talo-10q_20210331.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2021

☐	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: 001-38497

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

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, a 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 Exchange Act). Yes ☐ No ☒

As of April 28, 2021, the registrant had 81,707,594 shares of common stock, $0.01 par value per share, outstanding.

TABLE OF CONTENTS

		Page
GLOSSARY		1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		3
	PART I — FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	36
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults Upon Senior Securities	37
Item 4.	Mine Safety Disclosures	37
Item 5.	Other Information	37
Item 6.	Exhibits	38
	Signatures	40

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.

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.

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

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

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.

MMcf — One million cubic feet of natural gas.

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

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.

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-K.

SEC — The U.S. Securities and Exchange Commission.

SEC pricing — The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the prior twelve months, 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 of up to 600 feet.

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 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:

•

business strategy;

•

reserves;

•

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

•

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

•

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

•

realized oil and natural gas prices;

•

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

•

our hedging strategy and results;

•

future drilling plans;

•

availability of pipeline connections on economic terms;

•

competition, government regulations and political developments;

•

our ability to obtain permits and governmental approvals;

•

pending legal, governmental or environmental matters;

•

our marketing of oil, natural gas and NGLs;

•

leasehold or business acquisitions on desired terms;

•

costs of developing properties;

•

general economic conditions;

•

credit markets;

•

impact of new accounting pronouncements on earnings in future periods;

•

estimates of future income taxes;

•

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

•

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

•

plans, objectives, expectations and intentions contained in this Quarterly 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 due to the continued impact of the coronavirus disease 2019 (“COVID-19”) and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business; the ability or willingness of the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC countries, such as Saudi Arabia and Russia, to set and maintain oil production levels; the impact of any such actions; lack of transportation and storage capacity as a result of oversupply, government and regulations; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, and winter storms; inflation; 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 our 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” of Talos Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2020 (the “2020 Annual Report”).

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 Quarterly Report on Form 10-Q (this “Quarterly Report”).

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

	March 31, 2021			December 31, 2020
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	64,979		$	34,233
Accounts receivable
Trade, net		135,415			106,220
Joint interest, net		42,020			50,471
Other		13,371			18,448
Assets from price risk management activities		1,720			6,876
Prepaid assets		32,733			29,285
Other current assets		1,761			1,859
Total current assets		291,999			247,392
Property and equipment:
Proved properties		4,996,802			4,945,550
Unproved properties, not subject to amortization		266,321			254,994
Other property and equipment		33,086			32,853
Total property and equipment		5,296,209			5,233,397
Accumulated depreciation, depletion and amortization		(2,798,885	)		(2,697,228	)
Total property and equipment, net		2,497,324			2,536,169
Other long-term assets:
Assets from price risk management activities		2,123			945
Other well equipment inventory		20,069			18,927
Operating lease assets		6,722			6,855
Other assets		21,457			24,258
Total assets	$	2,839,694		$	2,834,546
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	72,770		$	104,864
Accrued liabilities		140,552			163,379
Accrued royalties		42,741			27,903
Current portion of asset retirement obligations		45,478			49,921
Liabilities from price risk management activities		133,167			66,010
Accrued interest payable		20,410			9,509
Current portion of operating lease liabilities		1,927			1,793
Other current liabilities		25,192			24,155
Total current liabilities		482,237			447,534
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		1,049,365			985,512
Asset retirement obligations		406,690			392,348
Liabilities from price risk management activities		27,617			9,625
Operating lease liabilities		18,015			18,554
Other long-term liabilities		48,616			54,372
Total liabilities		2,032,540			1,907,945
Commitments and contingencies (Note 11)
Stockholdersʼ Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of March 31, 2021 and December 31, 2020		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 81,707,214 and 81,279,989 shares issued and outstanding as of March 31, 2021 and December 31, 2020, respectively		817			813
Additional paid-in capital		1,661,840			1,659,800
Accumulated deficit		(855,503	)		(734,012	)
Total stockholdersʼ equity		807,154			926,601
Total liabilities and stockholdersʼ equity	$	2,839,694		$	2,834,546

See accompanying notes.

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share amounts)

(Unaudited)

	Three Months Ended March 31,
	2021			2020
Revenues and other:
Oil	$	229,561		$	166,624
Natural gas		28,234			11,898
NGL		9,113			4,301
Other		1,000			4,941
Total revenues and other		267,908			187,764
Operating expenses:
Lease operating expense		66,628			58,241
Production taxes		822			249
Depreciation, depletion and amortization		101,657			93,543
Write-down of oil and natural gas properties		—			57
Accretion expense		14,985			12,417
General and administrative expense		19,189			27,469
Total operating expenses		203,281			191,976
Operating income (expense)		64,627			(4,212	)
Interest expense		(34,076	)		(25,850	)
Price risk management activities income (expense)		(137,508	)		243,217
Other expense		(13,950	)		(146	)
Net income (loss) before income taxes		(120,907	)		213,009
Income tax expense		(584	)		(55,260	)
Net income (loss)	$	(121,491	)	$	157,749

Net income (loss) per common share:
Basic	$	(1.49	)	$	2.71
Diluted	$	(1.49	)	$	2.69
Weighted average common shares outstanding:
Basic		81,435			58,240
Diluted		81,435			58,572

See accompanying notes.

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

	Shares						Par Value						Additional						Total
	Common Stock			Preferred Stock			Common Stock			Preferred Stock			Paid- In Capital			Accumulated Deficit			Stockholders Equity
Balance at December 31, 2019		54,197,004			—		$	542		$	—		$	1,346,142		$	(268,407	)	$	1,078,277
Equity based compensation		200,077			—			—			—			3,381			—			3,381
Shares withheld for taxes on equity transactions		(54,808	)		—			—			—			(710	)		—			(710	)
Issuances of preferred shares (Note 2)		—			110,000			—			1			156,199						156,200
Conversion of preferred shares into common shares (Note 2)		11,000,000			(110,000	)		110			(1	)		(109	)					—
Net income		—			—			—			—			—			157,749			157,749
Balance at March 31, 2020		65,342,273			—		$	652		$	—		$	1,504,903		$	(110,658	)	$	1,394,897

Balance at December 31, 2020		81,279,989			—		$	813		$	—		$	1,659,800		$	(734,012	)		926,601
Equity based compensation		586,437			—			6			—			4,188			—			4,194
Shares withheld for taxes on equity transactions		(159,212	)		—			(2	)		—			(2,148	)		—			(2,150	)
Net loss		—			—			—			—			—			(121,491	)		(121,491	)
Balance at March 31, 2021		81,707,214			—		$	817		$	—		$	1,661,840		$	(855,503	)	$	807,154

See accompanying notes.

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2021			2020
Cash flows from operating activities:
Net income (loss)	$	(121,491	)	$	157,749
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense		116,642			105,960
Write-down of oil and natural gas properties and other well inventory		—			190
Amortization of deferred financing costs and original issue discount		3,142			1,466
Equity based compensation, net of amounts capitalized		2,664			1,627
Price risk management activities expense (income)		137,508			(243,217	)
Net cash received (paid) on settled derivative instruments		(48,381	)		36,460
Loss on extinguishment of debt		13,225			—
Settlement of asset retirement obligations		(10,120	)		(6,302	)
Gain on sale of assets		(319	)		—
Changes in operating assets and liabilities:
Accounts receivable		(17,108	)		(11,578	)
Other current assets		(3,350	)		18,318
Accounts payable		(10,978	)		(18,547	)
Other current liabilities		5,328			13,337
Other non-current assets and liabilities, net		194			54,769
Net cash provided by operating activities		66,956			110,232
Cash flows from investing activities:
Exploration, development and other capital expenditures		(64,745	)		(83,588	)
Cash paid for acquisitions, net of cash acquired		(8,322	)		(293,095	)
Proceeds from sale of oil and gas properties		330			—
Net cash used in investing activities		(72,737	)		(376,683	)
Cash flows from financing activities:
Issuance of Senior Notes		600,500			—
Redemption of Senior Notes and other long-term debt		(356,803	)		—
Proceeds from Bank Credit Facility		—			300,000
Repayment of Bank Credit Facility		(175,000	)		—
Deferred financing costs		(19,387	)		(1,285	)
Other deferred payments		(5,575	)		(7,575	)
Payments of finance lease		(5,058	)		(4,049	)
Employee stock transactions		(2,150	)		(710	)
Net cash provided by financing activities		36,527			286,381

Net increase in cash, cash equivalents and restricted cash		30,746			19,930
Cash, cash equivalents and restricted cash:
Balance, beginning of period		34,233			87,022
Balance, end of period	$	64,979		$	106,952

Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	65,755		$	66,712
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	$	13,712		$	4,906

See accompanying notes.

TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2021

(Unaudited)

Note 1 — Nature of Business and Basis of Presentation

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 its 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.

Basis of Presentation and Consolidation

The Condensed Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Accordingly, certain information and disclosures normally included in complete financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, these financial statements include all adjustments, which unless otherwise disclosed, are of a normal recurring nature, necessary for a fair presentation of the financial position, results of operations, cash flows and changes in equity for the periods presented. The results for interim periods are not necessarily indicative of results for the entire year. The Company has evaluated subsequent events through the date the Condensed Consolidated Financial Statements were issued. The unaudited financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s audited Consolidated Financial Statements and related notes included in the 2020 Annual Report.

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.

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

Note 2 — Acquisitions

Asset Acquisitions

Acquisitions qualifying as an asset acquisition requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the Condensed Consolidated Balance Sheets 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 LLOG Properties — On November 16, 2020, the Company completed the acquisition of select oil and natural gas assets from LLOG Exploration & Production Company, L.L.C. with an effective date of August 1, 2020 (the “LLOG Acquisition”). The oil and natural gas assets consist of interests in the Mississippi Canyon core area. The LLOG Acquisition was consummated pursuant to a Purchase and Sale Agreement executed on November 16, 2020 for $13.2 million in cash, inclusive of customary closing adjustments and $0.2 million of transaction related expenses.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on November 16, 2020 (in thousands):

Property and equipment	$	17,421
Asset retirement obligations		(4,234	)
Allocated purchase price	$	13,187

Acquisition of Castex Energy 2005 — On August 5, 2020, the Company completed the acquisition of select oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC with an effective date of April 1, 2020 (the “Castex Energy 2005 Acquisition”). The oil and natural gas assets consist of interests in 16 properties in the U.S. Gulf of Mexico Shelf and Gulf Coast core area. The Castex Energy 2005 Acquisition was consummated pursuant to a Purchase and Sale Agreement dated June 19, 2020 for consideration consisting of (i) $6.5 million in cash, (ii) 4.6 million shares of the Company’s common stock and (iii) $1.4 million in transaction related expenses, inclusive of customary closing adjustments.

The following table summarizes the purchase price, inclusive of customary closing adjustments (in thousands except share and per share data):

Talos common stock		4,602,460
Talos common stock price per share⁽¹⁾	$	7.69
Talos common stock value	$	35,393

Cash consideration	$	6,500
Transaction cost	$	1,413

Total purchase price	$	43,306

⁽¹⁾	Represents the closing price of the Company’s common stock on August 5, 2020, the date of the closing of the Castex Energy 2005 Acquisition.

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 5, 2020 (in thousands):

Property and equipment	$	46,626
Asset retirement obligations		(3,320	)
Allocated purchase price	$	43,306

Business Combination

Acquisitions qualifying as business combinations are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the Condensed Consolidated Balance Sheets 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 February 28, 2020, the Company acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate of the Riverstone Funds (as defined below) (the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers”) with an effective date of July 1, 2019 (collectively, the “ILX and Castex Acquisition”). The ILX and Castex Acquisition was consummated pursuant to separate Purchase and Sale Agreements, dated December 10, 2019 (as amended from time to time, the “Purchase Agreements”) for aggregate consideration consisting of (i) $385.0 million in cash subject to customary closing adjustments and (ii) an aggregate 110,000 shares (the “Preferred Shares”) of a series of the Company’s preferred stock designated as “Series A Convertible Preferred Stock” which subsequently converted to 11.0 million shares of the Company’s common stock on March 30, 2020 (such common stock, the “Conversion Stock”). The cash payment and escrow deposit were funded with borrowings under the Bank Credit Facility (as defined below).

The following table summarizes the purchase price (in thousands except share and per share data):

Talos Conversion Stock		11,000,000
Talos common stock price per share⁽¹⁾	$	14.20
Conversion Stock value	$	156,200

Cash consideration	$	385,000
Customary closing and post-closing adjustments		(81,878	)
Net cash consideration	$	303,122

Total purchase price	$	459,322

⁽¹⁾

Represents the closing price of the Company’s common stock on February 28, 2020, the date of the closing of the ILX and Castex Acquisition. The purchase price was based on the value of the Conversion Stock as the value approximates the value of the Preferred Shares as a result of the automatic conversion and dividend rights described in that certain Certificate of Designation, Preferences, Rights and Limitations.

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on February 28, 2020 (in thousands):

Current assets⁽¹⁾	$	11,060
Property and equipment		496,835
Other long-term assets		148
Current liabilities		(16,520	)
Other long-term liabilities		(32,201	)
Allocated purchase price	$	459,322

⁽¹⁾	Includes trade and other receivables of $8.2 million, which the Company expects all to be realizable.

The Company incurred a total of $12.1 million of transaction related costs, of which nil and $7.5 million were incurred during the three months ended March 31, 2021 and 2020, respectively. These costs are reflected in “General and administrative expense” in the Condensed Consolidated Statements of Operations.

The following table presents revenue and net income attributable to the assets acquired in the ILX and Castex Acquisition:

	Three Months Ended March 31,
	2021		2020
Revenue	$	71,639	$	13,892
Net income	$	27,375	$	3,209

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three months ended March 31, 2020 as if the ILX and Castex Acquisition had occurred on January 1, 2020. The unaudited pro forma information was derived from historical statements of operations of the Company and the Sellers adjusted to (i) include depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) include interest expense to reflect borrowings under the Bank Credit Facility, (iii) eliminate the write-down of oil and natural gas properties on the assets acquired to reflect the pro-forma ceiling test calculation and (iv) include weighted average basic and diluted shares of common stock outstanding, which was calculated assuming the 11.0 million shares of Conversion Stock were issued to the Sellers. This information does not purport to be indicative of results of operations that would have occurred had the ILX and Castex Acquisition occurred on January 1, 2020, nor is such information indicative of any expected future results of operations.

	Three Months Ended March 31, 2020
Revenue	$	235,199
Net income	$	167,566
Basic net income per common share	$	2.56
Diluted net income per common share	$	2.55

Note 3 — 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 U.S. 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.

During the three months ended March 31, 2021 and 2020, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At March 31, 2021, the Company’s ceiling test computation was based on SEC pricing of $39.49 per Bbl of oil, $2.15 per Mcf of natural gas and $11.19 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.

Asset Retirement Obligations

The discounted asset retirement obligations included in the Condensed Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):

	March 31, 2021
Beginning asset retirement obligations	$	442,269
Fair value of asset retirement obligations acquired		4
Obligations settled		(10,120	)
Fair value of asset retirement obligations divested		(176	)
Accretion expense		14,985
Obligations incurred		—
Changes in estimate		5,206
Ending asset retirement obligations	$	452,168
Less: Current portion		(45,478	)
Long-term portion	$	406,690

Note 4 — 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 (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. 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.

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 may 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 depending on how the leased asset is utilized. The components of lease costs were as follows (in thousands):

	Three Months Ended March 31,
	2021		2020
Finance lease cost - interest on lease liabilities	$	3,256	$	4,265
Operating lease cost, excluding short-term leases⁽¹⁾		716		866
Short-term lease cost⁽²⁾		5,760		3,535
Variable lease cost⁽³⁾		322		3
Total lease cost	$	10,054	$	8,669

⁽¹⁾	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.

⁽²⁾	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 Condensed Consolidated Balance Sheets.

⁽³⁾	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):

	March 31, 2021		December 31, 2020
Operating leases:
Operating lease assets	$	6,722	$	6,855

Current portion of operating lease liabilities	$	1,927	$	1,793
Operating lease liabilities		18,015		18,554
Total operating lease liabilities	$	19,942	$	20,347

Finance leases:
Proved property	$	124,299	$	124,299

Other current liabilities	$	23,002	$	21,804
Other long-term liabilities		33,966		40,222
Total finance lease liabilities	$	56,968	$	62,026

The table below presents the lease maturity by year as of March 31, 2021 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the Condensed Consolidated Balance Sheet.

	Operating Leases			Finance Leases
2021 (excluding the three months ended March 31, 2021)	$	3,421		$	27,715
2022		4,302			33,257
2023		4,239			13,857
2024		3,315			—
2025		3,293			—
Thereafter		12,496			—
Total lease payments	$	31,066		$	74,829
Imputed interest		(11,124	)		(17,861	)
Total lease liabilities	$	19,942		$	56,968

The table below presents the weighted average remaining lease term and discount rate related to leases:

	Three Months Ended March 31,
	2021			2020
Weighted average remaining lease term:
Operating leases	7.6 years			8.3 years
Finance leases	2.2 years			3.2 years
Weighted average discount rate:
Operating leases		12.0	%		10.3	%
Finance leases		21.9	%		21.9	%

The table below presents the supplemental cash flow information related to leases (in thousands):

	Three Months Ended March 31,
	2021		2020
Operating cash outflow from finance leases	$	3,256	$	4,265
Financing cash outflow from finance leases	$	5,058	$	4,049
Operating cash outflow from operating leases	$	987	$	455

Note 5 — Financial Instruments

The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s financial instruments (in thousands):

	March 31, 2021						December 31, 2020
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
12.00% Second-Priority Senior Secured Notes – due January 2026	$	581,728		$	636,012		$	—		$	—
11.00% Second-Priority Senior Secured Notes – due April 2022	$	—		$	—		$	343,579		$	355,935
7.50% Senior Notes – due May 2022	$	6,060		$	3,333		$	6,060		$	5,238
Bank Credit Facility – matures May 2022	$	461,577		$	465,000		$	635,873		$	640,000
Oil and Natural Gas Derivatives	$	(156,941	)	$	(156,941	)	$	(67,814	)	$	(67,814	)

As of March 31, 2021 and December 31, 2020, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values because of the short-term nature of these instruments.

12.00% Second-Priority Senior Secured Notes – due January 2026

The $650.0 million aggregate principal amount of 12.00% Second-Priority Senior Secured Notes (the “12.00% Notes”) is reported on the Condensed Consolidated Balance Sheet as of March 31, 2021 at its carrying value, net of original issue discount and deferred financing costs, see Note 6 — Debt. The fair value of the 12.00% Notes is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

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

The $347.3 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) was redeemed on January 13, 2021, see Note 6 — Debt. The fair value of the 11.00% Notes prior to the redemption was 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% Senior Notes (the “7.50% Notes”) is reported on the Condensed Consolidated Balance Sheet as of March 31, 2021 at its carrying value, see Note 6 — 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 $960.0 million at March 31, 2021 (the “Bank Credit Facility”), which is reported on the Condensed Consolidated Balance Sheet as of March 31, 2021 at its carrying value net of deferred financing costs, see Note 6 — 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 Condensed Consolidated Balance Sheets 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 Condensed Consolidated Statements of Operations in each period.

The following table presents the impact that derivatives, not qualifying as hedging instruments, had on its Condensed Consolidated Statements of Operations (in thousands):

	Three Months Ended March 31,
	2021			2020
Net cash received (paid) on settled derivative instruments	$	(48,381	)	$	36,460
Unrealized gain (loss)		(89,127	)		206,757
Price risk management activities income (expense)	$	(137,508	)	$	243,217

The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of March 31, 2021:

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 2021 – December 2021	Swaps		24,429	$	44.89	$	—	$	—
April 2021 – December 2021	Collars		1,000	$	—	$	30.00	$	40.00
January 2022 – December 2022	Swaps		16,605	$	47.22	$	—	$	—
January 2023 – June 2023	Swaps		2,000	$	53.33	$	—	$	—
Crude Oil – LLS:		(Bbls)		(per Bbl)		(per Bbl)		(per Bbl)
April 2021 – December 2021	Swaps		3,335	$	41.06	$	—	$	—
Natural Gas – NYMEX Henry Hub:		(MMBtu)		(per MMBtu)		(per MMBtu)		(per MMBtu)
April 2021 – December 2021	Swaps		56,385	$	2.52	$	—	$	—
April 2021 – December 2021	Collars		5,000	$	—	$	2.50	$	3.10
January 2022 – December 2022	Swaps		30,882	$	2.62	$	—	$	—
January 2023 – June 2023	Swaps		5,000	$	2.61	$	—	$	—

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

	March 31, 2021
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps and costless collars	$	—	$	3,843		$	—	$	3,843
Liabilities:
Oil and natural gas swaps and costless collars		—		(160,784	)		—		(160,784	)
Total net liability	$	—	$	(156,941	)	$	—	$	(156,941	)

	December 31, 2020
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps and costless collars	$	—	$	7,821		$	—	$	7,821
Liabilities:
Oil and natural gas swaps and costless collars		—		(75,635	)		—		(75,635	)
Total net liability	$	—	$	(67,814	)	$	—	$	(67,814	)

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 Condensed 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 (in thousands):

	March 31, 2021				December 31, 2020
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	1,720	$	133,167	$	6,876	$	66,010
Non-current		2,123		27,617		945		9,625
Total	$	3,843	$	160,784	$	7,821	$	75,635

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 March 31, 2021 represent derivative instruments from nine 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.

Note 6 — 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):

	March 31, 2021			December 31, 2020
12.00% Second-Priority Senior Secured Notes – due January 2026	$	650,000		$	—
11.00% Second-Priority Senior Secured Notes – due April 2022		—			347,254
7.50% Senior Notes – due May 2022		6,060			6,060
Bank Credit Facility – matures May 2022		465,000			640,000
Total debt, before discount and deferred financing cost		1,121,060			993,314
Discount and deferred financing cost		(71,695	)		(7,802	)
Total debt, net of discount and deferred financing costs	$	1,049,365		$	985,512

12.00% Second-Priority Senior Notes – due January 2026

The 12.00% Notes were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc., Talos Production Inc., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes mature January 15, 2026 and have interest payable semi-annually each January 15 and July 15, commencing on July 15, 2021. At any time prior to January 15, 2023, the Company may redeem up to 40% of the principal amount of 12.00% Senior Notes at a redemption rate of 112.00% of the principal amount plus accrued and unpaid interest. Thereafter, the Company may redeem all or a portion of the 12.00% Notes at redemption prices decreasing annually at January 15 from 106.00% to 100.00% plus accrued and unpaid interest.

The indenture governing the 12.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from Talos Production Inc.’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of Talos Production Inc.’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. The 12.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at March 31, 2021.

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 Talos Production Inc. (formerly Talos Production LLC) and Talos Production Finance Inc., 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, 2021, the Company may, at its option, redeem all or a portion of the 11.00% Notes at 102.75% of the principal amount plus accrued and unpaid interest. 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.

On January 13, 2021, the Company redeemed $347.3 million aggregate principal amount of the 11.00% Notes using the proceeds from the issuance of the 12.00% Notes. The debt repurchase resulted in a loss on extinguishment of debt for the three months ended March 31, 2021 of $13.2 million, which is presented as “Other income (expense)” on the Condensed Consolidated Statements of Operations.

7.50% Senior Notes – due May 2022

The 7.50% Notes were assumed as a result of the exchange offer and consent solicitation from the Company’s business combination with Stone Energy Corporation. 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, 2021, the Company may, at its option, redeem all of the 7.50% Notes at 105.63% of the principal amount plus accrued and unpaid interest. Thereafter, the Company may redeem all or a portion of the 7.50% Notes at redemption prices decreasing annually at May 31 from 105.63% to 100.0% plus accrued and unpaid interest.

Bank Credit Facility – matures May 2022

The Company and Talos Production Inc. maintain a Bank Credit Facility with a syndicate of financial institutions, with a borrowing base of $960.0 million as of March 31, 2021. The borrowing base requires certain lender approval to access the last $25.0 million of capacity. The Bank Credit Facility matures on May 10, 2022.

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 3.00% to 4.00% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 2.00% to 3.00%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unutilized 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 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. The Company must also maintain a current ratio of no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, unutilized 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 our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. As a result of the issuances of the 12.00% Notes exceeding $550.0 million, the Bank Credit Facility borrowing base was reduced from $985.0 million to $960.0 million under the terms of the Bank Credit Facility. The Company’s scheduled redetermination meeting was held in April 2021, with results expected in early May 2021.

As of March 31, 2021, no more than $200.0 million of the Company’s borrowing base 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 March 31, 2021. As of March 31, 2021, the Company has $465.0 million of outstanding borrowings and $13.6 million in letters of credit issued under the Bank Credit Facility.

Note 7 — Employee Benefits Plans and Share-Based Compensation

Talos Energy Inc. Long Term Incentive Plan

Under the Talos Energy Inc. Long Term Incentive Plans (the “LTIP”), the Company may issue, subject to approval by the Talos board of directors, grants of options (including incentive stock 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 5,415,576 shares of the Company’s common stock.

Restricted Stock Units (“RSUs”) — The following table summarizes RSU activity for the three months ended March 31, 2021:

	RSUs			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2020		1,652,988		$	13.73
Granted		1,067,141		$	13.11
Vested		(623,400	)	$	14.07
Forfeited		—		$	—
Unvested RSUs at March 31, 2021⁽¹⁾		2,096,729		$	13.31

⁽¹⁾	As of March 31, 2021, 1,045,703 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Condensed Consolidated Balance Sheet.

Performance Share Units (“PSUs”) — The following table summarizes PSU activity for the three months ended March 31, 2021:

	PSUs		Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2020		834,172	$	25.46
Granted		586,984	$	18.96
Vested		—	$	—
Forfeited		—	$	—
Unvested PSUs at March 31, 2021⁽¹⁾		1,421,156	$	22.77

⁽¹⁾As of March 31, 2021, 586,984 of the unvested PSUs were accounted for as liability awards in “Accrued liabilities” on the Condensed Consolidated Balance Sheet.

The grant date fair value of the PSUs granted during the three months ended March 31, 2021, calculated using a Monte Carlo simulation, was $11.1 million. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted:

	2021 Grant Date
	March 8
Number of simulations		100,000
Expected term (in years)		2.8
Expected volatility		78.3	%
Risk-free interest rate		0.3	%
Dividend yield		—	%

Share-based Compensation Expense, net

Share-based compensation expense associated with RSUs, PSUs and other awards are reflected as “General and administrative expense,” in the Condensed Consolidated Statements of Operations, net amounts capitalized to “Proved Properties,” in the Condensed Consolidated Balance Sheets. 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 provided by operating activities” in the Condensed Consolidated Statements of Cash Flows.

The Company recognized the following share-based compensation expense, net (in thousands):

	Three Months Ended March 31,
	2021			2020
Share-based compensation expense	$	4,915		$	3,212
Less: amounts capitalized to oil and gas properties		(2,251	)		(1,585	)
Total share-based compensation expense, net	$	2,664		$	1,627

Note 8 — Income Taxes

The Company is a corporation that is subject to U.S. federal, state and foreign income taxes.

For the three months ended March 31, 2021, the Company recognized an income tax expense of $0.6 million for an effective tax rate of -0.5%. The Company’s effective tax rate of -0.5% is lower than the U.S. federal statutory income tax rate of 21% primarily due to recording a valuation allowance for its deferred tax assets. For the three months ended March 31, 2020, the Company recognized income tax expense of $55.3 million for an effective tax rate of 25.9%. The difference between the Company’s effective tax rate of 25.9% and federal statutory income tax rate of 21% is primarily due to state income taxes.

The Company evaluates and updates the estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of the Company’s actual earnings compared to annual projections, the effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate. The tax effect of discrete items is recognized in the period in which they occur at the applicable statutory rate.

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 deductions and income in the future. 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 allowance, the Company considers cumulative losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax optimization planning and future taxable income for each of its taxable jurisdictions. The Company assesses the realizability of its deferred tax assets quarterly; changes to the Company’s assessment of its valuation allowance in future periods could materially impact its results of operations. As of March 31, 2021, the Company maintains a full valuation allowance for U.S. federal, state and foreign net deferred tax assets.

Note 9 — 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.

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):

	Three Months Ended March 31,
	2021			2020
Net income (loss)	$	(121,491	)	$	157,749
Weighted average common shares outstanding — basic		81,435			58,240

Dilutive effect of securities		—			332
Weighted average common shares outstanding — diluted		81,435			58,572
Net income (loss) per common share:
Basic	$	(1.49	)	$	2.71
Diluted	$	(1.49	)	$	2.69
Anti-dilutive potentially issuable securities excluded from diluted common shares		2,949			4,358

Note 10 — Related Party Transactions

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. The Sponsors hold a majority of the Company’s voting power.

ILX and Castex Acquisition

On February 28, 2020 the Company acquired assets and liabilities at fair value from sellers that include, the Riverstone Sellers, affiliates of the Riverstone Funds, for $459.3 million (comprised of $303.1 million in net cash paid and $156.2 million in Conversion Stock). See additional details in Note 2 — Acquisitions.

Whistler Acquisition

On August 31, 2018, the Company acquired certain properties 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 March 31, 2021 is $1.1 million in receivables from an affiliate of the Apollo Funds to reimburse the Company for certain payments made post-closing.

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, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) and certain clients of MacKay Shields LLC (“MacKay Shields”), 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”).

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) 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, the Company is 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 has terminated with respect to Franklin and will terminate with respect to MacKay Shields in the event that 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.

In connection with the closing of the ILX and Castex Acquisition, and pursuant to the Purchase Agreements, as amended, the Company and ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Riverstone V Castex 2014 Holdings, L.P., a Delaware limited partnership and designee of Castex Energy 2014, LLC, 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.

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 $0.1 million and $0.2 million for the three months ended March 31, 2021 and 2020, 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 was, prior to the conversion thereof, counted towards such ownership requirements on an as converted basis at the closing of the ILX and Castex Acquisition. On March 30, 2020, all 110,000 shares of Series A Convertible Preferred Stock were converted into an aggregate 11.0 million shares of the Company’s common stock.

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 three months ended March 31, 2021 and 2020, the Company incurred fees of approximately $0.9 million and $1.6 million, respectively, of which $1.1 million and $3.6 million were payable at each respective balance sheet date for legal services performed by Vinson & Elkins L.L.P.

Note 11 — Commitments and Contingencies

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 March 31, 2021, the Company had secured performance bonds totaling approximately $691.2 million. As of March 31, 2021, the Company had $13.6 million in letters of credit issued under its Bank Credit Facility.

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.

Asset Retirement Obligation

The Company has divested various leases, wells and facilities located in the U.S. Gulf of Mexico where the purchasers typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection and may not be able to perform required abandonment obligations. Under certain circumstances, regulations or federal laws could require the Company to assume such obligations.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following management’s discussion and analysis should be read in conjunction with our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Condensed Consolidated Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2020 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2020 Annual Report.

Our Business

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 (“U.S.”) 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 U.S. Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive 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, an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible.

Outlook

COVID-19 — In the first quarter of 2020, the COVID-19 pandemic spread quickly across the globe, causing federal, state and local governments to mobilize and implement containment mechanisms in order to minimize the virus’ impacts on their populations and economies. Various containment measures, such as stay-at-home orders and banning of group gatherings resulted in severe drops in general economic activity and corresponding decreases in global energy demand, including the slowing of economic growth, disruption of global manufacturing supply chains, reduction of crude oil and natural gas consumption and interference with workforce continuity. As cities, states and countries continue to gradually ease the confinement restrictions, the risk for the resurgence and recurrence of COVID-19 remains as it relates to our workforce and the way we meet our business objectives. The potential impact from COVID-19, both now and in the future, is difficult to predict, and 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 COVID-19 infection rate or the efficacy and distribution of COVID-19 vaccines, and the actions taken by authorities to contain or treat the virus’ impact.

Due to concerns over health and safety, we asked the vast majority of our corporate workforce to work remotely. During the first quarter of 2021, we began allowing employees to return to the office in phases, and our offshore employees continue to work offshore with modified rotations. Working remotely has not significantly impacted our ability to maintain operations, or caused us to incur significant additional expenses; however, we continue to evaluate the effect of COVID-19 on our business by, amongst other things, developing a flexible capital spending budget for fiscal year 2021.

Decline in Commodity Prices — In March 2020, OPEC and non-OPEC producers failed to agree to production cuts intended to stabilize and support commodity prices. With no agreement in place, Saudi Arabia, Russia and other producers committed to ramping up production in an attempt to protect, or increase, their global market share. This increased production, coupled with significant demand declines caused by the global response to COVID-19, contributed to significant crude oil price declines. Although pricing stabilized during the fourth quarter of 2020 and increased slightly in the first quarter of 2021, the overall commodity price environment is expected to remain depressed based on over-supply, decreased demand and a potential global economic recession. Saudi Arabia, Russia and other crude oil-producing nations (“OPEC Plus”) met in December 2020 with the parties agreeing to increase production by 500,000 barrels a day in January 2021 and, potentially, by a similar amount in the following months; however, that plan was paused during a subsequent meeting in January 2021. The OPEC Plus parties met again in March 2021 and approved the continuation of current production levels for April 2021, with Russia and Kazakhstan permitted to increase production by 130,000 to 20,000 barrels per day, respectively. The OPEC Plus parties additionally met in April 2021, whereby Saudi Arabia’s recently pledged 1 million barrels a day of voluntary cuts during February and March 2021 was extended. The OPEC Plus parties intend to meet again in June 2021. As such, we cannot predict whether or when oil production and economic activities will return to normalized levels. The decline in commodity prices has adversely affected oil and natural gas exploration and production in the United States. In response, the Company has developed a flexible fiscal year 2021 capital spending budget that is within operating cash flows and does not require any long-term commitments.

Global Economic Environment — COVID-19 and the numerous public and political responses thereto have contributed to equity market volatility and potentially the risk of a global recession. We expect the global equity market volatility experienced in 2020 to continue at least until the COVID-19 pandemic stabilizes, if not longer. The response to the COVID-19 outbreak in 2020 (such as stay-at-home orders, closures of restaurants and banning of group gatherings) slowed the global economy and contributed to increased unemployment rates. On March 27, 2020, the U.S. government passed the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), the largest relief package in U.S. history. The CARES Act, a $2.2 trillion stimulus package, includes various provisions intended to provide relief to individuals and businesses in the form of tax law changes, loans and grants, among others. We have evaluated the potential impact of these measures, and we do not meet the criteria to participate. President Biden is currently pursuing a $1.9 trillion stimulus package, which was passed in the U.S. House of Representatives on February 27, 2021 and is now under consideration in the U.S. Senate.

FERC Regulatory Matters — On June 18, 2020, the Federal Energy Regulatory Commission (“FERC”) issued a Notice of Inquiry requesting comments on a proposed oil pipeline index using the Producer Price Index for Finished Goods (PPI-FG) plus 0.09% as the index level, and requested comments on whether and how the index should reflect changes to FERC’s policies regarding income tax costs and return on equity. FERC issued its Five-Year Review of the Oil Pipeline Index establishing an index level of 0.78% (PPI-FG+0.78%) on December 17, 2020 for the five-year period commencing July 1, 2021. A number of parties requested rehearing of FERC’s order and these requests remain pending as a result of FERC’s February 18, 2021 order granting rehearing for further consideration. FERC’s final application of its indexing rate methodology for the next five-year term of index rates may impact our revenues associated with any transportation services we may provide pursuant to rates adjusted by the FERC oil pipeline index.

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

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

LLOG Properties Acquisition — On November 16, 2020, the Company completed the acquisition of select interests in oil and natural gas assets from LLOG Exploration & Production Company, LLC, for $13.2 million in cash, inclusive of customary closing adjustments and transaction related expenses (the “LLOG Acquisition”). See additional details in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for more information.

Castex Energy 2005 Acquisition — On August 5, 2020, the Company completed the acquisition of select oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC, for $43.3 million (comprised of $6.5 million in cash, $35.4 million in 4.6 million shares of the Company’s common stock and $1.4 million in transaction related expenses) (the “Castex 2005 Acquisition”). See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for more information.

ILX and Castex Acquisition — On February 28, 2020 we acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate with the entities controlled by or affiliated with Riverstone Energy Partners V, L.P. ( the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers”), for $459.3 million (comprised of $303.1 million in net cash paid and $156.2 million in 110,000 shares of a series of the Company’s preferred stock, which subsequently converted to an aggregate 11.0 million shares of our common stock) (collectively, the “ILX and Castex Acquisition”). See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — 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.

Known Trends and Uncertainties

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile, and prices experienced a steep decline in March and April 2020. In March 2020, Saudi Arabia and Russia failed to reach a decision to cut production of oil and gas along with the OPEC countries. Subsequently, Saudi Arabia significantly reduced the prices at which it sold oil and announced plans to increase production. These events, combined with the continued outbreak of COVID-19, contributed to a sharp drop in prices for oil and natural gas during 2020. During January 1, 2021 through March 31, 2021, the daily spot prices for NYMEX WTI crude oil ranged from a high of $66.08 per Bbl to a low of $47.47 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $23.86 per MMBtu to a low of $2.45 per MMBtu. 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 supply and demand, and we cannot predict whether or when oil production and economic activities will return to normalized levels.

Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting that we use for our oil and natural gas operations, our 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 “Write-down of oil and natural gas properties” on the Condensed Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on our Condensed 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. We perform this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, we utilize SEC Pricing when performing the ceiling test. We also hold 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. For the three months ended March 31, 2021 and 2020, we did not recognize an impairment based on the ceiling test computations. At March 31, 2021 our ceiling test computation was based on SEC pricing of $39.49 per Bbl of oil, $2.15 per Mcf of natural gas and $11.19 per Bbl of NGLs.

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning April 1, 2020 and ending March 1, 2021 used in the determination of the SEC pricing was 10 percent lower, resulting in $35.49 per Bbl of oil, $1.93 per Mcf of natural gas and $10.07 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $345.5 million.

As part of our period end reserves estimation process for future periods, we expect changes in the key assumptions used, which could be significant, including updates to future pricing estimates and differentials, future production estimates to align with our anticipated five-year drilling plan and changes in our capital costs and operating expense assumptions, which we expect to decrease further as a result of sustained lower commodity prices. There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 2020 Annual Report. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties.

Third Party Planned Downtime — Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the HP-I that is operated by Helix Energy Solutions Group, Inc. (“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. The next dry-dock is scheduled for the first half of 2022 with an estimated shut-in lasting approximately 60 days.

BOEM Bonding Requirements — In order to cover the various decommissioning obligations of lessees on the Outer Continental Shelf (“OCS”), the Bureau of Ocean Energy Management (“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 2016, the BOEM under the Obama Administration issued the 2016 Notice to Lessees and Operators (“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, right-of-ways (“ROWs”) and right of use easements (“RUEs”). The 2016 NTL, which bolstered supplemental bonding requirements, became effective in September 2016, but was not fully implemented as the BOEM under the Trump Administration first paused, and then in 2020 rescinded, the implementation of this NTL while the BOEM and Bureau of Safety and Environmental Enforcement (“BSEE”) issued a jointly proposed rulemaking in October 2020 in which BOEM proposed amendments to its financial assurance program. The October 2020 rulemaking proposes to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights owners) and RUE and ROW grant holders conducting operations on the federal OCS. However, with President Biden taking office in January 2021, it is possible that the new Administration will reconsider regulatory actions undertaken by the former Administration with respect to financial assurance requirements, including rescission of the 2016 NTL and publication of the October 2020 proposed rule, and may adopt and implement more stringent supplemental bonding requirements.

The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us, whether as current or predecessor lessee or grant holder, as a result of the 2016 NTL, to the extent re-implemented or the October 2020 proposed rule, to the extent finalized, as well as to the provisions of any new, more stringent NTLs or final rules on supplemental bonding published by the BOEM under the Biden Administration, could materially and adversely affect our financial condition, cash flows and results of operations. Moreover, the BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

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 U.S. 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” below.

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 (in thousands):

	Three Months Ended March 31,
	2021		2020		Change
Revenues and Other:
Oil	$	229,561	$	166,624	$	62,937
Natural gas		28,234		11,898		16,336
NGL		9,113		4,301		4,812
Other		1,000		4,941		(3,941	)
Total revenues and other	$	267,908	$	187,764	$	80,144

Total Production Volumes:
Oil (MBbls)		4,049		3,726		323
Natural gas (MMcf)		8,508		7,042		1,466
NGL (MBbls)		482		387		95
Total production volume (MBoe)		5,949		5,287		662

Daily Production Volumes by Product:
Oil (MBblpd)		45.0		40.9		4.1
Natural gas (MMcfpd)		94.5		77.4		17.1
NGL (MBblpd)		5.4		4.3		1.1
Total production volume (MBoepd)		66.1		58.1		8.0

Average Sale Price Per Unit:
Oil (per Bbl)	$	56.70	$	44.72	$	11.98
Natural gas (per Mcf)	$	3.32	$	1.69	$	1.63
NGL (per Bbl)	$	18.91	$	11.11	$	7.80
Price per Boe	$	44.87	$	34.58	$	10.29
Price per Boe (including realized commodity derivatives)	$	36.73	$	41.48	$	(4.75	)

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 (in thousands):

	Three Months Ended March 31, 2021 vs 2020
	Price		Volume		Total
Oil	$	48,492	$	14,445	$	62,937
Natural gas	$	13,858	$	2,478	$	16,336
NGL	$	3,757	$	1,055	$	4,812
Total revenues and other	$	66,107	$	17,978	$	84,085

Three Months Ended March 31, 2021 and 2020 Volumetric Analysis — Production volumes increased by 8.0 MBoepd to 66.1 MBoepd. The increase in production volumes was primarily attributable to an increase of 16.5 MBoepd in production from the oil and natural gas assets acquired primarily in the ILX and Castex Acquisition and Castex 2005 Acquisition. Additionally, production volumes increased 3.9 MBoepd from the Green Canyon 18 Field, primarily attributable to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 platform rig program. The increase was partially offset by a 4.9 MBoepd, 2.6 MBoepd and 2.5 MBoepd reduction in production volumes from the Phoenix Field, Pompano Field and Ewing Bank 305 Field, respectively. The decrease was primarily a result of deferred production for facility construction and maintenance and natural decline.

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 (in thousands, except per Boe data):

	Three Months Ended March 31,
	2021		2020
Lease operating expenses	$	66,628	$	58,241
Lease operating expenses per Boe	$	11.20	$	11.02

Three Months Ended March 31, 2021 and 2020 — Total lease operating expense for the three months ended March 31, 2021 increased by approximately $8.4 million, or 14%. This increase was primarily related to an increase in lease operating expenses of $13.4 million incurred in connection with assets acquired in the ILX and Castex Acquisition, Castex 2005 Acquisition, and LLOG Acquisition when compared to the same period in 2020. The increase was partially offset by a reduction in costs attributable to the shuttering of certain shelf fields. On a per unit basis, lease operating expense increased $0.18 per Boe to $11.20 per Boe.

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 (in thousands, except per Boe data):

	Three Months Ended March 31,
	2021		2020
Depreciation, depletion and amortization	$	101,657	$	93,543
Depreciation, depletion and amortization per Boe	$	17.09	$	17.69

Three Months Ended March 31, 2021 and 2020 — Depreciation, depletion and amortization expense for the three months ended March 31, 2021 increased by approximately $8.1 million, or 9%. This increase was primarily due to increased production of 8.0 MBoepd offset by a decrease of $0.59 per Boe, or 3% in the depletion rate on our proved oil and natural gas properties as a result of the impairment on oil and gas properties in the fourth quarter of 2020.

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 (in thousands, except per Boe data):

	Three Months Ended March 31,
	2021		2020
General and administrative expense	$	19,189	$	27,469
General and administrative expense per Boe	$	3.23	$	5.20

Three Months Ended March 31, 2021 and 2020 — General and administrative expense for the three months ended March 31, 2021, decreased by approximately $8.3 million, or 30%. Transaction related costs were $1.8 million or $0.30 per Boe for the three months ended March 31, 2021, which is a decrease of $6.0 million primarily due to the ILX and Castex Acquisition that occurred in the first quarter of 2020. The decrease is also attributable to $1.0 million in severance recognized during the three months ended March 31, 2020.

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 (in thousands):

	Three Months Ended March 31,
	2021		2020
Write-down of oil and natural gas properties	$	—	$	57
Accretion expense	$	14,985	$	12,417
Price risk management activities (income) expense	$	137,508	$	(243,217	)
Other expense	$	13,950	$	146
Income tax expense	$	584	$	55,260

Three Months Ended March 31, 2021 and 2020 —

Price risk management activities — Price risk management activities for the three months ended March 31, 2021, decreased by approximately $380.7 million, or 157%. The expense of $137.5 million for the three months ended March 31, 2021 consists of $89.1 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $48.4 million in cash settlement losses. The income of $243.2 million for the three months ended March 31, 2020 consists of $206.7 million in non-cash gains from the increase in the fair value of our open derivative contracts and $36.5 million in cash settlement gains. These unrealized gains or losses 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 Condensed 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 June 2023, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

Other expense — During the three months ended March 31, 2021 we recorded a $13.2 million loss on extinguishment of debt as a result of the redemption of the 11.00% Notes further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt.”

Income tax expense — During the three months ended March 31, 2021, we recorded $0.6 million of income tax expense compared to $55.3 million of income tax expense during the three months ended March 31, 2020. The change is primarily a result of recording a valuation allowance on our deferred tax assets. The realization of our deferred tax asset depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of all of the deferred tax assets will not be realized. See additional information on the valuation allowance as described in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 8 — Income Taxes.”

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, transaction and non-recurring expenses, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), loss on debt extinguishment, 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):

	Three Months Ended March 31,
	2021			2020
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	(121,491	)	$	157,749
Interest expense		34,076			25,850
Income tax expense		584			55,260
Depreciation, depletion and amortization		101,657			93,543
Accretion expense		14,985			12,417
EBITDA		29,811			344,819
Write-down of oil and natural gas properties		—			57
Transaction and non-recurring expenses⁽¹⁾		1,778			7,758
Derivative fair value (gain) loss⁽²⁾		137,508			(243,217	)
Net cash received (paid) on settled derivative instruments⁽²⁾		(48,381	)		36,460
Loss on extinguishment of debt		13,225			—
Non-cash write-down of other well equipment inventory		—			133
Non-cash equity-based compensation expense		2,664			1,627
Adjusted EBITDA	$	136,605		$	147,637

⁽¹⁾	Includes transaction related expenses, restructuring expenses and cost saving initiatives.

⁽²⁾

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 (as defined below). Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. As of March 31, 2021, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $521.4 million, or $546.4 million inclusive of the $25.0 million requiring certain lender approval.

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 three months ended March 31, 2021 (in thousands):

U.S. drilling & completions	$	38,226
Mexico appraisal & exploration		591
Asset management		6,108
Seismic and G&G, land, capitalized G&A and other		16,178
Total capital expenditures		61,103
Plugging & abandonment		10,120
Total capital expenditures and plugging & abandonment	$	71,223

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 2021 capital spending program of $340.0 million to $370.0 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.

Guarantor Financial Information — Talos owns no operating assets and has no operations independent of its subsidiaries. Talos Energy Inc. and Talos Production Inc. (together the “Talos Issuers”) issued the 12.00% Notes (as defined below) on January 4, 2021 and January 14, 2021, which are fully and unconditionally guaranteed, jointly and severally, by Talos and certain of its 100% wholly owned subsidiaries (the “Guarantors”) on a senior unsecured basis. Our non-domestic subsidiaries (the “Non-Guarantors”) are 100% owned by Talos but do not guarantee the 12.00% Notes issued on January 4, 2021 and January 14, 2021.

In lieu of providing separate financial statements for the Talos Issuers and the Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and income statement information for Talos, the Talos Issuers and the Guarantors on a combined basis after elimination of intercompany transactions and amounts related to investment in any subsidiary that is a Non-Guarantor.

The following table presents the balance sheet information for the respective periods (in thousands):

	March 31, 2021		December 31, 2020
Current assets	$	279,876	$	231,669
Non-current assets		2,402,854		2,444,886
Total Assets	$	2,682,730	$	2,676,555

Current liabilities	$	473,419	$	438,340
Non-current liabilities		1,549,789		1,459,816
Talos Energy Inc. stockholdersʼ equity		659,522		778,399
Total liabilities and stockholdersʼ equity	$	2,682,730	$	2,676,555

The following table presents the income statement information (in thousands):

	Three Months Ended March 31, 2021
Revenues and Other	$	267,908
Cost and expenses		(387,720	)
Net Loss	$	(119,812	)

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):

	Three Months Ended March 31,
	2021			2020
Operating activities	$	66,956		$	110,232
Investing activities	$	(72,737	)	$	(376,683	)
Financing activities	$	36,527		$	286,381

Operating Activities — Net cash provided by operating activities decreased $43.3 million in the three months ended March 31, 2021 compared to the corresponding period in 2020 primarily attributable to an increase in cash payments on derivative instruments of $84.8 million.

Investing Activities — Net cash used in investing activities decreased $303.9 million in the three months ended March 31, 2021 compared to the corresponding period in 2020 primarily due to a decrease in payments for acquisitions of $284.8 million and a decrease in capital expenditures of $18.8 million.

Financing Activities — Net cash provided by financing activities decreased $249.9 million in the three months ended March 31, 2021 compared to the corresponding period in 2020 primarily attributable to decrease in net proceeds of $475.0 million received from the Bank Credit Facility used primarily to fund the ILX and Castex Acquisition in the first quarter of 2020. Additionally, $356.8 million was utilized for the redemption of the 11.00% Notes in the first quarter of 2021. This decrease was offset by proceeds of $600.5 million from the issuance of the 12.00% Notes in January 2021.

Bank Credit Facility – matures May 2022 — The Company maintains a Bank Credit Facility with a syndicate of financial institutions, with a borrowing base of $960.0 million as of March 31, 2021. The Bank Credit Facility matures on May 10, 2022.

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate plus applicable margins ranging from 3.00% to 4.00% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 2.00% to 3.00%. In addition, we are obligated to pay a commitment fee of 0.50% on the unutilized 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 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. We must also maintain a current ratio of no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, unutilized 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 proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. As a result of the issuances of the 12.00% Notes exceeding $550.0 million, the Bank Credit Facility borrowing base was reduced from $985.0 million to $960.0 million under the terms of the Bank Credit Facility. The Company’s scheduled redetermination meeting was held in April 2021, with results expected in early May 2021.

As of March 31, 2021, no more than $200.0 million of the borrowing base 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 March 31, 2021. As of March 31, 2021, the Company has $465.0 million of outstanding borrowings and $13.6 million in letters of credit issued under the Bank Credit Facility.

12.00% Second-Priority Senior Secured Notes—due January 2026 — The 12.00% Second-Priority Senior Secured Notes (the “12.00% Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc., Talos Production Inc., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes mature on January 15, 2026 and have interest payable semi-annually each January 15 and July 15, commencing on July 15, 2021.

11.00% Second-Priority Senior Secured Notes—due April 2022 — The 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) were issued pursuant to an indenture dated May 10, 2018, between the Talos Issuers (as defined in that certain indenture), the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent.

On January 13, 2021, the Company redeemed $347.3 million aggregate principal amount of the 11.00% Notes using the proceeds from the issuance of 12.00% Notes. The debt repurchase resulted in a loss on extinguishment of debt for the three months ended March 31, 2021 of $13.2 million, which is presented as “Other income (expense)” on the Condensed Consolidated Statements of Operations.

7.50% Senior Notes—due May 2022 — The 7.50% Senior Notes (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.

Performance Bonds — As of March 31, 2021, we had secured performance bonds primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico and to guarantee the completion of the minimum work program under the Mexico production sharing contracts totaling approximately $691.2 million. In 2016, the 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 and RUEs. The 2016 NTL, which bolstered supplemental bonding requirements, became effective in September 2016, but was not fully implemented as the BOEM under the Trump Administration first paused, and then in 2020 rescinded, the implementation of this NTL while the BOEM and BSEE issued a jointly proposed rulemaking in October 2020 in which BOEM proposed amendments to its financial assurance program. The October 2020 rulemaking proposes to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights owners) and RUE and ROW grant holders conducting operations on the federal OCS. However, with President Biden having taken office in January 2021, it is possible that the new Administration will reconsider regulatory actions undertaken by the former administration with respect to financial assurance requirements, including rescission of the 2016 NTL and publication of the October 2020 proposed rule, and may adopt and implement more stringent supplemental bonding requirements.

Off Balance Sheet Arrangements

We did not have any off balance sheet arrangements as of March 31, 2021.

Critical Accounting Policies and Estimates

We consider accounting policies related to oil and natural gas properties, proved reserve estimates, fair value measure of financial instruments, asset retirement obligations, revenue recognition, imbalances and production handling fees and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting policies, which are summarized in the Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our 2020 Annual Report.

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

None.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2020 Annual Report. Except as disclosed in this Quarterly Report, there have been no material changes from the disclosures presented in our 2020 Annual Report regarding our exposures to certain market risks.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have 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 Quarterly Report. Our disclosure controls and procedures are designed to ensure that the 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 the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2021.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

There have been no material developments with respect to the information previously reported under Part I, Item 3. “Legal Proceedings” of our 2020 Annual Report.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under Part I, Item 1A. “Risk Factors” included in our 2020 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2020 Annual Report or our other SEC filings.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Number		Description

2.1#		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).

2.2		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).

2.3#		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).

2.4		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).

2.5#		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).

2.6		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).

2.7#		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).

2.8		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).

2.9#		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).

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		Indenture, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

4.2		First Supplemental Indenture, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).

4.3		Form of 12.00% Second-Priority Senior Secured Note due 2026 (included as Exhibit A to Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

4.4		Registration Rights Agreement, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

4.5		Registration Rights Agreement, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).

10.1*		Form of Talos Energy Inc. Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors).

10.2*		Talos Energy Inc. 2021 Long Term Incentive Plan.

10.3*		Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives).

10.4*		Form of Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives).

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.

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 Date File (Embedded within the Inline XBRL document and included in Exhibit 101).

*	Filed herewith.

**	Furnished herewith.

#	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.

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:	May 5, 2021	By:	/s/ Shannon E. Young III
			Shannon E. Young III
			Executive Vice President and Chief Financial Officer