UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 20182021

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: Common Stock, Par Value $0.01 Per Share; Common stock traded on the NYSE stock market

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 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 Yes ☐ NO ☒No ☑

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 Yes ☑ 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 Yes ☑ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒

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). YES Yes ☐ 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 NYSEthe New York Stock MarketExchange on June 30, 2018,2021, was $281,311,750.$703,193,887.

The number of shares of registrant’s Common Stock outstanding as of March 6, 2019February 17, 2022 was 54,155,805.81,881,477.

TABLE OF CONTENTS

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Table of ContentsGLOSSARY

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

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

Boepd. BOEM — Bureau of Ocean Energy Management.

BSEE — Bureau of Safety and Environmental Enforcement.

Boepd —Barrels of oil equivalent per day.

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

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

Deepwater. Deepwater —Water depths of more than 600 feet.

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

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

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

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

MBoe. MBoe —One thousand barrels of oil equivalent.

MBoepd. MBoepd —One thousand barrels of oil equivalent per day.

Mcf. Mcf —One thousand cubic feet of natural gas.

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

MMBoe. MMBoe —One million barrels of oil equivalent.

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

MMcf. MMcf —One million cubic feet of natural gas.

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

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

NGL. 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. NYMEX —The New York Mercantile Exchange.

NYMEX Henry Hub. 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. 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.reserves —In general, proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The Securities and Exchange CommissionSEC 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. 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.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 Securities and Exchange CommissionSEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.

PV-10. 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 Securities and Exchange CommissionSEC 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.SEC —The Securities and Exchange Commission.

SEC pricing. 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, 2018 and ending December 1, 2018,prior to the end of the reporting period, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The Securities and Exchange CommissionSEC provides a complete definition of prices in “Modernization“Modernization of Oil and Gas Reporting”Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

Shelf. 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 year ending December 31, 2018, we were subject to U.S. federal and state income taxes at the entity level. For the tax years ending December 31, 2017 and 2016, 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.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.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. Intermediate —A light crude oil produced in the United States with an APIAmerican Petroleum Institute (“API”) gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

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CAUTIONARY STATEMENT REGARDING 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 the business combination between Talos Energy LLCour acquisitions and Stone Energy Corporation,other 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 the two companies,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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SUMMARY RISK FACTORS

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

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Table of deep water assets with existing infrastructureContents

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 and unless otherwise indicated or are acquisition or joint venture opportunities. We addthe context otherwise requires, references to “we,” “us,” “our,” “Talos Energy Inc.,” “Talos” and reevaluate our inventory in orderthe “Company” refer to deploy capital as efficiently as possible.

Talos Energy Inc. wasand its consolidated subsidiaries.

We were incorporated on November 14, 2017 under the laws of the state of Delaware for the purpose of effecting the previously disclosed business combination between Talos Energy LLC (“Talos Energy”) 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 “Closing“Stone Closing Date.” In addition, as used in this report

We are a technically-driven independent exploration and unless otherwise indicated or the context otherwise requires, references to “we,” “us,” “our,” “Talos Energy Inc.,” “Talos”production company focused on safely and the “Company” refer to, from and after the Closing Date, Talos Energy Inc. andefficiently maximizing long-term value through its consolidated subsidiaries and prior to the Closing Date, Talos Energy and its consolidated subsidiaries.

Prior to the Stone Combination, Talos Energy Inc. had not conducted any material activities other than those incident to its incorporation and certain matters contemplated by that certain Transaction Agreement (the “Transaction Agreement”), dated as of November 21, 2017, among Stone, Talos Energy, us and Sailfish Merger Sub Corporation (“Merger Sub”). The transactions contemplated by the Transaction Agreement were accounted for as a business combination in accordance with accounting principles generally acceptedoperations, currently in the United States (“U.S.”) Gulf of America (“GAAP”), with Talos Energy treated as the “acquirer”Mexico and Stone treated as the “acquired” company for financial reporting purposes. Accordingly, the reported financial condition and results of operations of Talos Energy Inc. reflect the assets, liabilities and results of operations of Talos Energy (as our predecessor) prior to the Closing Date, 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 Inc. 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, our predecessor for financial reporting purposes, please read “—Talos Energy LLC.” For more information on the Stone Combination, please read “— Stone Combination.”

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Talos Energy LLC

Talos Energy was formed in 2011 under the laws of the state of Delaware and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy had incurred only certain general and administrative expenses associated with the start-up of its operations.  

On February 3, 2012, Talos Energy completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”, and together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which Talos Energy received a private equity capital commitment.

On February 6, 2013, Talos Energy acquired all of the equity of Energy Resource Technology GOM, LLC (“ERT”) and its subsidiary from Helix Energy Solutions Group, Inc. (“Helix”) for approximately $625.2 million (inclusive of purchase price and working capital adjustments of approximately $15.2 million), and payments for ongoing guarantees from Helix to third-parties. Additionally, Talos Energy agreed to assign Helix an overriding royalty interest in certain properties acquired in the transaction at closing. We refer to this purchase as the “ERT Acquisition.” The ERT Acquisition was effective December 1, 2012 and closed on February 6, 2013. Prior to the closing of the ERT Acquisition, the Sponsors and members of management had invested an aggregate of approximately $325 million in Talos Energy to fund a portion of the ERT Acquisition as well as to fund other asset purchases.

In September 2015, Talos Energy, together with consortium partners Sierra Oil and Gas S. de R.L de C.V. (“Sierra”) and Premier Oil Plc (“Premier”, and together with Talos Energy and Sierra, the “Consortium”) executed two Production Sharing Contracts (“PSCs”) with the National Hydrocarbons Commission (“CNH”), Mexico’soffshore Mexico both upstream through oil and gas regulator, for Blocks 2exploration and 7production and downstream through the development of Round 1. The PSCs were awarded to the Consortium during the first tenderfuture carbon capture and storage opportunities. We leverage decades of Mexico’s oiltechnical and natural gas fields in over 80 years. Blocks 2 and 7 are locatedoffshore operational expertise in the Sureste Basin,acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a prolific proven hydrocarbon province, in the shallow waters offfocus on environmental stewardship, we also utilize our expertise to explore opportunities to reduce industrial emissions through our carbon capture and storage collaborative arrangements along the coast of Mexico’s Veracruzthe U.S. Gulf of Mexico.

We combine our technical experience in geology, geophysics and Tabasco states, respectively. Blocks 2engineering with innovative resource evaluation techniques and 7 contain approximately 162,904 gross acres with numerous high impact prospects in well-establishedseismic imaging expertise to discover new resources. We rely on our operational experience to safely and emerging plays. In 2017, the Consortium drilled Zama-1, the initial exploration well in Block 7, resulting in the discovery of the Zama Field.  As of December 31, 2018,responsibly optimize production and recovery from our assets. Finally, we were in the process of appraising the discovery.leverage our commercial and corporate management experience to most effectively allocate our capital to balance risk and reward, grow our business and maximize long-term stockholder value.

Stone Combination

On the Closing Date, we consummated the transactions contemplated by the Transaction Agreement and Talos Energy and Stone became our wholly-owned subsidiaries. Pursuant to the Transaction Agreement, the following transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and our direct wholly-owned subsidiary (the “Merger”), and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of our common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (“Talos Production”) (which at that time owned 100% of the equity interests in Talos Energy) to us in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”).

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Concurrently with the consummation of the Transaction Agreement, we consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among us, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% senior notes due 2022 (“9.75% Senior Notes”) issued by Talos Production  and Talos Production Finance, Inc. (together, the “Talos Issuers”) to us in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Senior Secured Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes.

Substantially concurrent therewith, we consummated an exchange offer and consent solicitation, pursuant to which the holders of the 7.50% Stone Senior Notes, excluding the 7.50% Stone Senior Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Stone Senior Notes for 11.00% Senior Secured Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Stone Senior Notes. Approximately $81.5 million in aggregate principal amount of the 7.50% Stone Senior Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Stone Senior Notes remained outstanding as of the Closing Date.

As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.

Business Strategy

We intend to increase stockholder value through the following strategies:

Grow Production, Reservesby growing our hydrocarbon reserves, production, cash flow and Cash Flow by Developing Our Attractive Asset Basefuture growth opportunities in a Capital Efficient Manner.capital efficient manner, while exploring potential carbon capture and sequestration (“CCS”) opportunities with aspirations to become a contributor to U.S. emissions reduction goals. Our deep technical expertise and extensive physical operating experience allow us to successfully manage our hydrocarbon business asset base and consistently make attractive acquisitions, thereby increasing stockholder value over time. Additionally, we believe these same core competencies can be utilized to develop and commercialize future CCS opportunities.

Our team isHydrocarbon Strategy

We maintain a large and diverse in-house technical staff focused on continuously improving capital efficiency,geology, geophysics, engineering and other technical disciplines, providing many decades of exploration and production experience in the key resource trends in which we believe the combinationfocus. Our significant library of our experience and the existing infrastructure inseismic data resources, which focuses on the U.S. Gulf of Mexico willand 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 across our offshore operations, production operations, safety, facilities and business development.

Our strategic business development activities allow us to continueconsistently identify and evaluate new opportunities through a wide range of potential avenues, including government lease sales, joint ventures and acquisitions, among others. Our proven track record of success through organic drilling opportunities frequently attracts potential drilling partners in projects that we operate, while in non-operated projects we leverage our core competencies to benefit from attractive findingindependently identify the best investment opportunities, review partner-proposed projects and development costs. We alsobe a value-added contributor. Our asset acquisition strategy is focused on assets with a geological setting that can benefit from our proven ability to increase production from legacy fields and identified projects. Furthermore, we intend to use our seismic database and technical expertise to re-evaluate and seismic databaseimprove the acquired properties. Specifically, our acquisition focus areas target a variety of potential situations and sellers that are currently available in offshore basins, including single asset acquisitions, consolidation of private companies and broader asset package transactions. We seek to find additional drilling projectsactively participate in proximity to our existing assets.

Expand Our Reserves and Production Through Lease Acquisitions and Diversified Business Development.

We intend to deploy our expertise and seismic resourcesgovernment lease sales to identify and acquire attractive leasehold acreage, which in federal lease sales for the U.S. Gulf of Mexico. In many cases acreage available in the federal lease sales has not been evaluated with the latest reprocessed seismic data, resulting in an opportunity for us to identify previously unknown drilling prospects. In the latest federal lease

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Table of the August 2018 sale, we were the fifth most active bidderContents

We have historically focused our operations in the U.S. Gulf of Mexico because of our deep experience and we weretechnical expertise in the high bidder on 14 lease blocks. During that sale, we focused on blocks that adjoinbasin, 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 deep industry relationships, technical expertiseasset footprint, which includes operational control of several key shallow and extensive regional seismic database allowDeepwater facilities, allows us to effectively identify and evaluate these third-party proposed drilling projects.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 intendalso believe our operated infrastructure can be attractive to continue to strategically pursue these types of drilling projects with 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.

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Carbon Capture and Sequestration Strategy

Our CCS business intends to leverage our operationalexperience and technical expertise toin the extent we believe they will create additional value for stockholders.

Maintain High Operatorship to Leverage Our Technical Expertise.

We operate properties that generate approximately 94%U.S. Gulf of our production,Mexico, including sub-surface engineering expertise, seismic data sets and we strive to maintaininterpretation capabilities, operational experience offshore and along the coast and a majoritysolid track record of operational control over our producing properties. We believe that maintaining controlsafety and environmentally responsible operations. The U.S. Gulf of our production enablesMexico 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 apply leading practicesbe ideal for carbon sequestration. We intend to every aspect of our operations. In addition, maintaining high operatorship allows usprovide carbon dioxide removal solutions to leverage our technical team’s deep regional experienceassist industrial partners with carbon emissions capture, transportation and modern seismic expertiseinjection 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 generate attractive investmentincrease stockholder value:

Hydrocarbon Properties

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.

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, 2018, we had an interest in 271.0 gross producing wells (228.9 net producing wells) on 885,888 gross (624,891 net) total acres, of which 477,190 gross (342,604 net) are developed acres. We operate properties that contain 98% of our proved reserves at December 31, 2018.

At December 31, 2018,2021, our core propertiesareas in the United States which represent approximately 68% of our 2018 production and 78% of our December 31, 2018 proved reserves are illustrated below:

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

Phoenix Field—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 Helix Producer I (“HP-I”), that is leased from Helix Energy Solutions Group, Inc. (“Helix”). The HP-I interconnects with the Phoenix Field through

Mississippi Canyon — Mississippi Canyon is a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as 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 are eight active wellstrack record of prolific production and ongoing exploration success that continues to unlock new resources. We operate three production facilities in the Phoenix Fieldregion and are active as both an operator and non-operating partner in numerous development projects and producing fields.

Shelf and Gulf Coast —The U.S. Gulf of Mexico Shelf (the “Shelf”) and Gulf Coast area spans an enormous geographical area across the average net dailybasin and provides diverse production for the year ended December 31, 2018 was 17,907 Boepd.

Pompano Field— from numerous operated production facilities. The Pompano FieldShelf area is comprised of seven operated blocks which include Viosca Knoll Blocks 989 and 990, and Mississippi Canyon Blocks 26, 27, 28, 29 and 72 located in the deepwaters offshore Louisiana. The Pompano Field’s three current subsea systems are tied back to a fixed leg platform with a total of 23 active wells. The field’s average net daily production since the Closing Dateproducing region of the Stone Combination was 10,534 Boepd.basin with attractive redevelopment and recovery enhancement opportunities.

Ram Powell Field— The Ram Powell Field12

Our area of focus in Mexico is comprised of six operated blocks which include Viosca Knoll Blocks 911, 912, 913, 955, 956 and 957Block 7 located in the deepwaters offshore Louisiana. The Ram Powell Field has eight active dry tree wells that are located on a tension leg platform in Viosca Knoll Block 956. The field’s average net daily production since the Closing Date of the Stone Combination was 7,856 Boepd.

Amberjack Field—The Amberjack Field is comprised of three operated blocks which include Mississippi Canyon Block 108, 109 and 110. The Amberjack Field has 29 active conventional dry tree wells located on a fixed structure platform in Mississippi Canyon Block 109. The field’s average net daily production since the Closing Date of the Stone Combination was 2,021 Boepd.

Mexico Properties

In September 2015, we, together with the Consortium, executed a PSC with the CNH for each of Blocks 2 and 7 of Round 1. The PSCs were awarded to the Consortium during the first tender of Mexico’s oil and natural gas fields in over 80 years. Blocks 2 and 7 are located inwithin the Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico’s VeracruzTabasco state. 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 (“Block 7 Consortium”) with a term of thirty years, starting in September 2015, and Tabasco states, respectively. Blocks 2 and 7 contain approximately 162,904 gross acres with numerous high impact prospects in well-established and emerging plays. Ourextendable for two additional five-year periods. The Company’s participation interest (“PI”) in Block 27 is currently 20%35% and our PIwe are the operator. The Block 7 Consortium made a significant discovery in Block 7 is 35%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 Hydrocarbon Commission (“CNH”). We areSubsequent 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 Secretaría de Energía (“Ministry of Energy” or “SENER”) instructing the Block 7 Consortium and 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 7.

The PSCs includeBlock 7 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 Block 7 Consortium and the United Mexican States on a monthly basis based on the contractual value of the hydrocarbons as defined in the PSCs.PSC. Up to 60% of the monthly contractual value of the hydrocarbons will be allocated to the Block 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. Between 7.5% and 14%The amount of the contractual value of the oilroyalties will be allocated to the United Mexican States in the formdetermined for each type of a royalty, depending upon the price of a barrel of oil, with a collar between $48.00 and $100.00 per Bbl. The allocation for the royalty onhydrocarbons (oil, associated natural gas, is 0% when the price per MMBtu is below $5.00 and, if thenon-associated natural gas price exceeds $5.00 per MMBtu, the royalty allocation percentage is calculated as the price per MMBtu divided by 100.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 PSCs.PSC. The allocation of operating profit to the Block 7 Consortium after the allocation for cost recovery and royalties is 31%. The profit for oil and gas is determined on Blocks 2 and 7 is 44% and 31%, respectively. Additionally, ina monthly basis using an adjustment mechanism based on the event thatprojects rate of return (“ROR”). If the cumulative project internal rate of returnproject’s ROR in any one month exceeds 25%, the barrels of oil allocated to the Block 7 Consortium after cost recovery (“Profit Oil”) isare reduced on a sliding scale. The reduction in Profit Oil varies linearly between 0% and 75% of the entitled amount. The maximum 75% reduction occurs onceOnce the cumulative projectproject’s internal rate of returnROR 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 — We own a 25% PI in Block 31, which is operated by Hokchi Energy, S.A. de C.V. (“Hokchi”), a subsidiary of Pan American Energy 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 non-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 31 during the year ended December 31, 2018, our core properties in Mexico are2021, as the costs were not recoverable. This non-cash impairment is presented in the following acreage map:“Write-down of oil and natural gas properties” on our Consolidated Statements of Operations in Part IV, Item 15. Exhibits and Financial Statement Schedules.

Carbon Capture & Sequestration

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. The Zama appraisal campaign is expected to be completed by mid-year 2019. If the appraisal of the Zama Field confirms our initial estimates,what we expect to announcebe 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 Final Investment Decisionletter 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 2020, following Mexican government approvalFreeport, 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 development plan. In addition to Zama, other prospects within Block 7 are being analyzedinjection, storage, and matured to potentiallymonitoring and will be drilled over the next several years, assuming an extension of the Exploration Period is approvedjoined by the CHH. See Part II, Item 8. Financial Statements and Supplementary Data — Note 4 — Property, Plant & Equipment for further detail on Mexico properties.our partner, Storegga.

Pre-Unitization Agreement with Pemex. In September 2018, we and our consortium partners in Block 7 signed a Pre-Unitization Agreement (“PUA”) with Pemex Exploration 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 approved by the Mexican Secretariat of Energy (“SENER”).

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In February 2019, the CHN granted approval for drilling in the Acan-1 exploration well in Block 2. Operations are expected to begin in March 2019 and extend into the second quarter. Soon thereafter, we plan to participate in two prospects in Block 31. Beyond the Acan prospects, we believe that Blocks 2 and 31 contain a significant portfolio of compelling prospects with strong technical ties to offsetting discoveries.

Recent Developments

Gunflint Acquisition

On January 11, 2019, pursuant to a Purchase Sale Agreement with Samson Offshore Mapleleaf, LLC we acquired an approximate 9.6% non-operated working interest in the Gunflint Field located in the Mississippi Canyon area for $29.6 million.

HP-I Dry-Dock Downtime

During the first quarter of 2019, the HP-I entered into its regulatory required dry-dock period. Regulators require the ship to go to dry-dock twice every five years. On May 7, 2019, the HP-I completed its dry-dock requirement and departed the shipyard. After a period of sea trials, we expect production from the Phoenix Field to commence in late March 2019. The annualized production impact of the shut-in in the Phoenix Field is estimated to be between 2.0 MBoepd and 3.0 MBoepd.

Drilling and Exploration Activities

The Tornado 3 well’s drilling operations completed in December 2018 and completed in January 2019. We expect production to commence by early second quarter, 2019, with an expected net production rate between 10.0 MBoepd and 15.0 MBoepd. We are the operator and own a 65% working interest.

The Boris 3 wells started drilling operations in January 2019 and completed in February 2019. We expect production to commence in the second quarter of 2019, with a net production between or 2.8 Mboepd and 4.6 MBoepd. We are the operator and own a 100% working interest.

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Summary of Reserves

Our estimated proved reserves totaled 151.7 MMBoe at December 31, 2018. The following table summarizes our estimated proved reserves as of December 31, 2018, 2017 and 2016 which are all located in the United States.States:

Reconciliation of PV-10Standardized Measure to Standardized MeasurePV-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, 2018, 2017, and 2016.(in thousands):

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Changes in Proved Developed Reserves

Our proved developed reserves as of December 31, 2018 increased by 61.8 MMBoe to 115.5 MMBoe from 53.7 MMBoe at December 31, 2017, a 115% increase. This increase was due to:  

Development of Proved Undeveloped Reserves

The following table discloses our estimated PUD reserve activities during the year endedchanges in proved developed reserves:

Our proved developed reserves at December 31, 2018:2021 increased by 9.2 MMBoe, or 7% primarily due to:

Revisions of Previous Estimates — Upward revisions of 15.1 MMBoe are primarily attributable to a 13.2 MMBoe increase in commodity prices as well as net increase of 1.9 MMBoe in performance revisions across our core areas.

Additions — Additions of 1.8 MMBoe are primarily attributable to the successful drilling in the Crown and Anchor Field located in the Mississippi Canyon core area.

Development of Proved Undeveloped Reserves

The following table discloses our estimated proved undeveloped (“PUD”) reserve activities:

Our PUD reserves at December 31, 20182021 decreased by 10.710.6 MMBoe, or 23%30% primarily due to:

Extensions and Discoveries. We added 3.1 MMBoe of PUD reserves through an evaluation of Green Canyon Block 18 which was initially acquired in the Whistler Acquisition. See Part II, Item 8. Financial Statements and Supplementary Data — Note 3 — Acquisitions, for more information.

Revisions of Previous Estimates. Downward reserves — Upward revisions of 4.5 MMBoe primarily due to timing of development of certain PUD locations to move beyond 5 years of 3.3 MMBoe and downward revisions of 1.2 MMBoe. The revisions were caused by a new geological data and changes in overall project economics, and expiration of a block. Future development costs related to the PUD revisions decreased by $4.0 million primarily due to a review of completion strategy and optimization of capital expenditures in the Phoenix Field.

Acquired. We added a 0.7 MMBoe PUD reserves in Bayou Hebert Field through the Stone Combination.

Conversion to Proved Developed Producing. 2017 PUD to proved developed conversions of 10.05.2 MMBoe are primarily attributable to thean increase in commodity prices across our core areas.

Conversion to Proved Developed Producing —Conversions of 15.8 MMBoe are primarily attributable to our Deepwater drilling campaign which included successful development wells in our Phoenix Field Tornado #3ST and two wellsGrand Canyon 18 Field located in Main Pass Block 74, A8ST and A11ST.the Green Canyon core area.

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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, 20182021 totaled approximately $396.7$308.0 million, primarilyof which $123.0 million, $93.7 million and $91.3 million is attributable the Phoenix Field’s $317.3 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 BankCompany’s senior reserve-based revolving credit facility (the “Bank Credit Facility,Facility”), in each future annual period prior to the five year expiration. Our 20192022 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, 2018, 20172021, 2020 and 2016,2019, 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 reserve quantities, reserves categorization, future producing rates, future net revenue and the present value of such future net revenue to 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, 2018, 20172021, 2020 and 20162019 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

Floyd Bone, ourOur 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. Mr. BoneHe has over 4447 years of industry experience with positions of increasing responsibility, including 3639 years as a reserves evaluator or manager. Mr. Bone’sHis further professional qualifications include a State of Texas Professional Engineering License, extensive internal and external reserve training and asset evaluation. In addition, Mr. Bonehe is an active participant in industry reserve seminars and professional industry groups, and has been a member of the SPEESociety of Petroleum Engineers for over 4447 years. Mr. BoneHe reports directly to our Vice President of Corporate Development.

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Drilling Activity

The following table sets forth our drilling activity: