results included the capturing of approximately 717 feet of whole core.

Front-End Engineering & Design work is advancing to optimize the recovery and economic development of the field and allow for the earliest possible initial production date. We have significantly narrowed the number of potential development concepts and the prevailing concept design will be the basis for the development. We were also granted a two-year contract term extension as well as regulatory approvals to allow for exploration activities on additional retained acreage PI in Block 7,31, which is separate and incremental to the Zama discovery. See Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 4 — Property, Plant & Equipment for further detail on our Mexico properties.

In September 2018, we and our consortium partners in Block 7 signed a Pre-Unitization Agreement (“PUA”) with Pemex Exploracion y Produccion (“Pemex”) related to certain tracts within the Amoca-Yaxche-03 allocation and the contiguous Block 7 PSC. Both areas are situated in the offshore portion of the Sureste Basin. The two year PUA enables information sharing related to the Zama discovery and potential extension into Pemex’s neighboring block. The PUA has been approvedoperated by the Mexican Secretariat of Energy (“SENER”). Our participation interests (“PIs”) in Block 7 is 35%. We are the operator of Block 7.

Block 2 — In September 2018, we entered into a transaction (the “Hokchi Cross Assignment”) with Hokchi Energy, S.A. de C.V. (“Hokchi”), a subsidiary of Pan American Energy LLC (“PAE”),LLC. To date, we have participated in a two-well drilling campaign that was conducted during 2019. In considering the appraisal program proposed by Hokchi for Block 31, we made an election to cross assign 25% PIsnon-consent the program in order to allow us to allocate capital to other projects. We recorded an impairment of $18.1 million for our unproved property investment in Block 2 and Block 31. Our assignment of a 25% PI in Block 2 to Hokchi closed on December 21, 2018, and Hokchi’s assignment to us closed on May 22, 2019. Following the completion of the Hokchi Cross Assignment, we own a 25% PI in each of Block 2 and Block 31 and Hokchi is the operator of both blocks.

As a result of our evaluation of unproved property located in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from the exploratory wells drilled during the second quarter of 2019 andyear ended December 31, 2021, as the Block 2 production sharing contract’s expiration date, we recorded a $12.2 millioncosts were not recoverable. This non-cash impairment is presented asin “Write-down of oil and natural gas properties” on our Consolidated Statements of Operations in Part IV, Item 15. Exhibits and Financial Statement Schedules. Also,

Carbon Capture & Sequestration

We are leveraging decades of experience with conventional geology and offshore energy operations to pursue our goal of developing future carbon capture and storage opportunities. We are actively evaluating potential project opportunities through our collaborative arrangements along the U.S. Gulf Coast. Our areas of development are illustrated below:

Jefferson County GLO Hub Project — In August 2021, we, along with partner Carbonvert, Inc., were selected as the winning bidder for the Texas General Land Office's (“GLO”) Jefferson County carbon storage site. The successful bid makes us the operator of what we expect to be the first large-scale offshore carbon storage location in the United States near the Beaumont and Port Arthur, Texas industrial corridor. As of December 31, 2021, the lease with the Texas GLO remained subject to negotiation of final terms, which we expect to conclude and finalize in mid-2022.

Freeport LNG Point Source Project — In November 2021, we announced that, along with partner Storegga Geotechnologies Limited (“Storegga”), we had executed a resultletter of intent with an affiliate of Freeport LNG Development, L.P. (“Freeport LNG”) to develop a CCS project immediately adjacent to its existing LNG pre-treatment facilities in Freeport, Texas. The project intends to utilize a Freeport LNG-owned geological sequestration site located less than half a mile from point of capture with up to a 30-year injection term, and thus the project benefits from a dedicated source of carbon dioxide (“CO2”) and a secured injection site in close physical proximity. The companies anticipate first injection could occur by the end of 2024. As of December 31, 2021, definitive documentation with Freeport LNG remained subject to negotiation of final terms, which we expect to conclude and finalize in early 2022.

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River Bend Hub Project — In February 2022, we announced our entry into (i) a lease agreement for a major carbon capture and sequestration project along the Mississippi River industrial corridor and (ii) a memorandum of understanding with EnLink Midstream, LLC (“EnLink”) to jointly develop a carbon capture, transportation and sequestration joint service offering focused on the Mississippi River industrial corridor. The joint service offering is being marketed to potential customers by both us and EnLink. The lease agreement will allow for three sequestration sites near EnLink’s existing pipelines. We will be the project manager and operator of the 2019 drilling program, the consortium has fulfilled the minimum work program requirements for the Block 2 area.

Block 31 — In July 2019, we spud the first project on Block 31, the Xaxamani-2EXP well. This is the first well in the Olmeca project area, which is a shallow oil project set upinjection, storage, and monitoring and will be joined by the Xaxamani-1 exploratory well drilled in 2003, which logged oil pay in several intervals. Also in the third quarter 2019, PAE drilled the exploratory well, Tolteca-1EXP. A successful drill-stem test on the Xaxamani-2EXP confirmed productivity by producing oil to the surface. The two-well drilling campaign further confirmed the oil and gas discovery. The operator submitted an Appraisal Plan for the Xaxamani discovery in the fourth quarter of 2019. The Xaxamani discovery is located approximately one mile from shore on the Gulf of Mexico shelf. As a result of the 2019 drilling program, pending government approval, the Block 31 consortium has fulfilled the minimum work program requirements. Talos holds a 25% working interest in Block 31.our partner, Storegga.

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Summary of Reserves

The following table summarizes our estimated proved reserves as of December 31, 2019, 2018 and 2017 which are all located in the United States.States:

Reconciliation of Standardized Measure to PV-10

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent.10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 of our proved reserves at December 31, 2019, 2018 and 2017.(in thousands):

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Changes in Proved Developed Reserves

The following table discloses our estimated changes in proved developed reserves during the year ended December 31, 2019:reserves:

Our proved developed reserves at December 31, 2021 increased by 9.2 MMBoe, or 7% primarily due to:

Revisions of Previous Estimates — DownwardUpward revisions of 11.515.1 MMBoe are primarily attributable to a decrease13.2 MMBoe increase in commodity prices and under performance compared to expectationsas well as net increase of 6.51.9 MMBoe in the Phoenix Field, 3.3 MMBoe in the Ram Powell Field and 2.3 MMBoe in the Pompano Field.performance revisions across our core areas.

Additions — Additions in 2019 of 5.71.8 MMBoe are primarily attributable to the successful drilling in the EW 305 Field which consists of EW Block 306 A-2 ST2, EW Block 306 A-10 ST2Crown and the GI Block 82 A-22 wells which were included in our 2019 shallow water drilling campaign.

Acquired — Acquired proved developed reserves of 2.1 MMBoe are attributable to the January 2019 acquisition of an approximate 9.6% non-operated working interest in the GunflintAnchor Field located in the Mississippi Canyon area (the “Gunflint Acquisition”).core area.

Development of Proved Undeveloped Reserves

The following table discloses our estimated proved undeveloped (“PUD”) reserve activities during the year ended December 31, 2019:activities:

Our PUD reserves at December 31, 2019 increased2021 decreased by 7.510.6 MMBoe, or 21%30% primarily due to:

Extensions and Discoveries — Additions of 10.1 MMBoe of PUD reserves were the result of field evaluations primarily in the Green Canyon Block 21 for 4.0 MMBoe and Pompano Fields for 4.0 MMBoe.

Revisions of Previous Estimates — Upward revisions of 2.05.2 MMBoe are primarily dueattributable to increased PUD allocation based on offset proved developed producing (“PDP”) performancean increase in Phoenix Tornado B-6 reservoir. These revisions were partially offset by the lease expiration of Eugene Island 305 reserves of 1.2 MMBoe.commodity prices across our core areas.

Acquired — Acquisitions of 0.5 MMBoe of PUD reserves in the MC 948 Block as a result of the Gunflint Acquisition in January 2019.

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Conversion to Proved Developed Producing — 2018 PUD to proved developed conversionsConversions of 5.115.8 MMBoe isare primarily attributable to our Deepwater drilling campaign which included successful development wells in our Phoenix Field and Grand Canyon 18 Field located in the Phoenix Field’s Boris 4 well.Green Canyon core area.

We annually review all PUD reserves to ensure an appropriate plan for development exists. Our PUD reserves are required to be converted to proved developed reserves within five years of the date they are first booked as PUD reserves.reserves, unless the reserves are associated with an existing producing zone. Future development costs associated with our PUD reserves at December 31, 20192021 totaled approximately $501.7$308.0 million, primarilyof which $123.0 million, $93.7 million and $91.3 million is attributable the Phoenix Field’s $340.4 million future development costs.to our Green Canyon, Shelf and Gulf Coast and Mississippi Canyon core areas, respectively. When considering capital expenditures associated with other exploration projects and abandonment obligations, we expect to fund the development of PUD reserves using cash flows from operations and, if needed, availability under the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”), in each future annual period prior to the five year expiration. Our 20202022 drilling program includes development of PUD reserves, and the conversion rate may not be uniform due to obligatory wells, newly acquired PUD reserves and production performance targets.

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Internal Controls over Reserve Estimates and Reserve Estimation Procedures

At December 31, 2019, 20182021, 2020 and 2017,2019, proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists, as described in further detail below.

Our policies regarding internal controls over the determination of reserves estimates require reserves quantities, reserves categorization, future producing rates, future net revenue and the present value of such future net revenue prepared using the definitions set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance. These internal controls, which are intended to ensure reliability of our reserves estimations, include, but are not limited to, the following:

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are ultimately recovered.

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During the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil, natural gas and NGL production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. When compared on a well by well basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. NSAI determined that its estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. NSAI issued unqualified audit opinions on our reserves as of December 31, 2019, 20182021, 2020 and 20172019 based upon its evaluations. NSAI concluded that our estimates of reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPEE. The 2021 NSAI reports arereport is filed as exhibitsExhibit 99.1 to this report.Annual Report.

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Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

Qualifications of Primary Internal Engineer

Our Director of Reserves is the technical person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating reserve audits conducted by NSAI. He has over 4547 years of industry experience with positions of increasing responsibility, including 3739 years as a reserves evaluator or manager. His further professional qualifications include a State of Texas Professional Engineering License, extensive internal and external reserve training and asset evaluation. In addition, he is an active participant in industry reserve seminars and professional industry groups, and has been a member of the Society of Petroleum Engineers (“SPE”) for over 4547 years. He reports directly to our Vice President of Corporate Development.

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Drilling Activity

The following table sets forth our drilling activity duringactivity: