talo-10k_20191231.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2019

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

For the transition period from to

Commission File Number 01-38497

Talos Energy Inc.

(Exact name of Registrant as specified in its Charter)

Delaware	82-3532642
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
333 Clay Street, Suite 3300 Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

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

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

Title of Each Class		Trading Symbol(s)		Name of Each Exchange on Which Registered
Common Stock		TALO		NYSE

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 ☐

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

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 ☐

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.

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ 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, was $481,140,961.

The number of shares of registrant’s Common Stock outstanding as of March 4, 2020 was 54,204,730.

Portions of the registrant’s definitive proxy statement relating to the 2020 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

		Page
GLOSSARY		3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		5
	PART I
Items 1	Business	7
Item 1A	Risk Factors	31
Item 1B	Unresolved Staff Comments	59
Item 2	Properties	59
Item 3	Legal Proceedings	59
Item 4	Mine Safety Disclosures	59
	PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities	60
Item 6	Selected Financial Data	61
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	63
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	80
Item 8	Financial Statements and Supplementary Data	81
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	81
Item 9A	Controls and Procedures	81
Item 9B	Other Information	81
	PART III
Item 10	Directors, Executive Officers and Corporate Governance	82
Item 11	Executive Compensation	82
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	82
Item 13	Certain Relationships and Related Transactions, and Director Independence	82
Item 14	Principal Accounting Fees and Services	82
	PART IV
Item 15	Exhibits, Financial Statement Schedules	83
Item 16	Form 10-K Summary	89

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.

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.

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”).

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.

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.

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.

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 the period beginning January 1, 2019 and ending December 1, 2019, 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 of Oil and Gas 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%.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this 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, 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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business strategy;

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reserves;

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exploration and development drilling prospects, inventories, projects and programs;

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our ability to replace the reserves that we produce through drilling and property acquisitions;

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financial strategy, liquidity and capital required for our development program and other capital expenditures;

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realized oil and natural gas prices;

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timing and amount of future production of oil, natural gas and NGLs;

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our hedging strategy and results;

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future drilling plans;

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availability of pipeline connections on economic terms;

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competition, government regulations and political developments;

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our ability to obtain permits and governmental approvals;

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pending legal, governmental or environmental matters;

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our marketing of oil, natural gas and NGLs;

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leasehold or business acquisitions on desired terms;

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costs of developing properties;

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general economic conditions;

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credit markets;

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impact of new accounting pronouncements on earnings in future periods;

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estimates of future income taxes;

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our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;

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uncertainty regarding our future operating results and our future revenues and expenses; and

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plans, objectives, expectations and intentions contained in this report that are not historical.

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, lack of availability of drilling and production equipment and services, environmental 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, geologic risk, drilling and other operating risks, well control risk, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, potential adverse reactions or competitive responses to our acquisitions and other transactions, the possibility that the anticipated benefits of such business combination 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” 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 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.

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 driven independent exploration and production company focused on safely and efficiently maximizing value through our operations, currently in the United States Gulf of Mexico and offshore Mexico. We leverage decades of geology, geophysics and offshore operations expertise towards 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 our operations in the 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 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 organically from our existing acreage or are acquisition or joint venture opportunities. We add to and re- evaluate 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 incorporation 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.

Business Strategy

We intend to increase stockholder value by growing our production, reserves, cash flow and backlog of future growth opportunities in a capital efficient manner. Our core competencies of deep technical expertise, significant library of seismic data resources and extensive offshore operating experience allow us to successfully manage our asset base and consistently make attractive investments, thereby increasing shareholder value creation over time.

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 key resource trends that we focus in. Our seismic database, 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 experience with offshore operations, production operations, safety, facilities, lease acquisitions and negotiations and other staff.

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 through the drillbit 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, our 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 common in offshore basins, including single asset acquisitions, consolidation of private companies and broader asset package transactions.

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:

Continuously Optimizing our Attractive Existing Asset Base.

We benefit from our proven ability to enhance and extend the life of existing projects within our portfolio. Investments in optimization projects across our asset base aim to stabilize and improve the profile of producing assets by increasing recovery, production and cash flow with typically relatively low investment capital and risk. These projects allow for reinvestment opportunities in exploitation and exploration projects.

Conducting Development and Near-Field Exploration Projects In and Around Our Existing Asset Footprint.

We undertake asset development and exploitation drilling projects in close proximity to our existing assets as well as facilities that we either own or have access to. These projects leverage ongoing operations and existing technical knowledge of the area, often coupled with recent proprietary seismic reprocessing evaluations to provide attractive incremental investment opportunities that could grow reserves, production and cash flow in well-understood areas.

Engage in Exploration Activities to Grow Asset Base and Potentially Unlock Significant New Resources.

We conduct exploration drilling activities across our acreage set with risk-weighted investments that could establish significant new reserves and production. These projects are intended to optimize risk and reward across our deep portfolio of prospective drilling opportunities by finding and developing previously undiscovered resources along existing or emerging geological trends with the most efficient deployment of capital. When successful, exploration drilling activities could organically generate material new assets for the Company.

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. Our strategy is focused in areas characterized by clearly defined infrastructure, well 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 have resulted in increased industry focus on this area over the last decade.

We believe our deepwater 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 deepwater prospects that we believe are capable of delivering predictable production growth. We 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.

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

The following table sets forth certain information regarding our core properties in the United States:

	Estimated Proved Reserves														Full Year 2019
	MBoe		% Oil			% Natural Gas			% NGLs			% Proved Developed			Net Production (MBoe)		% Operated
United States Core Properties
Phoenix⁽¹⁾		55,381		80	%		14	%		6	%		51	%		5,980		100	%
Pompano⁽²⁾		27,241		80	%		12	%		8	%		85	%		3,946		100	%
Ram Powell		12,795		55	%		32	%		13	%		100	%		2,039		100	%
Amberjack		8,581		92	%		6	%		2	%		100	%		784		99	%
United States Core Properties Subtotal		103,998		78	%		15	%		7	%		70	%		12,749

Other United States Properties⁽³⁾		37,737		69	%		27	%		4	%		66	%		6,207		82	%
Total United States		141,735		75	%		18	%		7	%		69	%		18,956

⁽¹⁾	Production volumes and estimated proved reserves include the Tornado, Boris and Typhoon areas of the Phoenix Field, all of which tie back to the Helix Producer I (“HP-I”).

⁽²⁾	Production volumes and estimated proved reserves include the Pompano and Cardona Fields, both of which tie back to the Pompano Platform.

⁽³⁾	Other United States properties include Gulf of Mexico shelf and deepwater.

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

There are no conventional fixed or moored production platforms in the field-instead the subsea wells are tied back to a dynamically positioned floating production unit, the HP-I. The HP-I interconnects with the Phoenix Field through 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 or in the event of a mechanical problem with the dynamic positioning system. There were 11 wells contributing to production in the Phoenix Field during 2019.

Pompano — The Pompano Field is comprised of eight operated blocks, which include Viosca Knoll Blocks 989 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.

Ram Powell — The Ram Powell Field is comprised of six operated blocks which include Viosca Knoll Blocks 911, 912, 913, 955, 956 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.

Amberjack — The Amberjack Field is comprised 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.

Mexico Properties

Our areas of focus in Mexico are blocks 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 Contracts (“PSCs”) with the National Hydrocarbons Commission (“CNH”), Mexico’s oil and gas regulator.

Block 2 and 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 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 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 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’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 income tax rate is 30%.

Block 31 PSC — 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 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.

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 in Block 7, 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 approved 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”), to cross assign 25% PIs 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 and the Block 2 production sharing contract’s expiration date, we recorded a $12.2 million non-cash impairment presented as “Write-down of oil and natural gas properties” on our Consolidated Statements of Operations in Part IV, Item 15. Exhibits, Financial Statement Schedules. Also, as a result 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 up 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.

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.

	Oil (MBbls)		Natural Gas (MMcf)		NGL (MBbls)		MBoe		Standardized Measure (in thousands)		PV -10 (in thousands)
December 31, 2019
Proved Developed Producing		53,777		64,192		3,855		68,331			$	1,837,964
Proved Developed Non-Producing		18,239		51,189		2,878		29,648				378,244
Total Proved Developed		72,016		115,381		6,733		97,979				2,216,208
Proved Undeveloped		34,738		40,617		2,248		43,756				776,814
Total Proved		106,754		155,998		8,981		141,735	$	2,537,595	$	2,993,022
December 31, 2018
Proved Developed Producing		62,162		69,409		4,342		78,072			$	2,510,213
Proved Developed Non-Producing		23,368		61,955		3,762		37,456				680,942
Total Proved Developed		85,530		131,364		8,104		115,528				3,191,155
Proved Undeveloped		27,009		39,660		2,592		36,211				734,108
Total Proved		112,539		171,024		10,696		151,739	$	3,340,246	$	3,925,263
December 31, 2017⁽¹⁾
Proved Developed Producing		23,656		37,161		1,930		31,780			$	776,786
Proved Developed Non-Producing		13,804		40,416		1,385		21,924				270,363
Total Proved Developed		37,460		77,577		3,315		53,704				1,047,149
Proved Undeveloped		35,344		50,079		3,232		46,921				760,520
Total Proved		72,804		127,656		6,547		100,625	$	1,807,669	$	1,807,669

⁽¹⁾	Does not include reserves acquired in the Stone Combination, which closed in May 10, 2018.

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. 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.

	Year Ended December 31,
	2019		2018		2017⁽¹⁾
Standardized measure	$	2,537,595	$	3,340,246	$	1,807,669
Present value of future income taxes discounted at 10%		455,427		585,017		—
PV-10 (Non-GAAP)	$	2,993,022	$	3,925,263	$	1,807,669

⁽¹⁾	For the tax year ended December 31, 2017, we were not a taxpaying entity for federal income tax purposes, we were not subject to federal or state income taxes and thus made no provision for federal or state income taxes in the calculation of our standardized measure.

Changes in Proved Developed Reserves

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

	Oil, Natural Gas and NGLs
	(MBoe)
Proved developed reserves at December 31, 2018		115,528
Changes during the year:
Production ⁽¹⁾		(18,956	)
Revisions of previous estimates		(11,485	)
Additions		5,663
Acquired		2,147
Conversion to Proved Developed Producing reserves		5,082
Total proved developed reserves changes		(17,549	)
Proved developed reserves at December 31, 2019		97,979

⁽¹⁾	Excludes approximately 3.0 MBoe of Mexico well test production

Revisions of Previous Estimates — Downward revisions of 11.5 MMBoe are primarily attributable to a decrease in commodity prices and under performance compared to expectations of 6.5 MMBoe in the Phoenix Field, 3.3 MMBoe in the Ram Powell Field and 2.3 MMBoe in the Pompano Field.

Additions — Additions in 2019 of 5.7 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 ST2 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 Gunflint Field located in the Mississippi Canyon area (the “Gunflint Acquisition”).

Development of Proved Undeveloped Reserves

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

	Oil, Natural Gas and NGLs			Future Development Costs
	(MBoe)			(in thousands)
Proved undeveloped reserves at December 31, 2018		36,211		$	396,666
Changes during the year:
Extensions and discoveries		10,067			162,025
Revisions of previous estimates		2,045			2,815
Acquired		515			7,651
Conversion to Proved Developed Producing reserves		(5,082	)		(67,497	)
Total proved undeveloped reserves changes		7,545			104,994
Proved undeveloped reserves at December 31, 2019		43,756		$	501,660

Our PUD reserves at December 31, 2019 increased by 7.5 MMBoe, or 21% 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 2.0 MMBoe primarily due to increased PUD allocation based on offset proved developed producing (“PDP”) performance in Phoenix Tornado B-6 reservoir. These revisions were partially offset by the lease expiration of Eugene Island 305 reserves of 1.2 MMBoe.

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

Conversion to Proved Developed Producing — 2018 PUD to proved developed conversions of 5.1 MMBoe is attributable to the Phoenix Field’s Boris 4 well.

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. Future development costs associated with our PUD reserves at December 31, 2019 totaled approximately $501.7 million, primarily attributable the Phoenix Field’s $340.4 million future development costs. 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 2020 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.

Internal Controls over Reserve Estimates and Reserve Estimation Procedures

At December 31, 2019, 2018 and 2017, 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:

•

Reserve information, as well as models used to estimate such reserves, is stored on secure database applications to which only authorized personnel are given access rights consistent with their assigned job function.

•

A comparison of historical expenses is made to the lease operating costs in the reserve database.

•

Internal reserves estimates are reviewed by well and by area by our reservoir engineers. A variance analysis by well to the previous year-end reserve report is performed.

•

Reserve estimates are reviewed and approved by certain members of senior management, including our President and Chief Executive Officer.

•

We engaged NSAI to perform an independent audit of our processes and the reasonableness of our estimates of proved reserves at December 31, 2019, 2018 and 2017. Our management requires that the independent petroleum engineers and geologists and our reserve quantities and calculation of the net present value of the reserves, collectively, vary by no more than 10% in the aggregate, in accordance with Society of Petroleum Evaluation Engineers (“SPEE”) auditing standards.

•

Data is transferred to NSAI through a secure file transfer protocol site.

•

Material reserve variances are discussed among NSAI, as applicable, our internal reservoir engineers and our Director of Reserves to ensure the best estimate of remaining reserves.

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.

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, 2018 and 2017 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 NSAI reports are filed as exhibits this report.

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:

•

the quality and quantity of available data and the engineering and geological interpretation of that data;

•

estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results;

•

future prices of oil, natural gas and NGLs, which may vary considerably from those mandated by the SEC; and

•

the judgment of the persons preparing the estimates.

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 45 years of industry experience with positions of increasing responsibility, including 37 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 45 years. He reports directly to our Vice President of Corporate Development.

Drilling Activity

The following table sets forth our drilling activity during the years ended December 31, 2019, 2018 and 2017:

	Exploratory and Appraisal Wells												Development Wells												Total
	Productive⁽¹⁾				Dry⁽²⁾				Total				Productive⁽¹⁾				Dry⁽²⁾				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
December 31, 2019
United States		3.0		2.3		1.0		0.8		4.0		3.1		3.0		2.7		—		—		3.0		2.7		7.0		5.8
Mexico		—		—		2.0		0.5		2.0		0.5		—		—		—		—		—		—		2.0		0.5
Total		3.0		2.3		3.0		1.3		6.0		3.6		3.0		2.7		—		—		3.0		2.7		9.0		6.3
December 31, 2018
United States		—		—		1.0		0.1		1.0		0.1		5.0		5.0		—		—		5.0		5.0		6.0		5.1
Mexico		—		—		—		—		—		—		—		—		—		—		—		—		—		—
Total		—		—		1.0		0.1		1.0		0.1		5.0		5.0		—		—		5.0		5.0		6.0		5.1
December 31, 2017
United States		4.0		3.7		—		—		4.0		3.7		—		—		—		—		—		—		4.0		3.7
Mexico		—		—		—		—		—		—		—		—		—		—		—		—		—		—
Total		4.0		3.7		—		—		4.0		3.7		—		—		—		—		—		—		4.0		3.7

⁽¹⁾

A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas producing well. Productive wells are included in the table in the year they were determined to be productive, as opposed to the year the well was drilled.

⁽²⁾	A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were determined not to be productive, as opposed to the year the well was drilled.

As of December 31, 2019, we had wells actively drilling or completing and wells suspended or awaiting completion, as follows:

	Actively Drilling or Completing								Wells Suspended or Waiting on Completion
	Exploratory				Development				Exploratory				Development
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
United States		1.0		0.5		—		—		1.0		0.3		—		—
Mexico		—		—		—		—		6.0		2.0		—		—
Total		1.0		0.5		—		—		7.0		2.3		—		—

Productive Wells

The number of our productive wells is as follows for the year ended December 31, 2019:

	Gross		Net
Crude oil		175.0		152.0
Natural gas		55.0		39.8
Total		230.0		191.8

Acreage

Gross and net developed and undeveloped acreage is as follows for the year ended December 31, 2019:

	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
United States
Deepwater		174,354		126,402		504,297		283,220		678,651		409,622
Shelf		263,956		198,806		125,464		95,172		389,420		293,978
Total United States		438,310		325,208		629,761		378,392		1,068,071		703,600
Mexico		—		—		122,356		36,332		122,356		36,332
Total		438,310		325,208		752,117		414,724		1,190,427		739,932

Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well holding such lease. The terms of our leases on undeveloped acreage as of December 31, 2019 are scheduled to expire as shown in the table below (the terms of which may be extended by drilling and production operations):

	Gross		Net
2020		90,640		61,936
2021		74,707		31,071
2022		156,669		63,492
2023		165,452		140,040
2024		50,616		25,291
2025 and beyond		214,033		92,894
Total		752,117		414,724

Crude Oil, Natural Gas and NGL Production, Prices and Production Costs

Our production volumes, average sales prices and average production costs are as follows:

	Year Ended December 31,
	2019			2018			2017
Production Volumes:
Crude oil (MBbls)		13,847			11,771			7,048
Natural gas (MMcf)		23,306			22,771			16,308
NGLs (MBbls)		1,228			1,176			706
Total (MBoe)		18,959			16,742			10,472
Percent of Boe from crude oil		73	%		70	%		67	%

Average Sales Price (including commodity derivatives):
Crude oil (Per Bbl)	$	59.23		$	57.12		$	52.46
Natural gas (Per Mcf)	$	2.55		$	3.16		$	2.93
NGLs (Per Bbl)	$	16.02		$	30.50		$	23.59
Average (Per Boe)	$	47.43		$	46.60		$	41.46

Average Sales Price (excluding commodity derivatives):
Crude oil (Per Bbl)	$	60.17		$	66.42		$	48.92
Natural gas (Per Mcf)	$	2.37		$	3.23		$	3.00
NGLs (Per Bbl)	$	16.02		$	30.50		$	23.59
Average (Per Boe)	$	47.90		$	53.24		$	39.18
Average Lease Operating Expense (Per Boe)	$	12.84		$	13.52		$	14.59

Crude Oil, Natural Gas and NGL Production, Prices and Production Costs—Significant Fields

Phoenix Field

The following table sets forth certain information regarding our production volumes, average sales prices and average production costs for the Phoenix Field, which consisted of 15% or more of our total estimated proved reserves at December 31, 2019, 2018 and 2017:

	Year Ended December 31,
	2019			2018			2017
Production Volumes:
Crude oil (MBbls)		4,812			5,160			4,657
Natural gas (MMcf)		4,803			5,311			5,203
NGLs (MBbls)		368			491			520
Total (MBoe)		5,980			6,536			6,044
Percent of Boe from crude oil		80	%		79	%		77	%

Average Sales Price (excluding commodity derivatives):
Crude oil (Per Bbl)	$	59.72		$	65.11		$	48.75
Natural gas (Per Mcf)	$	2.74		$	3.57		$	3.48
NGLs (Per Bbl)	$	15.68		$	29.04		$	24.49
Average (Per Boe)	$	51.23		$	56.48		$	42.66
Average Lease Operating Expense (Per Boe)	$	5.90		$	4.35		$	4.46

Pompano Field

The following table sets forth certain information regarding our production volumes, average sales prices and average production costs for the Pompano Field, which consisted of 15% or more of our total estimated proved reserves at December 31, 2019 and 2018.

	Year Ended December 31,
	2019			2018 ⁽¹⁾
Production Volumes:
Crude oil (MBbls)		3,324			2,042
Natural gas (MMcf)		2,320			1,758
NGLs (MBbls)		236			151
Total (MBoe)		3,947			2,486
Percent of Boe from crude oil		84	%		82	%

Average Sales Price (excluding commodity derivatives):
Crude oil (Per Bbl)	$	61.83		$	69.06
Natural gas (Per Mcf)	$	2.61		$	3.50
NGLs (Per Bbl)	$	14.49		$	30.95
Average (Per Boe)	$	54.49		$	61.08
Average Lease Operating Expense (Per Boe)	$	2.17		$	1.88

⁽¹⁾	The year ended December 31, 2018 includes the period from the Stone Closing Date, May 10, 2018, through December 31, 2018.

Expenditures and Costs Incurred

For information on property development, exploration and acquisition costs, see Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 15 — Supplemental Oil and Gas Disclosures (Unaudited).

Title to Properties

We believe that we have satisfactory title to our oil and natural gas properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalties, overriding royalties, and carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes and development obligations under oil and natural gas leases. As is customary in the industry in the case of undeveloped properties, often limited investigation of record title is made at the time of acquisition. Title search investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. To the extent title opinions or other investigations reflect defects affecting such undeveloped properties, we are typically responsible for curing any such title defects at our expense.

Commodity Price Risks and Price Risk Management Activities

Production from our properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. We enter into derivative contracts on our oil and natural gas production primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. For additional information regarding our commodity price risk and commodity derivative instruments, see Part II, Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

Significant Customers

Oil and natural gas companies spend capital on exploration, drilling and production operations expenditures, the amount of which is generally dependent on the prevailing view of future oil and natural gas prices which are subject to many external factors which may contribute to significant volatility in future prices. We market substantially all of our oil, natural gas and NGL production from the properties we operate and those we do not operate. Our customers consist primarily of major oil and gas companies, well-established oil and pipeline companies and independent oil and natural gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. For the year ended December 31, 2019, 58% and 28% of our oil, natural gas and NGL revenues were attributable to Shell Trading (US) Company and Phillips 66, respectively, which are the customers that individually represented 10% or more of our oil, natural gas and NGL revenues.

Competitive Conditions

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of oil and natural gas leases, equipment and personnel required to find and produce reserves and in the gathering and marketing of oil, natural gas and NGLs. We compete with large integrated oil and natural gas companies as well as independent exploration and production companies. Certain of our competitors may have significantly more financial or other resources available to them. In addition, certain of the larger integrated companies may be better able to respond to industry changes, including price fluctuation, oil and natural gas demand and governmental regulations.

However, we believe our high quality oil-weighted production base, proven expertise in utilizing seismic technology to identify, evaluate and develop exploitation and exploration opportunities, balanced mix of assets in the Gulf of Mexico deep and shallow waters and significant operating control give us a strong competitive position relative to many of our competitors.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis. Generally, but not always, the demand for gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may impact general seasonal changes in demand.

Insurance Matters

Our oil and natural gas operations are subject to risks incident to the operation of oil and gas wells, including but not limited to uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could result in substantial losses to us. In addition, our oil and natural gas properties are located in the Gulf of Mexico, which makes us more vulnerable to tropical storms and hurricanes. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and the suspension of operations. Damages arising from such occurrences may result in lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on our financial condition, results of operations and cash flow. Although we obtain insurance against some of these risks, we cannot insure against all possible losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flow.

We have insurance policies to cover some of our risk of loss associated with our operations, and we maintain the amount of insurance we believe is prudent. However, not all of our business activities can be insured at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying cost).

Our general property damage insurance provides varying ranges of coverage based upon several factors, including well counts and the cost of replacement facilities. Our general liability insurance program provides a limit of $500 million for each occurrence and in the aggregate, and includes varying deductibles. Our Offshore Pollution Act insurance is subject to a maximum of up to $150 million for each occurrence and in the aggregate, including a $100,000 retention. Coverage is provided for damage to our assets resulting from a named U.S. Gulf of Mexico windstorm; however, such coverage is subject to a maximum of $170 million per named windstorm and in the aggregate, and is also subject to a maximum of $35 million per occurrence retention. We separately maintain an operators extra expense policy with additional coverage for an amount up to $500 million for U.S. Gulf of Mexico deepwater drilling wells, $150 million for U.S. Gulf of Mexico shelf drilling wells, $75 million for U.S. Gulf of Mexico producing and shut-in wells, $75 million for drilling and workover in inland waters and $25 million for drilling and workover in onshore fields that would cover costs involved in making a well safe after a blow-out or getting the well under control; re-drilling a well to the depth reached prior to the well being out of control or blown out; costs for plugging and abandoning the well; and costs for clean-up and containment and for damages caused by contamination and pollution. For our Mexico insurance policies, we maintain $250 million in operators extra expense coverage for operations and $500 million per occurrence and aggregate limit for general liability.

We may increase or decrease insurance coverage around our key strategic assets, including potentially purchasing catastrophic bond instruments. Our highest value assets, which are located in the Phoenix Field, produce through the HP-I floating production system, which has the capability to disconnect and move away in the event of a storm, mitigating the risk of property damage.

We customarily have reciprocal agreements with our customers and vendors in which each contracting party is responsible for its respective personnel for liability related to work performed for us. Under these agreements, we generally are indemnified against third party claims related to the injury or death of our customers’ or vendors’ personnel, subject to the application of various states’ laws.

Government Regulation

Exploration and development and the production and sale of oil, natural gas and NGLs are subject to extensive federal, state, local and foreign laws and regulations. An overview of these legal requirements is set forth below. Historically, our compliance with existing requirements has not had a material adverse effect on our financial position, results of operations or cash flows. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

General Overview — Our oil and natural gas operations are subject to various federal, state, local and foreign laws and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to:

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location of wells;

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size of drilling and spacing units or proration units;

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number of wells that may be drilled in a unit;

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unitization or pooling of oil and natural gas properties;

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drilling and casing of wells;

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issuance of permits in connection with exploration, drilling and production;

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well production;

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spill prevention plans;

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protection of private and public surface and ground water supplies;

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emissions permitting or limitations;

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protection of endangered species;

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use, transportation, storage and disposal of fluids and materials incidental to oil and natural gas operations;

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surface usage and the restoration of properties upon which wells have been drilled;

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calculation and disbursement of royalty payments and production taxes;

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requirements for the posting of supplemental bonds or providing other forms of financial assurance for the plugging and abandonment of wells located in the United States Gulf of Mexico and offshore Mexico and, following cessation of operations, the removal or appropriate abandonment of all production facilities, structures and pipelines in those areas (“P&A” or “decommissioning” obligations);

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performance of P&A obligations; and

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transportation of production.

Outer Continental Shelf (“OCS”) Regulation — Our operations on federal oil and natural gas leases in the United States Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”), the Bureau of Ocean Energy Management (“BOEM”) and the Office of Natural Resources Revenue (“ONRR”), which are all agencies of the U.S. Department of the Interior (“DOI”). These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the federal Outer Continental Shelf Lands Acts (“OCSLA”). These laws and regulations are subject to change, and many new requirements, including those related to safety, permitting and performance, have been imposed by BSEE and BOEM subsequent to the 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (the “EPA”), lessees must obtain a permit from BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, P&A of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities.

The trend in the United States over the past decade has been for these governmental agencies to continue to evaluate and as necessary develop and implement new, more restrictive requirements, although in recent years under the Trump Administration there have been actions seeking to mitigate certain of those more rigorous standards. For example, in 2016, BSEE under the Obama Administration published a final rule on well control that, among other things, imposed rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deepwater, high temperature, high pressure drilling activities, and enhanced reporting requirements. Pursuant to President Trump’s Executive Orders dated March 28, 2017, and April 28, 2017 (the “Executive Orders”), BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. One consequence of this review is that on May 15, 2019, BSEE published final revisions to the existing 2016 rule on well control that became effective on July 15, 2019 and, among other things, eliminated the requirement for a BSEE-approved verification organization for third parties providing certifications of certain critical well control functions. In another example, BSEE published a final rule in September 2018 amending its production safety systems regulations, which includes the imposition of operational and design standards and the removal of the requirement of offshore operators to certify through an independent third party that their critical safety and pollution prevention equipment (e.g. subsea safety equipment, including blowout preventers) is operational and functioning as designed in the most extreme conditions. There exists the possibility that certain of these recent mitigatory actions under the Trump Administration could be withdrawn or revised in the future as a result of litigation or by a different presidential administration to impose or re-implement more stringent standards.

Furthermore, hurricanes in the Gulf of Mexico can have a significant impact on oil and natural gas operations. The effects from past hurricanes have included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. BOEM and BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, BOEM and BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be issued by BOEM and BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs and/or capital expenditures.

In addition, in order to cover the various decommissioning obligations of leases , rights of way (“ROWs”) and rights of use and easements (“RUEs”) on the OCS, BOEM generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. For example, in the Notice to Lessees and Operators (“NTL”) No. 2016-N01 (the “2016 NTL”), BOEM under the Obama Administration announced updated financial assurance and risk management requirements for offshore leases. The 2016 NTL details procedures to determine a lessee’s ability to carry out its lease obligations—primarily the decommissioning of facilities—and whether to require lessees to furnish additional financial assurance to meet BOEM’s estimate of the lessees’ decommissioning obligations. The 2016 NTL supersedes the agency’s prior practice of allowing lessees of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The 2016 NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby a lessee and BOEM agree to set a timeframe for the posting of additional financial assurances. The 2016 NTL became effective in September 2016. Following the effectiveness of the 2016 NTL, we received orders from BOEM in late 2016 to provide additional financial assurance in material amounts relating to our OCS properties (the “BOEM 2016 Orders”). We entered into discussions with BOEM regarding the requested additional financial security and submitted a proposed tailored plan for the posting of additional financial security to the agency for review. However, BOEM under the Trump Administration has indefinitely delayed beyond June 30, 2017 implementation of the 2016 NTL, has rescinded the BOEM 2016 Orders while BOEM reviews its financial assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored plan.

We remain in active discussions with our government regulators and our industry peers with regard to any future rule making and financial assurance requirements. BOEM is continuing to review and reconsider its financial assurance program and thus the amounts of any financial assurance that may be demanded by the agency is uncertain at this time. Notwithstanding the 2016 NTL, BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. BOEM, whether under the Trump Administration or a future administration, could also make new demands for additional financial assurance in material amounts in the event the agency chooses to implement the 2016 NTL. Such demands could exceed our ability to provide any additional financial assurance that may be required by BOEM in the future. The future cost of compliance with our existing supplemental bonding requirements, including the obligations imposed upon us as a result of the 2016 NTL, to the extent implemented, as well as any other future BOEM directives, or any other changes to BOEM’s rules applicable to our or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows, and results of operations.

Regulation in Shallow Waters Off the Coast of Mexico — Our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are subject to regulation by SENER, the CNH and other Mexican regulatory bodies. The CNH is responsible for, among other things, overseeing the tender procedures for awarding contracts for the exploration and production of oil and natural gas in Mexican waters, managing and supervising contracts that have been awarded, and approving exploration and production plans. The PSCs that we and our consortium partners have entered into for the development of these acreages contain terms that impose on us the duty to comply with various laws and regulations. These laws and regulations govern, among other things, the exploration and exploitation of hydrocarbons (including certain national content requirements), the treatment, conveyance, marketing, transport and storage of petroleum, and requirements for industrial safety, operational security, and facility decommissioning. Failure to comply can result in the imposition of monetary penalties, revocation of permits, rescission of the relevant PSC, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and regulations governing activities in the Mexican energy sector are relatively new, having been significantly reformed in 2013, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.

Environmental and Occupational Safety and Health Regulations

We are subject to various federal, state, local and foreign regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things:

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assessing the environmental impact of seismic acquisition, drilling or construction activities;

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the generation, storage, transportation and disposal of waste materials;

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the emission of certain gases into the atmosphere;

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the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations;

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various environmental permitting requirements, such as permits for wastewater discharges;

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the development of emergency response and spill contingency plans;

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specific operating criteria addressing worker protection; and

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protection of private and public surface and ground water supplies.

Based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and it is possible such expenses will continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters and the cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, natural resource damages or the issuance of injunctive relief (including orders to cease operations). Both onshore and offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. Additionally, due primarily to the threat of climate change arising from greenhouse gas (“GHG”) emissions, certain candidates seeking the office of President of the United States in 2020 have pledged to take actions to ban new mineral leases on federal properties, including offshore leases on the OCS. Moreover, some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts onshore or offshore drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.

We expect to continue making expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. Our insurance coverage provides for the reimbursement to us of certain costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure against pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

Water Discharges — Our discharges into waters of the United States are limited by the federal Clean Water Act (“CWA”) and analogous state laws. The CWA prohibits any discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, except in compliance with permits issued by federal and state governmental agencies. These discharge permits also include monitoring and reporting obligations. Failure to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. Violations of the CWA can result in suspension, debarment or the imposition of statutory disability, each of which prevents companies and individuals from participating in government contracts and receiving some non-procurement government benefits. The CWA also requires the preparation of oil spill response plans and spill prevention, control and countermeasure plans.

Oil Pollution Act — The Oil Pollution Act of 1990 (“OPA”) holds owners and operators of offshore oil production or handling facilities, including the lessee or permittee of the area where an offshore facility is located, strictly liable for the costs of removing oil discharged into waters of the United States and for certain damages from such spills. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. OPA’s damages liability cap is currently $137.7 million; however, a party cannot take advantage of liability limits if a spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation, or if the party failed to report a spill or cooperate fully in the clean-up. OPA also requires responsible parties to maintain evidence of financial responsibility in prescribed amounts. OPA currently requires a minimum financial responsibility demonstration of between $35 million to $150 million, based on a worst case oil spill discharge volume, for companies operating on the OCS, although BOEM may increase this amount in certain situations, but in no event greater than $150 million. From time to time, the United States Congress has proposed, but not adopted, amendments to OPA raising the financial responsibility requirements. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

National Environmental Policy Act — The National Environmental Policy Act (“NEPA”) requires federal agencies, including the DOI, to consider the impacts their actions have on the human environment, and to prepare detailed statements for major federal actions having the potential to significantly impact the environment. These requirements can lead to additional costs and delays in permitting for operators as the DOI or its bureaus may need to prepare Environmental Assessments (“EA”) and more detailed Environmental Impact Statements (“EIS”) in support of its leasing and other activities that have the potential to significantly affect the quality of the environment. If the EA indicates that no significant impact is likely, then the agency can release a finding of no significant impact and carry on with the proposed action. Otherwise, the agency must then conduct a full-scale EIS. The NEPA process involves public input through comment. These comments, as well as the agency’s analysis of the proposed project, can result in changes to the nature of a proposed project, such as by limiting the scope of the project or requiring resource-specific mitigation. The adequacy of the agency’s NEPA process can be challenged in federal court by process participants. This process may result in delaying the permitting and development of projects, and result in increased costs.

Endangered Species Act — The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats. Additionally, the Migratory Bird Treaty Act (“MBTA”) implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit. The Marine Mammal Protection Act (“MMPA”) similarly prohibits the taking of marine mammals without authorization. Additionally, the U.S. Fish and Wildlife Service (“FWS”) may make determinations on the listing of species as threatened or endangered under the ESA and litigation with respect to the listing or non-listing of certain species may result in more fulsome protections for non-protected or lesser-protected species. We conduct operations on oil and natural gas leases in areas where certain species that are protected by the ESA, MBTA and MMPA are known to exist and where other species that could potentially be protected under these statutes are known to exist. The FWS or the National Marine Fisheries Service may designate critical habitat that it believes is necessary for survival of a threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for oil and natural gas development. These statutes may result in operating restrictions or a temporary, seasonal or permanent ban in affected areas.

Hazardous Substances and Waste Management — The Resource Conservation and Recovery Act (“RCRA”) generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in response to a federal consent decree issued in 2016, the EPA was required during 2019 to determine whether certain Subtitle D criteria regulations require revision in a manner that could result in oil and natural gas wastes being regulated as RCRA hazardous wastes. In April 2019, the EPA made a determination that such revision of the regulations was unnecessary at this time. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in increased costs to manage and dispose of generated wastes. Also, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

Comprehensive Environmental Response, Compensation and Liability Act — Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Further, it is not uncommon for coastal landowners or other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Air Emissions — The Clean Air Act (“CAA”) and comparable state statutes restrict the emission of air pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed, and continues to develop, more stringent regulations governing emissions of toxic air pollutants, and is considering the regulation of additional air pollutants and air pollutant parameters. For example, in 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Worker Health and Safety — The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Climate Change — Climate change continues to attract considerable public, political and scientific attention. As a result, numerous regulatory initiatives have been made, and are likely to continue to be made, at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. These regulatory efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. Additionally, the threat of climate change has resulted in increasing political, litigation and financial risks associated with the production of fossil fuels and emission of GHGs. The adoption and implementation of any federal or state legislation, regulations or executive orders or the occurrence of any litigation or financial developments that impose more stringent requirements or bans on GHG-emitting production activities or locations where such production activities may occur, impose liabilities for past conduct relating to GHG-emitting production activities, or limit or eliminate sources of financing for on-going production operations could require us to incur increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas that we produce. See "Item 1A. Risk Factors – Our operations are subject to various risks that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduced demand for the oil and natural gas that we produce" for additional information relating to risks arising out of climate change including the emission of GHGs.

Environmental Regulation in Shallow Waters Off the Coast of Mexico — Our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are subject to regulation by the Mexican National Agency of Industrial Safety and Environmental Protection of the Hydrocarbons Sector (“ASEA”). We must obtain ASEA-issued permits and comply with ASEA regulations governing hydrocarbon activities, including requirements for environmental impact and risk assessments, industrial safety, waste management, water and air emissions, operational security, and facility decommissioning. Failure to comply with applicable laws and regulations can result in the imposition of monetary penalties, revocation of permits, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and regulations governing the protection of health, safety, and the environment from activities in the Mexican energy sector are relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. For example, in January 2019, the ASEA published the “General Administrative Provisions on the Guidelines for the Design, Construction, Pre-start, Maintenance, Closing, Dismantling and Abandonment of the Facilities and Transfer Operations associated with the Transportation and/or Distribution of Hydrocarbons and/or Oil Products activities, by means other than Pipelines.” These legal provisions apply to permit holders in charge of the transportation or distribution of hydrocarbons and oil products by means other than pipelines, such as tank trucks, tank vessels and/or by railroad, in connection with the transfer, racking, loading, discharge, reception or delivery of such hydrocarbons and oil products. The permit holders must comply with requirements relating to insurance, facility construction and design, law compliance, and risk analysis scenarios.

Under the PSCs, we are jointly and severally liable for the performance of all obligations under the PSCs, including exploration, appraisal, extraction, and abandonment activities and compliance with all environmental regulations, and failure to perform such obligations could result in contractual rescission of the PSCs.

Federal Regulation of Sales and Transportation of Natural Gas — Our sales of natural gas are affected directly or indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”) and by regulations and orders promulgated under the NGA and/or NGPA by the Federal Energy Regulatory Commission (“FERC”). In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the United States Congress and by FERC regulations. However, certain offshore gathering and transportation services we rely upon are subject to limited FERC regulation and are regulated by the states.

Pursuant to authority delegated to it by the Energy Policy Act of 2005 (“EPAct 2005”), FERC promulgated anti-manipulation regulations establishing violation enforcement mechanisms that make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC to (i) use or employ any device, scheme or artifice to defraud, (ii) make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (iii) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any entity. The EPAct 2005 also amended the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes and regulations, up to $1,291,894 per violation, per day for 2019 (this amount is adjusted annually for inflation). FERC may also order disgorgement of profits and corrective action. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes annual reporting requirements for entities that purchase or sell a certain volume of natural gas in a given calendar year. We believe, however, that neither the EPAct 2005 nor the regulations promulgated by FERC as a result of the EPAct 2005 will affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and marketers with which we compete.

Our sales of oil and natural gas are also subject to market manipulation and anti-disruptive requirements under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), and regulations promulgated thereunder by the U.S. Commodity Futures Trading Commission (the “CFTC”). The CFTC prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

The current statutory and regulatory framework governing interstate natural gas transactions is subject to change in the future, and the nature of such changes is impossible to predict. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by the United States Congress, the applicable federal agencies, or the various state legislatures, and what effect, if any, the proposals might have on our operations. The natural gas industry historically has been very heavily regulated. In the past, the federal government regulated the prices at which natural gas could be sold. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. However, we are subject to reporting requirements imposed by FERC. There is always some risk, however, that the United States Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines or impose additional reporting or other requirements upon our operations, and we cannot predict what future action FERC will take. Therefore, there is no assurance that the current regulatory approach recently pursued by FERC and the United States Congress will continue. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil — FERC regulates the interstate pipeline of crude oil, petroleum products, and other liquids, such as NGLs. Our sales of crude oil and condensate are currently not regulated and are made at negotiated prices. There is always some risk, however, that the United States Congress may reenact crude oil, petroleum products and NGL price controls in the future. We cannot predict whether new legislation to regulate crude oil, or the prices charged for crude oil might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.

Our ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”), and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. Certain regulations implemented by FERC in recent years and certain pending rulemaking and other proceedings could result in an increase in the cost of transportation service on certain petroleum products pipelines. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other crude oil and condensate producers with which we compete.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to other crude oil and condensate producers with which we compete.

Our SP 49 Pipeline LLC system is subject to regulation by FERC under the ICA, the Energy Policy Act of 1992, and the rules and orders promulgated thereunder. The ICA requires that tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory. FERC-regulated liquids pipelines, including SP 49 Pipeline LLC, typically use the FERC indexing methodology to change its rates. FERC, however, retained cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach that may be used in certain specified circumstances. FERC reviews the index formula every five years. Effective July 1, 2016, the annual index adjustment for the five-year period ending June 30, 2021, will equal the producer price index for finished goods for the applicable year plus an adjustment factor of 1.23%. Pipelines may raise their rates to the rate ceiling level generated by application of the annual index adjustment factor each year; however, a shipper may challenge such increase if the increase in the pipeline’s rates was substantially in excess of the actual cost increases incurred by the pipeline during the relevant year. Because the indexing methodology for the next five-year period is tied to an inflation index and is not based on pipeline-specific costs, the indexing methodology could hamper our ability to recover cost increases.

On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating, among other things, that with respect to oil and refined products pipelines subject to FERC jurisdiction, the impacts of the Revised Policy Statement and Public Law No. 115-97 (“Tax Cuts and Jobs Act”) on the costs of FERC-regulated oil and NGL pipelines will be reflected in FERC’s next five-year review of the oil pipeline index, which will generate the index level to be effective July 1, 2021. FERC’s establishment of a just and reasonable rate, including the determination of the appropriate oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of the appropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-year term of index rates, the Revised Policy Statement and tax effects related to the Tax Cuts and Jobs Act may impact our revenues associated with any transportation services we may provide pursuant to cost-of-service based rates in the future, including indexed rates.

FERC historically has not investigated rates of liquids pipelines on its own initiative when those rates have not been the subject of a protest or complaint by a shipper. FERC issued an Advance Notice of Proposed Rulemaking on October 20, 2016, that addressed issues related to FERC’s indexing methodology and liquids pipeline reporting practices. If implemented, the proposals in this rulemaking could affect the profitability of certain liquids pipelines.

We have an undivided interest in a pipeline owned by CKB Petroleum, Inc. that is subject to FERC jurisdiction under the ICA, but FERC has granted us a temporary waiver of the filing and reporting requirements. This pipeline is still subject to FERC’s jurisdiction under the ICA and is still subject to the other requirements of the ICA. If the facts upon which the waiver was granted change materially, we are required to inform FERC, which may result in revocation of the waiver. If conditions change such that the pipeline no longer qualifies for a waiver, we may be subject to regulation by FERC of the rates, terms, and conditions of service on the CKB Petroleum, Inc. pipeline, however these burdens generally would not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar pipelines.

FERC also implements the OCSLA pertaining to transportation and pipeline issues, which requires that all pipelines operating on or across the OCS provide nondiscriminatory transportation service. We own and operate pipelines that are located in the OCS and are subject to the non-discrimination requirements in the OCSLA.

Employees

We had 440 employees as of March 4, 2020.

Available Information

We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, all amendments to those reports, and all other information filed with or furnished to the SEC available, free of charge, through our website, https://www.talosenergy.com, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. The filings are also available by accessing the SEC’s website at https://www.sec.gov.

Item 1A. Risk Factors

Certain factors may have a material adverse effect on our business, financial condition, and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Annual Report on Form 10-K, including our consolidated financial statements and related notes. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occur, our business, financial condition, results of operations and future prospects could be materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment.

Oil and natural gas prices are volatile. Significant declines in commodity prices in the future may adversely affect our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.

Our revenues, cash flows, profitability and future rate of growth substantially depend upon the market prices of oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to access funds under our Bank Credit Facility and through the capital markets. The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves, and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such time. Oil and natural gas prices significantly declined in the second half of 2014, with sustained lower prices continuing throughout 2015, 2016 and 2017. Despite a modest recovery from late 2017 to mid-2018, commodity prices could remain suppressed in 2020 or decline further in the future, which will likely have material adverse effects on our proved reserves and borrowing base. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, which is impacted by declining prices. Significant price declines could cause us to take ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See the Risk Factor entitled “Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values” for further discussion.

In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period January 1, 2017 through December 31, 2019, the NYMEX WTI crude oil price per Bbl ranged from a low of $45.18 to a high of $70.98, and the NYMEX natural gas price per MMBtu ranged from a low of $2.22 to a high of $4.09. Commodity prices have experienced significant further declines during the first quarter of 2020, with prices for NYMEX WTI crude oil and NYMEX natural gas, respectively, reaching lows of $31.13 per Bbl and $1.68 during the period from January 1, 2020 through March 9, 2020. The high, low and average prices for NYMEX WTI and NYMEX Henry Hub are monthly contract prices. The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others:

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changes in the supply of and demand for oil and natural gas;

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market uncertainty;

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level of consumer product demands;

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hurricanes and other adverse weather conditions;

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the impact of applicable market differentials, including those relating to quality, transportation, fees, energy content and regional pricing;

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domestic and foreign governmental regulations and taxes;

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price and availability of alternative fuels;

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political and economic conditions in oil-producing countries, particularly those in the Middle East, Russia, South America and Africa;

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actions by the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

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U.S. and foreign supply of oil and natural gas;

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price and quantity of oil and natural gas imports and exports;

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the level of global oil and natural gas exploration and production;

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the level of global oil and natural gas inventories;

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localized supply and demand fundamentals and transportation availability;

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speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

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price and availability of competitors’ supplies of oil and natural gas;

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technological advances affecting energy consumption; and

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overall domestic and foreign economic conditions.

These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because oil, natural gas and NGLs accounted for approximately 75%, 18%, and 7%, respectively, of our estimated proved reserves as of December 31, 2019, and approximately 73%, 21%, and 6%, respectively, of our 2019 production on an MBoe basis, our financial results are sensitive to movements in oil, natural gas and NGL prices.

Our debt level and the covenants in our current or future agreements governing our debt, including our Bank Credit Facility and the indenture for our 11.00% Second-Priority Senior Secured Notes, could negatively impact our financial condition, results of operations and business prospects. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

The terms of the agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including:

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incurring additional debt;

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paying dividends on stock, redeeming stock or redeeming subordinated debt;

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making investments;

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creating liens on our assets;

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selling assets;

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guaranteeing other indebtedness;

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entering into agreements that restrict dividends from our subsidiaries to us;

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merging, consolidating or transferring all or substantially all of our assets;

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hedging future production; and

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entering into transactions with affiliates.

Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the Bank Credit Facility and the indenture for our 11.00% Second-Priority Senior Secured Notes due 2022 (the “11.00% Notes”) of Talos Production Inc. and Talos Production Finance, Inc. (together, the “Talos Issuers”), have important consequences on our operations, including:

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requiring that we dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures, and other general business activities;

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limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities;

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limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

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detracting from our ability to successfully withstand a downturn in our business or the economy generally;

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placing us at a competitive disadvantage against other less leveraged competitors; and

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making us vulnerable to increases in interest rates because debt under our Bank Credit Facility is at variable rates.

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which have declined significantly as compared to mid-2014.

We depend on our Bank Credit Facility for a portion of our future capital needs. We are required to comply with certain debt covenants and certain financial ratios under the Bank Credit Facility. Our borrowing base under the Bank Credit Facility, which is redetermined semi-annually, is based on an amount established by the lenders after their evaluation of our proved oil and natural gas reserve values. If, due to a redetermination of our borrowing base, our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency. Our Bank Credit Facility allows us to cure a borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding sufficient to cure the borrowing base deficiency within 30 days after the existence of such deficiency; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first installment due within 30 days after the existence of such deficiency; or (iv) any combination of the above. We are required to elect one of the foregoing options within 10 days after the existence of such deficiency.

We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets are available to pay or refinance such debt. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our debt, including our Bank Credit Facility and the indenture for our 11.00% Notes, may also prohibit us from taking such actions. Factors that affect our ability to raise cash through offerings of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offerings, refinancing or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing or sale of assets would be successfully completed.

Changes in the method of determining the London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest rates.

On July 27, 2017, the Financial Conduct Authority (“FCA”) in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021, or whether different benchmark rates used to price indebtedness will develop. In the future, we may need to renegotiate the Bank Credit Facility or incur other indebtedness, and the phase-out of LIBOR may negatively impact the terms of such indebtedness. In addition, the overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR. Disruption in the financial market could have a material adverse effect on our financial position, results of operations and liquidity.

Regulatory requirements and permitting procedures imposed by BOEM and BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

BSEE and BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the United States Gulf of Mexico and, as a result, are continuing to develop and implement new, more restrictive requirements. For example, in 2016, BSEE under the Obama Administration published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deepwater, high temperature, high pressure drilling activities and enhanced reporting requirements. However, pursuant to President Trump’s Executive Orders, BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. One consequence of this review is that on May 15, 2019, BSEE published final revisions to the existing 2016 rule on well control that became effective on July 15, 2019 and, among other things, eliminated the requirement for offshore operators to certify through an independent third party that their critical safety and pollution prevention equipment (e.g., subsea safety equipment, including blowout preventers) is operational and functioning as designed in the most extreme conditions. There exists the possibility that any mitigatory actions under the Trump Administration could be withdrawn or revised in the future as a result of litigation or by a different presidential administration to impose or re-implement more stringent standards.

Compliance with these regulatory actions, or any new laws, regulations or other legal initiatives, whether under the Trump Administration or another administration could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Furthermore, among other adverse impacts, to the extent that BOEM and BSEE do not reduce the stringency of existing oil and gas safety and performance-related regulations and other regulatory initiatives, the regulatory requirements imposed by such existing or future, more stringent regulations or other regulatory initiatives could delay operations, disrupt our operations or increase the risk of leases expiring before exploration and development efforts have been completed due to the time required to develop new technology. Additionally, if left unchanged, the existing, or future, more stringent oil and gas safety and performance-related regulations and other regulatory initiatives imposed by BOEM and BSEE could result in incurrence of associated added costs, limit operational activities in certain areas or cause us to incur penalties or shut-in production at one or more of our facilities. Also, if material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

Finally, due primarily to the threat of climate change arising from GHG emissions, certain candidates seeking the office of President of the United States in 2020 have pledged to take actions to ban new mineral leases on federal properties, including offshore leases on the OCS.

Guidelines issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS may have a material adverse effect on our business, financial condition or results of operations.

BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In 2016, BOEM under the Obama Administration issued the 2016 NTL to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs or RUEs. The 2016 NTL became effective in September 2016, but pursuant to President Trump’s Executive Orders, BOEM initiated a review of the 2016 NTL and extended implementation indefinitely beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, so as to provide BOEM with time to review its complex financial assurance program.

Following the effectiveness of the 2016 NTL, we received the BOEM 2016 Orders in late 2016 directing us to provide additional financial assurance in material amounts relating to our OCS properties. We entered into discussions with BOEM regarding the requested additional financial security and submitted a proposed tailored plan for the posting of additional financial security to the agency for review. However, as noted, BOEM under the Trump Administration has indefinitely delayed beyond June 30, 2017 implementation of the 2016 NTL, has rescinded the BOEM 2016 Orders while BOEM reviews its financial assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored plan.

As of the filing date of this Annual Report on Form 10-K, we have no outstanding BOEM orders for financial assurance obligations. Until BOEM and BSEE’s completion and publication of its proposed joint rule regarding financial assurance, we cannot estimate what additional financial assurance may be required by us, and therefore, we cannot provide any assurance of the amount of any additional financial assurance, which may be material, that may be ordered by BOEM and required of us in the future, or that such additional financial assurance amounts can be obtained. Moreover, BOEM, whether under the Trump Administration or another administration, could in the future make new demands for additional financial assurances in material amounts relating to the decommissioning of our OCS properties. BOEM may reject our proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities.

If we fail to comply with the current or future orders of BOEM to provide additional surety bonds or other financial assurances, BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.

In addition, if fully implemented, the 2016 NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which could in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator’s collateral. Moreover, depressed oil prices could result in sureties seeking additional collateral to support existing bonds, such as cash or letters of credit, and we cannot provide assurance that we will be able to satisfy collateral demands for future bonds to comply with supplemental bonding requirements of BOEM. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine mammals and endangered and threatened species.

Our oil and natural gas operations are subject to stringent federal, state, local and foreign laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

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require the acquisition of a permit or other approval before drilling or other regulated activity commences;

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restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

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limit or prohibit exploration or drilling activities on certain lands lying within protected areas or that may affect certain marine species and endangered and threatened species; and

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impose substantial liabilities for pollution resulting from our operations.

Failure to comply with these laws and regulations may result in:

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the assessment of administrative, civil and criminal penalties;

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loss of our leases;

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incurrence of investigatory, remedial or corrective obligations; and

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the imposition of injunctive relief, which could prohibit, limit or restrict our operations in a particular area.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could incur strict joint and several liability for the removal or remediation of previously released materials or contamination, regardless of whether we were responsible for the release or contamination and regardless of whether our operations met previous standards in the industry at the time they were conducted. Our permits require that we report any incidents that cause or could cause environmental damages.

New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement could significantly increase our capital expenditures and operating costs or could result in delays, limitations or cancelations to our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows. See Business – Environmental and Occupational Safety and Health Regulations under Part I, Item 1 in this Form 10-K for a more detailed description of our environmental, marine species, and endangered and threatened species legal requirements.

A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our Bank Credit Facility or in the capital markets.

We use our cash flows from operating activities and borrowings under our Bank Credit Facility to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. However, we may not be able to access adequate funding under our Bank Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. In addition, we may face limitations on our ability to access the debt and equity capital markets and complete asset sales, an increased counterparty credit risk on our derivatives contracts, and the requirement by our contractual counterparties to post collateral guaranteeing performance.

We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

We spend a substantial amount of capital for the acquisition, exploration, exploitation, development, and production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash flows, cash on hand and borrowings under our Bank Credit Facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A further reduction in commodity prices may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital is subject to a number of variables, including:

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our proved reserves;

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the level of hydrocarbons we are able to produce from our wells;

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the prices at which our production is sold;

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our ability to acquire, locate and produce new reserves; and

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our ability to borrow under our Bank Credit Facility.

If low oil and natural gas prices, operating difficulties, declines in reserves or other factors, many of which are beyond our control, cause our revenues, cash flows from operating activities, and the borrowing base under our Bank Credit Facility to decrease, we may be limited in our ability to fund the capital necessary to complete our capital expenditure program. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot be sure that additional debt or equity financing will be available, and we cannot be sure that cash flows provided by operations will be sufficient to meet these requirements. For example, the ability of oil and gas companies to access the equity and high yield debt markets has been, and continues to be, significantly limited since the significant decline in commodity prices as compared to mid-2014.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. Accordingly, we are dependent upon distributions from Talos Production Inc. to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. We have no independent means of generating revenue. To the extent Talos Production Inc. has available cash, we will cause Talos Production Inc. to make distributions of cash to us, directly and indirectly through our wholly owned subsidiaries, to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock. As we have never declared or paid any cash dividends on our common stock, we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends on our common stock, if our board of directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make distributions and other payments to us. To the extent that we need funds and Talos Production Inc. is restricted from making such distributions under applicable law or regulation or under the terms of our financing agreements, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

Our production, revenue, and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. Unlike other entities that are geographically diversified, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate, and result in our dependency upon a single or limited number of hydrocarbon basins. In addition, the geographic concentration of our properties in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico means that some or all of our properties could be affected should the region experience:

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severe weather, such as hurricanes and other adverse weather conditions;

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delays or decreases in production or the availability of equipment, facilities or services;

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delays or decreases in the availability or capacity to transport, gather or process production;

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changes in the status of pipelines that we depend on for transportation of our production to the marketplace;

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extensive governmental regulation (including regulations that may, in certain circumstances, impose strict liability for pollution damage or require posting substantial bonds to address decommissioning and P&A costs) and interruption or termination of operations by governmental authorities based on environmental, safety or other considerations;

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changes in the regulatory environment such as the guidelines issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS; and/or

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changes imposed as a result of litigation or by a new presidential administration or by the Congress in the United States that may result in added restrictions and delays or prohibitions in offshore oil and natural gas exploration and production activities, including with respect to permitting, site development or operation in federal waters, or hydraulic fracturing.

Because all or a number of our properties could experience many of the same conditions at the same time, these conditions may have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

We may experience significant shut-ins and losses of production due to the effects of hurricanes in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico.

Our production is primarily associated with our properties in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes and tropical storms in the Gulf of Mexico. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production.

A significant portion of our production, revenue and cash flow is concentrated in our Phoenix Field and our Pompano Field. Because of this concentration, any production problems, impacts of adverse weather or inaccuracies in reserve estimates could have a material adverse impact on our business.

For the year ended December 31, 2019, approximately 32% and 21% of our production and 34% and 24% of our oil, natural gas, and NGL revenue was attributable to our Phoenix Field and our Pompano Field, respectively, both of which are located in the federal waters offshore in the United States Gulf of Mexico. This concentration in these fields means that any impact on our production from these fields, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment, or otherwise, could have a material effect on our business. We produce the Phoenix Field through the HP-I, a dynamically positioned floating production facility that is operated by Helix. The HP-I interconnects the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as in the event of a mechanical problem with the dynamic positioning system or the approach of a hurricane. Because the HP-I may have to be disconnected from the Phoenix Field if circumstances require, our production from the Phoenix Field may be subject to more frequent interruptions than if the Phoenix Field was produced by a more conventional platform. We are also required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field. During the year ended December 31, 2019, Helix dry-docked the HP-1. After conducting sea trials, production resumed in late March 2019, resulting in a total shut-in period of 57 days.

The HP-I is part of the Helix Well Containment Group (“HWCG”), which is a consortium that is available to respond to any deepwater well control event, such as the Macondo well oil spill. If such an event were to occur and the HWCG was to be utilized for well control, the HP-I, which is the vessel that would be used to respond to the deepwater well control event, would be required to disconnect from the Phoenix Field until such time as the well control event was resolved and the HP-I could return to the Phoenix Field. During such time period, we would not be able to produce the Phoenix Field. In the event the HP-I has to disconnect from the Phoenix Field, our production, revenue, and cash flow could be adversely affected, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, all of our production from the Phoenix Field flows through the Green Canyon 19 connection facility operated by Shell GOM Pipeline Company LLC. To the extent Shell GOM Pipeline Company LLC temporarily shuts in its Green Canyon 19 connection facility, whether for maintenance or otherwise, we would not be able to produce the Phoenix Field during this period of time, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

If the actual reserves associated with the Phoenix Field are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, all of our production from the Pompano Field flows through the Pompano Pipeline System operated by Crimson Gulf LLC. To the extent Crimson Gulf LLC temporarily shuts in the Pompano Pipeline System, whether for maintenance or otherwise, we would not be able to produce the Pompano Field during this period of time, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

If the actual reserves associated with the Pompano Field are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are not insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, named Gulf of Mexico windstorm, oil pollution, construction all risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses.

We have general liability insurance coverage with an annual aggregate limit of $500 million. We selectively purchase physical damage insurance coverage for our pipelines, platforms, facilities and umbilicals for losses resulting from named windstorms and operational activities.

Our operational control of well coverage is expected to provide limits that vary by well location and depth and range from a combined single limit of $25 million to $500 million per occurrence. Exploratory deepwater wells have a coverage limit of up to $500 million per occurrence. Additionally, we maintain up to $150 million in oil pollution liability coverage. Our operational control of well and physical damage policy limits is scaled proportionately to our working interests. Our general liability program utilizes a combination of assured’s interest and scalable limits. All of our policies described above are subject to deductibles, sub-limits, or self-insurance. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider, subject to the application of various states’ laws.

An operational or hurricane or other adverse weather-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have production interruption insurance.

We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the Gulf of Mexico, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, we compare, at the end of each financial reporting period for each cost center, the present value of estimated future net cash flows from proved reserves (based on a trailing 12-month average, hedge-adjusted commodity price and excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the estimated discounted future net cash flows. A write-down of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we are required to write-down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local governmental regulations that materially affect our operations.

Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can discharge materials into the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well P&A and other decommissioning costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; regulations regarding the rate, terms and conditions of transportation service or the price, terms, and conditions related to the purchase and sale of oil and natural gas; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations. In addition, because we hold federal leases, the federal government requires that we comply with numerous additional regulations applicable to government contractors.

In July 2017, we, along with partners Sierra and Premier, reported the discovery of a significant reservoir of crude oil in the Sureste Basin offshore Mexico through the Zama-1 well. Data from the Zama-1 well indicates that it is possible the deposit could be part of a field that extends into an exploration block in which the state entity Pemex holds exploration and development rights.

The Ministry of Energy of Mexico has promulgated guidelines to establish procedures for conducting the unitization of shared reservoirs and approving the terms and conditions of unitization and unit operating agreements, as well as the authority to direct parties holding rights in a potentially shared reservoir to appraise and potentially form a unit for development of such reservoir.

Even with the final regulations in place, there are still some uncertainties regarding the unitization process, including the selection of a unit operator and the exact length of time that it will take to obtain approvals of any unit agreements. Any unit operating agreement eventually agreed to by the relevant parties or any unit order issued by a governmental entity in Mexico could be adverse to us and affect the value that we are able to recognize from the reservoir discovery, including but not limited to an agreement or unit order that would require us to allow a third party to develop and produce the crude oil reservoir identified through the Zama-1 well.

In September 2015, we, together with our consortium partners executed a PSC with the CNH for each of Blocks 2 and 7 of Round 1. The PSCs require that the consortium execute a minimum work program expressed in work units during a four-year exploration period. Effective January 23, 2018, the activities already performed on Block 7 have satisfied the minimum work program on Block 7. Effective September 4, 2019, the activities already performed on Block 2 have satisfied the minimum work program on Block 2. As a result of the 2019 drilling program, pending government approval, the activities already performed on Block 31 have satisfied the minimum work program on Block 31.

Our Mexican operations are subject to certain offshore regulatory and environmental laws and regulations promulgated by Mexico.

Our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are subject to regulation by the SENER, the CNH and other Mexican regulatory bodies. The CNH is responsible for, among other things, overseeing the tender procedures for awarding contracts for the exploration and production of oil and natural gas in Mexican waters, managing and supervising contracts that have been awarded, and approving exploration and production plans. The PSCs that we and our consortium partners have entered into for the development of these acreages contain terms that impose on us the duty to comply with various laws and regulations. These laws and regulations govern, among other things, the exploration and exploitation of hydrocarbons (including certain national content requirements), the treatment, conveyance, marketing, transport and storage of petroleum, requirements for industrial safety, operational security, and facility decommissioning. Failure to comply can result in the imposition of monetary penalties, revocation of permits, rescission of the relevant PSC, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and regulations governing activities in the Mexican energy sector are relatively new, having been significantly reformed in 2013, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.

In addition, our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are subject to regulation by the ASEA. We must obtain ASEA-issued permits and comply with ASEA regulations governing hydrocarbon activities, including requirements for environmental impact and risk assessments, industrial safety, waste management, water and air emissions, operational security and facility decommissioning. Failure to comply with applicable laws and regulations can result in the imposition of monetary penalties, revocation of permits, suspension of operations and ordered decommissioning of offshore facilities and systems. The laws and regulations governing the protection of health, safety and the environment from activities in the Mexican energy sector are relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. For example, in January 2019, the ASEA published the “General Administrative Provisions on the Guidelines for the Design, Construction, Pre-start, Maintenance, Closing, Dismantling and Abandonment of the Facilities and Transfer Operations associated with the Transportation and/or Distribution of Hydrocarbons and/or Oil Products activities, by means other than Pipelines.” These legal provisions apply to permit holders in charge of the transportation or distribution of hydrocarbons and oil products by means other than pipelines, such as tank trucks, tank vessels and/or by railroad, in connection with the transfer, racking, loading, discharge, reception or delivery of such hydrocarbons and oil products. The permit holders must comply with requirements relating to insurance, facility construction and design, law compliance, and risk analysis scenarios.

Under the PSCs, we are also jointly and severally liable for the performance of all obligations under the PSCs, including exploration, appraisal, extraction and abandonment activities and compliance with all environmental regulations, and failure to perform such obligations could result in contractual rescission of the PSCs.

Production periods or reserve lives for Gulf of Mexico properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

Substantially all of our operations are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.

Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves or make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and natural gas. We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, current market conditions may adversely impact our ability to obtain financing to fund acquisitions, and they have lowered the level of activity and depressed values in the oil and natural gas property sales market.

Our actual recovery of reserves may substantially differ from our proved reserve estimates.

Estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that any present value of future net cash flows from our proved reserves represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2019 on historical 12-month average prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues are affected by factors such as:

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the amount and timing of capital expenditures and decommissioning costs;

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the rate and timing of production;

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changes in governmental legislation, regulations or taxation;

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volume, pricing and duration of our oil and natural gas hedging contracts;

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supply of and demand for oil and natural gas;

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actual prices we receive for oil and natural gas; and

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our actual operating costs in producing oil and natural gas.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties affects the timing of actual future net cash flows from reserves, and thus their actual present value. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.

At December 31, 2019, approximately 31% of our estimated proved reserves (by volume) were undeveloped and approximately 21% were non-producing. Any or all of our PUD or proved developed non-producing reserves may not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developed non-producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling or waterflood operations. Our reserve estimates include the assumptions that we incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as estimated. Any material inaccuracies in these reserve estimates or underlying assumptions materially affects the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present, produce in economic quantities.

We rely on 3D seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or, if present, produce in economic quantities, and seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock. These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition.

SEC rules could limit our ability to book additional PUD reserves in the future.

SEC rules require that, subject to limited exceptions, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book additional PUD reserves as we pursue our drilling program. Moreover, we may be required to write down our PUD reserves if we do not drill those wells within the required five-year timeframe.

Our acreage has to be drilled before lease expiration in order to hold the acreage by production. If commodity prices become depressed for an extended period of time, it might not be economical for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an adverse effect on our business.

Unless production is established as required by the leases covering the undeveloped acres, the leases for such acreage may expire.

Our drilling plans for areas not held by production are subject to change based upon various factors. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. On the acreage that we do not operate, we have less control over the timing of drilling, and therefore there is additional risk of expirations occurring in those sections.

The marketability of our production depends mostly upon the availability, proximity, and capacity of oil and natural gas gathering systems, pipelines and processing facilities.

The marketability of our production depends upon the availability, proximity, operation and capacity of oil and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity of these gathering systems, pipelines and processing facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. The disruption of these gathering systems, pipelines and processing facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. Federal, state, and local regulation of oil and natural gas production and transportation, general economic conditions, and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors changed dramatically, the financial impact could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.

Our actual production could differ materially from our forecasts.

From time to time, we may provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. In addition, our forecasts may assume that none of the risks associated with our oil and natural gas operations summarized in this section would occur, such as facility or equipment malfunctions, adverse weather effects or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.

Our operations are subject to numerous risks of oil and natural gas drilling and production activities.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves are found. The cost of drilling and completing wells is often uncertain. To the extent we drill additional wells in the Gulf of Mexico deepwater and/or in the Gulf Coast deep gas, our drilling activities increase capital cost. In addition, the geological complexity of the areas in which we have oil and natural gas operations make it more difficult for us to sustain the historical rates of drilling success. Oil and natural gas drilling and production activities may be shortened, delayed or cancelled as a result of a variety of factors, many of which are beyond our control. These factors include:

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unexpected drilling conditions;

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pressure or irregularities in formations;

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equipment failures or accidents;

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hurricanes and other adverse weather conditions;

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shortages in experienced labor; and

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shortages or delays in the delivery of equipment.

The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry holes and wells that are productive but do not produce sufficient cash flows to recoup drilling costs.

Our industry experiences numerous operating risks.

The exploration, development and production of oil and gas properties involves a variety of operating risks, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. We are also involved in completion operations that utilize hydraulic fracturing, which may potentially present additional operational and environmental risks. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collisions and adverse weather and sea conditions, including the effects of hurricanes.

In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for containment and oil removal costs and a variety of public and private damages, including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we could be liable for costs and damages, which costs and damages could be material to our results of operations and financial position.

Our business is also subject to the risks and uncertainties normally associated with the exploration for and development and production of oil and natural gas that are beyond our control, including uncertainties as to the presence, size and recoverability of hydrocarbons. We may not encounter commercially productive oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and/or result in a total loss of our investment, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, we may be uncertain as to the future cost or timing of drilling, completing and operating wells.

We have an interest in deepwater fields and may attempt to pursue additional operational activity in the future and acquire additional fields and leases in the deepwaters of the Gulf of Mexico. Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration in the shallower waters of the Gulf of Mexico conventional shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. For example, the drilling of deepwater wells requires specific types of drilling rigs with significantly higher day rates and limited availability as compared to the rigs used in shallower water. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present in the shallower waters of the Gulf of Mexico conventional shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.

If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and production and repairs to resume operations. Any of these industry operating risks could have a material adverse effect on our business, results of operations and financial condition.

Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other disruptions.

As an oil and gas producer, we have various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business. In particular, the implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls are sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers or vendors, could have a material adverse effect on our financial condition and operations.

Events outside of our control, including an epidemic or outbreak of an infectious disease, such as the Coronavirus Disease 2019 (or COVID-19), may materially adversely affect our business.

We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. For example, the recent outbreak in Wuhan, China of COVID-19, which has spread across the globe and impacted financial markets and worldwide economic activity, may adversely affect our operations or the health of our workforce by rendering employees or contractors unable to work or unable to access our facilities for an indefinite period of time. In addition, the effects of COVID-19 and concerns regarding its global spread could negatively impact the domestic and international demand for crude oil and natural gas, which could contribute to price volatility, impact the price we receive for oil and natural gas and materially and adversely affect the demand for and marketability of our production. As the potential impact from COVID-19 is difficult to predict, the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. Any potential impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could adversely affect our operating results.

Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs. As a result, we may significantly increase or decrease our estimated asset retirement obligations in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions. The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimates of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster. Also, a sustained lower commodity price environment may cause our non-operator partners to be unable to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs.

Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the U.S Gulf of Mexico following BSEE’s issuance of an NTL in 2010 and updated in late 2018 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron,” which are wells, platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease in the U.S. Gulf of Mexico. Pursuant to the idle iron NTL requirements, on October 3, 2019, BSEE issued us a letter, directing us to P&A numerous wells that the agency identified as no longer capable of production in paying quantities by a specified timeline of December 31, 2021. In response, we are currently evaluating the list of wells proposed as idle iron by BSEE and currently anticipate that those wells determined to be idle iron will be decommissioned by the specified timeline or at times as otherwise determined following further discussions with BSEE. While we have established AROs for well decommissioning, additional AROs, significant in amount, may be necessary to conduct P&A of the wells designated by BSEE as idle iron but we do not expect the costs to P&A these wells will have a material effect on our financial condition, results of operations or cash flows. Additionally, there exists the possibility that increased decommissioning costs beyond what we established as AROs may arise and the pace for completing these activities could be adversely affected by idle iron decommissioning activities being pursued by other offshore oil and gas lessees in the U.S. Gulf of Mexico that may also have received similar BSEE directives, which could restrict the availability of salvage contractors and equipment necessary to accomplish this work. We may have to draw on funds from other sources to satisfy decommissioning costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations.

In addition, we could become responsible for decommissioning liabilities related to offshore facilities we no longer own or operate. Under existing BOEM rules relating to assignment of offshore leases and other legal interests on the OCS, assignors of such interest may be held jointly and severally liable, regardless of any indemnity agreements, for decommissioning of OCS facilities existing at the time the assignment was approved by BOEM in the event that the assignee, or any subsequent assignee, is unable or unwilling to conduct required decommissioning obligations. The costs of performance of required decommissioning obligations, whether our or any assignees, may be material. Moreover, several onshore and offshore exploration and production companies have sought bankruptcy protection over the past several years. The government may seek to impose a bankrupt entity’s P&A obligations on us or other predecessors-in-interest, which could be significant and have a material adverse effect on our business, results of operations, financial condition and cash flows.

We may not receive payment for a portion of our future production.

We may not receive payment for a portion of our future production. We attempt to diversify our sales and obtain credit protections, such as parent guarantees, from certain of our purchasers. The tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by customers. We are unable to predict what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.

The market price of our common stock may decline as a result of the ILX and Castex Acquisition.

The market price of our common stock may decline as a result of the ILX and Castex Acquisition (defined below) if, among other things, we are unable to achieve the expected benefits of the transaction, or if the transaction costs related thereto and with respect to integration thereof are greater than expected. The market price also may decline if we do not achieve the perceived benefits of the ILX and Castex Acquisition as rapidly or to the extent anticipated by financial or industry analysts or if the effect of the ILX and Castex Acquisition on our financial results is not consistent with the expectations of financial or industry analysts.

We may not realize all of the anticipated benefits from our future acquisitions, and we may be unable to successfully integrate future acquisitions.

Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. We expect to grow in the future by expanding the exploitation and development of our existing assets, in addition to growing through targeted acquisitions in the Gulf of Mexico or in other basins. We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, inexperience with operating in new geographic regions, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices.

In addition, integrating acquired businesses and properties involves a number of special risks and unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. These difficulties include, among other things:

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operating a larger organization;

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coordinating geographically disparate organizations, systems and facilities;

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integrating corporate, technological and administrative functions;

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diverting management’s attention from regular business concerns;

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diverting financial resources away from existing operations;

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increasing our indebtedness; and

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incurring potential environmental or regulatory liabilities and title problems.

Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results. The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage our business. If our management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

Additionally, in connection with the signing and closing of the ILX and Castex Acquisition, we have released certain estimated operating results, costs and activities, including without limitation, estimated Adjusted EBITDA and capital expenditures for the assets acquired under the ILX and Castex Acquisition. The guidance released represents our management’s estimates as of the date thereof, and is based upon a number of assumptions that are inherently uncertain and is subject to numerous business, economic, competitive, financial and regulatory risks. Many of these risks and uncertainties are beyond our control, such as declines in commodity prices and the speculative nature of estimating natural gas, NGLs and oil reserves and in projecting future rates of production. In addition, the Adjusted EBITDA estimates exclude general and administrative expenses associated with the acquired assets, which may not be representative following the integration of the acquired assets into our existing business. If any of these risks and uncertainties actually occur or the assumptions underlying our estimates are incorrect, our actual operating results, costs and activities may be materially and adversely different from our estimates.

Our future acquisitions could expose us to potentially significant liabilities, including P&A liabilities.

We expect that future acquisitions will contribute to our growth. In connection with potential future acquisitions, we may only be able to perform limited due diligence.

Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental, regulatory and other liabilities, including P&A liabilities. Such assessments are inexact and may not disclose all material issues or liabilities. In connection with our assessments, we perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.

There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We may be successful in obtaining contractual indemnification for preclosing liabilities, including environmental liabilities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and could potentially expose us to unindemnified liabilities, which could materially adversely affect our production, revenues and results of operations.

We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act (the “FCPA”).

We are subject to the FCPA and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business. We may do business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, or private entities. Thus, we face the risk of unauthorized payments or offers of payments by one of our employees or consultants, given that these parties may not always be subject to our control. Our existing safeguards and any future improvements may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible.

Under the PSCs with the CNH, we work as a consortium with our partners. Violations of the FCPA, by any consortium partner, may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the CNH has the authority to rescind the PSCs if these violations occur.

Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.

Our oil and gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them), expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions, currency fluctuations, royalty and tax increases, and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to acts of terrorism, piracy, disease, illegal cartel activities and other political risks, including tension and confrontations among political parties. Some of these risks may be higher in the developing countries in which we conduct our activities, namely, Mexico. Mexico’s most recent presidential election was held in July 2018. Presidential reelection is not permitted in Mexico. President Andrés Manuel López Obrador, took office on December 1, 2018, and his political party, Movimiento Regeneración Nacional has a majority in both houses of Mexico’s congress. Mr. Lopez Obrador, and certain members of his cabinet have, in the past, made statements that would call into question the degree of support their administration will have for Mexico’s energy reforms. However, at this time we cannot predict what changes (if any) will result from this change in administration. Political events in Mexico could adversely affect economic conditions and/or the oil and gas industry and, by extension, our results of operations and financial position.

Our operations may be exposed to risks of illegal cartel activities, local economic conditions, political disruption, and governmental policies that may:

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disrupt our operations;

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restrict the movement of funds or limit repatriation of profits;

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in the case of our non-U.S. operations, lead to U.S. government or international sanctions; and

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limit access to markets for periods of time.

Disruptions may occur in the future, and losses caused by these disruptions may not be covered by insurance. Consequently, our exploration, development and production activities may be substantially affected by factors that could have a material adverse effect on our financial condition and results of operations. Furthermore, in the event of a dispute arising from non-U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the outcome of such dispute.

Our operations are adversely affected by laws and policies of the jurisdictions, including Mexico, the United States, Luxembourg and other jurisdictions, in which we do business that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof could have a material adverse effect on our results of operations and financial position.

New technologies may cause our current exploration and drilling methods to become obsolete, and we may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We rely heavily on the use of seismic technology to identify low-risk development and exploitation opportunities and to reduce our geological risk. Seismic technology or other technologies that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.

We may not be in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves from our non-operated properties.

As we carry out our drilling program, we may not serve as operator of all planned wells. We may have limited ability to exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could prevent the realization of anticipated results in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depends upon a number of factors that could be largely outside of our control, including:

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the timing and amount of capital expenditures;

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the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

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the operator’s expertise and financial resources;

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approval of other participants in drilling wells;

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risk of other non-operator’s failing to pay its share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs;

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selection of technology;

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the rate of production of the reserves; and

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the timing and cost of P&A operations.

In addition, with respect to oil and natural gas projects that we do not operate, we have limited influence over operations, including limited control over the maintenance of safety and environmental standards. The operators of those properties may, depending on the terms of the applicable joint operating agreement:

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refuse to initiate exploration or development projects;

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initiate exploration or development projects on a slower or faster schedule than we would prefer;

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delay the pace of exploratory drilling or development; and/or

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drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

Competition within our industry may adversely affect our operations.

Competition within our industry is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than our budget, which may adversely affect our ability to compete. If other companies relocate to the Gulf of Mexico region, levels of competition may increase and our business could be adversely affected. In the exploration and production business, some of the larger integrated companies may be better able than we are to respond to industry changes including price fluctuations, oil and gas demand, political change and government regulations.

We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. The competitors may also have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the current decline in oil prices, and to absorb the burden of current and future governmental regulations and taxation. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe impacts attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

The loss of our larger customers could materially reduce our revenue and materially adversely affect our business, financial condition and results of operations.

We have a limited number of customers that provide a substantial portion of our revenue. The loss of our larger customers, including Shell Trading (US) Company, could adversely affect our current and future revenue, and could have a material adverse effect on our business, financial condition and results of operations.

Our business depends on access to oil and natural gas processing, gathering and transportation systems and facilities.

The marketability of our oil and natural gas production depends in large part on the operation, availability, proximity, capacity and expansion of processing, gathering and transportation facilities owned by third parties. We can provide no assurance that sufficient processing, gathering and/or transportation capacity exists or that we will be able to obtain sufficient processing, gathering and/or transportation capacity on economic terms. A lack of available capacity on processing, gathering and transportation facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these facilities for an extended period of time could negatively impact our revenues. In addition, we enter into contracts for firm transportation, and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above. In addition, the rates charged for processing, gathering and transportation services may increase over time.

The loss of key personnel could adversely affect our ability to operate.

Our industry has lost a significant number of experienced professionals over the years due to its cyclical nature, which is attributable, among other reasons, to the volatility in commodity prices. Our operations are dependent upon key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have an adverse effect on us and our operations.

In addition, our exploration, production and decommissioning activities require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable depends upon our ability to employ and retain skilled workers. Our ability to expand operations depends in part on our ability to increase the size of our skilled labor force, including geologists and geophysicists, field operations managers and engineers, to handle all aspects of our exploration, production and decommissioning activities. The demand for skilled workers in our industry is high, and the supply is limited. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our labor force, increases in the wage rates that we will have to pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Resolution of litigation could materially affect our financial position and results of operations.

Resolution of litigation could materially affect our financial position and results of operations. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we may incur losses that could be material to our financial position or results of operations in future periods.

We have operations in multiple jurisdictions, including jurisdictions in which the tax laws, their interpretation or their administration may change. As a result, our tax obligations and related filings are complex and subject to change, and our after-tax profitability could be lower than anticipated. Additionally, future tax legislative or regulatory changes in the United States, Mexico or any other jurisdiction in which we operate or have subsidiaries could result in changes to the taxation of our income and operations, which could also adversely impact our after-tax profitability.

We are subject to income, withholding and other taxes in the United States on a worldwide basis and in numerous state, local and foreign jurisdictions with respect to our income, operations and subsidiaries related to those jurisdictions. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions, refunds (including refunds of value added taxes) and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate or have subsidiaries, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing business structure and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions.

Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect. In 2017, the United States enacted tax reform legislation in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act. Additionally, the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent BEPS recently entered into force among the jurisdictions that have ratified it, although the United States has not yet entered into this convention. Both of these recent changes could result in further changes to our global taxation. Additionally, Mexico enacted tax reform legislation, and a majority of the provisions became effective on January 1, 2020, and most of the remaining provisions will become effective in the near future. These tax reforms provided for new and complex provisions that significantly change how the United States and Mexico tax entities and operations, and these provisions are subject to further legislative change and administrative guidance and interpretation, all of which may differ from our interpretation. Future tax legislative or regulatory changes in the United States, Mexico or in any other jurisdictions in which we operate now or in the future could also adversely impact our after-tax profitability.

Final regulations relating to and interpretations of the provisions of the Tax Cuts and Jobs Act may vary from our current interpretation of such legislation.

The U.S. federal income tax legislation enacted in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Cuts and Jobs Act. The Treasury Department and the Internal Revenue Service have issued, and are expected to continue to issue, final regulations and additional interpretive guidance with respect to the provisions of the Tax Cuts and Jobs Act. Any significant variance of our current interpretation of such legislation from any future final regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.

Our operations are subject to various risks that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduced demand for the crude oil and natural gas that we produce.

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, the U.S. Congress has from time to time considered climate change legislation but no comprehensive climate change legislation has been adopted. The EPA, however, has adopted regulations under the existing CAA to restrict emissions of GHG. For example, the EPA imposes preconstruction and operating permit requirements on certain large stationary sources that are already potential sources of certain other significant pollutant emissions. The EPA also adopted rules requiring the monitoring and reporting of GHG emissions on an annual basis from specified large GHG emission sources in the United States, including onshore and offshore oil and natural gas production facilities. Federal agencies have also begun directly regulating emissions of methane, a GHG, from oil and natural gas operations as described above. Compliance with these rules could result in increased compliance costs on our operations.

State implementation of these revised air emission standards could result in stricter permitting requirements, delay, limit or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in federal political risks in the United States in the form of pledges made by certain candidates seeking the office of the President of the United States in 2020. Critical declarations made by one or more presidential candidates include proposals to ban hydraulic fracturing of oil and natural gas wells and to ban new leases for production of minerals on federal properties, including onshore lands and offshore waters. Other actions to oil and natural gas production activities that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas export facilities, as well as the rescission of the United States’ withdrawal from the Paris Agreement in November 2020. Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

There are also increasing financial risks for fossil fuel producers as stockholders and bondholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

The adoption of legislation or regulatory programs to reduce or eliminate future emissions of GHG could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce or eliminate future emissions of GHG could have an adverse effect on our business, financial condition and results of operations. Also, political, financial and litigation risks may result in our restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing the ability to continue to operate in an economic manner.

Finally, some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such effects of climate changes were to occur, they could have an adverse effect on our financial condition and results of operations.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, expanded federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC and the SEC have finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this is accomplished.

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also requires us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or to take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps to be entered into to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for, and to utilize, the end-user exception from such margin requirements for swaps to be entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows.

The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we may encounter, or reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

In addition, the European Union and other non-U.S. jurisdictions have implemented and continue to implement new regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become directly subject to such regulations and in any event the global derivatives market are affected to the extent that foreign counterparties are affected by such regulations. At this time, the impact of such regulations is not clear.

Hedging transactions may limit our potential gains.

In order to manage our exposure to price risks in the marketing of our oil, natural gas and NGLs, we periodically enter into oil, natural gas and NGLs price hedging arrangements with respect to a portion of our expected production. Our hedging policy provides that we may enter into hedging arrangements covering up to the following maximum percentages of volumes: (i) 90% of the reasonably anticipated quarterly production of oil, natural gas and NGLs of PDP volumes during months January through July and November through December, (ii) 65% of the reasonably anticipated quarterly production of oil, natural gas and NGLs of PDP volumes during months August through October, (iii) 50% of the reasonably anticipated quarterly production of oil, natural gas and NGLs of our proved developed non-producing volumes during months January through July and November through December and (iv) 0% of the reasonably anticipated quarterly production of oil, natural gas and NGLs of its proved developed non-producing volumes during months August through October. These arrangements may include futures contracts on the NYMEX. While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

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our production is less than expected or is shut-in for extended periods due to hurricanes or other factors;

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there is a widening of price differentials between delivery points for our production and the delivery point to be assumed in the hedge arrangement;

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the counterparties to our futures contracts fails to perform the contracts;

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a sudden, unexpected event materially impacts oil or natural gas prices; or

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we are unable to market our production in a manner contemplated when entering into the hedge contract.

A majority of our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our Bank Credit Facility. Our derivative agreements with the lenders are secured by the security documents executed by the parties under the Bank Credit Facility. Future collateral requirements for our commodity hedging activities are uncertain and depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions.

We are controlled by Apollo Funds and Riverstone Funds. The interests of Apollo Funds and Riverstone Funds may differ from the interests of our other stockholders.

As of December 31, 2019, the 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”) beneficially owned and possessed voting power over 62.9% of our common stock. At the closing of the ILX and Castex Acquisition, the Riverstone Funds received 110,000 shares of Series A Convertible Preferred Stock which are subject to automatic conversion into common stock upon the terms of the Certificate of Designation. Following the closing of the ILX and Castex Acquisition, the Riverstone Funds are expected to beneficially own and possess voting power over 39.8% of our common stock. Under the Stockholders’ Agreement, the Apollo Funds and the Riverstone Funds may acquire additional shares of our common stock without the approval of our Independent Directors as defined in that certain Stockholders’ Agreement, dated as of May 10, 2018 (the “Stockholders’ Agreement”).

Through their ownership of a majority of our voting power and the provisions set forth in our Amended and Restated Certificate of Incorporation, our Amended and Restated Bylaws and the Stockholders’ Agreement, the Apollo Funds and the Riverstone Funds have the ability to designate a majority of our directors to be nominated for election by our stockholders. As a result of the Apollo Funds’ and the Riverstone Funds’ ownership of a majority of the voting power of our common stock, we are a “controlled company” as defined in the New York Stock Exchange (“NYSE”) listing rules and, therefore, we are not subject to NYSE requirements that would otherwise require us to have a majority of independent directors and nominating and compensation committees composed solely of independent directors. We have not elected to take advantage of the “controlled company” exemptions available to us, but we may choose to do so in the future.

The Apollo Funds and the Riverstone Funds also have control over all other matters submitted to stockholders for approval, including changes in capital structure, transactions requiring stockholder approval under Delaware law, and corporate governance, subject to the terms of the Stockholders’ Agreement that require the Apollo Funds and the Riverstone Funds to vote in a specified manner on certain actions, including their agreement to vote in favor of director nominees not designated by the Apollo Funds and the Riverstone Funds. The Apollo Funds and the Riverstone Funds may have different interests than other holders of our common stock and may make decisions adverse to your interests.

Among other things, the Apollo Funds’ and Riverstone Funds’ control could delay, defer or prevent a sale of us that our other stockholders support, or, conversely, this control could result in the consummation of such a transaction that other stockholders do not support. This concentrated control could discourage a potential investor from seeking to acquire our common stock and, as a result, might harm the market price of our common stock.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock, or if our operating results do not meet their expectations, the price of our common stock could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover us downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

Negative publicity may adversely impact us.

Media coverage and public statements that insinuate improper actions by us, regardless of their factual accuracy or truthfulness, may result in negative publicity, litigation or governmental investigations by regulators. Addressing negative publicity and any resulting litigation or investigations may distract management, increase costs and divert resources. Negative publicity may have an adverse impact on our reputation and the morale of our employees, which could materially adversely affect our business, financial position, results of operations, cash flows, growth prospects and stock price.

The corporate opportunity provisions in our Amended and Restated Certificate of Incorporation could enable others to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our Amended and Restated Certificate of Incorporation, among other things:

•permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;

•permits the Apollo Funds, the Riverstone Funds, and any of our officers or directors who is also an officer, director, employee, managing director, or other affiliate of the Apollo Funds or the Riverstone Funds to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

•provides that if the Apollo Funds, the Riverstone Funds, or any of our officers or directors who is also an officer, director, employee, managing director or other affiliate of the Apollo Funds or the Riverstone Funds becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as an director or officer of us), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to any other entity or individual and that director or officer will not be deemed to have acted in a manner inconsistent with his or her fiduciary duty to us or our stockholders.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of others.

Our Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery will be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of us, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, employees, agents or stockholders (including a beneficial owner of stock) to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our Amended and Restated Certificate of Incorporation or Amended and Restated Bylaws, or (iv) any action asserting a claim governed by the internal affairs doctrine, in each case subject to the Court of Chancery having personal jurisdiction over the indispensable parties named as defendants in the case. Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations promulgated thereunder. As a result, the exclusive forum provision will not apply to actions arising under the Exchange Act or the rules and regulations promulgated thereunder. However, Section 22 of the Securities Act provides for concurrent federal and state court jurisdiction over actions under the Securities Act and the rules and regulations promulgated thereunder, subject to a limited exception for certain “covered class actions” as defined in Section 16 of the Securities Act and interpreted by the courts. Accordingly, we believe that the exclusive forum provision would apply to actions arising under the Securities Act or the rules and regulations promulgated thereunder, except to the extent a particular action fell within the exception for covered class actions or the exception in the certificate of incorporation described above otherwise applied to such action, which could occur if, for example, the action also involved claims under the Exchange Act. Stockholders will not be deemed, by operation of Article 12 of our Amended and Restated Certificate of Incorporation alone, to have waived claims arising under the federal securities laws and the rules and regulations promulgated thereunder.

Any person or entity purchasing or otherwise acquiring any interest in any share of our capital stock will be deemed to have notice of and consent to these provisions of our Amended and Restated Certificate of Incorporation. This exclusive forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Amended and Restated Certificate of Incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

A change in the jurisdictional characterization of our FERC-jurisdictional pipelines, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of such asset, which may cause our revenues to decline and operating expenses to increase or delay or increase the cost of expansion projects.

SP 49 Pipeline LLC is considered a common carrier pipeline subject to regulation by FERC under ICA. The ICA requires that we maintain a tariff on file with FERC for SP 49 Pipeline LLC that sets forth the rates we charge for providing transportation service as well as the rules and regulations governing such service. The ICA requires, among other things, that the rates, terms and conditions of service on interstate common carrier pipelines be “just and reasonable” and non-discriminatory. In the event a shipper protests the rates, terms or conditions of service in effect pursuant to the tariff, we may be required to modify such rates, terms, or conditions, which could adversely affect the results of our operations. With respect to CKB Petroleum, Inc., which has been granted a waiver of certain portions of the ICA and related regulations by FERC, should the pipeline’s circumstances change, FERC could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies for a waiver. In the event that FERC were to determine that CKB Petroleum, Inc. no longer qualified for a waiver, we would likely be required to file a tariff with FERC, provide a cost justification for the transportation charge, and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on the CKB Petroleum, Inc. pipeline could adversely affect our results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information regarding our properties is included in Part I, Item 1. Business, Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 3 — Acquisitions and Note 4 — Property, Plant and Equipment.

Item 3. Legal Proceedings

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

The following proceedings represent previous Stone litigation that was assumed as part of the Stone Combination.

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, the “CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in two of the three Jefferson Parish Coastal Zone Management lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The Jefferson Parish lawsuits have been removed to the United States District Court for the Eastern District of Louisiana. The plaintiffs have moved to remand the lawsuit to the state courts.

On November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The Plaquemines Parish lawsuit has been stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. The Plaquemines Parish lawsuit has been removed to the United States District Court for the Eastern District of Louisiana. The plaintiffs have moved to remand the lawsuit to the state courts. Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters. See Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 12 — Commitments and Contingencies for more information.

Item 4. Mine Safety Disclosures.

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuers Purchases of Equity Securities

Market for Common Stock

Our common stock is listed on the NYSE under the symbol “TALO”.

Holders of Record

Pursuant to the records of our transfer agent, as of March 4, 2020, there were approximately 298 holders of record of our common stock.

For additional information about shares authorized for issuance under equity compensation plans, see Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 8 — Employee Benefits Plans and Share-Based Compensation.

Dividends

We have never declared or paid any cash dividends on our common stock, and we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends on our common stock, if our board of directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions that the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make distributions and other payments to us.

Stockholder Return Performance Presentation

The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic stock price performance is not necessarily indicative of future stock performance. The graph compares the change in the cumulative total return of our common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500 Index for May 10, 2018 through December 31, 2019. The graph assumes that $100 was invested in our common stock and each index on May 10, 2018 and that dividends were reinvested.

	May 10, 2018		December 31, 2018		December 31, 2019
Talos Energy Inc.	$	100	$	45	$	83
S&P 500 Index	$	100	$	93	$	123
Dow Jones U.S. Exploration and Production Index	$	100	$	71	$	78

The performance graph and the information contained in this section is not “soliciting material,” is being “furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing.

Item 6. Selected Financial Data

The following table sets forth our selected consolidated historical financial data as of and for the periods ended on the dates indicated below. The selected historical statement of operations data for the years ended December 31, 2019, 2018 and 2017 and the selected historical balance sheet data as of December 31, 2019 and 2018, have been derived from our audited consolidated financial statements and related notes for the year ended December 31, 2019, which are included elsewhere in this report. The selected historical statement of operations data for the years ended December 31, 2016 and 2015, and the selected historical balance sheet data as of December 31, 2017, 2016 and 2015 have been derived from our audited consolidated financial statements, which have not been included in this report. Our consolidated financial statements have been prepared in accordance with GAAP. Our results of operations in any period may not necessarily be indicative of the results that may be expected for any future period. See Part I, Item 1A. Risk Factors for additional information.

As previously described, Stone and Talos Energy LLC became our wholly-owned subsidiaries on the Stone Closing Date in connection with the Stone Combination. Prior to the Stone Closing Date, Talos Energy Inc. had not conducted any material activities other than those incident to its incorporation and certain matters contemplated by the Stone Transaction Agreement. Talos Energy LLC is the acquirer of Stone for financial reporting and accounting purposes. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the selected consolidated historical financial data presented in the tables below, which covers periods prior to the Stone Closing Date, reflects the assets, liabilities and operations of Talos Energy LLC prior to the Stone Closing Date and does not reflect the assets, liabilities and operations of Stone prior to the Stone Closing Date. In addition, we incurred material costs associated with the Stone Combination that are reflected in our historical results of operations for periods prior to the Stone Closing Date, and Talos Energy LLC did not incur United States federal income tax expense or the incremental expense associated with being a public company.

The selected consolidated historical financial information should be read in conjunction with our financial statements and the related notes included elsewhere in this report, as well as Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (in thousands, except for per share amounts):

	Year Ended December 31,
	2019⁽¹⁾		2018⁽¹⁾		2017⁽¹⁾			2016			2015
Consolidated statements of operations data:
Revenues:
Oil revenue	$	833,118	$	781,815	$	344,781		$	197,583		$	244,167
Natural gas revenue		55,278		73,610		48,886			42,705			55,026
NGL revenue		19,668		35,863		16,658			9,532			10,523
Other		19,556		—		2,503			8,934			5,890
Total revenue	$	927,620	$	891,288	$	412,828		$	258,754		$	315,606
Operating income (loss)	$	213,094	$	253,129	$	45,300		$	(80,679	)	$	(777,651	)
Net income (loss)	$	58,729	$	221,540	$	(62,868	)	$	(208,087	)	$	(646,685	)
Net income (loss) per common share:
Basic	$	1.08	$	4.81	$	(2.01	)	$	(7.99	)	$	(26.20	)
Diluted	$	1.08	$	4.81	$	(2.01	)	$	(7.99	)	$	(26.20	)
Weighted average common shares outstanding:
Basic		54,185		46,058		31,244			26,036			24,685
Diluted		54,413		46,061		31,244			26,036			24,685
Consolidated balance sheets data (at period end):
Total assets	$	2,589,482	$	2,479,986	$	1,239,293		$	1,212,298		$	1,194,842
Total debt⁽²⁾	$	732,981	$	655,304	$	697,558		$	701,175		$	690,178
Stockholders' equity (deficit)	$	1,078,277	$	1,007,496	$	(54,087	)	$	6,986		$	120,895

⁽¹⁾	For more information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

⁽²⁾

In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendment changes the presentation of long-term debt issuance costs in the financial statements, and was adopted by Talos Energy LLC during the first quarter of 2016 and applied retrospectively to December 31, 2015 as presented above.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15. Exhibits, Financial Statement Schedules; Part 1, Items 1 and 2. Business and Properties; Part I, Item 1A. Risk Factors; and Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk. This discussion and analysis contains forward-looking statements that involve risk and uncertainties. Actual results may differ materially from those anticipated in these forward-looking statements.

Our Business

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 organically from our existing acreage, an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible.

Recent Developments

On December 10, 2019, the Company entered into separate Purchase Agreements with ILX Holdings, LLC, a Delaware limited liability company (“ILX Holdings”), ILX Holdings II, LLC, a Delaware limited liability company (“ILX Holdings II”), ILX Holdings III LLC, a Delaware limited liability company (“ILX Holdings III”), Castex Energy 2014, LLC, a Delaware limited liability company (“Castex 2014” and, together with ILX Holdings, ILX Holdings II and ILX Holdings III, the “Riverstone Sellers”) and Castex Energy 2016, L.P. (“Castex 2016” and, together with the Riverstone Sellers, the “Sellers”). On February 24, 2020, the Company, Talos Production and the Riverstone Sellers amended the Purchase Agreements applicable to the Riverstone Sellers. Pursuant to the Purchase Agreements, as amended, among other things, the Company will acquire all of the issued and outstanding limited liability company interests in certain wholly owned subsidiaries of each of the respective Sellers (collectively, the “ILX and Castex Acquisition”) for an aggregate consideration consisting of the following, subject to certain negotiated adjustments: (i) an aggregate amount of cash equal to $385.0 million and (ii) an aggregate of 110,000 shares of the Company’s preferred stock, par value $0.01 per share, designated as “Series A Convertible Preferred Stock.” The Series A Convertible Preferred Stock is subject to automatic conversion into common stock upon the terms of that certain Certificate of Designation, Preferences, Rights and Limitations related thereto (such common stock, the “Conversion Stock”) to be issued to the Riverstone Sellers. At signing, the Company deposited in escrow $31.8 million that was applied at closing towards the cash component of the purchase price under the Purchase Agreements. On February 28, 2020, the Company completed the ILX and Castex Acquisition with an effective date of July 1, 2019.

Factors Affecting the Comparability of our Financial Condition and Results of Operations

Stone Combination — On May 10, 2018, the Stone Closing Date, Stone and Talos Energy LLC became our wholly-owned subsidiaries. Prior to the Stone Closing Date, Talos had not conducted any material activities other than those incident to its formation. Talos is the acquirer of Stone for financial reporting and accounting purposes and considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, our historical financial and operating data, which covers periods prior to the Stone Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC prior to the Stone Closing Date and does not reflect the assets, liabilities and results of operations of Stone prior to the Stone Closing Date. See Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 3 — Acquisitions for more information.

Whistler Acquisition — On August 31, 2018, we completed the acquisition of all the issued and outstanding membership interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC for $52.6 million ($14.8 million net of $37.8 million of cash acquired) (the “Whistler Acquisition”). See Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 3 — Acquisitions for more information.

Mexico Exchange — On September 11, 2018, we entered into the Hokchi Cross Assignment with Hokchi, a subsidiary of PAE, to cross assign 25% PI in each of Block 2 and Block 31. Our assignment of a 25% PI in Block 2 to Hokchi closed on December 21, 2018, and Hokchi has assumed operator responsibilities with respect to Block 2. Hokchi’s assignment of Block 31 to us closed on May 22, 2019. In addition, Premier Oil Plc exercised its option to reduce its PI in Block 2 to zero and assigned a 5% PI to each of Sierra and Talos. 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.

Write-down of oil and natural gas properties — As a result of our evaluation of unproved property located in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from exploratory wells drilled during the second quarter of 2019 and the Block 2 production sharing contract’s expiration date, for the year ended December 31, 2019 we recorded non-cash impairment expense of $12.2 million presented as “Write-down of oil and natural gas properties” on the consolidated statements of operations.

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 ($27.9 million after customary purchase price adjustments). See Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 3 — Acquisitions for more information.

Transaction Expenses — We have incurred and will continue to incur transaction related and restructuring costs associated with our business development activities that may vary significantly in our comparative historical results of operations. See Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 3 — Acquisitions for more information.

Income Tax Expenses — Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. Talos Energy LLC’s operations in the shallow waters off the coast of Mexico were conducted under a different legal form and are subject to foreign income taxes. In connection with the Stone Combination, Talos Energy LLC was contributed to us. We are subject to federal and state income taxes. We record current income taxes based on estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts.

Third Party Planned Downtime — Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering or processing of production. We produce the Phoenix Field through the HP-I that is operated by Helix. Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field.

During the year ended December 31, 2019, Helix dry-docked the HP-1. After conducting sea trials, production resumed in late March 2019, resulting in a total shut-in period of 57 days. The shut-in resulted in deferred production of 3.3 MBoepd during the year ended December 31, 2019 when compared to the same period in 2018.

Known Trends and Uncertainties

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.

BOEM Bonding Requirements — In order to cover the various decommissioning obligations of lessees on the OCS, BOEM generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. As many BOEM regulations are being reviewed by the agency, we may be subject to additional financial assurance requirements in the future. For example, in July 2016, BOEM issued the 2016 NTL to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs and RUEs. The 2016 NTL became effective in September 2016, but BOEM subsequently postponed any implementation of the 2016 NTL and has indicated they will be issuing a modified or substitute NTL or proposed rule. This postponement of implementation currently remains in effect. We remain in active discussions with government regulators and industry peers with regard to any future rulemaking and financial assurance requirements. Notwithstanding BOEM’s 2016 NTL, BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us as a result of the 2016 NTL, to the extent implemented, as well as any other future BOEM directives, or any other changes to BOEM’s rules applicable to our or any of our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows and results of operations.

Deepwater Operations — We have interests in deepwater fields in the U.S. Gulf of Mexico. Operations in the deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

Oil Spill Response Plan — We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are generally approved by BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.

Hurricanes — Since our operations are in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes has become less effective due to rising retentions and limitations on named windstorm coverage and has been difficult to obtain at times in recent years. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

•

production volumes;

•

realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;

•

lease operating expenses;

•

capital expenditures; and

•

Adjusted EBITDA, which is discussed under—Supplemental Non-GAAP Measure.

Basis of Presentation

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in price risk management activities income (expense) in our consolidated statements of operations. The following table presents a breakout of each revenue component:

	Year Ended December 31,
	2019			2018			2017
Revenue breakout:
Oil revenue		90	%		88	%		83	%
Natural gas revenue		6	%		8	%		12	%
NGL revenue		2	%		4	%		4	%
Other		2	%		—	%		1	%

Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Realized Prices on the Sale of Oil, Natural Gas and NGLs — The NYMEX WTI prompt month oil settlement price is a widely used benchmark in the pricing of domestic oil in the United States. The actual prices we realize from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the Gulf of Mexico Basin’s proximity to U.S. Gulf Coast refineries and the quality of the oil production sold in Eugene Island Crude, Louisiana Light Sweet Crude and Heavy Louisiana Sweet Crude markets.

The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hub monthly contract prices as well as our average realized oil, natural gas, and NGL sales prices for the periods indicated.

	Year Ended December 31,
	2019			2018			2017
Oil:
NYMEX WTI High per Bbl	$	63.86		$	70.98		$	57.88
NYMEX WTI Low per Bbl	$	51.38		$	49.52		$	45.18
Average NYMEX WTI per Bbl	$	56.98		$	65.23		$	50.80
Average Oil Sales Price per Bbl (including commodity derivatives)	$	59.23		$	57.12		$	52.46
Average Oil Sales Price per Bbl (excluding commodity derivatives)	$	60.17		$	66.42		$	48.92
Natural Gas:
NYMEX Henry Hub High per MMBtu	$	3.11		$	4.09		$	3.30
NYMEX Henry Hub Low per MMBtu	$	2.22		$	2.67		$	2.82
Average NYMEX Henry Hub per MMBtu	$	2.56		$	3.15		$	2.99
Average Natural Gas Sales Price per Mcf (including commodity derivatives)	$	2.55		$	3.16		$	2.93
Average Natural Gas Sales Price per Mcf (excluding commodity derivatives)	$	2.37		$	3.23		$	3.00
NGLs:
NGL Realized Price as a % of Average NYMEX WTI		28	%		47	%		46	%

To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, from time to time we enter into commodity derivative arrangements for our anticipated production. By removing a significant portion of price volatility associated with our anticipated production, we believe it will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, our price risk management activity may also reduce our ability to benefit from increases in prices. We will sustain losses to the extent our commodity derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our commodity derivatives contract prices are higher than market prices.

We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different from what we have done on a historical basis.

Expenses

Lease operating expense — Lease operating expense consists of the daily costs incurred to bring oil, natural gas and NGLs out of the underground formation and to the market, together with the daily costs incurred to maintain our producing properties. Expenses for direct labor, insurance, the HP-I lease, materials and supplies, rental and third party costs comprise the most significant portion of our lease operating expense. It further consists of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Because the amount of workover and maintenance expense is closely correlated to the levels of workover activity, which is not regularly scheduled, workover and maintenance expense is not necessarily comparable from period to period.

Production taxes — Production taxes consist of severance taxes levied by the Louisiana Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of Louisiana.

Depreciation, depletion and amortization expense — Depreciation, depletion and amortization expense is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. See Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for further discussion.

Accretion expense — We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to replace, remove or retire the associated assets. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values.

General and administrative expense — General and administrative expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity based compensation expense, audit and other fees for professional services and legal compliance.

Interest expense — We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Bank Credit Facility and term based debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory projects that are not subject to current amortization.

Price risk management activities — We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

Results of Operations

Revenue

The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,						Change
	2019		2018		2017		2019 vs. 2018			2018 vs. 2017
Revenues:
Oil	$	833,118	$	781,815	$	344,781	$	51,303		$	437,034
Natural gas		55,278		73,610		48,886		(18,332	)		24,724
NGL		19,668		35,863		16,658		(16,195	)		19,205
Other		19,556		—		2,503		19,556			(2,503	)
Total revenue	$	927,620	$	891,288	$	412,828	$	36,332		$	478,460

Total Production Volumes:
Oil (MBbls)		13,847		11,771		7,048		2,076			4,723
Natural gas (MMcf)		23,306		22,771		16,308		535			6,463
NGL (MBbls)		1,228		1,176		706		52			470
Total production volume (MBoe)		18,959		16,742		10,472		2,217			6,270

Daily Production Volumes by Product:
Oil (MBblpd)		37.9		32.2		19.3		5.7			12.9
Natural gas (MMcfpd)		63.9		62.4		44.7		1.5			17.7
NGL (MBblpd)		3.4		3.2		1.9		0.2			1.3
Total production volume (MBoepd)		52.0		45.9		28.7		6.1			17.2

Average sale price per unit:
Oil (per Bbl)	$	60.17	$	66.42	$	48.92	$	(6.25	)	$	17.50
Natural gas (per Mcf)	$	2.37	$	3.23	$	3.00	$	(0.86	)	$	0.23
NGL (per Bbl)	$	16.02	$	30.50	$	23.59	$	(14.48	)	$	6.91
Price per Boe	$	47.90	$	53.24	$	39.18	$	(5.34	)	$	14.06
Price per Boe (including realized commodity derivatives)	$	47.43	$	46.60	$	41.46	$	0.83		$	5.14

The information below provides an analysis of the change in our oil, natural gas and NGL revenues, due to changes in sales prices and production volumes for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	2019 vs. 2018								2018 vs. 2017
	Price			Volume		Total			Price		Volume		Total
Oil	$	(86,582	)		137,885	$	51,303		$	205,985		231,049	$	437,034
Natural gas	$	(20,061	)		1,729	$	(18,332	)	$	5,335		19,389	$	24,724
NGL	$	(17,776	)		1,581	$	(16,195	)	$	8,118		11,087	$	19,205
Total	$	(124,419	)		141,195	$	16,776		$	219,438		261,525	$	480,963

2019 vs. 2018 Volumetric Analysis — Revenue increased due to production volumes attributable to an increase of 6.3 MBoed due to the Stone Combination and 3.4 MBoed from the Tornado 3 well and Boris 3 well in the Phoenix Field that were completed and commenced production during the second quarter of 2019. The increase in production volumes was partially offset by a reduction of 3.3 MBoed resulting from the shut-in of the HP-I for regulatory-mandated dry-dock.

2018 vs. 2017 Volumetric Analysis — Revenue increased due to production volumes, which was attributable to 15.9 MBoed from the Stone Combination and the Whistler Acquisition collectively, and 3.2 MBoed from the Tornado 2 well in the Phoenix Field which commenced initial production in December 2017. The increase in production was partially offset by unplanned third party downtime.

Expenses

Lease Operating Expense

The following table highlights lease operating expense items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results for the years ended December 31, 2019, 2018 and 2017 (in thousands, except per Boe data):

	Year Ended December 31,
	2019		2018		2017
Lease operating expenses	$	243,427	$	226,291	$	152,748
Lease operating expenses per Boe	$	12.84	$	13.52	$	14.59

2019 vs. 2018 — Total lease operating expense for the year ended December 31, 2019 increased by approximately $17.1 million, or 8%. This increase was primarily related to $8.9 million of lease operating expense in connection with the Stone Combination and $9.7 million of lease operating expense in connection with the Whistler Acquisition, offset by a $1.3 million decrease in reimbursements from our production handling agreements. While total lease operating expense increased, lease operating expense per Boe decreased $0.68 per Boe to $12.84 per Boe as a result of increased deepwater production from the Stone Combination and increased production in the Phoenix Field.

2018 vs. 2017 — Total lease operating expense for the year ended December 31, 2018 increased by approximately $73.5 million, or 48%. This increase was primarily related to $56.6 million of lease operating expense in connection with the Stone Combination and $3.2 million of lease operating expense in connection with the Whistler Acquisition. In addition, lease operating expense increased due to a more competitive offshore environment and non-recurring workovers of $15.9 million, offset by an $8.7 million increase in PHA reimbursements. While total lease operating expense has increased, lease operating expense decreased $1.07 per Boe to $13.52 per Boe as a result of increased deepwater production from the Stone Combination and increased production in the Phoenix Field.

Depreciation, Depletion and Amortization

The following table highlights depreciation, depletion and amortization items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results for the years ended December 31, 2019, 2018 and 2017 (in thousands, except per Boe data):

	Year Ended December 31,
	2019		2018		2017
Depreciation, depletion and amortization	$	345,931	$	288,719	$	157,352
Depreciation, depletion and amortization per Boe	$	18.25	$	17.25	$	15.03

2019 vs. 2018 — Depreciation, depletion and amortization expense for the year ended December 31, 2019 increased by approximately $57.2 million, or 20%. This increase was primarily due to a $0.98 per Boe, or 6%, increase in the depletion rate on our proved oil and natural gas properties during the year ended December 31, 2019. Depletion on a per Boe basis increased primarily due to a decrease in proved properties related to well performance in the Phoenix Field.

2018 vs. 2017 — Depreciation, depletion and amortization expense for the year ended December 31, 2018 increased by approximately $131.4 million or 83%. This increase was primarily due to a $2.22 per Boe, or 15%, increase in the depletion rate on our proved oil and natural gas properties during the year ended December 31, 2018. Depletion on a per Boe basis increased primarily due to an increase in proved properties related to the Stone Combination and higher estimated future development costs related to proved undeveloped reserves in the Phoenix Field.

General and Administrative Expense

The following table highlights general and administrative expense items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results for the years ended December 31, 2019, 2018 and 2017 (in thousands, except per Boe data):

	Year Ended December 31,
	2019		2018		2017
General and administrative expense	$	77,209	$	85,816	$	36,673
General and administrative expense per Boe	$	4.07	$	5.13	$	3.50

2019 vs. 2018 — General and administrative expense for the year ended December 31, 2019, decreased by approximately $8.6 million, or 10%. The change is attributable to a decrease of $29.2 million in transaction related costs primarily related to the Stone Combination incurred in 2018, partially offset by an increase of $12.4 million in employee and contract related costs and $5.9 million in other administrative costs, the majority of which are attributable to expenses related to additional professional services, information technology and compliance that were incurred subsequent to the Stone Combination. On a per unit basis, general and administrative expense decreased $1.06 per Boe.

2018 vs. 2017 — General and administrative expense for the year ended December 31, 2018, increased by approximately $49.1 million, or 134%. This increase was primarily attributable to $29.2 million in transaction related costs related to the Stone Combination and $16.4 million in additional payroll cost and additional general and administrative expenses as a result of the combined company.

Other Income and Expense

The following table highlights other income and expense items in total. The information below provides the financial results and an analysis of significant variances in these results for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018			2017
Write-down of oil and natural gas properties	$	12,221		$	—		$	—
Accretion expense	$	34,389		$	35,344		$	19,295
Price risk management activities income (expense)	$	(95,337	)	$	60,435		$	(27,563	)
Income tax benefit (expense)	$	36,141		$	(2,922	)	$	—

2019 vs. 2018 —

Write down of oil and natural gas properties — During the year ended December 31, 2019, we recorded a $12.2 million impairment. The impairment is a result of our evaluation of unproved property located in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from exploratory wells drilled and demobilized during the second and third quarter of 2019 and the Block 2 PCS’s expiration date.

Price risk management activities — Price risk management activities for year ended December 31, 2019, increased by approximately $155.8 million, or 258%. The expense of $95.3 million for the year ended December 31, 2019 consists of $8.8 million in cash settlement losses and $86.5 million in non-cash losses from the decrease in the fair value of our open derivative contracts. The income of $60.4 million for the year ended December 31, 2018 consists of $171.6 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $111.1 million in cash settlement losses. These unrealized gains on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our consolidated statements of operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through 2021, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

2018 vs. 2017 —

Price risk management activities — Price risk management activities for the year ended December 31, 2018, decreased by approximately $88.0 million or 319%. The income of $60.4 million for the year ended December 31, 2018 consists of $171.6 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $111.1 million in cash settlement losses. The expense of $27.6 million for the year ended December 31, 2017 consists of a $51.4 million in non-cash losses from the decrease in the fair value of our open derivatives contracts offset by cash settlement gains of $23.8 million. These unrealized gains on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our consolidated statements of operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through 2019, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 12 — Commitments and Contingencies. Additionally, we are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on our financial condition. See Part I, Item 3. Legal Proceedings for additional information.

Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims, employment related disputes and civil penalties by regulators. In the opinion of our management, none of these other pending litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operation. See Part I, Item 3. Legal Proceedings for additional information.

Supplemental Non-GAAP Measure

EBITDA and Adjusted EBITDA

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

We define these as the following:

EBITDA — Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense.

Adjusted EBITDA — EBITDA plus non-cash write-down of oil and natural gas properties, loss on debt extinguishment, transaction related costs, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), non-cash (gain) loss on sale of assets, non-cash write-down of other well equipment inventory and non-cash equity based compensation expense.

The following tables present a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):

	Year Ended December 31,
	2019			2018			2017
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	58,729		$	221,540		$	(62,868	)
Interest expense		97,847			90,114			80,934
Income tax expense (benefit)		(36,141	)		2,922			—
Depreciation, depletion and amortization		345,931			288,719			157,352
Accretion expense		34,389			35,344			19,295
EBITDA		500,755			638,639			194,713
Write-down of oil and natural gas properties		12,221			—			—
Loss on debt extinguishment		132			1,764			—
Transaction related costs		7,460			32,484			9,652
Derivative fair value (gain) loss⁽¹⁾		95,337			(60,435	)		27,563
Net cash receipts (payments) on settled derivative instruments⁽¹⁾		(8,820	)		(111,147	)		23,834
Non-cash gain on sale of assets		—			(1,710	)		—
Non-cash write-down of other well equipment inventory		165			244			260
Non-cash equity-based compensation expense		6,964			2,893			875
Adjusted EBITDA	$	614,214		$	502,732		$	256,897

⁽¹⁾

The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on a cash basis during the period the derivatives settled.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. As of December 31, 2019, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $673.4 million.

We fund exploration and development activities primarily through operating cash flows, cash on hand, and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2019 (in thousands):

U.S. drilling & completions	$	284,900
Mexico appraisal & exploration		65,968
Asset management		57,787
Seismic and G&G, land, capitalized G&A and other⁽¹⁾		61,721
Total capital expenditures		470,376
Plugging & abandonment		75,331
Total capital expenditures and plugging & abandonment	$	545,707

⁽¹⁾	Amount excludes $6.0 million of non-cash share-based awards.

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our board approved 2020 capital spending project of $520.0 million to $545.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, raising debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding debt.

Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

	Year Ended December 31,
	2019			2018			2017
Operating activities	$	393,733		$	263,445		$	176,053
Investing activities	$	(495,956	)	$	37,495		$	(157,641	)
Financing activities	$	48,083		$	(193,211	)	$	(18,412	)

Operating Activities — Net cash provided by operating activities increased $130.3 million in 2019 from 2018 primarily attributable to a decrease in cash payments on derivatives of $102.3 million and decrease in settlements of asset retirement obligations of $37.6 million. Net cash provided by operating activities increased $87.4 million from 2018 to 2017 primarily attributable to an increase in revenue offset by a decrease in cash settlements on derivatives and transaction related cost related to the Stone Combination.

Investing Activities — Net cash used in investing activities increased $533.5 million in 2019 from 2018 primarily due to our payment of $37.9 million for acquisitions during 2019 compared to receiving $278.4 million in cash resulting from acquisitions in 2018. Additionally, we had an increase of $206.3 million in capital expenditures. The increase of $195.1 million in net cash provided by investing activities from 2018 to 2017 is primarily attributable to $280.9 million of cash received from the Stone Combination and Whistler Acquisition, partially offset by an increase of $85.7 million in capital expenditures.

Financing Activities — Net cash provided by financing activities increased $241.3 million in 2019 from 2018 primarily attributable to receiving net proceeds of approximately $75.1 million from the Bank Credit Facility and other obligations, partially offset by repayments of $10.6 million for the Building Loan during 2019 compared to net repayments of approximately $163.3 million for 2018. Net cash used in financing activities increased $174.8 million in 2018 from 2017 primarily attributable to the repayment of $403.0 million related to the LLC Bank Credit Facility, $54.0 million related to the repayment of the Bank Credit Facility, $25.3 million related to the redemption of our 2018 Senior Notes and other long-term debt, $17.0 million in deferred financing cost, partially offset by proceeds received from the Bank Credit Facility of $319.0 million.

Financing Arrangements — As of December 31, 2019, total debt, net of discount and deferred financing costs, was approximately $733.0 million, comprised of our $383.9 million aggregate principal amount of the 11.00% Notes due 2022 and $6.1 million aggregate principal amount of our 7.50% Senior Notes due 2022 issued by Stone (“7.50% Notes”), and $343.1 million outstanding under our Bank Credit Facility. During June 2019, we repaid $10.4 million in aggregate remaining principal and accrued interest on the Stone 4.20% term loan maturing on November 20, 2030. We were in compliance with all debt covenants at December 31, 2019. For additional details on our debt, see Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 7 — Debt.

Bank Credit Facility – matures May 2022 — The Company maintains a Bank Credit Facility with a syndicate of financial institutions, with a borrowing base of $950.0 million as of December 31, 2019. The Bank Credit Facility matures on May 10, 2022, provided that the Bank Credit Facility mandates a springing maturity that is 120 days prior to May 10, 2022, if greater than $25.0 million of the 11.00% Notes or any permitted refinancing indebtedness in respect thereof is outstanding on such date.

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, we are obligated to pay a commitment fee of 0.50% on the unfunded portion of the commitments. The Bank Credit Facility has certain debt covenants, the most restrictive of which requires that we maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 each quarter. We must also maintain a current ratio no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, undrawn commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all of our oil and natural gas assets. The Bank Credit Facility is fully and unconditionally guaranteed by us and certain of our wholly-owned subsidiaries.

The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our PUD reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year.

On July 3, 2019, the Company entered into a Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement in which, (a) the $850.0 million borrowing base was reaffirmed, (b) the commitments were increased from $600.0 million to $850.0 million and (c) certain other amendments were made to the Bank Credit Facility as more particularly described therein.

On December 10, 2019, the Company entered into a Joinder, Commitment Increase Agreement, Second Amendment to Credit Agreement, Borrowing Base Redetermination Agreement, and Amendment to Other Credit Documents in which (a) the borrowing base was increased from $850.0 million to $950.0 million, (b) the commitments were increased from $850.0 million to $950.0 million and (c) certain other amendments were made to the Bank Credit Facility as more particularly described therein. Upon closing of the ILX and Castex Acquisition, the borrowing base was increased from $950.0 million to $1.15 billion and the commitments were increased from $950.0 million to $1.15 billion.

As of December 31, 2019, commitments under our borrowing base were set at $950.0 million, of which no more than $200 million can be used as letters of credit. The amount that we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2019. As of December 31, 2019, the Bank Credit Facility had approximately $586.4 million of undrawn commitments (taking into account $13.6 million letters of credit and $350.0 million drawn from the Bank Credit Facility).

11.00% Second-Priority Senior Secured Notes—due April 2022 — The 11.00% Notes were issued pursuant to an indenture dated May 10, 2018, between the Talos Issuers, the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 11.00% Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15.

7.50% Senior Notes—due May 2022 — The 7.50% Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Notes pursuant to the exchange offer and consent solicitation, and thus remain outstanding. As a result of the Exchange Offer and Consent Solicitation, substantially all of the restrictive covenants relating to the 7.50% Notes have been removed and collateral securing the 7.50% Notes has been released. The 7.50% Notes mature May 31, 2022 and have interest payable semiannually each May 31 and November 30.

Building Loan—matures November 2030 — In connection with the Stone Combination, the Company assumed Stone’s 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million. During June 2019, the Company repaid $10.4 million aggregate remaining principal, plus accrued interest, of the Building Loan using proceeds from the sale of an office building in Lafayette acquired in the Stone Combination and cash on hand. As of December 31, 2019, there is no outstanding balance under the Building Loan.

Performance Bonds — As of December 31, 2019, we had secured performance bonds primarily related to plugging and abandonment of wells and removal of facilities in the United States Gulf of Mexico and to guarantee the completion of the minimum work program under the Mexico production sharing contracts totaling approximately $637.3 million. In July 2016, BOEM issued the 2016 NTL to clarify the procedures and guidelines BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs and RUEs to meet BOEM’s estimate of the lessees’ decommissioning obligations. The 2016 NTL became effective in September 2016 and allows qualifying operators to self-insure for an amount up to 10% of their tangible net worth. The 2016 NTL also provides for operators to propose a tailored plan subject to BOEM approval that allows the posting of additional financial assurance over time. However, BOEM has indefinitely delayed beyond June 30, 2017 implementation of the 2016 NTL, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, to allow BOEM time to reconsider a number of regulatory initiatives. We received notice from BOEM in late 2016 ordering us to provide additional financial assurances in the form of additional security in material amounts. We entered into discussions with BOEM regarding the requested security and submitted a proposed tailored plan for the posting of additional financial security to the agency for review. However, as noted, BOEM has indefinitely delayed implementation beyond June 30, 2017 of the 2016 NTL, has rescinded the late December 2016 orders while BOEM reviews its financial assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored plan. We remain in active discussion with our government regulators and industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding the 2016 NTL, BOEM may also increase its financial assurance requirements mandated by rule for all companies operating in federal waters. BOEM could also make new demands for additional financial security in material amounts in the event the agency chooses to implement the 2016 NTL, and such amounts may be material and exceed our capability to provide additional financial assurance. The future cost of compliance with our existing supplemental bonding requirements, including with respect to any tailored plan, the 2016 NTL, as well as any other future directives or any other changes to BOEM’s rules applicable to us or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows and results of operations.

Off Balance Sheet Arrangements

We did not have any off balance sheet arrangements as of December 31, 2019.

Contractual Obligations

We are party to various contractual obligations. Some of these obligations may be reflected in our accompanying consolidated financial statements, while other obligations, such as operating leases and capital commitments, are not reflected on our accompanying consolidated financial statements.

The following table and discussion summarizes our contractual cash obligations as of December 31, 2019 (in thousands):

	2020		2021		2022		2023		Thereafter		Total⁽⁵⁾
Long-term financing obligations:
Debt Principal	$	—	$	—	$	746,928	$	—	$	—	$	746,928
Debt Interest		55,325		55,325		15,432		—		—		126,082
Vessel Commitments ⁽¹⁾		28,260		—		—		—		—		28,260
Derivative liabilities		19,476		511		—		—		—		19,987
Operating Lease Obligations		2,744		4,079		4,302		4,239		19,105		34,469
Capital lease ⁽²⁾		45,000		45,000		45,000		18,750		—		153,750
Purchase Obligations⁽³⁾		61,434		—		—		—		—		61,434
Other Liabilities ⁽⁴⁾		14,921		7,921		—		—		—		22,842
Total contractual obligations⁽⁵⁾	$	227,160	$	112,836	$	811,662	$	22,989	$	19,105	$	1,193,752

⁽¹⁾

Includes vessel commitments we will utilize for certain deep water well intervention and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs. Includes commitments for drilling rigs and Helix’s Q4000 well intervention vessel we will utilize for certain deep water well intervention and decommissioning activities.

⁽²⁾	Lease agreement for the HP-I floating production facility in the Phoenix Field.

⁽³⁾	Includes committed purchase orders to execute planned future drilling and completion activities.

⁽⁴⁾	Includes seismic use agreements of $19.8 million as of December 31, 2019.

⁽⁵⁾

This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $369.5 million as of December 31, 2019. For additional information regarding these liabilities, please see Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 4 — Property, Plant and Equipment.

Performance Bonds — As of December 31, 2019 and 2018, we had secured performance bonds primarily related to P&A of wells and removal of facilities and executing the minimum work program under the PSCs totaling approximately $637.3 million and $644.1 million, respectively. As of December 31, 2019 and 2018, we had $13.6 million and $14.7 million, respectively, in letters of credit issued under our Bank Credit Facility and our previous credit facility primarily for the P&A of wells and the removal of facilities.

For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 12 — Commitments and Contingencies.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense, and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates. Our significant accounting policies that have been implemented or changed since December 31, 2017 are described in Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

Oil and Natural Gas Properties — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. Capitalized overhead for the years ended December 31, 2019, 2018 and 2017 was $28.2 million, $21.9 million and $13.7 million, respectively.

The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash impairment expense on the consolidated statements of operations and an increase to accumulated depreciation, depletion and amortization on the Company’s consolidated balance sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.

Proved Reserve Estimates — We estimate our proved oil, natural gas and NGL reserves in accordance with the guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC pricing.

Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. The estimates of proved reserves are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments.

Fair Value Measure of Financial Instruments — Our financial instruments generally consisted of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt as of December 31, 2019. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

Fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value as an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

Level 1—Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2—Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.

Level 3—Inputs to the valuation methodology are unobservable (little or no market data), which require us to develop our own assumptions, and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

Market Approach—Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

Cost Approach—Amount that would be required to replace the service capacity of an asset (replacement cost).

Income Approach—Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate in the table below represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in the Company’s consolidated statements of operations. If the Company incurs an amount different from the amount accrued for decommissioning obligations, the Company recognizes the difference as an adjustment to proved properties.

Revenue Recognition, Imbalances and Production Handling Fees — With the adoption of Accounting Standards Codification (“ASC”) 606 in 2018, revenues are recorded based from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred.

Prior to the adoption in 2018, we used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on our entitled share of production with any difference recorded as an imbalance on the consolidated balance sheet. Upon the adoption of ASC 606 in 2018, revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. The change in accounting method from the entitlements method to the sales method resulted in an immaterial cumulative-effect adjustment to members’ deficit on the date of adoption. Our imbalances are recorded gross on our consolidated balance sheets. At December 31, 2019, our imbalance receivable was approximately $1.7 million and imbalance payable was approximately $3.6 million. At December 31, 2018, our imbalance receivable was approximately $1.7 million and imbalance payable was approximately $2.5 million.

Prior to the adoption in 2018, we presented certain reimbursements for costs from certain third parties as other revenue on the consolidated statements of operations. Upon the adoption of ASC 606 in 2018, the reimbursements are presented as a reduction of lease operating expense on the consolidated statements of operations. The impact of the reclassification for the year ended December 31, 2019 was immaterial.

Income Taxes — Our provision for income taxes includes U.S. state and federal and foreign taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2019, we believe it is more likely than not that the federal and state deferred tax asset will be realized and therefore recorded as a full-release in our federal valuation allowance and as a significant portion of our state valuation allowance. We maintain a valuation allowance on most of our Mexico deferred tax assets.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Recently Adopted Accounting Standards

See Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 1 — Formation and Basis of Presentation to the consolidated financial statements included elsewhere in this report for our Recently Adopted Accounting Standards.

Recently Issued Accounting Standards

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are currently exposed to market risk in two areas: commodity prices and, to a lesser extent, interest rate risk. Our risk management activities involve the use of derivative financial instruments to mitigate the impact of market price risk exposures primarily related to our oil and natural gas production. All derivatives are recorded on the consolidated balance sheet at fair value with settlements of such contracts and changes in the unrealized fair value recorded as price risk management activities income (expense) on the consolidated statements of operations in each period.

Commodity Price Risks

Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and cash flow. During year ended December 31, 2019, our average oil price realizations after the effect of derivatives increased 4% to $59.23 per Bbl from $57.12 per Bbl in the comparable 2018 period. Our average natural gas price realizations after the effect of derivatives decreased 19% during the year ended December 31, 2019 to $2.55 per Mcf from $3.16 per Mcf in the comparable 2018 period.

Price Risk Management Activities

We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production through the use of oil and natural gas swaps. These contracts will impact our earnings as the fair value of these derivatives changes. Our derivatives will not mitigate all of the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production.

We had commodity derivative instruments in place to reduce the price risk associated with future production of 9,638 MBbls of crude oil and 5,935 MMBtu of natural gas at December 31, 2019, with a net derivative liability position of $11.6 million. For additional information regarding our commodity derivative instruments, see Part IV, Item 15. Exhibits, Financial Statement Schedules — Note 6 — Financial Instruments, included elsewhere in this report. The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at December 31, 2019 (in thousands):

				Oil and Natural Gas Derivatives
				10 Percent Increase				10 Percent Decrease
	Fair Value			Fair Value		Change		Fair Value			Change
Price impact⁽¹⁾	$	(11,594	)	$	37,008	$	48,602	$	(60,691	)	$	(49,097	)

⁽¹⁾	Presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from changes in oil and natural gas prices.

Variable Interest Rate Risks

We had total debt outstanding of $733.0 million at December 31, 2019, net of unamortized original issue discount and deferred financing costs. Of this, $389.9 million was from our 11.00% Notes and 7.50% Notes, which bear interest at fixed rates. The remaining $343.1 million is from borrowings under our Bank Credit Facility with variable interest rates. We are subject to the risk of changes in interest rates under our Bank Credit Facility. In addition, the terms of our Bank Credit Facility require us to pay higher interest rates as we utilize a larger percentage of our available borrowing base. We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates. We believe our interest rate risk exposure is partially mitigated as a result of fixed interest rates on 53% of our debt. The interest rate on our variable rate debt at December 31, 2019 was 4.79%. A 10% change in the interest rate on this variable rate debt balance at December 31, 2019 would change interest expense for the year ended December 31, 2019 by approximately $0.6 million.

Item 8. Financial Statements and Supplementary Data

See the Consolidated Financial Statements and Report of Independent Registered Public Accounting Firm as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017, included in Part IV, Item 15. Exhibits, Financial Statements Schedules.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Based on such evaluation, our chief executive officer and chief financial officer have concluded that as of December 31, 2019, our disclosure controls and procedures are designed at a reasonable assurance level and are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of SEC, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Management conducted an assessment of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on the assessment, management has concluded that its internal control over financial reporting was effective as of December 31, 2019 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with U.S. GAAP. Our independent registered public accounting firm, Ernst & Young LLP, has issued an audit report with respect to our internal control over financial reporting, which is included in this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the fourth quarter of 2019 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The information required by this item is incorporated by reference to our Proxy Statement for the 2020 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2019.

Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors and employees, which is available on our website (www.talosenergy.com) under “Corporate Governance and Board Committees.” We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our Code of Business Conduct and Ethics by posting such information on the website address and location specified above.

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accounting Fees and Services

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) 1

Financial Statements

Refer to the Index to Consolidated Financial Statements on page F-1 for a list of all financial statements filed as part of this Annual Report on Form 10-K.

(a) 2

Financial Statement Schedules

Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in our Consolidated Financial Statements and related notes.

(a) 3

Exhibits:

Exhibit Number		Description

2.1#		Transaction Agreement, dated as of November 21, 2017, by and among Stone Energy Corporation, Sailfish Energy Holdings Corporation, Sailfish Merger Sub Corporation, Talos Energy LLC and Talos Production LLC (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

2.2#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings, LLC (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

2.3		Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings LLC (incorporated by reference to Exhibit 2.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

2.4#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings II, LLC (incorporated by reference to Exhibit 2.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

2.5		Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings II LLC (incorporated by reference to Exhibit 2.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

2.6#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings III LLC (incorporated by reference to Exhibit 2.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

2.7		Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings III LLC (incorporated by reference to Exhibit 2.6 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

2.8#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and Castex Energy 2014, LLC (incorporated by reference to Exhibit 2.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

2.9		Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and Castex Energy 2014, LLC (incorporated by reference to Exhibit 2.8 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

2.10#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and Castex Energy 2016, LP (incorporated by reference to Exhibit 2.5 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

Exhibit Number		Description

3.1		Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

3.2		Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

3.3		Certificate of Designation, dated as of February 27, 2020 (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020).

4.1		Form of Stock Certificate for Common Stock of Talos Energy Inc. (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).

4.2		Indenture, dated as of May 10, 2018, by and among Talos Production LLC, Talos Production Finance, Inc., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.5 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

4.3		Supplemental Indenture No. 1, dated as of September 12, 2018, by and among Talos Production LLC, Talos Production Finance, Inc., Talos Energy Inc. and Wilmington Trust, National Association, as trustee and collateral agent. (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Registration Statement on Form S-4 (File No. 333-227362) filed with the SEC on September 14, 2018).

4.4		Registration Rights Agreement, dated as of May 10, 2018, by and among Talos Production LLC, Talos Production Finance, Inc., the subsidiary guarantors named therein and each of the holders set forth on the signature pages thereto (incorporated by reference to Exhibit 4.6 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

4.5		Form of 11.00% Second-Priority Senior Secured Note due 2022 (included in Exhibit 4.2).

4.6		Stockholders’ Agreement, dated as of May 10, 2018, by and among Talos Energy Inc. and each of the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

4.7		Stockholders’ Agreement Amendment, dated as of February 24, 2020, by and among Talos Energy Inc. and each of the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

4.8		Registration Rights Agreement, dated as of May 10, 2018, by and among Talos Energy Inc. and each of the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

4.9		Registration Rights Agreement Amendment, dated as of February 28, 2020, by and among Talos Energy Inc. and each of the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020).

4.10		Warrant Agreement, dated as of February 28, 2017, by and among Stone Energy Corporation, Computershare Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

4.11		Amendment No. 1 to Warrant Agreement, dated as of May 10, 2018, by and among Talos Energy Inc., Stone Energy Corporation, Computershare Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Exhibit Number		Description

4.12*		Description of Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934.

10.1		Credit Agreement, dated as of May 10, 2018, by and among Talos Production LLC, as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders named therein (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K12B/A filed with the SEC on July 18, 2018).

10.2		Intercreditor Agreement, dated as of May 10, 2018, between JPMorgan Chase Bank, N.A., as First Lien Agent, and Wilmington Trust, National Association, as Second Lien Agent (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.3†		Separation and Release Agreement, dated as of January 22, 2020, between Stephen E. Heitzman and Talos Energy Operating Company LLC (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 23, 2020).

10.4†		Transition, Separation and Release Agreement between Michael L. Harding II and Talos Energy Operating Company LLC, dated as of June 18, 2019 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on June 19, 2019).

10.5†		Offer Letter between Talos Energy Inc. and Shannon Young, dated as of April 13, 2019 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on April 24, 2019).

10.6†		Offer Letter between Talos Energy Inc. and Robert D. Abendschein, dated as of December 26, 2019 (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 23, 2020).

10.7†		Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating Company LLC and Timothy S. Duncan (incorporated by reference to Exhibit 10.10 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

10.8†		Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating Company LLC and Stephen E. Heitzman (incorporated by reference to Exhibit 10.11 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

10.9†		Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating Company LLC and John A. Parker (incorporated by reference to Exhibit 10.12 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

10.10†		Employment Agreement, dated as of March 14, 2016, by and between Talos Energy Operating Company LLC and Michael L. Harding II (incorporated by reference to Exhibit 10.13 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

10.11†		Employment Agreement, dated as of August 30, 2013, by and between Talos Energy Operating Company LLC and William S. Moss III (incorporated by reference to Exhibit 10.14 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

10.12†		Talos Energy Inc. Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Exhibit Number		Description

10.13		Voting Agreement, dated as of November 21, 2017, by and among Talos Energy LLC, Stone Energy Corporation, Franklin Advisers, Inc., as investment manager on behalf of the company stockholders listed therein and, solely for purposes of Section 11, Franklin Advisers, Inc., as investment manager on behalf of JNL/Franklin Templeton Income Fund and FT Opportunistic Destressed Fund, LTD. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).

10.14		Voting Agreement, dated as of November 21, 2017, by and among Talos Energy LLC, Stone Energy Corporation and MacKay Shields LLC, in its capacity as investment manager on behalf of certain of its clients and, to the extent expressly set forth therein, in its individual capacity (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).

10.15		Support Agreement, dated as of November 21, 2017, by and among Stone Energy Corporation, Sailfish Energy Holdings Corporation, Apollo Management VII, L.P., Apollo Commodities Management, L.P., with respect to Series I, and Riverstone Energy Partners V, L.P. (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).

10.16		Exchange Agreement, dated as of November 21, 2017, by and among Talos Production LLC, Talos Production Finance Inc., Stone Energy Corporation, Sailfish Energy Holdings Corporation and the lenders and noteholders listed on the schedules thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.17		Contract for the Exploration and Extraction of Hydrocarbons under Production Sharing Modality (Contract Area 2), dated as of September 4, 2015, by and among the National Hydrocarbons Commission, Sierra O&G Exploración y Producción, S. de R.L. de C.V., Talos Energy Offshore México 2, S. de R.L. de C.V. and Premier Oil Exploration and Production Mexico, S.A. de C.V. (incorporated by reference to Exhibit 10.8 to Talos Energy Inc.’s Amendment No. 2 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 15, 2018).

10.18		Contract for the Exploration and Extraction of Hydrocarbons under Production Sharing Modality (Contract Area 7), dated as of September 4, 2015, by and among the National Hydrocarbons Commission, Sierra O&G Exploración y Producción, S. de R.L. de C.V., Talos Energy Offshore México 7, S. de R.L. de C.V. and Premier Oil Exploration and Production Mexico, S.A. de C.V. (incorporated by reference to Exhibit 10.9 to Talos Energy Inc.’s Amendment No. 4 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on April 4, 2018).

10.19†		Indemnification Agreement (Timothy S. Duncan) (incorporated by reference to Exhibit 10.5 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.20†		Indemnification Agreement (Stephen E. Heitzman) (incorporated by reference to Exhibit 10.6 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.21†		Indemnification Agreement (John A. Parker) (incorporated by reference to Exhibit 10.7 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.22†		Indemnification Agreement (Michael L. Harding II) (incorporated by reference to Exhibit 10.8 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.23†		Indemnification Agreement (William S. Moss III) (incorporated by reference to Exhibit 10.9 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.24†		Indemnification Agreement (Olivia C. Wassenaar) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on November 23, 2018).

10.25†		Indemnification Agreement (Christine Hommes) (incorporated by reference to Exhibit 10.11 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Exhibit Number		Description

10.26†		Indemnification Agreement (Robert M. Tichio) (incorporated by reference to Exhibit 10.12 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.27†		Indemnification Agreement (Neal P. Goldman) (incorporated by reference to Exhibit 10.14 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.28†		Indemnification Agreement (John “Brad” Juneau) (incorporated by reference to Exhibit 10.15 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.29†		Indemnification Agreement (James M. Trimble) (incorporated by reference to Exhibit 10.16 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.30†		Indemnification Agreement (Charles M. Sledge) (incorporated by reference to Exhibit 10.17 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.31†		Indemnification Agreement (Donald R. Kendall, Jr.) (incorporated by reference to Exhibit 10.18 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.32†		Indemnification Agreement (Rajen Mahagaokar) (incorporated by reference to Exhibit 10.19 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.33†		Indemnification Agreement (Shannon E. Young III), effective as of May 16, 2019 (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K filed with the SEC on April 24, 2019).

10.34†		Indemnification Agreement (Robert D. Abendschein) (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K filed with the SEC on January 23, 2020).

10.35†		Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors) (incorporated by reference to Exhibit 10.20 to Talos Energy Inc.’s Form 10-Q filed with the SEC on August 9, 2018).

10.36†		Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.32 to Talos Energy Inc.’s Registration Statement on Form S-4 (File No. 333-227362) filed with the SEC on September 14, 2018)

10.37†		Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives) (incorporated by reference to Exhibit 10.33 to Talos Energy Inc.’s Registration Statement on Form S-4 (File No. 333-227362) filed with the SEC on September 14, 2018).

10.38†		Talos Energy Operating Company LLC Executive Severance Plan (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on September 5, 2018).

10.39†		Form of Participation Agreement pursuant to the Talos Energy Operating Company LLC Executive Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K filed with the SEC on September 5, 2018).

10.40		First Amendment Agreement to the Contract for the Exploration and Extraction of Hydrocarbons in the Form of Shared Production, dated as of August 8, 2018, between the National Hydrocarbons Commission and Talos Energy Offshore México 2, S. de R.L. de C.V., Premier Oil Exploration and Production México, S.A. de C.V., and Sierra Blanca P&D, S. de R.L. de C.V. (incorporated by reference to Exhibit 10.34 to Talos Energy Inc.’s Form 10-K (File No. 01-38497) filed with the SEC on March 13, 2019).

10.41		Second Amendment Agreement to the Contract for the Exploration and Extraction of Hydrocarbons in the Form of Shared Production, dated as of December 20, 2018, between the National Hydrocarbons Commission and Hokchi Energy, S.A. de C.V., Sierra Blanca P&D, S. de R.L. de C.V., Talos Energy Offshore México 2, S. de R.L. de C.V., and Premier Oil Exploration and Production México, S.A. de C.V. (incorporated by reference to Exhibit 10.35 to Talos Energy Inc.’s Form 10-K (File No. 01-38497) filed with the SEC on March 13, 2019).

Exhibit Number		Description

10.42		Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement, dated as of July 3, 2019, by and among Talos Energy Inc., as holdings, Talos Production LLC, as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender, and the lenders (including the new lenders) party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on July 10, 2019).

10.43		Joinder, Commitment Increase Agreement, Second Amendment to Credit Agreement, Borrowing Base Redetermination Agreement, and Amendment to Other Credit Documents, dated as of December 10, 2019, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender, and the lenders (including the new lenders) party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

21.1*		List of Subsidiaries of Talos Energy Inc.

23.1*		Consent of Ernst & Young LLP.

23.2*		Consent of Netherland, Sewell & Associates, Inc.

24.1*		Powers of Attorney (included on signature pages of this Part IV)

31.1*		Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.

99.1*		Netherland, Sewell & Associates, Inc. reserve report for Talos Energy Inc. as of December 31, 2019.

99.2		Netherland, Sewell & Associates, Inc. reserve report for Talos Energy Inc. as of December 31, 2018 (incorporated by reference to Exhibit 99.1 to Talos Energy Inc.’s Annual Report on Form 10-K (File No. 001-38497) filed with the SEC on March 13, 2019).

99.3		Netherland, Sewell & Associates, Inc. reserve report for Talos Energy LLC as of December 31, 2017 (incorporated by reference to Exhibit 99.12 to Talos Energy Inc.’s Amendment No. 2 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 15, 2018).

101.INS*		Inline XBRL Instance.

101.SCH*		Inline XBRL Taxonomy Extension Schema.

101.CAL*		Inline XBRL Taxonomy Extension Calculation.

101.DEF*		Inline XBRL Taxonomy Extension Definition.

101.LAB*		Inline XBRL Taxonomy Extension Label.

101.PRE*		Inline XBRL Taxonomy Extension Presentation.

104*		Cover Page Interactive Data File – The cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

*	Filed herewith.

**	Furnished herewith.

†	Identifies management contracts and compensatory plans or arrangements.

#	Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K, but will be furnished supplementally to the SEC upon request.

Item 16. Form 10-K Summary

None.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		TALOS ENERGY INC.

Date:	March 12, 2020	By:	/s/ Shannon E. Young III
			Shannon E. Young III
			Executive Vice President and Chief Financial Officer

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Timothy S. Duncan and Shannon E. Young III, and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming that all said attorneys-in-fact and agents, or any of them or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Timothy S. Duncan	Chief Executive Officer	March 12, 2020
Timothy S. Duncan	(Principal Executive Officer, Director)

/s/ Shannon E. Young III	Chief Financial Officer	March 12, 2020
Shannon E. Young III	(Principal Financial Officer, Authorized Signatory)

/s/ Rajen Mahagaokar	Director	March 12, 2020
Rajen Mahagaokar

/s/ James M. Trimble	Director	March 12, 2020
James M. Trimble

/s/ Olivia C. Wassenaar	Director	March 12, 2020
Olivia C. Wassenaar

/s/ Christine Hommes	Director	March 12, 2020
Christine Hommes

/s/ Neal P. Goldman	Director	March 12, 2020
Neal P. Goldman

/s/ Charles M. Sledge	Director	March 12, 2020
Charles M. Sledge

/s/ Robert M. Tichio	Director	March 12, 2020
Robert M. Tichio

/s/ John “Brad” Juneau	Director	March 12, 2020
John “Brad” Juneau

/s/ Donald R. Kendall, Jr.	Director	March 12, 2020
Donald R. Kendall, Jr.

Index to Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2019 and 2018	F-4
Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017	F-5
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the years ended December 31, 2019, 2018 and 2017	F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	F-7
Notes to Consolidated Financial Statements	F-8

F-1

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of

Talos Energy Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Talos Energy Inc. (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2019, and the related notes(collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 12, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2010.

Houston, Texas

March 12, 2020

F-2

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of

Talos Energy Inc.

Opinion on Internal Control Over Financial Reporting

We have audited Talos Energy Inc.’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Talos Energy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019 based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”) and our report dated March 12, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

March 12, 2020

F-3

TALOS ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

	Year Ended December 31,
	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	87,022		$	139,914
Restricted cash		—			1,248
Accounts receivable
Trade, net		107,842			103,025
Joint interest, net		16,552			20,244
Other		6,346			19,686
Assets from price risk management activities		8,393			75,473
Prepaid assets		65,877			38,911
Income tax receivable		116			10,701
Other current assets		1,836			7,644
Total current assets		293,984			416,846
Property and equipment:
Proved properties		4,066,260			3,629,430
Unproved properties, not subject to amortization		194,532			108,209
Other property and equipment		29,843			33,191
Total property and equipment		4,290,635			3,770,830
Accumulated depreciation, depletion and amortization		(2,065,023	)		(1,719,609	)
Total property and equipment, net		2,225,612			2,051,221
Other long-term assets:
Other well equipment inventory		7,732			9,224
Operating lease assets		7,779			—
Other assets		54,375			2,695
Total assets	$	2,589,482		$	2,479,986
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	71,357		$	51,019
Accrued liabilities		154,816			188,650
Accrued royalties		31,729			38,520
Current portion of long-term debt		—			443
Current portion of asset retirement obligations		61,051			68,965
Liabilities from price risk management activities		19,476			550
Accrued interest payable		10,249			10,200
Current portion of operating lease liabilities		1,594			—
Other current liabilities		20,180			22,071
Total current liabilities		370,452			380,418
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		732,981			654,861
Asset retirement obligations		308,427			313,852
Liabilities from price risk management activities		511			—
Operating lease liabilities		17,239			—
Other long-term liabilities		81,595			123,359
Total liabilities		1,511,205			1,472,490
Commitments and contingencies (Note 12)
Stockholders' Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2019 and December 31, 2018		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 54,197,004 and 54,155,768 shares issued and outstanding as of December 31, 2019 and December 31, 2018, respectively		542			542
Additional paid-in capital		1,346,142			1,334,090
Accumulated deficit		(268,407	)		(327,136	)
Total stockholders' equity		1,078,277			1,007,496
Total liabilities and stockholders' equity	$	2,589,482		$	2,479,986

The accompanying notes are an integral part of these consolidated financial statements.

F-4

TALOS ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share amounts)

	Year Ended December 31,
	2019			2018			2017
Revenues:
Oil revenue	$	833,118		$	781,815		$	344,781
Natural gas revenue		55,278			73,610			48,886
NGL revenue		19,668			35,863			16,658
Other		19,556			—			2,503
Total revenue		927,620			891,288			412,828
Operating expenses:
Lease operating expense		243,427			226,291			152,748
Production taxes		1,349			1,989			1,460
Depreciation, depletion and amortization		345,931			288,719			157,352
Write-down of oil and natural gas properties		12,221			—			—
Accretion expense		34,389			35,344			19,295
General and administrative expense		77,209			85,816			36,673
Total operating expenses		714,526			638,159			367,528
Operating income		213,094			253,129			45,300
Interest expense		(97,847	)		(90,114	)		(80,934	)
Price risk management activities income (expense)		(95,337	)		60,435			(27,563	)
Other income		2,678			1,012			329
Net income (loss) before income taxes		22,588			224,462			(62,868	)
Income tax benefit (expense)		36,141			(2,922	)		—
Net income (loss)	$	58,729		$	221,540		$	(62,868	)

Net income (loss) per common share:
Basic	$	1.08		$	4.81		$	(2.01	)
Diluted	$	1.08		$	4.81		$	(2.01	)
Weighted average common shares outstanding:
Basic		54,185			46,058			31,244
Diluted		54,413			46,061			31,244

The accompanying notes are an integral part of these consolidated financial statements.

F-5

TALOS ENERGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

(In thousands, except share amounts)

						Additional						Total
	Common Stock					Paid- In			Accumulated			Stockholders
	Shares			Amounts		Capital			Deficit			Equity (Deficit)
Balance at January 1, 2017		31,244,085		$	312	$	492,157		$	(485,483	)	$	6,986
Equity based compensation		—			—		1,795			—			1,795
Net loss		—			—		—			(62,868	)		(62,868	)
Balance at December 31, 2017		31,244,085			312		493,952			(548,351	)		(54,087	)
Cumulative effect adjustment		—			—		—			(325	)		(325	)
Sponsor Debt Exchange		2,874,049			29		101,971			—			102,000
Stone Combination		20,037,634			201		731,763			—			731,964
Equity based compensation		—			—		6,404			—			6,404
Net income		—			—		—			221,540			221,540
Balance at December 31, 2018		54,155,768			542		1,334,090			(327,136	)		1,007,496
Equity based compensation		53,787			—		12,385			—			12,385
Shares withheld for taxes on equity transactions		(12,551	)		—		(333	)		—			(333	)
Net income		—			—		—			58,729			58,729
Balance at December 31, 2019		54,197,004		$	542	$	1,346,142		$	(268,407	)	$	1,078,277

The accompanying notes are an integral part of these consolidated financial statements.

F-6

TALOS ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities:
Net income (loss)	$	58,729		$	221,540		$	(62,868	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense		380,320			324,063			176,647
Write-down of oil and natural gas properties and other well inventory		12,386			244			260
Amortization of deferred financing costs and original issue discount		5,207			4,253			2,383
Equity based compensation, net of amounts capitalized		6,964			2,893			875
Price risk management activities expense (income)		95,337			(60,435	)		27,563
Net cash received (paid) on settled derivative instruments		(8,820	)		(111,147	)		23,834
Settlement of asset retirement obligations		(75,331	)		(112,946	)		(32,573	)
Changes in operating assets and liabilities:
Accounts receivable		5,788			(786	)		(9,132	)
Other current assets		(15,114	)		(2,624	)		(4,441	)
Accounts payable		7,523			(48,825	)		2,409
Other current liabilities		(35,459	)		32,044			46,364
Other non-current assets and liabilities, net		(43,797	)		15,171			4,732
Net cash provided by operating activities		393,733			263,445			176,053
Cash flows from investing activities:
Exploration, development and other capital expenditures		(463,409	)		(240,914	)		(155,177	)
Cash (paid for) received from acquisitions, net of cash acquired		(37,916	)		278,409			(2,464	)
Proceeds from sale of other property and equipment		5,369			—			—
Net cash provided by (used in) investing activities		(495,956	)		37,495			(157,641	)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt		(10,567	)		(25,257	)		(1,000	)
Proceeds from Bank Credit Facility		110,000			319,000			10,000
Repayment of Bank Credit Facility		(25,000	)		(54,000	)		—
Repayment of LLC Bank Credit Facility		—			(403,000	)		(15,000	)
Deferred financing costs		(1,963	)		(17,002	)		—
Other deferred payments		(9,921	)		—			—
Payments of finance lease		(14,133	)		(12,952	)		(12,412	)
Employee stock transactions		(333	)		—			—
Net cash provided by (used in) financing activities		48,083			(193,211	)		(18,412	)

Net increase (decrease) in cash, cash equivalents and restricted cash		(54,140	)		107,729			—
Cash, cash equivalents and restricted cash:
Balance, beginning of period		141,162			33,433			33,433
Balance, end of period	$	87,022		$	141,162		$	33,433

Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	90,956		$	100,664		$	40,626
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	$	62,571		$	53,476		$	47,994

The accompanying notes are an integral part of these consolidated financial statements.

F-7

TALOS ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2019

Note 1 — Formation and Basis of Presentation

Formation and Nature of Business

Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing value through our operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. The Company leverages decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world.

Talos Energy Inc. was formed in connection with the previously disclosed business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) that occurred on May 10, 2018, pursuant to which Talos Energy LLC and Stone became indirect wholly owned subsidiaries of Talos Energy Inc.

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

On February 3, 2012, Talos Energy LLC 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 the Company received a private equity capital commitment.

Stone Combination — On May 10, 2018 (the “Stone Closing Date”), the Company (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), by and among Stone, the Company, Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC (which was converted into a Delaware Corporation and 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 the Company (the “Stone Combination”). Prior to the Stone Closing Date, the Company did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement.

On the Stone Closing Date, 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 a direct wholly-owned subsidiary of the Company (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 the Company’s common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”).

Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, 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 LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company 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% Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Notes due 2022 issued by Stone (“7.50% Notes”) for $137.4 million aggregate principal amount of 11.00% Notes.

F-8

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

Basis of Presentation and Consolidation

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include each subsidiary from the date of inception. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods are reflected herein. The Company has evaluated subsequent events through the date the consolidated financial statements were issued.

Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which covers periods prior to the Stone Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the assets, liabilities and results of operations of Stone. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Stockholders’ Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy Inc.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

For presentation purposes, as of December 31, 2019, operating expenses previously presented as “Direct lease operating expense,” “Insurance” and “Workover and maintenance expense” have been combined and presented as “Lease operating expense” on our Consolidated Statements of Operations. Such reclassification had no effect on our results of operations, financial position or cash flows.

The Company has one reportable segment, which is the exploration and production of oil and natural gas. Substantially all the Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States.

Recently Adopted Accounting Standards

Leases — In February 2016, the Financial Accounting Standards Board issued Accounting Standards Codification 2016-02, Leases (“Topic 842”) requiring an entity to recognize a right-of-use asset representing the right to use an underlying asset for the lease term and a lease liability representing the obligation associated with future lease payments for virtually all leases. The pattern of expense recognition in the income statement is dependent on lease classification as finance or operating. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration. However, Topic 842 does not apply to leases of mineral rights.

F-9

On January 1, 2019, the Company adopted Topic 842, using the modified retrospective approach, which does not require an adjustment to comparative-period financial statements. As such, results for reporting periods beginning January 1, 2019 are presented in accordance with Topic 842, while prior period amounts are reported in accordance with previous lease accounting treatment. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other items, allowed Talos not to reassess whether expired or existing contracts, including land easements, contain a lease or reassess the classification and indirect costs associated with existing or expired leases. On the January 1, 2019 adoption date, the Company recorded a right-of-use asset of approximately $7.3 million and corresponding lease liability of $16.9 million representing the present value of its future operating lease payments. Upon the adoption of Topic 842, lease incentives are presented as a reduction to the right-of-use asset resulting in the difference between the right-of-use asset and lease liability. Adoption of this standard did not require an adjustment to retained earnings and did not impact the consolidated statements of operations, consolidated statements of cash flows or consolidated statements of changes in stockholders’ equity. See Note 5 – Leases for further information.

Recently Issued Accounting Standards

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which changes accounting requirements for the recognition of credit losses from an incurred or probable impairment methodology to a current expected credit losses (CECL) methodology. The guidance is effective for interim and annual periods beginning after December 15, 2019. The adoption of this guidance will not have a material effect on our consolidated financial statements.

Note 2 — Summary of Significant Accounting Policies

Overview of Significant Accounting Policies

Cash and Cash Equivalents — The Company presents cash as cash and cash equivalents on the Company’s consolidated balance sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value.

Accounts Receivable and Allowance for Uncollectible Accounts — Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $9.9 million at December 31, 2019 and $8.7 million at December 31, 2018. The Company establishes provisions for losses on accounts receivable with other parties if it believes that it will not collect all or part of the outstanding balance. On a quarterly basis, the Company reviews collectability and establishes or adjusts the Company’s allowance as necessary using the specific identification method. The Company presented $18.0 million of refund claims for value added taxes paid in Mexico in other assets on the consolidated balance sheets as of December 31, 2019.

Prepaid Assets — Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”) and transaction escrow related to the ILX and Castex Acquisition as further defined in Note 3 — Acquisitions. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis the Company adjusts the deposit based on actual royalty payments remitted to the ONRR. The transaction escrow was applied to the purchase price that closed in the first quarter of 2020. The escrow for the year ended December 31, 2019 was $31.8 million.

Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

F-10

Gas Imbalances — Prior to the adoption of Accounting Standards Codification (“ASC”) 606 in 2018, the Company used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on the Company’s entitled share of production with any difference recorded as an imbalance on the consolidated balance sheet. Upon the adoption of ASC 606 in 2018, revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. The change in accounting method from the entitlements method to the sales method resulted in an immaterial cumulative-effect adjustment to stockholders’ deficit on the date of adoption.

Production Handling Fees — Prior to the adoption of ASC 606 in 2018, the Company presented certain reimbursements for costs from certain third parties as other revenue on the consolidated statements of operations. Upon the adoption of ASC 606 in 2018, the reimbursements are presented as a reduction of lease operating expense on the consolidated statements of operations. The impact of the reclassification for the year ended December 31, 2018 was immaterial.

Other Revenue — Other revenues primarily represents a multi-year federal royalty refund claim from the ONRR. The company records revenue when a refund is filed and its collection is reasonably assured. The refunds for the year ended December 31, 2019 was $19.3 million.

Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

F-11

Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures, computer hardware and software. Acquisitions, renewals and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years.

Other Well Equipment Inventory — Other well equipment inventory primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When this inventory is supplied to wells, the cost of this inventory is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. The Company’s inventory is stated at the lower of cost or net realizable value. The Company recorded $0.2 million, $0.2 million, and $0.3 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in lease operating expense, during the years ended December 31, 2019, 2018 and 2017, respectively.

Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.

Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions, and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost).

Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

F-12

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in the Company’s consolidated statements of operations. If the Company incurs an amount different from the amount accrued for decommissioning obligations, the Company recognizes the difference as an adjustment to proved properties.

Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.

Commodity derivatives are recorded on the consolidated balance sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in price risk management activities income (expense) in the consolidated statements of operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes.

The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable.

Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as operating lease assets, current portion of operating lease liabilities and operating lease liabilities on the consolidated balance sheet. Finance leases are included in property and equipment, other current liabilities, and other long-term liabilities in our consolidated balance sheets.

A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the consolidated balance sheet for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, we generally use our incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date.

The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. The Company has elected to not apply the recognition requirements of Topic 842 to leases with durations of twelve months or less (i.e. short-term).

F-13

Income Taxes — Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to U.S. federal and state income taxes. The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the consolidated balance sheets.

The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations.

The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expense on the consolidated statements of operations, respectively.

Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of restricted stock units (“RSUs”), performance share units (“PSUs”) and outstanding warrants. See Note 10 — Income (Loss) Per Share for additional information.

Share-Based Compensation — Certain of the Company’s employees participate in its equity based compensation. The Company measures all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to its employees and recognize compensation cost on a straight-line basis in the Company’s financial statements over the vesting period of each grant according to ASC 718, Compensation—Stock Compensation.

During 2019, the Company issued RSUs and PSUs to certain employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity, but is remeasured at each reporting period for awards classified as a liability. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in general and administrative expense on the consolidated statements of operations, net of amounts capitalized to oil and gas properties. See Note 8 — Employee Benefits Plans and Share-Based Compensation for additional information.

RSUs — Share-based compensation is based on the market price of the Company’s Common Stock on the grant date and recognized over the vesting period using the straight-line method as the requisite service period is fulfilled.

PSUs — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over the vesting period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of Common Stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”) relative to the TSR achieved by a specified industry peer group. Share-based compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition is not achieved.

F-14

Concentration of Credit Risk

Consisting principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk.

Cash and cash equivalents and restricted cash balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts.

Commodity derivatives are entered into with registered swap dealers, the majority of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments.

The Company markets substantially all of its oil and natural gas production, and all of its revenues are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances for probable credit losses when necessary. The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows:

	Year Ended December 31,
	2019			2018			2017
Shell Trading (US) Company		58	%		65	%		80	%
Phillips 66		28	%		18	%	**

**	less than 10%

The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.

Note 3 — Acquisitions

Asset Acquisitions

Each of the acquisitions below qualified as an asset acquisition that requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the balance sheet by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired and any contingent consideration is recognized as the contingency is resolved.

Acquisition of Gunflint Field — On January 11, 2019, the Company completed the acquisition of an approximate 9.6% non-operated working interest in the Gunflint Field located in the Mississippi Canyon area (the “Gunflint Acquisition”) from Samson Offshore Mapleleaf, LLC for $29.6 million ($27.9 million after customary purchase price adjustments).

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on January 11, 2019 (in thousands):

Property and equipment	$	28,912
Asset retirement obligations		(996	)
Allocated purchase price	$	27,916

F-15

Acquisition of Whistler Energy II, LLC — On August 31, 2018, the Company completed the acquisition of all the issued and outstanding membership interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds (the “Whistler Acquisition”), for $52.6 million ($14.8 million, net of $37.8 million of cash acquired). The $37.8 million of cash acquired consists of $30.8 million of cash collateral posted by Whistler and released by third party surety companies at closing and $7.0 million of cash on hand for working capital purposes. Through the acquisition, the Company acquired and assumed all of Whistler’s oil and natural gas assets and the associated asset retirement obligations for interests located in Green Canyon Block 18, Green Canyon Block 60 and Ewing Bank Blocks 944 and 988, including a fixed production platform on Green Canyon Block 18.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on August 31, 2018 (in thousands):

Current assets⁽¹⁾	$	45,337
Property and equipment		35,344
Other long-term assets		66
Current liabilities		(4,261	)
Asset retirement obligations		(23,862	)
Allocated purchase price	$	52,624

⁽¹⁾	Includes $37.8 million of cash acquired and trade receivables of $3.2 million, which the Company expects all to be realizable.

Business Combination

Acquisitions qualifying as a business combination are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the consolidated balance sheet at their fair values as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation.

ILX and Castex Acquisition — On December 10, 2019, the Company and Talos Production Inc., formerly known as Talos Production LLC, entered into separate Purchase and Sale Agreements (collectively, the “Purchase Agreements”) with each of the following parties: ILX Holdings, LLC (“ILX Holdings”), ILX Holdings II, LLC (“ILX Holdings II”), ILX Holdings III LLC (“ILX Holdings III”) and Castex Energy 2014, LLC (“Castex 2014”), each a related party and an affiliate of the Riverstone Funds (“Riverstone Sellers” and such Purchase Agreements the “Riverstone Purchase Agreements”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers”).

Subsequent Event — On February 24, 2020, the Company, Talos Production Inc. and the Riverstone Sellers amended the Riverstone Purchase Agreements. Pursuant to the Purchase Agreements, as amended, among other things, the Company will acquire all of the issued and outstanding limited liability company interests in certain wholly owned subsidiaries of each of the respective Sellers (collectively, the “ILX and Castex Acquisition”) for an aggregate consideration of cash equal to $385.0 million and 110,000 shares of Series A Convertible Preferred Stock. Each share of Series A Convertible Preferred Stock will automatically convert into 100 shares (subject to adjustment) of Common Stock on the 20th day following the mailing of a definitive information statement relating to such conversion. On February 28, 2020, the Company completed the ILX and Castex Acquisition with an effective date of July 1, 2019. Due to the timing of the ILX and Castex Acquisition, the Company is unable to make a reasonable estimate of the purchase price allocation of such acquisition at this time.

Combination Between Talos Energy LLC and Stone Energy Corporation — On May 10, 2018, the Company consummated the Transactions contemplated by the Transaction Agreement and Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-owned subsidiaries of the Company. The combination was executed as an all-stock transaction whereby the former stakeholders of Talos Energy LLC 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 Stone Closing Date.

F-16

The purchase price of $732.0 million is based on the closing price of Stone common stock and common warrants immediately prior to closing. The following table summarizes the purchase price (in thousands, except per share data):

Stone Energy common stock - issued and outstanding as of May 9, 2018		20,038
Stone Energy common stock price	$	35.49
Common stock value	$	711,149

Stone Energy common stock warrants - issued and outstanding as of May 9, 2018		3,528
Stone Energy common stock warrants price	$	5.90
Common stock warrants value	$	20,815
Total purchase price	$	731,964

During 2018, the Company incurred approximately $88.6 million of transaction related costs, of which, $32.5 million was expensed and reflected in general and administrative expense on the consolidated statements of operations. The remaining $56.1 million was the result of (i) $9.3 million in work fees paid to holders of the 11.00% Notes reflected as a debt discount reducing long-term debt on the consolidated balance sheet and (ii) $46.8 million in fees for seismic use agreements for change in control provisions and reflected in proved properties on the consolidated balance sheet.

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 10, 2018 (in thousands):

Current assets⁽¹⁾	$	372,963
Property and equipment		886,406
Other long-term assets		19,494
Current liabilities		(132,846	)
Long-term debt		(235,416	)
Other long-term liabilities		(178,637	)
Allocated purchase price	$	731,964

⁽¹⁾	Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable.

The follow table presents revenue and net income attributable to the assets acquired in the Stone Combination for the years ended December 31, 2019 and 2018:

	Year Ended December 31,
	2019		2018
Revenue	$	414,056		332,944
Net income	$	187,428		148,473

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited pro forma information was derived from historical statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for transaction related costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2017, nor is such information indicative of any expected future results of operations.

	Year Ended December 31,
	2018		2017
Revenue	$	1,013,184	$	712,648
Net income (loss)	$	274,577	$	(100,980	)
Basic net income (loss) per common share	$	5.07	$	(1.86	)
Diluted net income (loss) per common share	$	5.07	$	(1.86	)

F-17

Note 4 — Property, Plant and Equipment

Proved Properties

The Company’s interests in oil and natural gas proved properties are located in the United States, primarily in the Gulf of Mexico deep and shallow waters. The Company follows the full cost method of accounting for its oil and natural gas exploration and development activities.

Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, the Company’s capitalized oil and natural gas costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. The Company performs this ceiling test calculation each quarter utilizing SEC pricing. During 2019, 2018 and 2017, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At December 31, 2019, its ceiling test computation was based on SEC pricing of $61.01 per Bbl of oil, $2.59 per Mcf of natural gas and $26.17 per Bbl of NGLs.

Unproved Properties

Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the U.S. Gulf of Mexico federal lease sales, certain geological and geophysical costs, expenditures associated with certain exploratory wells in progress and capitalized interest. Unproved properties also include expenditures associated with exploration and appraisal activities in Block 7 and Block 31 located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states.

The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2019, by the year in which such costs were incurred (in thousands):

			Year Ended December 31,
	Total		2019		2018		2017		2016 and Prior
Acquisition United States	$	42,501	$	16,062	$	26,439	$	—	$	—
Exploration United States		45,117		35,656		7,087		2,372		2
Exploration Mexico		106,914		61,809		14,362		23,332		7,411
Total unproved properties, not subject to amortization	$	194,532	$	113,527	$	47,888	$	25,704	$	7,413

The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined.

As a result of the Company’s evaluation of unproved property located in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from exploratory wells drilled during the second quarter of 2019 and the Block 2 production sharing contract’s expiration date, the Company recorded a $12.2 million non-cash impairment presented as “Write-down of oil and natural gas properties” on the consolidated statements of operations for the year ended December 31, 2019.

F-18

Asset Retirement Obligations

The discounted asset retirement obligations included in the consolidated balance sheets in current and non-current liabilities, and the changes in that liability during each of the years ended December 31, 2019 and 2018 were as follows (in thousands):

	Year Ended December 31,
	2019			2018
Asset retirement obligations at January 1	$	382,817		$	214,733
Fair value of asset retirement obligations acquired⁽¹⁾		5,047			244,766
Obligations settled		(75,331	)		(112,946	)
Fair value of asset retirement obligations divested		(5,450	)		—
Accretion expense		34,389			35,344
Obligations incurred		4,111			358
Changes in estimate		23,895			562
Asset retirement obligations at December 31	$	369,478		$	382,817
Less: Current portion		(61,051	)		(68,965	)
Long-term portion	$	308,427		$	313,852

⁽¹⁾	Year ended December 31, 2018 includes $220.6 million and $23.9 million of asset retirement obligations assumed in the Stone Combination and the Whistler Acquisition, respectively.

Note 5 — Leases

The Company enters into service contracts and other contractual arrangements for the use of office space, drilling, completion and abandonment equipment (e.g., drilling rigs), production related equipment (e.g., compressors) and other equipment from third-party lessors to support its operations. The Company’s leasing activities as a lessor are negligible. At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement.

On August 2, 2016, the Company executed a seven-year lease agreement for the use of the Helix Producer 1 (“HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. Under the terms of the agreement, the Company agreed to pay a $49.0 million annual fixed demand charge for each of the first two years and $45.0 million for each of the five years thereafter.

Prior to implementation, the HP-I lease was accounted for as a capital lease under previous lease accounting treatments. The Company initially recorded a capital lease asset and liability of $124.3 million on its consolidated balance sheet at lease inception. As the HP-I is utilized in the Company’s oil and natural gas development activities, the capital lease asset was included within proved property and depleted as part of the full cost pool. Upon adoption of Topic 842, the HP-I capital lease was classified as a finance lease resulting in no change to the amounts recognized on the consolidated balance sheet.

The Company has operating leases expiring at various dates, principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Operating leases are reflected as operating lease assets, current portion of operating lease liabilities and operating lease liabilities on the consolidated balance sheet. The Company’s operating lease liabilities recognized on the balance sheet as of December 31, 2019 was $18.8 million. Costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying asset is utilized.

F-19

The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands):

	December 31, 2019
Finance lease cost - interest on lease liabilities⁽¹⁾	$	19,115
Operating lease cost, excluding short-term leases⁽²⁾		3,261
Short-term lease cost⁽³⁾		85,865
Variable lease cost⁽⁴⁾		11
Total lease cost	$	108,252

⁽¹⁾

The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserved using the unit-of-production method, computed quarterly.

⁽²⁾	Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.

⁽³⁾	Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the balance sheet.

⁽⁴⁾	Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability, adjusted for initial direct costs and incentives are as follows (in thousands):

	December 31, 2019
Operating leases:
Operating lease assets	$	7,779

Current portion of operating lease liabilities	$	1,594
Operating lease liabilities		17,239
Total operating lease liabilities	$	18,833

Finance leases:
Proved property ⁽¹⁾	$	124,299

Other current liabilities	$	17,509
Other long-term liabilities		62,026
Total finance lease liabilities	$	79,535

⁽¹⁾

The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly.

F-20

The table below presents the lease maturity by year as of December 31, 2019 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the consolidated balance sheet.

	Operating Leases			Finance Leases
2020	$	2,744		$	33,257
2021		4,079			33,257
2022		4,302			33,257
2023		4,239			13,857
2024		3,315			—
Thereafter		15,790			—
Total lease payments	$	34,469		$	113,628
Imputed interest		(15,636	)		(34,093	)
Total	$	18,833		$	79,535

The table below presents the weighted average remaining lease term and discount rate related to leases for the year ended December 31, 2019 (in thousands):

	December 31, 2019
Weighted average remaining lease term:
Operating leases	8.4 years
Finance leases	3.4 years
Weighted average discount rate:
Operating leases		10.2	%
Finance leases		21.9	%

The table below presents the supplemental cash flow information related to leases for the year ended December 31, 2019 (in thousands):

Operating cash outflow from finance leases	$	19,115
Financing cash outflow from finance leases	$	14,133
Operating cash outflow from operating leases	$	1,812

Right-of-use assets obtained in exchange for new finance lease liabilities	$	—
Right-of-use assets obtained in exchange for new operating lease liabilities	$	2,225

Note 6 — Financial Instruments

The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments (in thousands):

	December 31, 2019						December 31, 2018
	Carrying Amount			Fair Value			Carrying Amount		Fair Value
11.00% Second-Priority Senior Secured Notes – due April 2022⁽¹⁾	$	383,871		$	401,128		$	381,229	$	362,168
7.50% Senior Notes – due May 2022	$	6,060		$	5,030		$	6,060	$	5,151
Bank Credit Facility – matures May 2022⁽¹⁾	$	343,050		$	350,000		$	257,448	$	265,000
Oil and Natural Gas Derivatives	$	(11,594	)	$	(11,594	)	$	74,923	$	74,923

⁽¹⁾	The carrying amounts are net of discount and deferred financing costs.

As of December 31, 2019 and 2018, the carrying amounts of cash and cash equivalents, accounts receivable, restricted cash and accounts payable approximate their fair values because of the short-term nature of these instruments.

F-21

11.00% Second-Priority Senior Secured Notes – due April 2022

The $390.9 million aggregate principal amount of 11.00% Notes is reported on the consolidated balance sheet at its carrying value, net of original issue discount and deferred financing costs, see Note 7 — Debt. The fair value of the 11.00% Notes is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

7.50% Senior Notes – due May 2022

The $6.1 million aggregate principal amount of 7.50% Notes is reported on the consolidated balance sheet as of December 31, 2019 at its carrying value, see Note 7 — Debt. The fair value of the 7.50% Notes is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

Bank Credit Facility – matures May 2022

The Company and Talos Production Inc., our wholly-owned subsidiary that was formerly known as Talos Production LLC, maintains a bank credit facility with a borrowing base of $950.0 million at December 31, 2019 (the “Bank Credit Facility”), which is reported on the consolidated balance sheet at its carrying value net of deferred financing costs (see Note 7 – Debt). The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).

Oil and natural gas derivatives

The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Collar contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.

The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the consolidated balance sheet at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as price risk management activities income (expense) on the consolidated statements of operations in each period.

The following table presents the impact that derivatives, not qualifying as hedging instruments, had on its consolidated statements of operations (in thousands):

	Year Ended December 31,
	2019			2018			2017
Net cash received (paid) on settled derivative instruments	$	(8,820	)	$	(111,147	)	$	23,834
Unrealized gain (loss)		(86,517	)		171,582			(51,397	)
Price risk management activities income (expense)	$	(95,337	)	$	60,435		$	(27,563	)

The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of December 31, 2019:

Production Period	Instrument Type	Average Daily Volumes		Weighted Average Swap Price		Weighted Average Put Price		Weighted Average Call Price
Crude Oil – WTI:		(Bbls)		(per Bbl)		(per Bbl)		(per Bbl)
January 2020 – December 2020	Swap		17,862	$	56.21	$	—	$	—
January 2021 – June 2021	Swap		2,000	$	53.30	$	—	$	—
January 2020 – December 2020	Collar		7,481	$	—	$	55.00	$	64.23
Natural Gas – Henry Hub NYMEX:		(MMBtu)		(per MMBtu)		(per MMBtu)		(per MMBtu)
January 2020 – December 2020	Swaps		16,216	$	2.78	$	—	$	—

F-22

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

	December 31, 2019
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps and costless collars	$	—	$	8,393		$	—	$	8,393
Liabilities:
Oil and natural gas swaps and costless collars		—		(19,987	)		—		(19,987	)
Total net asset	$	—	$	(11,594	)	$	—	$	(11,594	)

	December 31, 2018
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps and costless collars	$	—	$	75,473		$	—	$	75,473
Liabilities:
Oil and natural gas swaps and costless collars		—		(550	)		—		(550	)
Total net liability	$	—	$	74,923		$	—	$	74,923

Financial Statement Presentation

Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its consolidated balance sheets. On derivative contracts recorded as assets in the table below, the Company is exposed to the risk the counterparties may not perform. The following table presents the fair value of derivative financial instruments at December 31, 2019 and 2018 (in thousands):

	December 31, 2019				December 31, 2018
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	8,393	$	19,476	$	75,473	$	550
Non-current		—		511		—		—
Total	$	8,393	$	19,987	$	75,473	$	550

Credit Risk

The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2019 represent derivative instruments from eleven counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and all of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities.

F-23

Subsequent event

The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts entered into subsequent to December 31, 2019, which are not reflected in the table above:

Production Period	Instrument Type	Average Daily Volumes		Weighted Average Swap Price		Weighted Average Put Price		Weighted Average Call Price
Crude Oil – WTI:		(Bbls)		(per Bbl)		(per Bbl)		(per Bbl)
April 2020 – December 2020	Swap		4,664	$	40.98	$	—	$	—
January 2021 – December 2021	Swap		1,992	$	48.48	$	—	$	—
Natural Gas – Henry Hub NYMEX:		(MMBtu)		(per MMBtu)		(per MMBtu)		(per MMBtu)
April 2020 – December 2020	Swaps		6,000	$	2.15	$	—	$	—
January 2021 – December 2021	Swaps		5,000	$	2.39	$	—	$	—

Note 7 — Debt

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):

	Year Ended December 31,
	2019			2018
11.00% Second-Priority Senior Secured Notes – due April 2022	$	390,868		$	390,868
7.50% Senior Notes – due May 2022		6,060			6,060
Bank Credit Facility – matures May 2022		350,000			265,000
4.20% Building Loan – matures November 2030		—			10,567
Total debt, before discount and deferred financing cost		746,928			672,495
Discount and deferred financing cost		(13,947	)		(17,191	)
Total debt, net of discount and deferred financing costs		732,981			655,304
Less: Current portion of long-term debt		—			(443	)
Long-term debt, net of discount and deferred financing costs	$	732,981		$	654,861

In connection with the Stone Combination, the Company consummated the Transactions, pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes to the Company in exchange for Common Stock; (ii) the holders of 11.00% Bridge Loans exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Notes and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Notes for $137.4 million aggregate principal amount of 11.00% Notes. An additional $81.5 million of 7.50% Notes held by non-affiliates were also exchanged for 11.00% Notes pursuant to an Exchange Offer and Consent Solicitation in connection with the Stone Combination.

The exchanges to 11.00% Notes were accounted for as a debt modification. Under a debt modification, a new effective interest rate that equates the revised cash flows to the carrying amount of the 11.00% Notes is computed and applied prospectively. Costs incurred with third parties directly related to the modification are expensed as incurred. The Company incurred approximately $4.3 million of transaction fees related to the modification which were expensed and reflected in general and administrative expense on the consolidated statements of operations during the year ended December 31, 2018. The Company also paid $9.3 million in work fees to holders of the 11.00% Notes, which are reflected as debt discount reducing long-term debt on the consolidated balance sheet.

11.00% Second-Priority Senior Secured Notes – due April 2022

The 11.00% Notes were issued pursuant to an indenture dated May 10, 2018, between the Talos Issuers, the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 11.00% Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15. Prior to May 10, 2020, the Company may, at its option, redeem all or a portion of the 11.00% Notes at 105.5% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 11.00% Notes at redemption prices decreasing annually at May 10 from 102.75% to 100.0% plus accrued and unpaid interest.

F-24

The indenture governing the 11.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii) transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in transactions with affiliates. The 11.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2019.

7.50% Senior Notes – due May 2022

The 7.50% Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Notes pursuant to the Exchange Offer and Consent Solicitation, and thus remain outstanding. As a result of the Exchange Offer and Consent Solicitation, substantially all of the restrictive covenants relating to the 7.50% Notes have been removed and collateral securing the 7.50% Notes has been released. The 7.50% Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and November 30. Prior to May 31, 2020, the Company may, at its option, redeem up to 35% of the 7.50% Notes at 107.5% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 7.50% Notes at redemption prices decreasing annually at May 31 from 105.625% to 100.0% plus accrued and unpaid interest.

Bank Credit Facility – matures May 2022

The Company and Talos Production Inc., a subsidiary of the Company that was formerly known as Talos Production LLC, maintains a Bank Credit Facility with a syndicate of financial institutions, with a borrowing base of $950.0 million as of year ended December 31, 2019. The Bank Credit Facility matures on May 10, 2022, provided that the Bank Credit Facility mandates a springing maturity that is 120 days prior to May 10, 2022, if greater than $25.0 million of the 11.00% Notes or any permitted refinancing indebtedness in resect thereof is outstanding on such date.

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unfunded portion of the commitments. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 each quarter. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, undrawn commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries.

The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of its proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter.

On July 3, 2019, the Company entered into a Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement in which, (a) the $850.0 million borrowing base was reaffirmed, (b) the commitments were increased from $600.0 million to $850.0 million and (c) certain other amendments will be made to the Bank Credit Facility as more particularly described therein.

F-25

As of December 31, 2019, the Company’s borrowing base and commitments were $950.0 million, of which no more than $200.0 million can be used as letters of credit. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at December 31, 2019. As of December 31, 2019, the Bank Credit Facility had approximately $586.4 million of undrawn commitments (taking into account $13.6 million letters of credit and $350.0 million drawn from the Bank Credit Facility).

Building Loan – matures November 2030

In connection with the Stone Combination, the Company assumed Stone’s 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million. During June 2019, the Company repaid $10.4 million aggregate remaining principal, plus accrued interest, of the Building Loan using proceeds from the sale of an office building in Lafayette acquired in the Stone Combination and cash on hand. As of December 31, 2019, there is no outstanding balance under the Building Loan.

Subsequent Event

On January 17, 2020, the Company borrowed $25.0 million from the Bank Credit Facility to fund 2020 general corporate activities. On February 27, 2020, the Company borrowed $275.0 million to fund the cash portion of the purchase price in the ILX and Castex Acquisition. On February 28, 2020, as a result of the closing of the ILX and Castex Acquisition, the borrowing base and commitments were increased from $950.0 million to $1.15 billion. As of the closing of the ILX and Castex Acquisition, the Bank Credit Facility had approximately $486.4 million of undrawn commitments (taking into account $13.6 million letters of credit and $650.0 million drawn from the Bank Credit Facility). See Note 16 — Subsequent Events.

Note 8 — Employee Benefits Plans and Share-Based Compensation

Stone Change of Control and Severance Plans

As a result of the Stone Combination, the Company assumed the Stone Energy Corporation Executive Severance Plan and Stone Energy Corporation Employee Severance Plan, each a legacy plan of Talos Petroleum LLC (f/k/a Stone Energy Corporation). The plans provided for the payment of severance and change in control benefits to certain individuals who, prior to the Stone Combination, were executive officers or employees of Talos Petroleum LLC, in each case upon an involuntary termination within twelve months of the Stone Closing Date. For the years ended December 31, 2019 and 2018 the Company incurred $0.2 million and $7.8 million of severance expense, reflected in general and administrative expense on the consolidated statements of operations. The plans were terminated on July 11, 2019.

Talos Energy Inc. Long Term Incentive Plan

In 2018, the Company adopted the Talos Energy Inc. Long Term Incentive Plan (the “LTIP”), pursuant to which the Company may, subject to approval by the Talos board of directors, grant options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards or any combination of the foregoing to employees, directors and consultants. The LTIP authorizes the Company to grant awards of up to 5,374,340 shares of the Company’s Common Stock.

Restricted Stock Units – Employees — RSUs granted to employees under the LTIP primarily vest ratably over an approximate three year period subject to such employee’s continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one share of Common Stock. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2019 was approximately $12.9 million, which is expected to be recognized over a weighted average period of 2.1 years.

Restricted Stock Units – Non-employee Directors —RSUs granted to non-employee directors under the LTIP vested approximately one year following the date of grant, subject to such non-employee director’s continued service through the vesting date. Upon vesting, these RSUs represent a contingent right to receive one share of Common Stock for each RSU for 60%, and cash for the remaining 40%. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2019 was approximately $0.1 million, which is expected to be recognized over a weighted average period of 0.2 years. Of the unrecognized share-based compensation expense, $0.1 million relates to liability awards and will be subsequently remeasured at each reporting period.

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The following table summarizes RSU activity for the years ended December 31, 2019 and 2018:

	Restricted Stock Units			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2017		—		$	—
Granted		139,411			33.85
Vested		(53	)		32.86
Forfeited		(654	)		32.86
Unvested RSUs at December 31, 2018		138,704		$	33.85
Granted		732,771			24.39
Vested		(69,235	)		33.72
Forfeited		(68,463	)		25.43
Unvested RSUs at December 31, 2019		733,777		$	25.20

Performance Share Units – Employees —PSUs granted to employees under the LTIP represent the contingent right to receive one share of Common Stock. However, the number of shares of Common Stock issuable upon vesting ranges from zero to 200% of the target number of PSUs granted based on the TSR of the Common Stock relative to the TSR achieved by a specific industry peer group over an approximate three-year performance period, the last day of which is also the vesting date. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2019 was approximately $9.6 million, which is expected to be recognized over a weighted average period of 1.7 years.

The following table summarizes PSU activity for the years ended December 31, 2019 and 2018:

	Performance Share Units			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2017		—		$	—
Granted		232,891			44.47
Vested		—			—
Forfeited		(1,349	)		42.94
Unvested PSUs at December 31, 2018		231,542		$	44.47
Granted		218,060			33.96
Vested		—			—
Forfeited		(31,771	)		40.27
Unvested PSUs at December 31, 2019		417,831		$	39.31

The grant date fair value of the PSUs, calculated using a Monte Carlo simulation, was $7.4 million and $10.4 million for the years ended December 31, 2019 and 2018. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted for the years ended December 31, 2019 and 2018:

	2019 Grant Date						2018 Grant Date
	March 5			May 16			August 29			September 28
Number of simulations		100,000			100,000			100,000			100,000
Expected term (in years)		2.8			2.6			2.7			2.6
Expected volatility		46.9	%		44.8	%		50.6	%		47.4	%
Risk-free interest rate		2.5	%		2.1	%		2.7	%		2.9	%
Dividend yield		—	%		—	%		—	%		—	%

F-27

Talos Energy LLC Series B Units

Prior to the Stone Combination, the Limited Liability Company Agreement of Talos Energy LLC established Series A, Series B and Series C Units. Series B Units were generally intended to be used as incentives for Talos Energy LLC employees. Series B Units do not participate in distributions prior to vesting or until Series A Units have received cumulative distributions equal to (i) the original cash contributed to the Company for such Series A Units and (ii) an 8% return, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received no distributions. In connection with the Transactions, the Series A, Series B and Series C Units were exchanged for an equivalent number of units in each of an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock of the Company. The modification did not result in incremental value to the Series B Units.

For accounting and financial reporting purposes, the Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to accumulated deficit on the consolidated balance sheet.

The Company’s unrecognized compensation expense at December 31, 2019 is approximately $2.4 million. Of this amount, approximately $0.2 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $2.2 million will be recognized upon an Aggregate Series A Payout. The weighted-average period over which the unrecognized compensation expense for the Series B Units will be recognized is 1.1 years.

New Talos Energy LLC Series B Units

In connection with the transactions contemplated in the Exchange Agreement on May 10, 2018, an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock in the Company as a result of the Sponsor Debt Exchange, established new Series A Units (“New Series A Units”) and new Series B Units (“New Series B Units”). The New Series B Units are generally intended to be used as incentives for Talos Energy LLC employees.

The New Series B Units do not participate in distributions prior to vesting or until the New Series A Units have received cumulative distributions of $102.0 million. After issuance, 80% of the New Series B Units vest on a monthly basis over a four year period based on the initial vesting schedule of the original Series B Units, subject to continued employment. All unvested New Series B Units fully vest upon the cumulative distribution of $102.0 million.

For accounting and financial reporting purposes, the New Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to accumulated deficit on the consolidated balance sheet.

The New Series B Units issued were valued using the option pricing method for valuing securities. In this method, the rights and claims of each security are modeled as a portfolio of Black-Scholes-Merton call options written on the total equity of the entities affiliated with the Apollo Funds and Riverstone Funds. The total value of the equity is calculated in an iterative process that results in the New Series A Units being valued at par. The risk-free rate of interest is based on the U.S. Treasury yield curve on the grant date. The expected time to a liquidity event is based on a weighted average calculation of management’s estimate considering market conditions and expectations. The expected volatility of equity is based on the volatility of the assets of similar publicly traded companies using a Black-Scholes-Merton model. The discount for lack of marketability is based on the restrictions on the New Series B Units and the volatility of the New Series B Units using a Black-Scholes-Merton model.

The Company’s unrecognized compensation expense at December 31, 2019 is approximately $1.0 million. Of this amount, approximately $0.1 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $1.0 million will be recognized upon the New Series A Units receiving the cumulative distribution. The weighted-average period over which the unrecognized compensation expense will be recognized is 0.6 years.

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Share-based Compensation Expense, net

Share-based compensation expense associated with RSUs, PSUs and Series B Units are reflected as general administrative expense, net amounts capitalized to oil and gas properties, in the consolidated statements of operations. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash used in or provided by operating activities in the consolidated statements of cash flows.

For the year ended December 31, 2019, share-based compensation expense did not have any associated income tax benefit. The Company recognized the following share-based compensation expense, net for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018			2017
Talos Energy Inc. Long Term Incentive Plan	$	12,523		$	2,091		$	—
Talos Energy LLC Series B Units		256			666			1,795
New Talos Energy LLC Series B Units		145			3,752			—
Total share-based compensation expense		12,924			6,509			1,795
Less: amounts capitalized to oil and gas properties		(5,960	)		(3,616	)		(920	)
Total share-based compensation expense, net	$	6,964		$	2,893		$	875

Note 9 — Income Taxes

Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. Talos Energy LLC’s operations in the shallow waters off the coast of Mexico were conducted under a different legal form and are subject to foreign income taxes.

Tax Cuts and Jobs Act

On December 22, 2017, the President signed into law Public Law No. 115-97 (“Tax Act”), an Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018. The Tax Act made broad and complex changes to the U.S. tax code. The SEC issued Staff Accounting Bulletin 118, which has since been codified into ASC 740, providing guidance on the accounting for the tax effects of the Tax Act. ASC 740 provides a measurement period that should not extend beyond one year from the Tax Act enactment date to complete the accounting under ASC 740. In accordance with this pronouncement, the Company completed its assessment on certain effects of the Tax Act in the financial statements for the period ending December 31, 2018. In assessing the need for a valuation allowance on its deferred tax assets, the Company considered whether it was more likely than not that some portion or all of them will not be realized. Due to a full valuation allowance against the Company’s deferred tax assets, the adjustments did not have any net impact on tax expense for 2018.

Income Tax Expense (Benefit)

The components of income tax expense (benefit) were as follows (in thousands):

	Year Ended December 31,
	2019			2018		2017
Current income tax expense
United States	$	437		$	—	$	—
Mexico		1,183			1,345		—
Total current income tax expense	$	1,620		$	1,345	$	—

Deferred income tax expense (benefit)
United States	$	(37,131	)	$	1,064	$	—
Mexico		(630	)		513		—
Total deferred income tax expense (benefit)		(37,761	)		1,577		—
Total income tax expense (benefit)	$	(36,141	)	$	2,922	$	—

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The reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company’s income tax expense is as follows (in thousands, except percentages):

	Year Ended December 31,
	2019			2018			2017
Income tax expense (benefit) at the federal statutory tax rate	$	4,744		$	47,137		$	(22,004	)
Earnings not subject to tax		—			9,980			22,004
State income taxes		1,396			11,738			—
Foreign income taxes		—			1,008			—
Permanent differences		340			—			—
Foreign rate differential		(4,948	)		432			—
Prior year taxes		(1,950	)		417			—
Other adjustments		137			800			—
Change in tax status		—			(35,925	)		—
Legal entity reorganization		39,336			—			—
Change in valuation allowance		(75,196	)		(32,665	)		—
Total income tax expense (benefit)	$	(36,141	)	$	2,922		$	—
Effective tax rate		(159.99	)%		1.30	%		—	%

The Company’s effective tax rate for the year ending December 31, 2019 differed from the federal statutory rate of 21.0% primarily due to a non-cash tax benefit of $75.2 million related to the full release of the valuation allowance for its federal and a significant portion of its state deferred tax assets. The federal and state portion of the release equals $80.2 million, partially offset by a $5.0 million increase in valuation allowance recorded against foreign deferred tax assets. Additionally, the Company recorded a tax expense of $39.3 million related to the reorganization of our subsidiaries, of which $38.9 million represents the non-cash impact from the legal entity conversion of a partnership to a corporation.

The effective tax rate for years 2018 differed from the federal statutory rate of 21% primarily due to recording a full valuation allowance against its deferred tax assets. The effective tax rate for year 2017 differed from the federal statutory rate of 35.0% because the Company was not subject to U.S. federal or state taxation as a partnership and the Company’s Mexico operations did not incur a material income tax expense.

F-30

Deferred Tax Assets and Liabilities

Deferred taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of deferred tax assets and liabilities were as follows (in thousands):

	Year Ended December 31,
	2019			2018
Deferred tax assets:
Federal net operating loss	$	131,204		$	117,546
Foreign tax loss carryforward		2,316			2,303
State net operating loss		24,270			23,542
Asset retirement obligations		89,059			95,546
Tax credits		449			12
Interest		—			33,867
Derivatives		2,794			—
Other well equipment inventory		10,014			12,901
Accrued bonus		3,753			4,042
Operating lease liabilities		2,317			2,509
Other		7,004			—
Total deferred tax assets		273,180			292,268
Valuation allowance		(19,118	)		(94,085	)
Total deferred tax assets, net	$	254,062		$	198,183

Deferred tax liabilities:
Oil and gas properties		211,216			179,780
Deferred financing		3,752			—
Operating lease assets		1,814			—
Derivatives		—			18,246
Prepaid		3,419			3,371
Other		—			642
Deferred tax liabilities		220,201			202,039
Net deferred tax asset (liability)	$	33,861		$	(3,856	)

Net Operating Loss

The table below presents the details of the Company’s net operating loss and tax credit carryovers as of December 31, 2019 (in thousands):

	Amount		Expiration Year
Federal net operating losses	$	536,463	2035 - 2037
Federal net operating losses	$	60,948	Unlimited
Foreign tax loss carryforward	$	26,879	2025 - 2029
State net operating losses	$	380,609	2020 - 2038

As of December 31, 2019, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $597.4 million, of which $536.5 million is subject to limitation under Section 382 of the Internal Revenue Code (“IRC”). IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would begin to expire in 2035.

F-31

Valuation Allowance

The Company recorded a valuation allowance of $19.1 million and $94.1 million as of December 31, 2019 and December 31, 2018, respectively. Deferred income tax assets and liabilities are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions and income in the future. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses relate. In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of them will not be realized.

Through the third quarter of 2019 and period ended December 31, 2018, the Company maintained a valuation allowance related to federal, state and foreign deferred tax assets, as there was insufficient positive evidence to overcome the substantial negative evidence of cumulative losses in these periods. During the fourth quarter of 2019, the Company reached the conclusion that it was appropriate to release the valuation allowances against its federal deferred tax assets and a significant portion of its state deferred tax assets due to the sustained positive operating performance and the availability of expected future taxable income. Additionally, the Company achieved a cumulative three-year income position. The Company’s remaining valuation allowance primarily relates to various state operating loss carryforwards and foreign deferred tax assets.

Uncertain Tax Positions

The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. There are no unrecognized benefits that would impact the effective tax rate if recognized. While amounts could change during the next 12 months, the Company does not anticipate having a material impact on its financial statements.

Balances in the uncertain tax positions are as follows (in thousands):

	Year Ended December 31,
	2019		2018
Total unrecognized tax benefits, beginning balance	$	360	$	—
Increases in unrecognized tax benefits as a result of:
Tax positions taken during a prior period		8		360
Tax positions taken during the current period		423		—
Settlements with taxing authorities		—		—
Lapse of applicable statute of limitations		—		—
Total unrecognized tax benefits, ending balance	$	791	$	360

The Company recognizes interest and penalties related to uncertain tax positions as interest expense and general and administrative expenses, respectively.

Years open to examination

The 2016 through 2018 tax years remain open to examination by the tax jurisdictions in which the Company is subject to tax. The statute of limitations with respect to the U.S. federal income tax returns of the Company for years ending on or before December 31, 2015 are closed.

Note 10 — Income (Loss) Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs, PSUs and outstanding warrants.

F-32

The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts):

	Year Ended December 31,
	2019		2018		2017
Net income (loss)	$	58,729	$	221,540	$	(62,868	)
Weighted average common shares outstanding — basic		54,185		46,058		31,244

Dilutive effect of securities		228		3		—
Weighted average common shares outstanding — diluted		54,413		46,061		31,244
Net income (loss) per common share:
Basic	$	1.08	$	4.81	$	(2.01	)
Diluted	$	1.08	$	4.81	$	(2.01	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		4,220		3,538		4,282

For the periods prior to May 10, 2018, the Company retrospectively adjusted the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. There is no impact in fiscal year 2017 on diluted earnings per common share from the RSUs, PSUs and outstanding warrants as these instruments did not exist throughout such periods.

Note 11 — Related Party Transactions

ILX and Castex Acquisition

On December 10, 2019, the Company and Talos Production Inc. entered into separate Purchase Agreements with the Sellers. On February 24, 2020, the Company, Talos Production Inc. and the Riverstone Sellers amended the Riverstone Purchase Agreements. Pursuant to the Purchase Agreements, as amended, among other things, the Company will acquire all of the issued and outstanding limited liability company interest in certain wholly owned subsidiaries of each of the respective entities for aggregate consideration consisting of the following, subject to certain negotiated adjustments: (i) an aggregate amount of cash from the Company equal to $385.0 million and (ii) an aggregate of 110,000 shares of a series of the Company’s preferred stock, par value $0.01 per share, designated as the “Series A Convertible Preferred Stock.” The Series A Convertible Preferred Stock is subject to automatic conversion into Common Stock upon the terms of that certain Certificate of Designation, Preferences, Rights and Limitations related thereto (such Common Stock, the “Conversion Stock”), to be newly issued to the Riverstone Sellers. As of signing, the Company deposited into escrow $31.8 million that will be applied at closing towards the cash component of the purchase price under each Purchase Agreement. See additional details in Note 3 – Acquisitions.

Whistler Acquisition

On August 31, 2018, the Company acquired Whistler from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds, for $52.6 million ($14.8 million, net of $37.8 million of cash acquired). Included in current assets acquired as of December 31, 2019 is $1.1 million in receivables from an affiliate of the Apollo Funds to reimburse the Company for certain payments made post closing. See additional details in Note 3 – Acquisitions.

Equity Registration Rights Agreement

On May 10, 2018, the Company entered into a Registration Rights Agreement (the “Original Equity Registration Rights Agreement”) with certain of the Apollo Funds and the Riverstone Funds, Franklin and MacKay Shields LLC, relating to the registered resale of the Company’s common stock owned by such parties as of the closing of the Stone Combination (the “Original Registrable Securities”).

F-33

The Company and the Riverstone Sellers (and their designated affiliates) agreed under the Purchase Agreements to enter into an amendment to the Original Equity Registration Rights Agreement (such amendment, the “Registration Rights Agreement Amendment,” and the Original Equity Registration Rights Agreement, as amended by the Registration Rights Agreement Amendment, the “Registration Rights Agreement”). The Registration Rights Agreement Amendment will add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Series A Convertible Preferred Stock (and Conversion Stock) (each as defined below) that the Riverstone Sellers received at the closing of the ILX and Castex Acquisition (the “New Registrable Securities” and together with the Original Registrable Securities, the “Registrable Securities”). Under the Registration Rights Agreement, we are required to file a shelf registration statement within 30 days of the Company’s receipt of written request by a holder of Registrable Securities (a “Holder”). Each Holder will be limited to two demand registrations in any twelve-month period.

The Holders have the right to request that we initiate underwritten offerings of the Company’s common stock; provided, that the Apollo Funds and the Riverstone Funds will have the right to demand three underwritten offerings in any twelve-month period, and Franklin and MacKay Shields will only have the collective right to demand one underwritten offering. The Holders have customary piggyback rights with respect to any underwritten offering that we conduct for as long as the Holders and their respective affiliates own 5% of the Registrable Securities. Each Holder will agree to a lock up with underwriters in the event of an underwritten offering, provided that the lock up will not apply to any Holder who does not have a right to participate in such underwritten offering. The Registration Rights Agreement will terminate with respect to Franklin and MacKay Shields in the event that either Franklin or MacKay Shields ceases to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding.

The Company will bear all of the expenses incurred in connection with the offer and sale, while the Apollo Funds, the Riverstone Funds, Franklin and MacKay Shields will be responsible for paying underwriting fees, discounts and selling commissions. Fees incurred by the Company in conjunction with the Original Equity Registration Rights Agreement were $0.7 million and $1.8 million for the fiscal years ended December 31, 2019 and 2018, respectively.

Stockholders’ Agreement Amendment

On May 10, 2018, the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020, the Company and the other parties thereto amended the Stockholders’ Agreement (the “Stockholders’ Agreement Amendment”) to, among other things, add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Stockholders’ Agreement and provide that for purposes of determining whether the Riverstone Sellers and their affiliates continue to satisfy certain stock ownership requirements necessary to retain their rights to nominate directors to the board of directors, the Series A Convertible Preferred Stock owned by the Riverstone Sellers will be counted towards such ownership requirements on an as converted basis at the closing of the ILX and Castex Acquisition.

Registration Rights Agreement Amendment

In connection with the closing of the ILX and Castex Acquisition, and pursuant to the Purchase Agreements, as amended, the Company and ILX Holdings, ILX Holdings II, ILX Holdings III and Riverstone V Castex 2014 Holdings, L.P., a Delaware limited partnership and designee of Castex 2014, entered into the Registration Rights Agreement Amendment to the Registration Rights Agreement to, among other things, add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Company’s Series A Convertible Preferred Stock issued to the Riverstone Sellers at the closing of the ILX and Castex Acquisition.

F-34

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at Vinson & Elkins L.L.P. For the years ended December 31, 2019, 2018 and 2017, the Company incurred fees of approximately $4.2 million, $4.4 million and $4.0 million, respectively, of which $2.3 million, $1.1 million and $4.0 million were payable at each respective balance sheet date for legal services performed by Vinson & Elkins L.L.P.

Service Fee Agreement

The Company entered into service fee agreements with Apollo Funds and Riverstone Funds for the provision of certain management consulting and advisory services. Under each agreement, the Company paid a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however, such fees did not exceed in each case $0.5 million, in aggregate, for any calendar year. For the years ended December 31, 2019, 2018 and 2017, the Company incurred approximately nil, $0.5 million and $0.5 million, respectively, for these services. These fees are recognized in general and administrative expense on the consolidated statements of operations. In connection with the Stone Combination on May 10, 2018, the Service Fee Agreement was terminated.

Debt Modification Work Fees

In 2018, the Company paid $9.3 million in work fees to holders of the 11.00% Bridge Loans and 7.50% Notes to exchange into 11.00% Notes as a result of the Stone Combination. The Apollo Funds and Riverstone Funds received $4.1 million and the Franklin Noteholders and McKay Noteholders received $3.3 million as a result of the work fees paid.

Note 12 — Commitments and Contingencies

Legal Proceedings and Other Contingencies

The Company is named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. The Company does not expect that these matters, individually or in the aggregate, will have a material adverse effect on its financial condition.

Performance Obligations

Regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities and to guarantee the execution of the minimum work program under the Mexico production sharing contracts. As of December 31, 2019 and 2018, the Company had secured performance bonds totaling approximately $637.3 million and $644.1 million, respectively. As of December 31, 2019 and 2018, the Company had $13.6 million and $14.7 million, respectively, in letters of credit issued under its Bank Credit Facility.

The table below summarizes the Company’s total minimum commitments associated with vessel commitments and purchase obligations as of December 31, 2019 (in thousands):

	2020		2021		2022		2023		Thereafter		Total
Vessel Commitments⁽¹⁾	$	28,260	$	—	$	—	$	—	$	—	$	28,260
Committed purchase orders⁽²⁾		61,434		—		—		—		—		61,434
Total	$	89,694	$	—	$	—	$	—	$	—	$	89,694

⁽¹⁾

Includes vessel commitments the Company will utilize for certain deep water well intervention and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

⁽²⁾	Includes committed purchase orders to execute planned future drilling and completion activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

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Note 13 — Condensed Consolidating Financial Information

Talos Energy Inc. owns no operating assets and has no operations independent of its subsidiaries. Talos Production Inc. (formerly Talos Production LLC) and Talos Production Finance Inc. issued 11.00% Notes on May 10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by Talos Energy Inc. and certain 100% owned subsidiaries on a senior unsecured basis.

The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of the Company’s results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

F-36

TALOS ENERGY INC.

CONSOLIDATING BALANCE SHEET

AS OF December 31, 2019

(In thousands)

	Parent		Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	78,780		$	593		$	7,649		$	—		$	87,022
Restricted cash		—		—			—			—			—			—
Accounts receivable
Trade, net		—		—			107,842			—			—			107,842
Joint interest, net		—		—			11,567			4,985			—			16,552
Other		—		474			5,555			317			—			6,346
Assets from price risk management activities		—		8,393			—			—			—			8,393
Prepaid assets		—		33,323			32,529			25			—			65,877
Income tax receivable		—		—			116			—			—			116
Other current assets		—		—			1,836			—			—			1,836
Total current assets		—		120,970			160,038			12,976			—			293,984
Property and equipment:
Proved properties		—		—			4,066,260			—			—			4,066,260
Unproved properties, not subject to amortization		—		—			87,618			106,914			—			194,532
Other property and equipment		—		23,142			6,484			217			—			29,843
Total property and equipment		—		23,142			4,160,362			107,131			—			4,290,635
Accumulated depreciation, depletion and amortization		—		(11,001	)		(2,053,971	)		(51	)		—			(2,065,023	)
Total property and equipment, net		—		12,141			2,106,391			107,080			—			2,225,612
Other long-term assets:
Other well equipment inventory		—		—			7,732			—			—			7,732
Operating lease assets		—		3,178			3,224			1,377			—			7,779
Investments in subsidiaries		1,045,886		1,690,362			—			—			(2,736,248	)		—
Other assets		33,371		364			2,136			18,504			—			54,375
		1,079,257		1,827,015			2,279,521			139,937			(2,736,248	)		2,589,482
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable		428		5,145			58,827			6,957			—			71,357
Accrued liabilities		—		4,740			145,051			5,025			—			154,816
Accrued royalties		—		—			31,729			—			—			31,729
Current portion of asset retirement obligations		—		—			61,051			—			—			61,051
Liabilities from price risk management activities		—		19,476			—			—			—			19,476
Accrued interest payable		—		10,211			38			—			—			10,249
Current portion of operating lease liabilities		—		196			821			577			—			1,594
Other current liabilities		255		—			19,925			—			—			20,180
Total current liabilities		683		39,768			317,442			12,559			—			370,452
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		—		726,921			6,060			—			—			732,981
Asset retirement obligations		—		—			308,427			—			—			308,427
Liabilities from price risk management activities		—		511			—			—			—			511
Operating lease liabilities		—		13,929			2,416			894			—			17,239
Other long-term liabilities		297		—			81,298			—			—			81,595
Total liabilities		980		781,129			715,643			13,453			—			1,511,205
Commitments and Contingencies (Note 12)
Stockholders' equity		1,078,277		1,045,886			1,563,878			126,484			(2,736,248	)		1,078,277
	$	1,079,257	$	1,827,015		$	2,279,521		$	139,937		$	(2,736,248	)	$	2,589,482

F-37

TALOS ENERGY INC.

CONSOLIDATING BALANCE SHEET

AS OF December 31, 2018

(In thousands)

	Parent		Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	13,541		$	100,801		$	25,572		$	—		$	139,914
Restricted cash		—		—			1,248			—			—			1,248
Accounts receivable
Trade, net		—		—			103,025			—			—			103,025
Joint interest, net		—		—			15,870			4,374			—			20,244
Other		—		3,100			9,566			7,020			—			19,686
Assets from price risk management activities		—		75,473			—			—			—			75,473
Prepaid assets		—		1,225			37,639			47			—			38,911
Income tax receivable		—		—			10,701			—			—			10,701
Other current assets		—		—			7,644			—			—			7,644
Total current assets		—		93,339			286,494			37,013			—			416,846
Property and equipment:
Proved properties		—		—			3,629,430			—			—			3,629,430
Unproved properties, not subject to amortization		—		—			63,104			45,105			—			108,209
Other property and equipment		—		20,670			12,440			81			—			33,191
Total property and equipment		—		20,670			3,704,974			45,186			—			3,770,830
Accumulated depreciation, depletion and amortization		—		(8,310	)		(1,711,288	)		(11	)		—			(1,719,609	)
Total property and equipment, net		—		12,360			1,993,686			45,175			—			2,051,221
Other long-term assets:
Other well equipment inventory		—		—			9,224			—			—			9,224
Investments in subsidiaries		1,011,359		1,560,922			—			—			(2,572,281	)		—
Other assets		—		364			2,258			73			—			2,695
		1,011,359		1,666,985			2,291,662			82,261			(2,572,281	)		2,479,986
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable		144		1,242			42,736			6,897			—			51,019
Accrued liabilities		—		4,995			159,491			24,164			—			188,650
Accrued royalties		—		—			38,520			—			—			38,520
Current portion of long-term debt		—		—			443			—			—			443
Current portion of asset retirement obligations		—		—			68,965			—			—			68,965
Liabilities from price risk management activities				550			—			—			—			550
Accrued interest payable		—		10,162			38			—			—			10,200
Other current liabilities		—		—			22,071			—			—			22,071
Total current liabilities		144		16,949			332,264			31,061			—			380,418
Long-term debt, net of discount and deferred financing costs		—		638,677			16,184			—			—			654,861
Asset retirement obligations		—		—			313,852			—			—			313,852
Other long-term liabilities		3,719		—			119,432			208			—			123,359
Total liabilities		3,863		655,626			781,732			31,269			—			1,472,490
Commitments and Contingencies (Note 12)
Stockholders' equity		1,007,496		1,011,359			1,509,930			50,992			(2,572,281	)		1,007,496
	$	1,011,359	$	1,666,985		$	2,291,662		$	82,261		$	(2,572,281	)	$	2,479,986

F-38

TALOS ENERGY INC.

CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE YEAR ENDED December 31, 2019

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non-Guarantors			Elimination			Consolidated
Revenues:
Oil revenue	$	—		$	—		$	832,909		$	209		$	—		$	833,118
Natural gas revenue		—			—			55,278			—			—			55,278
NGL revenue		—			—			19,668			—			—			19,668
Other		—			—			19,556			—			—			19,556
Total revenue		—			—			927,411			209			—			927,620
Operating expenses:
Lease operating expense		—			—			243,427			—			—			243,427
Production taxes		—			—			1,349			—			—			1,349
Depreciation, depletion and amortization		—			2,690			343,201			40			—			345,931
Write-down of oil and natural gas properties		—			—			—			12,221			—			12,221
Accretion expense		—			—			34,389			—			—			34,389
General and administrative expense		1,107			31,567			40,863			3,672			—			77,209
Total operating expenses		1,107			34,257			663,229			15,933			—			714,526
Operating income (loss)		(1,107	)		(34,257	)		264,182			(15,724	)		—			213,094
Interest expense		(7	)		(67,582	)		(29,603	)		(655	)		—			(97,847	)
Price risk management activities expenses		—			(95,337	)		—			—			—			(95,337	)
Other income (loss)		—			1,060			1,794			(176	)		—			2,678
Income tax expense (benefit)		36,579			(1	)		(313	)		(124	)		—			36,141
Equity earnings from subsidiaries		23,263			219,380			—			—			(242,643	)		—
Net income (loss)	$	58,728		$	23,263		$	236,060		$	(16,679	)	$	(242,643	)	$	58,729

F-39

TALOS ENERGY INC.

CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE YEAR ENDED December 31, 2018

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non-Guarantors			Elimination			Consolidated
Revenues:
Oil revenue	$	—		$	—		$	781,815		$	—		$	—		$	781,815
Natural gas revenue		—			—			73,610			—			—			73,610
NGL revenue		—			—			35,863			—			—			35,863
Total revenue		—			—			891,288			—			—			891,288
Operating expenses:
Lease operating expense		—			—			226,291			—			—			226,291
Production taxes		—			—			1,989			—			—			1,989
Depreciation, depletion and amortization		—			1,955			286,760			4			—			288,719
Accretion expense		—			—			35,344			—			—			35,344
General and administrative expense		142			43,841			40,035			1,798			—			85,816
Total operating expenses		142			45,796			590,419			1,802			—			638,159
Operating income (loss)		(142	)		(45,796	)		300,869			(1,802	)		—			253,129
Interest expense		—			(58,172	)		(30,255	)		(1,687	)		—			(90,114	)
Price risk management activities income		—			50,025			10,410			—			—			60,435
Other income (loss)		—			(1,563	)		874			1,701			—			1,012
Income tax expense		(1,065	)		—			(360	)		(1,497	)		—			(2,922	)
Equity earnings from subsidiaries		222,747			278,253			—			—			(501,000	)		—
Net income (loss)	$	221,540		$	222,747		$	281,538		$	(3,285	)	$	(501,000	)	$	221,540

F-40

TALOS ENERGY INC.

CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2017

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non-Guarantors			Elimination		Consolidated
Revenues:
Oil revenue	$	—		$	—		$	344,781		$	—		$	—	$	344,781
Natural gas revenue		—			—			48,886			—			—		48,886
NGL revenue		—			—			16,658			—			—		16,658
Other		—			—			2,503			—			—		2,503
Total revenue		—			—			412,828			—			—		412,828
Operating expenses:
Lease operating expense		—			—			152,748			—			—		152,748
Production taxes		—			—			1,460			—			—		1,460
Depreciation, depletion and amortization		—			1,401			155,947			4			—		157,352
Accretion expense		—			—			19,295			—			—		19,295
General and administrative expense		—			21,882			14,172			619			—		36,673
Total operating expenses		—			23,283			343,622			623			—		367,528
Operating income (loss)		—			(23,283	)		69,206			(623	)		—		45,300
Interest expense		—			(48,236	)		(30,252	)		(2,446	)		—		(80,934	)
Price risk management activities expense		—			(22,998	)		(4,565	)		—			—		(27,563	)
Other income (expense)		—			600			(333	)		62			—		329
Equity earnings (losses) from subsidiaries		(62,868	)		31,049			—			—			31,819		—
Net income (loss)	$	(62,868	)	$	(62,868	)	$	34,056		$	(3,007	)	$	31,819	$	(62,868	)

F-41

TALOS ENERGY INC.

CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED December 31, 2019

(In thousands)

	Parent			Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(828	)	$	(95,960	)	$	512,956		$	(22,435	)	$	—		$	393,733
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—			(1,614	)		(380,622	)		(81,173	)		—			(463,409	)
Cash paid for acquisitions, net of cash acquired		—			—			(37,916	)		—			—			(37,916	)
Investments in subsidiaries		—			(1,580,833	)		—			—			1,580,833			—
Proceeds from sale of other property and equipment		—			—			5,369			—			—			5,369
Distributions from subsidiaries		—			1,660,609			—			—			(1,660,609	)		—
Net cash provided by (used in) investing activities		—			78,162			(413,169	)		(81,173	)		(79,776	)		(495,956	)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt		—			—			(10,567	)		—			—			(10,567	)
Proceeds from Bank Credit Facility		—			110,000			—			—			—			110,000
Repayment of Bank Credit Facility		—			(25,000	)		—			—			—			(25,000	)
Repayment of LLC Bank Credit Facility		—			—			—			—			—			—
Deferred financing costs		—			(1,963	)		—			—			—			(1,963	)
Other deferred payments		—			—			(9,921	)		—			—			(9,921	)
Payment of capital lease		—			—			(14,133	)		—			—			(14,133	)
Employee stock transactions		—			—			(333	)		—			—			(333	)
Capital contributions		828			—			1,350,086			229,919			(1,580,833	)		—
Distributions to Subsidiary Issuer		—			—			(1,516,375	)		(144,234	)		1,660,609			—
Net cash provided by (used in) financing activities		828			83,037			(201,243	)		85,685			79,776			48,083

Net increase (decrease) in cash, cash equivalents and restricted cash		—			65,239			(101,456	)		(17,923	)		—			(54,140	)
Cash, cash equivalents and restricted cash
Balance, beginning of period		—			13,541			102,049			25,572			—			141,162
Balance, end of period	$	—		$	78,780		$	593		$	7,649		$	—		$	87,022

F-42

TALOS ENERGY INC.

CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED December 31, 2018

(In thousands)

	Parent		Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	—	$	(193,088	)	$	442,890		$	13,643		$	—		$	263,445
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—		(13,404	)		(227,228	)		(282	)		—			(240,914	)
Cash paid for acquisitions, net of cash acquired		—		—			278,409			—			—			278,409
Investments in subsidiaries		—		(1,316,588	)		—			—			1,316,588			—
Proceeds from sale of other property and equipment		—		—			—			—			—			—
Distributions from subsidiaries		—		1,694,460			9			—			(1,694,469	)		—
Net cash provided by (used in) investing activities		—		364,468			51,190			(282	)		(377,881	)		37,495
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt		—		(25,152	)		(105	)		—			—			(25,257	)
Proceeds from Bank Credit Facility		—		319,000			—			—			—			319,000
Repayment of Bank Credit Facility		—		(54,000	)		—			—			—			(54,000	)
Repayment of LLC Bank Credit Facility		—		(403,000	)		—			—			—			(403,000	)
Deferred financing costs		—		(17,002	)		—			—			—			(17,002	)
Other deferred payments		—		—			—			—			—			—
Payment of capital lease		—		—			(12,952	)		—			—			(12,952	)
Employee stock transactions		—		—			—			—			—			—
Capital contributions		—		—			1,301,876			14,712			(1,316,588	)		—
Distributions to Subsidiary Issuer		—		—			(1,689,898	)		(4,571	)		1,694,469			—
Net cash provided by (used in) financing activities		—		(180,154	)		(401,079	)		10,141			377,881			(193,211	)

Net increase (decrease) in cash, cash equivalents and restricted cash		—		(8,774	)		93,001			23,502			—			107,729
Cash, cash equivalents and restricted cash
Balance, beginning of period		—		22,315			9,048			2,070			—			33,433
Balance, end of period	$	—	$	13,541		$	102,049		$	25,572		$	—		$	141,162

F-43

TALOS ENERGY INC.

CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2017

(In thousands)

	Parent		Subsidiary Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	—	$	(30,245	)	$	204,419		$	1,879		$	—		$	176,053
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—		(260	)		(132,317	)		(22,600	)		—			(155,177	)
Cash paid for acquisitions, net of cash acquired		—		—			(2,464	)		—			—			(2,464	)
Investments in subsidiaries		—		(577,055	)		—			—			577,055			—
Proceeds from sale of other property and equipment		—		—			—			—			—			—
Distributions from subsidiaries		—		611,526			6,041			—			(617,567	)		—
Net cash provided by (used in) investing activities		—		34,211			(128,740	)		(22,600	)		(40,512	)		(157,641	)
Cash flows from financing activities:
Redemption of 2018 Senior Notes		—		(1,000	)		—			—			—			(1,000	)
Proceeds from Bank Credit Facility		—		10,000			—			—			—			10,000
Repayment of Bank Credit Facility		—		(15,000	)		—			—			—			(15,000	)
Payments of capital lease		—		—			(12,412	)		—			—			(12,412	)
Capital contributions		—		—			550,555			26,500			(577,055	)		—
Distributions to subsidiaries		—		—			(611,526	)		(6,041	)		617,567			—
Net cash provided by (used in) financing activities		—		(6,000	)		(73,383	)		20,459			40,512			(18,412	)

Net increase (decrease) in cash, cash equivalents and restricted cash		—		(2,034	)		2,296			(262	)		—			—
Cash, cash equivalents and restricted cash:
Balance, beginning of period		—		24,349			6,752			2,332			—			33,433
Balance, end of period	$	—	$	22,315		$	9,048		$	2,070		$	—		$	33,433

F-44

Note 14 —Selected Quarterly Financial Data (Unaudited)

Unaudited quarterly financial data are as follows (in thousands):

	March 31			June 30			September 30			December 31
Quarter Ended 2019
Revenues	$	178,713		$	286,810		$	228,857		$	233,240
Operating income	$	18,369		$	94,872		$	52,883		$	46,970
Price risk management activities income (expense)	$	(109,579	)	$	29,990		$	43,760		$	(59,508	)
Net income (loss)	$	(109,636	)	$	94,764		$	73,297		$	304
Net income (loss) per common share:
Basic	$	(2.02	)	$	1.75		$	1.35		$	0.01
Diluted	$	(2.02	)	$	1.74		$	1.35		$	0.01
Weighted average common shares outstanding:
Basic		54,156			54,178			54,200			54,203
Diluted		54,156			54,451			54,430			54,559
Quarter Ended 2018
Revenues	$	145,850		$	203,906		$	282,868		$	258,664
Operating income	$	48,584		$	39,211		$	91,361		$	73,973
Price risk management activities income (expense)	$	(51,976	)	$	(91,176	)	$	(53,330	)	$	256,917
Net income (loss)	$	(22,943	)	$	(74,912	)	$	13,109		$	306,286
Net income (loss) per common share:
Basic	$	(0.73	)	$	(1.69	)	$	0.24		$	5.66
Diluted	$	(0.73	)	$	(1.69	)	$	0.24		$	5.66
Weighted average common shares outstanding:
Basic		31,244			44,336			54,156			54,156
Diluted		31,244			44,336			54,164			54,159

Note 15 —Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands):

	Year Ended December 31,
	2019			2018
Proved properties	$	4,066,260		$	3,629,430
Unproved oil and gas properties, not subject to amortization⁽¹⁾		194,532			108,209
Total oil and gas properties		4,260,792			3,737,639
Less: Accumulated depletion		(2,051,856	)		(1,709,614	)
Net capitalized costs	$	2,208,936		$	2,028,025
Depletion and amortization rate (Per Boe)	$	18.05		$	17.07

⁽¹⁾	Amount includes $106.9 million and $45.1 million of unproved properties, not subject to amortization related to the Company’s Mexico properties for the year ended December 31, 2019 and 2018, respectively.

Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as asset retirement obligations in the accompanying consolidated balance sheets. At December 31, 2019 and 2018, the Company’s liability for oil and gas asset retirement obligations totaled $369.5 million and $382.8 million, respectively.

F-45

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year.

	Year Ended December 31,
	2019		2018		2017
Property acquisition costs:
Proved properties	$	27,660	$	850,515	$	1,108
Unproved properties, not subject to amortization		16,062		65,063		5,778
Total property acquisition costs		43,722		915,578		6,886
Exploration costs⁽¹⁾		209,161		93,780		82,887
Development costs		292,547		215,467		114,846
Total costs incurred	$	545,430	$	1,224,825	$	204,619

⁽¹⁾	Amount includes $74.2 million, $16.9 million and $22.8 million of exploration costs related to the Company’s Mexico properties for the year ended December 31, 2019, 2018 and 2017, respectively.

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. The Company’s Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located in the United States primarily offshore Gulf of Mexico.

At December 31, 2019, 2018 and 2017, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists.

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The following table presents the Company’s estimated proved reserves at its net ownership interest:

	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			Oil Equivalent (MBoe)
Total proved reserves at December 31, 2016		72,366			150,604			6,236			103,702
Revision of previous estimates		(2,673	)		(15,860	)		250			(5,067	)
Production		(7,048	)		(16,308	)		(706	)		(10,472	)
Extensions and discoveries		10,159			9,220			767			12,462
Total proved reserves at December 31, 2017		72,804			127,656			6,547			100,625
Revision of previous estimates		2,595			(37,933	)		3,187			(539	)
Production		(11,771	)		(22,771	)		(1,176	)		(16,742	)
Purchases of reserves		44,788			95,661			2,074			62,806
Extensions and discoveries		4,123			8,411			64			5,589
Total proved reserves at December 31, 2018		112,539			171,024			10,696			151,739
Revision of previous estimates		(5,553	)		(15,898	)		(1,237	)		(9,440	)
Production		(13,844	)		(23,306	)		(1,228	)		(18,956	)
Purchases of reserves		2,094			2,626			130			2,662
Extensions and discoveries		11,518			21,552			620			15,730
Total proved reserves at December 31, 2019		106,754			155,998			8,981			141,735
Total proved developed reserves as of:
December 31, 2017		37,460			77,577			3,315			53,704
December 31, 2018		85,530			131,364			8,104			115,528
December 31, 2019		72,016			115,381			6,733			97,979
Total proved undeveloped reserves as of:
December 31, 2017		35,344			50,079			3,232			46,921
December 31, 2018		27,009			39,660			2,592			36,211
December 31, 2019		34,738			40,617			2,248			43,756

⁽²⁾	Excludes approximately 3.0 MBoe of Mexico well test production

During 2019, proved reserves decreased by 10.0 MMBoe primarily due to a decrease of 19.0 MMBoe of production and revision to previous estimates of 9.7 MMBoe due to the Phoenix and Ram Powell Fields. The decrease was partially offset by the addition of 15.7 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon 21, Pompano, and Ewing Bank 305 as well as 3.0 MMBoe added through purchases from the Gunflint Acquisition.

During 2018, the Company added 51.1 MMBoe of estimated proved reserves, which included 62.8 MMBoe added through purchases of 59.3 MMBoe from the Stone Combination and 3.5 MMBoe from the Whistler Acquisition. The Company also added 5.6 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon Block 18. The increase was partially offset by a decrease of 16.7 MMBoe of production.

During 2017, the Company added 12.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from drilling the Tornado 2 exploration prospect in the Phoenix Field. The increase was offset by a decrease of 10.5 MMBoe of production and 5.1 MMBoe of negative performance revisions.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands):

	Year Ended December 31,
	2019			2018			2017
Future cash inflows	$	7,151,875		$	8,654,631		$	4,308,863
Future costs:
Production		(1,633,432	)		(1,740,850	)		(815,509	)
Development and abandonment		(1,464,270	)		(1,349,005	)		(823,164	)
Future net cash flows before income taxes		4,054,173			5,564,776			2,670,190
Future income tax expense ⁽¹⁾		(662,317	)		(862,473	)		—
Future net cash flows after income taxes		3,391,856			4,702,303			2,670,190
Discount at 10% annual rate		(854,261	)		(1,362,057	)		(862,521	)
Standardized measure of discounted future net cash flows	$	2,537,595		$	3,340,246		$	1,807,669

⁽¹⁾	For December 31, 2017, the standardized measure of discounted future net cash flows did not include the impact of future federal income taxes because Talos Energy LLC was not subject to federal income taxes prior to the Stone Combination.

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for base prices used in determining the standardized measure:

	Year Ended December 31,
	2019		2018		2017
Oil price per Bbl	$	61.01	$	69.42	$	51.36
Natural gas price per Mcf	$	2.59	$	3.08	$	3.20
NGL price per Bbl	$	26.17	$	29.50	$	24.64

Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.

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Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands):

	Year Ended December 31,
	2019			2018			2017
Standardized measure, beginning of year	$	3,340,246		$	1,807,669		$	1,336,035
Sales and transfers of oil, net gas and NGLs produced during the period		(665,226	)		(727,969	)		(288,942	)
Net change in prices and production costs		(849,696	)		1,578,330			555,100
Changes in estimated future development costs		(75,564	)		32,328			(156,282	)
Previously estimated development costs incurred		117,049			45,937			146,687
Accretion of discount		392,526			180,767			133,603
Net change in income taxes⁽¹⁾		129,590			(585,017	)		—
Purchases of reserves		75,009			943,519			—
Extensions and discoveries		306,515			148,068			328,565
Net change due to revision in quantity estimates		(199,576	)		190,853			(113,629	)
Changes in production rates (timing) and other		(33,278	)		(274,239	)		(133,468	)
Standardized measure, end of year	$	2,537,595		$	3,340,246		$	1,807,669

⁽¹⁾	For December 31, 2017, the standardized measure of discounted future net cash flows did not include the impact of future federal income taxes because Talos Energy LLC was not subject to federal income taxes prior to the Stone Combination.

Note 16 —Subsequent Events

ILX and Castex Acquisition

For additional information, see Note 3 — Acquisitions.

Derivative Contracts

For additional information, see Note 6 — Financial Instruments.

Debt

For additional information, see Note 7 — Debt.

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