TALOS ENERGY INC. - Quarter Report: 2021 September (Form 10-Q)

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 September 30, 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 October 27, 2021, the registrant had 81,881,477 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
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Operations	6
	Condensed Consolidated Statements of Changes in Stockholders' Equity	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Condensed Consolidated Financial Statements	9
	Note 1 — Nature of Business and Basis of Presentation	9
	Note 2 — Acquisitions	9
	Note 3 — Property, Plant and Equipment	11
	Note 4 — Leases	12
	Note 5 — Financial Instruments	13
	Note 6 — Debt	16
	Note 7 — Employee Benefits Plans and Share-Based Compensation	17
	Note 8 — Income Taxes	18
	Note 9 — Income (Loss) Per Share	19
	Note 10 — Related Party Transactions	20
	Note 11 — Commitments and Contingencies	21
	Note 12 — Subsequent Events	21
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
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

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GLOSSARY

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

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

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

BOEM — Bureau of Ocean Energy Management.

BSEE — Bureau of Safety and Environmental Enforcement.

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.

OPEC — Organization of Petroleum Exporting Countries.

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.

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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%.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q (this "Quarterly 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;



the success of our carbon capture and storage opportunities;



our ongoing strategy with respect to our Zama assets;



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.

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We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility due to the continued impact of the coronavirus disease 2019 (“COVID-19”), including any new strains or variants, and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business; the ability or willingness of OPEC and 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; cybersecurity threats; 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 acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations, and the other risks discussed in Part I, Item 1A. “Risk Factors” of Talos Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on March 11, 2021 (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 Quarterly 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.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)


	September 30, 2021			December 31, 2020
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	59,427		$	34,233
Accounts receivable:
Trade, net		111,471			106,220
Joint interest, net		21,480			50,471
Other		13,606			18,448
Assets from price risk management activities		2			6,876
Prepaid assets		46,024			29,285
Other current assets		1,718			1,859
Total current assets		253,728			247,392
Property and equipment:
Proved properties		5,190,096			4,945,550
Unproved properties, not subject to amortization		250,629			254,994
Other property and equipment		28,904			32,853
Total property and equipment		5,469,629			5,233,397
Accumulated depreciation, depletion and amortization		(2,986,142	)		(2,697,228	)
Total property and equipment, net		2,483,487			2,536,169
Other long-term assets:
Assets from price risk management activities		49			945
Other well equipment inventory		21,163			18,927
Operating lease assets		5,748			6,855
Other assets		21,989			24,258
Total assets	$	2,786,164		$	2,834,546
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	106,098		$	104,864
Accrued liabilities		133,261			163,379
Accrued royalties		40,404			27,903
Current portion of long-term debt		6,060			—
Current portion of asset retirement obligations		51,488			49,921
Liabilities from price risk management activities		248,361			66,010
Accrued interest payable		17,812			9,509
Current portion of operating lease liabilities		1,651			1,793
Other current liabilities		30,697			24,155
Total current liabilities		635,832			447,534
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		978,777			985,512
Asset retirement obligations		406,475			392,348
Liabilities from price risk management activities		35,856			9,625
Operating lease liabilities		16,781			18,554
Other long-term liabilities		37,819			54,372
Total liabilities		2,111,540			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 September 30, 2021 and December 31, 2020		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 81,881,477 and 81,279,989 shares issued and outstanding as of September 30, 2021 and December 31, 2020, respectively		819			813
Additional paid-in capital		1,671,781			1,659,800
Accumulated deficit		(997,976	)		(734,012	)
Total stockholdersʼ equity		674,624			926,601
Total liabilities and stockholdersʼ equity	$	2,786,164		$	2,834,546

See accompanying notes.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Revenues and other:
Oil	$	246,208		$	117,190		$	743,759		$	358,285
Natural gas		31,723			12,337			86,088			35,375
NGL		12,978			3,409			31,738			9,674
Other		—			2,201			1,000			8,441
Total revenues and other		290,909			135,137			862,585			411,775
Operating expenses:
Lease operating expense		70,034			62,064			208,675			184,187
Production taxes		764			225			2,539			640
Depreciation, depletion and amortization		88,596			80,547			290,094			262,533
Write-down of oil and natural gas properties		—			—			—			57
Accretion expense		13,668			11,537			44,110			37,748
General and administrative expense		20,427			17,823			58,993			62,484
Other operating expense		5,081			—			7,864			—
Total operating expenses		198,570			172,196			612,275			547,649
Operating income (expense)		92,339			(37,059	)		250,310			(135,874	)
Interest expense		(32,390	)		(24,124	)		(100,036	)		(76,164	)
Price risk management activities income (expense)		(81,479	)		(19,882	)		(405,604	)		154,653
Other income (expense)		4,475			813			(7,916	)		139
Net loss before income taxes		(17,055	)		(80,252	)		(263,246	)		(57,246	)
Income tax benefit (expense)		364			28,252			(718	)		22,384
Net loss	$	(16,691	)	$	(52,000	)	$	(263,964	)	$	(34,862	)

Net loss per common share:
Basic	$	(0.20	)	$	(0.73	)	$	(3.23	)	$	(0.54	)
Diluted	$	(0.20	)	$	(0.73	)	$	(3.23	)	$	(0.54	)
Weighted average common shares outstanding:
Basic		81,901			71,286			81,721			65,134
Diluted		81,901			71,286			81,721			65,134

See accompanying notes.

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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 June 30, 2020		68,414,782		—	$	684	$	—	$	1,545,138		$	(251,269	)	$	1,294,553
Equity-based compensation		—		—		—		—		4,366			—			4,366
Equity-based compensation tax withholdings		—		—		—		—		(36	)		—			(36	)
Equity-based compensation stock issuances		12,747		—		—		—		—			—			—
Issuance of common stock for acquisitions (Note 2)		4,602,460		—		46		—		35,347			—			35,393
Net loss		—		—		—		—		—			(52,000	)		(52,000	)
Balance at September 30, 2020		73,029,989		—	$	730	$	—	$	1,584,815		$	(303,269	)	$	1,282,276

Balance at June 30, 2021		81,872,498		—	$	819	$	—	$	1,666,887		$	(981,285	)		686,421
Equity-based compensation		—		—		—		—		4,936			—			4,936
Equity-based compensation tax withholdings		—		—		—		—		(42	)		—			(42	)
Equity-based compensation stock issuances		8,979		—		—		—		—			—			—
Net loss		—		—		—		—		—			(16,691	)		(16,691	)
Balance at September 30, 2021		81,881,477		—	$	819	$	—	$	1,671,781		$	(997,976	)	$	674,624


	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		—		—			—		—			12,135			—			12,135
Equity-based compensation tax withholdings		—		—			—		—			(827	)		—			(827	)
Equity-based compensation stock issuances		180,525		—			1		—			(1	)		—			—
Issuance of preferred stock (Note 2)		—		110,000			—		1			156,199			—			156,200
Conversion of preferred stock into common stock (Note 2)		11,000,000		(110,000	)		110		(1	)		(109	)		—			—
Issuance of common stock for acquisitions (Note 2)		4,602,460		—			46		—			35,347			—			35,393
Issuance of common stock for debt exchange (Note 6)		3,050,000		—			31		—			35,929			—			35,960
Net loss		—		—			—		—			—			(34,862	)		(34,862	)
Balance at September 30, 2020		73,029,989		—		$	730	$	—		$	1,584,815		$	(303,269	)	$	1,282,276

Balance at December 31, 2020		81,279,989		—		$	813	$	—		$	1,659,800		$	(734,012	)	$	926,601
Equity-based compensation		—		—			—		—			15,148			—			15,148
Equity-based compensation tax withholdings		—		—			—		—			(3,161	)		—			(3,161	)
Equity-based compensation stock issuances		601,488		—			6		—			(6	)		—			—
Net loss		—		—			—		—			—			(263,964	)		(263,964	)
Balance at September 30, 2021		81,881,477		—		$	819	$	—		$	1,671,781		$	(997,976	)	$	674,624

See accompanying notes.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2021			2020
Cash flows from operating activities:
Net loss	$	(263,964	)	$	(34,862	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense		334,204			300,281
Write-down of oil and natural gas properties and other well inventory		—			190
Amortization of deferred financing costs and original issue discount		10,085			5,393
Equity-based compensation, net of amounts capitalized		8,294			6,321
Price risk management activities expense (income)		405,604			(154,653	)
Net cash received (paid) on settled derivative instruments		(189,252	)		141,529
Loss (gain) on extinguishment of debt		13,225			(1,644	)
Settlement of asset retirement obligations		(58,001	)		(34,502	)
Gain on sale of assets		(677	)		—
Changes in operating assets and liabilities:
Accounts receivable		29,078			(1,729	)
Other current assets		(16,598	)		21,835
Accounts payable		(1,591	)		23,500
Other current liabilities		16,395			31,826
Other non-current assets and liabilities, net		846			(41,418	)
Net cash provided by operating activities		287,648			262,067
Cash flows from investing activities:
Exploration, development and other capital expenditures		(211,580	)		(280,273	)
Cash paid for acquisitions, net of cash acquired		(5,399	)		(304,879	)
Proceeds from sale of property and equipment, net		4,826			—
Net cash used in investing activities		(212,153	)		(585,152	)
Cash flows from financing activities:
Issuance of senior notes		600,500			—
Redemption of senior notes and other long-term debt		(356,803	)		(4,735	)
Proceeds from Bank Credit Facility		75,000			300,000
Repayment of Bank Credit Facility		(315,000	)		—
Deferred financing costs		(26,991	)		(1,287	)
Other deferred payments		(7,921	)		(11,921	)
Payments of finance lease		(15,925	)		(12,790	)
Employee stock awards tax withholdings		(3,161	)		(827	)
Net cash provided by (used in) financing activities		(50,301	)		268,440

Net increase (decrease) in cash and cash equivalents		25,194			(54,645	)
Cash and cash equivalents:
Balance, beginning of period		34,233			87,022
Balance, end of period	$	59,427		$	32,377

Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	72,802		$	97,517
Debt exchanged for common stock	$	—		$	35,960
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	64,603		$	41,188

See accompanying notes.

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TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2021

(Unaudited)

Note 1 — Nature of Business and Basis of Presentation

Nature of Business

Talos Energy Inc. (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage opportunities. The Company leverages decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, the Company also utilizes its expertise to explore opportunities to reduce industrial emissions through the Company's carbon capture and storage collaborative arrangements along the U.S. Gulf Coast and Gulf of Mexico.

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 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 accompanying 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 of 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 Acquisition

The following acquisition was accounted for as an asset acquisition whereby the cost of the acquisition, including transaction costs, was allocated to the assets acquired on the basis of their relative fair values.

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 consisted of 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.

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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 closing date 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

The following acquisition was accounted for as a business combination whereby the Company recorded the assets acquired and liabilities assumed at their respective fair values as of the acquisition date.

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 consideration was funded with borrowings under the Bank Credit Facility (as defined in Note 5 — Financial Instruments).

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 closing date 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.

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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.

The Company incurred a total of $12.1 million of transaction related costs, of which $0.4 million and $8.7 million were incurred during the three and nine months ended September 30, 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 September 30, 2020			Nine Months Ended September 30, 2020
Revenue	$	37,538		$	77,729
Net loss	$	(1,131	)	$	(13,083	)

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 nine months ended September 30, 2020 as if the ILX and Castex Acquisition had occurred on January 1, 2019. 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, 2019, nor is such information indicative of any expected future results of operations.


	Nine Months Ended September 30, 2020
Revenue	$	459,210
Net loss	$	(22,799	)
Basic net loss per common share	$	(0.34	)
Diluted net loss per common share	$	(0.34	)

Note 3 — Property, Plant and Equipment

Ceiling Test

During the three and nine months ended September 30, 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 September 30, 2021, the Company’s ceiling test computation was based on SEC pricing of $58.25 per Bbl of oil, $3.02 per Mcf of natural gas and $20.75 per Bbl of NGLs.

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Asset Retirement Obligations

The 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):


	Asset Retirement Obligations
Asset retirement obligations at December 31, 2020	$	442,269
Obligations acquired		433
Obligations incurred		52
Obligations settled		(58,001	)
Obligations divested		(340	)
Accretion expense		44,110
Changes in estimate		29,440
Asset retirement obligations at September 30, 2021	$	457,963
Less: Current portion at September 30, 2021		51,488
Long-term portion at September 30, 2021	$	406,475

Note 4 — Leases

The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Additionally, the Company has a finance lease related to the use of the Helix Producer I (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. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized.

The lease costs described below are presented on a gross basis and do not represent 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, as applicable. The components of lease costs were as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Finance lease cost - interest on lease liabilities	$	2,749	$	3,848	$	9,017	$	12,153
Operating lease cost, excluding short-term leases(1)		702		815		2,138		2,547
Short-term lease cost(2)		14,541		21,845		32,393		41,128
Variable lease cost(3)		350		215		994		221
Total lease cost	$	18,342	$	26,723	$	44,542	$	56,049

(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.

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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 were as follows (in thousands):


	September 30, 2021		December 31, 2020
Operating leases:
Operating lease assets	$	5,748	$	6,855

Current portion of operating lease liabilities	$	1,651	$	1,793
Operating lease liabilities		16,781		18,554
Total operating lease liabilities	$	18,432	$	20,347

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

Other current liabilities	$	25,643	$	21,804
Other long-term liabilities		20,458		40,222
Total finance lease liabilities	$	46,101	$	62,026

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


	Nine Months Ended September 30,
	2021		2020
Operating cash outflow from finance leases	$	9,017	$	12,153
Operating cash outflow from operating leases	$	2,946	$	1,666

Right-of-use assets obtained in exchange for new operating lease liabilities	$	1,020	$	—

Note 5 — Financial Instruments

As of September 30, 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.

Debt Instruments

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


	September 30, 2021				December 31, 2020
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
12.00% Second-Priority Senior Secured Notes – due January 2026	$	586,139	$	695,741	$	—	$	—
11.00% Second-Priority Senior Secured Notes – due April 2022	$	—	$	—	$	343,579	$	355,935
7.50% Senior Notes – due May 2022	$	6,060	$	6,181	$	6,060	$	5,238
Bank Credit Facility – matures November 2024	$	392,638	$	400,000	$	635,873	$	640,000

The carrying value of the senior notes are presented net of the original issue discount and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

The carrying amount of the Company’s bank credit facility, as amended and restated (the “Bank Credit Facility”), is presented net of deferred financing costs. 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).

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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 designated as hedging instruments, had on its Condensed Consolidated Statements of Operations (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Net cash received (paid) on settled derivative instruments	$	(71,634	)	$	19,030		$	(189,252	)	$	141,529
Unrealized gain (loss)		(9,845	)		(38,912	)		(216,352	)		13,124
Price risk management activities income (expense)	$	(81,479	)	$	(19,882	)	$	(405,604	)	$	154,653

The following tables reflect the contracted volumes and weighted average prices under the terms of the Company's derivative contracts as of September 30, 2021:


Swap Contracts
Production Period	Settlement Index	Average Daily Volumes		Weighted Average Swap Price
Crude oil:		(Bbls)		(per Bbl)
October 2021 – December 2021	NYMEX WTI CMA		27,989	$	50.23
January 2022 – December 2022	NYMEX WTI CMA		21,112	$	50.28
January 2023 – June 2023	NYMEX WTI CMA		8,994	$	59.75
October 2021 – December 2021	Argus LLS		3,000	$	38.83
Natural gas:		(MMBtu)		(per MMBtu)
October 2021 – December 2021	NYMEX Henry Hub		54,630	$	2.58
January 2022 – December 2022	NYMEX Henry Hub		40,912	$	2.70
January 2023 – June 2023	NYMEX Henry Hub		14,989	$	3.14


Collar Contracts
Production Period	Settlement Index	Average Daily Volumes		Weighted Average Put Price		Weighted Average Call Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
October 2021 – December 2021	NYMEX WTI CMA		1,000	$	30.00	$	40.00
Natural gas:		(MMBtu)		(per MMBtu)		(per MMBtu)
October 2021 – December 2021	NYMEX Henry Hub		5,000	$	2.50	$	3.10

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


	September 30, 2021
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps and costless collars	$	—	$	51		$	—	$	51
Liabilities:
Oil and natural gas swaps and costless collars		—		(284,217	)		—		(284,217	)
Total net liability	$	—	$	(284,166	)	$	—	$	(284,166	)


	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 as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands):


	September 30, 2021				December 31, 2020
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	2	$	248,361	$	6,876	$	66,010
Non-current		49		35,856		945		9,625
Total gross amounts presented on balance sheet		51		284,217		7,821		75,635
Less: Gross amounts not offset on the balance sheet		51		51		4,877		4,877
Net amounts	$	—	$	284,166	$	2,944	$	70,758

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 has 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 September 30, 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 eight 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.

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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):


	September 30, 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 November 2024		400,000			640,000
Total debt, before discount and deferred financing cost		1,056,060			993,314
Discount and deferred financing cost		(71,223	)		(7,802	)
Total debt, net of discount and deferred financing costs		984,837			985,512
Less: Current portion of long-term debt		6,060			—
Long-term debt, net of discount and deferred financing costs	$	978,777		$	985,512

12.00% Second-Priority Senior Notes

The 12.00% Second-Priority Senior Secured Notes due 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. (the "Parent Guarantor"), Talos Production Inc. (the "Issuer"), and certain of the Issuer's subsidiaries (the "Subsidiary Guarantors" and, together with the Parent Guarantor, the "Guarantors") 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 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Subsidiary Guarantors and will be unconditionally guaranteed on the same basis by certain of the Issuer’s future subsidiaries. The 12.00% Notes are secured on a second-priority basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. 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 the 12.00% 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 in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below:


Period	Redemption Price
2023		106.00	%
2024		103.00	%
2025		100.00	%

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 September 30, 2021.

11.00% Second-Priority Senior Secured Notes

On January 13, 2021, the Company redeemed $347.3 million aggregate principal amount of the 11.00% Second-Priority Senior Secured Notes due 2022 (the “11.00% Notes”) at 102.75% plus accrued and unpaid interest using the proceeds from the issuance of the 12.00% Notes. The debt redemption resulted in a loss on extinguishment of debt of $13.2 million for the nine months ended September 30, 2021, which is presented as “Other income (expense)” on the Condensed Consolidated Statements of Operations.

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On June 15, 2020, the Company entered into an exchange agreement pursuant to which the Company agreed to exchange $37.2 million aggregate principal amount of the 11.00% Notes from certain holders in exchange for 3.1 million shares of the Company’s common stock plus cash in an amount equal to accrued interest up to the June 18, 2020 settlement date. Additionally, during the nine months ended September 30, 2020, the Company repurchased $5.8 million of the 11.00% Notes. The exchange agreement and debt repurchases resulted in a gain on extinguishment of $0.2 million and $1.7 million for the three and nine months ended September 30, 2020, respectively, and is presented as “Other income (expense)” on the Condensed Consolidated Statements of Operations.

Bank Credit Facility

The Company maintains a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. On August 2, 2021, an additional lender was added to the syndicate which increased commitments from $655.0 million to $730.0 million.

The Bank Credit Facility sets the interest rate at either (at the Company’s option) an alternative base rate plus a specified percentage, or London Interbank Offered Rate (“LIBOR”) plus a specified percentage. The specified percentage is referred to as the applicable margin, which varies based on the borrowing base utilization percentage.

As of September 30, 2021, the Company's borrowing base was $950.0 million with total commitments of $730.0 million. Additionally, no more than $200.0 million of the Company’s borrowing base can be used as letters of credit with current commitments at $150.0 million. 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 September 30, 2021. As of September 30, 2021, the Company had outstanding borrowings at a weighted average interest rate of 3.65%.

Note 7 — Employee Benefits Plans and Share-Based Compensation

Long Term Incentive Plans

On May 11, 2021, the Company’s stockholders approved the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”), which had previously been approved by the board of directors of the Company. No further awards will be granted under the Talos Energy Inc. Long Term Incentive Plan (the “2018 LTIP”).

The 2021 LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs (together with ISOs, “Options”), (iii) stock appreciation rights, (iv) restricted stock awards, (v) restricted stock units (the “RSUs”), (vi) awards of vested stock, (vii) dividend equivalents, (viii) other stock-based or cash awards and (ix) substitute awards (collectively, the “Awards”). Employees, non-employee directors and consultants of the Company and its affiliates are eligible to receive awards under the 2021 LTIP. The 2021 LTIP authorizes the Company to grant awards of up to 8,639,415 shares of the Company’s common stock, subject to the share counting and share recycling provisions of the 2021 LTIP.

Restricted Stock Units — The following table summarizes RSU activity for the nine months ended September 30, 2021:


	RSUs			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2020		1,652,988		$	13.73
Granted		1,102,038		$	13.11
Vested		(669,832	)	$	15.01
Forfeited		(94,922	)	$	12.55
Unvested RSUs at September 30, 2021(1)		1,990,272		$	13.01

(1)

As of September 30, 2021, 25,592 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Condensed Consolidated Balance Sheet.

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The Company considers its intent and ability to settle awards in cash or shares in determining whether to classify the awards as equity or as a liability. Certain awards granted during the nine months ended September 30, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The aggregate amount of compensation cost related to these awards is determined by the fair value of the award on the modification date.

Performance Share Units (“PSUs”) — The following table summarizes PSU activity for the nine months ended September 30, 2021:


	PSUs			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2020		834,172		$	25.46
Granted		586,995		$	18.96
Vested		(197,585	)	$	44.61
Forfeited		(14,400	)	$	18.48
Unvested PSUs at September 30, 2021		1,209,182		$	19.26

Certain awards granted during the nine months ended September 30, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the PSUs granted and modified at the date indicated:


	Modification Date			Grant Date
	May 11, 2021			March 8, 2021
Expected term (in years)		2.6			2.8
Expected volatility		80.9	%		78.3	%
Risk-free interest rate		0.3	%		0.3	%
Dividend yield		—	%		—	%
Fair value (in thousands)	$	9,715		$	11,129

Share-based Compensation Costs

Share-based compensation costs 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 following table presents the amount of cost expensed and capitalized (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Share-based compensation costs	$	4,993	$	4,386	$	15,534	$	12,053
Less: Amounts capitalized to oil and gas properties		2,380		2,039		7,240		5,732
Total share-based compensation expense	$	2,613	$	2,347	$	8,294	$	6,321

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 September 30, 2021, the Company recognized an income tax benefit of $0.4 million for an effective tax rate of 2.1%. The Company’s effective tax rate of 2.1% is different than the U.S. federal statutory income tax rate of 21% and is primarily due to recording a valuation allowance for its deferred tax assets. For the three months ended September 30, 2020, the Company recognized an income tax benefit of $28.3 million for an effective tax rate of 35.2%. The difference between the Company’s effective tax rate of 35.2% and the U.S. federal statutory income tax rate of 21% is primarily due to state income taxes and the income tax benefit from adopting the final regulations under section 163(j) of the Internal Revenue Code for tax years ended December 31, 2019 and 2020.

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For the nine months ended September 30, 2021, the Company recognized income tax expense of $0.7 million for an effective tax rate of negative 0.3%. The Company’s effective tax rate of negative 0.3% is different than the U.S. federal statutory income tax rate of 21% and is primarily due to recording a valuation allowance for its deferred tax assets. For the nine months ended September 30, 2020, the Company recognized an income tax benefit of $22.4 million for an effective tax rate of 39.1%. The difference between the Company’s effective tax rate of 39.1% and the U.S. federal statutory income tax rate of 21% is primarily due to state income taxes and the income tax benefit from adopting the final regulations under section 163(j) of the Internal Revenue Code for tax years ended December 31, 2019 and 2020.

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 September 30, 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 warrants expired unexercised on February 28, 2021.

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 September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Net loss	$	(16,691	)	$	(52,000	)	$	(263,964	)	$	(34,862	)

Weighted average common shares outstanding — basic		81,901			71,286			81,721			65,134
Dilutive effect of securities		—			—			—			—
Weighted average common shares outstanding — diluted		81,901			71,286			81,721			65,134

Net loss per common share:
Basic	$	(0.20	)	$	(0.73	)	$	(3.23	)	$	(0.54	)
Diluted	$	(0.20	)	$	(0.73	)	$	(3.23	)	$	(0.54	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		1,516			5,407			2,007			4,957

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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. Collectively, the Sponsors held 44.6% of the Company’s common stock as of September 30, 2021.

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. See additional details in Note 2 — Acquisitions.

Whistler Acquisition

On August 31, 2018, the Company acquired Whistler Energy II, LLC from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds. Included in "Other" accounts receivable on the Condensed Consolidated Balance Sheets is $5.5 million and $1.1 million at September 30, 2021 and December 31, 2020, respectively, due from an affiliate of the Apollo Funds. The outstanding receivable includes $1.1 million to reimburse the Company for certain payments made post-closing. The remaining $4.4 million is attributable to a settlement agreement executed in September 2021 related to a dispute regarding decommissioning obligation of a deep water well. During the three and nine months ended September 30, 2021, the Company recognized a $4.4 million gain resulting from the settlement which is reflected in “Other income (expense)” on the Company’s Condensed Consolidated Statements of Operations.

Subsequent Event — During October 2021, the Company received the payment from an affiliate of Apollo Funds to satisfy the outstanding $5.5 million receivable outstanding as of September 30, 2021.

Equity Registration Rights Agreement

The Sponsors and Riverstone Sellers are parties to an amended registration rights agreement relating to the registered resale of the Company’s common stock owned by such parties, a discussion of which is included in the Notes to the Consolidated Financial Statements in the 2020 Annual Report.

The Company will bear all of the expenses incurred in connection with the offer and sale, while the selling stockholders will be responsible for paying underwriting fees, discounts and selling commissions. For the three and nine months ended September 30, 2021, fees incurred by the Company were nil and $0.4 million, respectively. For the three and nine months ended September 30, 2020, the Company incurred nil and $0.2 million, 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”). A discussion of the Stockholders’ Agreement Amendment is included in the Notes to Consolidated Financial Statements in the 2020 Annual Report.

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. ("V&E") 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 V&E. For the three and nine months ended September 30, 2021, the Company incurred fees of approximately $1.1 million and $2.8 million, respectively, of which $1.9 million were payable for legal services performed by V&E as of September 30, 2021. For the three and nine months ended September 30, 2020, the Company incurred fees of approximately $0.6 million and $4.0 million, respectively, of which $2.2 million were payable for legal services performed by V&E as of September 30, 2020.

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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 September 30, 2021, the Company had secured performance bonds totaling approximately $810.6 million. The cost of securing these bonds are reflected as “Interest expense” in the Condensed Consolidated Statements of Operations. As of September 30, 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.

Decommissioning Obligations

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 or undergone associated reorganizations 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. During the three and nine months ended September 30, 2021, the Company recorded $4.1 million and $6.9 million, respectively, related to estimated decommissioning obligations reflected in “Other operating expense” in the Condensed Consolidated Statements of Operations.

Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, we could incur judgments, enter into settlements, or revise our opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.

Note 12 — Subsequent Events

Whistler Acquisition

For additional information, see Note 10 — Related Party Transactions.

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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.

Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

Our Business

We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage opportunities. We leverage decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, we are also utilizing our expertise to explore opportunities to reduce industrial emissions through our carbon capture and storage collaborative arrangements along the U.S. Gulf Coast and Gulf of Mexico.

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 and Global Economic Environment — The ongoing COVID-19 pandemic that emerged at the beginning of 2020 has resulted in the reimplementation of travel and social distancing restrictions as well as border and office closures in the various countries in which we operate, and continues to impact some of our business operations. On March 11, 2021, President Biden signed the American Rescue Plan Act of 2021, which is the latest stimulus package aimed at mitigating the financial impact of the pandemic. Beginning June 1, 2021, based on the high vaccination rate of our employees, our entire corporate workforce returned to the office and our offshore employees returned to normal offshore rotations; however, we continue to actively monitor the ongoing situation with respect to any future containment measures which may result from the emergence of new strains or variants of COVID-19 and promote the safety and wellbeing of our employees. Working remotely did not significantly impact 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, focusing on lower risk in-field drilling and development.

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FERC Regulatory Matters — The Federal Energy Regulatory Commission (“FERC”) issued its Five-Year Review of the Oil Pipeline Index establishing an index level of Producer Price Index for Finished Goods ("PPI-FG") plus 0.78% on December 17, 2020 for the five-year period commencing July 1, 2021 ("December 2020 Order"). A number of parties requested rehearing of the December 2020 Order and these requests remain pending as a result of FERC’s February 18, 2021 order granting rehearing for further consideration. FERC published a revised oil pricing index factor on May 14, 2021, utilizing the pricing index factor established in the December 2020 Order, resulting in a negative percent change for the index year July 1, 2021 through June 30, 2022. A negative percent changes means that the ceiling level for certain oil pipelines’ rates may decrease and, if the actual transportation rate would be above such ceiling level, the rate also must decrease to be equal to or less than the applicable ceiling. Accordingly, on June 15, 2021, SP 49 Pipeline filed to reduce certain of its rates, effective July 1, 2021. FERC’s final application of its indexing rate methodology for the next five-year term of index rates will be determined based on the outcome of these requests for rehearing, and any changes to FERC's index level may impact our revenues associated with any transportation services we may provide pursuant to rates adjusted by the FERC oil pipeline index.

Outer Continental Shelf Regulation — With regard to President Biden’s issuance of an executive order in January 2021 mandating the suspension of new leasing activities for oil and gas exploration and production on federal lands and offshore waters pending review and reconsideration of federal oil and gas permitting and leasing practices, in June 2021, a federal judge issued a nationwide temporary injunction in a lawsuit filed in federal district court in Louisiana that effectively halts the Biden Administration’s suspension on new leasing. The Biden Administration has announced that it will comply with the judge's order while the decision is appealed, and has separately scheduled a GOM lease sale for certain blocks to occur in November 2021. Several nongovernmental organizations have filed a lawsuit against the Department of the Interior challenging the proposed sale, which currently remains pending.

SEC Climate Change Regulation — The SEC's Division of Corporation Finance issued a sample letter on September 22, 2021 to highlight its increased focus on climate change-related disclosures. A climate change disclosure rulemaking is on the SEC's near-term agenda, but no new rules have been proposed yet.

Recent Developments

Below is a cumulative list of significant developments that have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended June 30, 2021.

TechnipFMC Strategic Alliance — In October 2021, we announced that we had entered into a long-term strategic alliance with TechnipFMC to develop and deliver technical and commercial solutions to Carbon Capture and Storage (“CCS”) projects along the United States Gulf Coast. Under the alliance, the companies intend to collaborate to progress CCS opportunities through the full lifecycle of storage site characterization, front-end engineering and design, and first injection through life of field operations.

Winning Bidder for Jefferson County Carbon Capture and Storage Site — In August 2021, we announced that, along with our partner Carbonvert, Inc., we were the successful bidder partnership for the Texas General Land Office's Jefferson County, Texas carbon storage site (the "Project Site") located near Beaumont and Port Arthur, Texas. The Project Site encompasses a total land area of over 40,000 gross acres and is located offshore in Texas state waters in the Gulf of Mexico. We expect it can ultimately sequester approximately 225 to 275 million metric tons of carbon dioxide from industrial sources in the area. The award provides us with a physical project site dedicated to carbon sequestration and storage. We are designated as the operator of this project.

Bank Credit Facility — On August 2, 2021, we announced the addition of a new lender to our Bank Credit Facility (as defined below under "Liquidity and Capital Resources — Overview of Debt Instruments"). See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.

Zama Update — On July 2, 2021, we were notified by Mexico’s Ministry of Energy ("SENER") that it had designated Petróleos Mexicanos ("PEMEX") as the operator of the Zama unit, just three days after SENER received a letter directly from PEMEX arguing for operatorship. Such designation may potentially result in material delays, underperformance, insufficient access to capital or adverse consequences as compared to our expectations for such project should we have been designated as operator. The Block 7 partners and PEMEX had engaged a third-party reservoir engineering firm to evaluate initial tract participation within the Zama reservoir, which concluded that the Block 7 consortium led by us holds 49.6% of the gross interest in Zama and PEMEX holds 50.4%.

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On September 3, 2021, we announced our submission of notices of dispute (the "Notices of Dispute") to the Government of Mexico over decisions taken by SENER, including the designation of PEMEX as the operator of a yet-to-be unitized asset. The actions taken by SENER constitute violations of the Agreement between the United States of America, the United Mexican States and Canada and the Bilateral Investment Treaty between the United Mexican States and the Belgo-Luxembourg Economic Union. We will continue to engage in good faith with the institutionally appointed representatives of the Government of Mexico by seeking to achieve a fair and mutually beneficial agreement.

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, we completed the acquisition of select interests in oil and natural gas assets from LLOG Exploration & Production Company, LLC (the “LLOG Acquisition”). A discussion of the LLOG Acquisition is included the Notes to Consolidated Financial Statements in the 2020 Annual Report.

Castex Energy 2005 Acquisition — On August 5, 2020, we completed the acquisition of select oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC (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” and collectively, the “ILX and Castex Acquisition”). See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for more information.

Hurricanes and Tropical Storms — During the third quarter of 2021, production from the U.S. Gulf of Mexico was impacted due to Hurricane Ida. While our assets did not sustain significant damage, the storm impacted key third-party downstream infrastructure, which prevented us from restoring the majority of our production for several weeks. For the three and nine months ended September 30, 2021, we estimate that deferred production related to this storm was approximately 12.7 MBoepd and 4.3 MBoepd, respectively, based on production rates prior to the storm. As of October 31, 2021, we still have approximately 3.8 MBoepd of production offline due to the continued impact of Hurricane Ida.

During 2020, production from the U.S. Gulf of Mexico was impacted due to precautionary shut-ins of facilities and evacuations associated with Hurricanes Hanna, Laura, Marco, Sally and Delta and Tropical Storms Cristobal and Beta. Although there was no major storm-related damage to our facilities, we incurred production downtime associated with the shut-ins for the storms. For the three and nine months ended September 30, 2020, we estimate deferred production related to these storms was approximately 8.6 MBoepd and 3.3 MBoepd, respectively, based on production rates prior to the storms.

Ram Powell Shut-In — Production at our Ram Powell facility was shut-in in late June 2020 while waiting for the repair of the platform’s oil export riser. We received final regulatory approvals and completed the repair of the export riser. Production commenced on November 21, 2020. For the three and nine months ended September 30, 2020, the Ram Powell facility shut-in resulted in deferred production of 4.9 MBoepd and 2.0 MBoepd, respectively.

Known Trends and Uncertainties

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2020 Annual Report for a detailed discussion of known trends and uncertainties. The following carries forward or provides an update to known trends and uncertainties discussed in our 2020 Annual Report.

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. 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.

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In 2020, OPEC and certain non-OPEC producers (“OPEC Plus”) agreed to production cuts intended to stabilize and support commodity prices, which resulted in cutting production by a record 9.7 million barrels per day starting on May 1, 2020 but was subsequently scaled back to 7.7 million barrels per day from August 1, 2020 through December 2020. On December 3, 2020, OPEC Plus agreed to increase production by 500,000 barrels per day beginning in January 2021 bringing the total production cuts to 7.2 million barrels per day. In January 2021, Saudi Arabia pledged 1.0 million barrels per day of voluntary cuts during February and March 2021. On March 4, 2021, OPEC Plus agreed to increase production by 150,000 barrels per day beginning in April 2021 and Saudi Arabia extended its one million barrels per day voluntary production cut into April 2021. At the April 1, 2021 meeting, OPEC Plus agreed to ease production cuts by 1.2 million barrels per day over a three month period starting May 1, 2021 through July 31, 2021, reducing the total production cuts to 5.8 million barrels per day. Moreover, Saudi Arabia decided to roll back its 1.0 million barrels per day of voluntary cuts over this same period. On July 18, 2021, OPEC Plus reached an agreement that will allow its members to collectively increase production by 400,000 barrels per day each month beginning August 2021 until phasing out the 5.8 million barrels per day and to reassess market developments in December 2021.

Oil prices have benefited from the continuation of coordinated production policies by OPEC Plus and capital discipline by oil and gas producers. Despite the recent upswing in oil prices, we believe that commodity prices will remain cyclical and volatile. We developed a flexible fiscal year 2021 capital spending budget that is within projected operating cash flows and does not require any long-term commitments. During January 1, 2021 through September 30, 2021, the daily spot prices for NYMEX WTI crude oil ranged from a high of $75.54 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 $2.43 per MMBtu. The spread between the high and low natural gas prices was caused by a severe winter storm that precipitated both an immediate constraint in the supply of and a significant increase in the demand for natural gas. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of production. From time to time, we may hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Financial Instruments” for more additional information regarding our commodity derivative positions as of September 30, 2021.

Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three and nine months ended September 30, 2021 and 2020, we did not recognize an impairment based on the ceiling test computations. At September 30, 2021 our ceiling test computation was based on SEC pricing of $58.25 per Bbl of oil, $3.02 per Mcf of natural gas and $20.75 per Bbl of NGLs.

There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 2020 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change in price differentials or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties.

With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties, not subject to amortization. The finalization of the Unitization and Unit Operating Agreement, which sets out the terms on which the reservoir will be jointly developed, and the outcome of the dispute with the Government of Mexico over decisions taken by SENER with respect to the Zama discovery could adversely affect the value of the oil and natural gas assets and result in an impairment of our unevaluated oil and gas properties prior to reaching a final investment decision or of our evaluated properties upon reaching a final investment decision.

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 Helix Producer I (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 mid-2022 with an estimated shut-in lasting approximately 45 days.

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BOEM Bonding Requirements — In 2016, the BOEM issued the 2016 Notice to Lessees and Operators (“NTL”), which bolstered supplemental bonding requirements. The NTL was not fully implemented as the BOEM under the Trump Administration first paused, and then in 2020 rescinded, this NTL. The BOEM and BSEE issued a jointly proposed rulemaking in October 2020 in which the BOEM proposed amendments to its financial assurance program. The proposed rule was significantly less stringent with respect to financial assurance than 2016 NTL. To date, however, a final rule has not issued.

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 implementation of a new NTL analogous to the 2016 NTL, or the October 2020 proposed rule, to the extent finalized, as well as to the provisions of any other 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 and the Biden Administration may elect to pursue more stringent supplemental bonding requirements.

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 the 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 and Tropical Storms — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes and tropical storms on production and capital projects. Significant 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.

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Results of Operations

Revenue and Other

The information below provides a discussion of, and an analysis of significant variances in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands):


	Three Months Ended September 30,							Nine Months Ended September 30,
	2021		2020		Change			2021		2020		Change
Revenues and other:
Oil	$	246,208	$	117,190	$	129,018		$	743,759	$	358,285	$	385,474
Natural gas		31,723		12,337		19,386			86,088		35,375		50,713
NGL		12,978		3,409		9,569			31,738		9,674		22,064
Other		—		2,201		(2,201	)		1,000		8,441		(7,441	)
Total revenues and other	$	290,909	$	135,137	$	155,772		$	862,585	$	411,775	$	450,810

Total Production Volumes:
Oil (MBbls)		3,609		3,005		604			11,827		10,010		1,817
Natural gas (MMcf)		6,975		6,922		53			24,055		20,961		3,094
NGL (MBbls)		429		311		118			1,344		1,028		316
Total production volume (MBoe)		5,200		4,470		730			17,180		14,532		2,648

Daily Production Volumes by Product:
Oil (MBblpd)		39.2		32.7		6.5			43.3		36.5		6.8
Natural gas (MMcfpd)		75.8		75.2		0.6			88.1		76.5		11.6
NGL (MBblpd)		4.7		3.4		1.3			4.9		3.8		1.1
Total production volume (MBoepd)		56.5		48.6		7.9			62.9		53.0		9.9

Average Sale Price Per Unit:
Oil (per Bbl)	$	68.22	$	39.00	$	29.22		$	62.89	$	35.79	$	27.10
Natural gas (per Mcf)	$	4.55	$	1.78	$	2.77		$	3.58	$	1.69	$	1.89
NGL (per Bbl)	$	30.25	$	10.96	$	19.29		$	23.61	$	9.41	$	14.20
Price per Boe	$	55.94	$	29.74	$	26.20		$	50.15	$	27.75	$	22.40
Price per Boe (including realized commodity derivatives)	$	42.17	$	34.00	$	8.17		$	39.13	$	37.49	$	1.64

The information below provides an analysis of the change in our oil, natural gas and NGL revenues due to changes in sale prices and production volumes (in thousands):


	Three Months Ended September 30, 2021 vs 2020						Nine Months Ended September 30, 2021 vs 2020
	Price		Volume		Total		Price		Volume		Total
Oil	$	105,462	$	23,556	$	129,018	$	320,444	$	65,030	$	385,474
Natural gas		19,292		94		19,386		45,484		5,229		50,713
NGL		8,276		1,293		9,569		19,090		2,974		22,064
Total revenues	$	133,030	$	24,943	$	157,973	$	385,018	$	73,233	$	458,251

Three Months Ended September 30, 2021 and 2020 Volumetric Analysis — Production volumes increased by 7.9 MBoepd to 56.5 MBoepd. The increase in production volumes was an increase of 5.9 MBoepd from the Green Canyon 18 Field, primarily due to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 Field platform rig program. Additionally, production volumes increased 4.9 MBoepd from temporary shut-ins for repairs and maintenance on the Ram Powell Field export riser during the third quarter of 2020. The increase was partially offset by a decrease in production of 4.1 MBoepd from disruptions from weather events in the U.S. Gulf of Mexico when compared to the same period in 2020.

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Nine Months Ended September 30, 2021 and 2020 Volumetric Analysis — Production volumes increased by 9.9 MBoepd to 62.9 MBoepd. The increase in production volumes was attributable to 6.4 MBoepd from temporary downtime as a result of repairs and maintenance that occurred in 2020 and 5.6 MBoepd from the Green Canyon 18 Field, primarily attributable to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 Field platform rig program. The increase was partially offset by a decrease in production of 1.0 MBoepd from disruptions from weather events in the U.S. Gulf of Mexico when compared to the same period in 2020.

Operating 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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Lease operating expenses	$	70,034	$	62,064	$	208,675	$	184,187
Lease operating expenses per Boe	$	13.47	$	13.88	$	12.15	$	12.67

Three Months Ended September 30, 2021 and 2020 — Total lease operating expense for the three months ended September 30, 2021 increased by approximately $8.0 million, or 13%. This increase was primarily related to an increase in lease operating expenses of $2.0 million incurred in connection with assets acquired in the Castex 2005 Acquisition and LLOG Acquisition when compared to the same period in 2020. Additionally, there was an overall increase in direct operating expenses and labor costs primarily due to the temporary shuttering of certain Shelf fields and cost cutting measures taken during third quarter of 2020 as a result of the economic environment caused by the COVID-19 pandemic. On a per unit basis, lease operating expense decreased $0.41 per Boe to $13.47 per Boe primarily as a result of higher production.

Nine Months Ended September 30, 2021 and 2020 — Total lease operating expense for the nine months ended September 30, 2021 increased by approximately $24.5 million, or 13%. This increase was primarily related to an increase in lease operating expenses of $11.6 million incurred in connection with assets acquired in the Castex 2005 Acquisition and LLOG Acquisition when compared to the same period in 2020. Hurricane related repairs increased $4.3 million due to Hurricane Ida and ongoing repairs for 2020 named storms in the first half of 2021. Further, there was an increase in workover expense of $10.6 million primarily related to South Marsh Island 130 Field, non-operated deepwater Marmalard Field and Amberjack Fields. On a per unit basis, lease operating expense decreased $0.52 per Boe to $12.15 per Boe primarily as a result of higher production.

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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Depreciation, depletion and amortization	$	88,596	$	80,547	$	290,094	$	262,533
Depreciation, depletion and amortization per Boe	$	17.04	$	18.02	$	16.89	$	18.07

Three Months Ended September 30, 2021 and 2020 — Depreciation, depletion and amortization expense for the three months ended September 30, 2021 increased by approximately $8.0 million, or 10%. This increase was primarily due to increased production of 7.9 MBoepd partially offset by a decrease of $0.91 per Boe, or 5% 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.

Nine Months Ended September 30, 2021 and 2020 — Depreciation, depletion and amortization expense for the nine months ended September 30, 2021 increased by approximately $27.6 million, or 10%. This increase was primarily due to increased production of 9.9 MBoepd offset by a decrease of $1.14 per Boe, or 6% 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.

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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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
General and administrative expense	$	20,427	$	17,823	$	58,993	$	62,484
General and administrative expense per Boe	$	3.93	$	3.99	$	3.43	$	4.30

Three Months Ended September 30, 2021 and 2020 — General and administrative expense for the three months ended September 30, 2021 increased by approximately $2.6 million, or 15%, which was primarily related to increased employee and contract labor costs.

Nine Months Ended September 30, 2021 and 2020 — General and administrative expense for the nine months ended September 30, 2021 decreased by approximately $3.5 million, or 6%. Transaction and non-recurring expenses were $4.8 million, or $0.28 per Boe, for the nine months ended September 30, 2021, which is a decrease of $8.1 million primarily due to the ILX and Castex Acquisition that occurred in the first quarter of 2020. This decrease was partially offset by increased employee and contract labor costs. General and administrative expense includes non-cash equity-based compensation of $8.3 million, or $0.48 per Boe, for the nine months ended September 30, 2021, which is an increase of $2.0 million.

Miscellaneous

The following table highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021		2020
Write-down of oil and natural gas properties	$	—		$	—		$	—	$	57
Accretion expense	$	13,668		$	11,537		$	44,110	$	37,748
Other operating expense	$	5,081		$	—		$	7,864	$	—
Interest expense	$	32,390		$	24,124		$	100,036	$	76,164
Price risk management activities (income) expense	$	81,479		$	19,882		$	405,604	$	(154,653	)
Other (income) expense	$	(4,475	)	$	(813	)	$	7,916	$	(139	)
Income tax (benefit) expense	$	(364	)	$	(28,252	)	$	718	$	(22,384	)

Three Months Ended September 30, 2021 and 2020 —

Interest Expense — During the three months ended September 30, 2021, we recorded $32.4 million of interest expense compared to $24.1 million during the three months ended September 30, 2020. The change is primarily a result of the interest associated with the 12.00% Notes (as defined below under “Liquidity and Capital Resources — Overview of Debt Instruments”) issued in January 2021 with an aggregate principal amount of $650.0 million when compared to the interest on the 11.00% Notes (as defined below under “Liquidity and Capital Resources — Overview of Debt Instruments”) that were redeemed in January 2021. See further discussion in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt.”

Other operating expense — During the three months ended September 30, 2021, we recorded $4.1 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 11 — Commitments and Contingencies.”

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Price risk management activities — Price risk management activities for the three months ended September 30, 2021 decreased by approximately $61.6 million, or 310%. The expense of $81.5 million for the three months ended September 30, 2021 consists of $71.6 million in cash settlement losses and $9.8 million in non-cash losses from the decrease in the fair value of our open derivative contracts. The expense of $19.9 million for the three months ended September 30, 2020 consists of $38.9 million in non-cash losses from the decrease in the fair value of our open derivative contracts partially offset by $19.0 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. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Financial Instruments.”

Other (income) expense — During the three months ended September 30, 2021 we recorded a $4.4 million gain as a result of the settlement related to the Whistler Acquisition that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Related Party Transactions.”

Income tax (benefit) expense — During the three months ended September 30, 2021, we recorded $0.4 million of income tax benefit compared to $28.3 million of income tax benefit during the three months ended September 30, 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.”

Nine Months Ended September 30, 2021 and 2020 —

Interest Expense — During the nine months ended September 30, 2021, we recorded $100.0 million of interest expense compared to $76.2 million during the nine months ended September 30, 2020. The change is primarily a result of the interest associated with the 12.00% Notes issued in January 2021 with an aggregate principal amount of $650.0 million when compared to the interest on the 11.00% Notes that were redeemed in January 2021. See further discussion in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt.”

Other operating expense — During the nine months ended September 30, 2021, we recorded $6.9 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 11 — Commitments and Contingencies.”

Price risk management activities — Price risk management activities for the nine months ended September 30, 2021 decreased by approximately $560.3 million, or 362%. The expense of $405.6 million for the nine months ended September 30, 2021 consists of $216.4 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $189.3 million in cash settlement losses. The income of $154.7 million for the nine months ended September 30, 2020 consists of $141.5 million in cash settlement gains and $13.2 million in non-cash gains from the increase in the fair value of our open derivative contracts. 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. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Financial Instruments.”

Other (income) expense — During the nine months ended September 30, 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.” This was partially offset by a $4.4 million gain as a result of the settlement related to the Whistler Acquisition that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Related Party Transactions.”

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Income tax (benefit) expense — During the nine months ended September 30, 2021, we recorded $0.7 million of income tax expense compared to $22.4 million of income tax benefit during the nine months ended September 30, 2020. The change is primarily a result of recording a valuation allowance on our deferred tax assets as of December 31, 2020. 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), (gain) loss on debt extinguishment, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense.

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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 September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Reconciliation of net loss to Adjusted EBITDA:
Net loss	$	(16,691	)	$	(52,000	)	$	(263,964	)	$	(34,862	)
Interest expense		32,390			24,124			100,036			76,164
Income tax (benefit) expense		(364	)		(28,252	)		718			(22,384	)
Depreciation, depletion and amortization		88,596			80,547			290,094			262,533
Accretion expense		13,668			11,537			44,110			37,748
EBITDA		117,599			35,956			170,994			319,199
Write-down of oil and natural gas properties		—			—			—			57
Transaction and non-recurring expense(1)		1,370			1,607			7,231			12,863
Derivative fair value (gain) loss(2)		81,479			19,882			405,604			(154,653	)
Net cash received (paid) on settled derivative instruments(2)		(71,634	)		19,030			(189,252	)		141,529
(Gain) loss on extinguishment of debt		—			(174	)		13,225			(1,644	)
Non-cash write-down of other well equipment inventory		—			—			—			133
Non-cash equity-based compensation expense		2,613			2,347			8,294			6,321
Adjusted EBITDA	$	131,427		$	78,648		$	416,096		$	323,805

(1)

Includes transaction related expenses, restructuring expenses, cost saving initiatives and other miscellaneous income and expenses.

(2)

The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) 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 an unrealized basis during the period the derivatives settled.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. Our working capital deficit has increased since December 31, 2020 primarily due to an increase of $182.4 million in liabilities from price risk management activities. As of September 30, 2021, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $375.9 million.

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

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2021 (in thousands):


U.S. drilling & completions	$	115,391
Mexico appraisal & exploration		777
Asset management		62,015
Seismic and G&G, land, capitalized G&A and other		38,366
Total capital expenditures		216,549
Plugging & abandonment		58,001
Total capital expenditures and plugging & abandonment	$	274,550

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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 the remainder of our board approved 2021 capital spending program of $340.0 million to $370.0 million and our working capital deficit. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, raising debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding debt.

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


	Nine Months Ended September 30,
	2021			2020
Operating activities	$	287,648		$	262,067
Investing activities	$	(212,153	)	$	(585,152	)
Financing activities	$	(50,301	)	$	268,440

Operating Activities — Net cash provided by operating activities increased $25.6 million in the nine months ended September 30, 2021 compared to the corresponding period in 2020 primarily attributable to an increase in revenues net of lease operating expense of $426.3 million. This was offset by an increase in cash payments on derivative instruments of $330.8 million, interest expense of $23.9 million and settlements of asset retirement obligations of $23.5 million.

Investing Activities — Net cash used in investing activities decreased $373.0 million in the nine months ended September 30, 2021 compared to the corresponding period in 2020 primarily due to a decrease in payments for acquisitions of $299.5 million and a decrease in capital expenditures of $68.7 million.

Financing Activities — Cash flow from financing activities decreased $318.7 million in the nine months ended September 30, 2021 compared to the corresponding period in 2020. During the nine months ended September 30, 2020, net proceeds of $300.0 million were received from the Bank Credit Facility and used primarily to fund the ILX and Castex Acquisition in the first quarter of 2020. During the nine months ended September 30, 2021, the issuance of the 12.00% Notes in January 2021 generated $579.4 million after original discount and deferred financing costs. The net proceeds from the 12.00% Notes funded the $356.8 million redemption of the 11.00% Notes and reduced the indebtedness under the Bank Credit Facility by $175.0 million in the first quarter of 2021. Indebtedness under the Bank Credit Facility was then further reduced by $65.0 million.

Overview of Debt Instruments

Bank Credit Facility — matures November 2024 — We maintain a Bank Credit Facility with a syndicate of financial institutions (the “Bank Credit Facility”). 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. On August 2, 2021, an additional lender was added to the syndicate which increased commitments from $655.0 million to $730.0 million. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.

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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. (the "Parent Guarantor"), Talos Production Inc. (“Issuer”), and the Subsidiary Guarantors (as defined below) 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 are secured on a second-priority basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. 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. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.

Redemption of the 11.00% Second-Priority Senior Secured Notes—due April 2022 — On January 13, 2021, we redeemed the 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) using the proceeds from the issuance of 12.00% Notes. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.

Guarantor Financial Information — Talos owns no operating assets and has no operations independent of its subsidiaries. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material domestic subsidiaries (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”) that guarantees the Issuer’s senior reserve-based revolving credit facility. Our non-domestic subsidiaries (the “Non-Guarantors”) are 100% owned by Talos but do not guarantee the 12.00% Notes.

In lieu of providing separate financial statements for the Issuer and the Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and income statement information for the Issuer 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):


	September 30, 2021		December 31, 2020
Current assets	$	246,199	$	231,669
Non-current assets		2,384,660		2,444,886
Total assets	$	2,630,859	$	2,676,555

Current liabilities	$	633,368	$	438,340
Non-current liabilities		1,475,365		1,459,816
Talos Energy Inc. stockholdersʼ equity		522,126		778,399
Total liabilities and stockholdersʼ equity	$	2,630,859	$	2,676,555

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


	Nine Months Ended September 30, 2021
Revenues and other	$	862,585
Costs and expenses		(1,122,621	)
Net loss	$	(260,036	)

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Contractual Obligations

We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations since those reported in our 2020 Annual Report except:



The aggregate principal amount of our debt increased from $993.3 million to $1,056.1 million due to the issuance of the 12.00% Notes, redemption of the 11.00% Notes and lower borrowings under the Bank Credit Facility;



Interest expense through the maturity of our debt instruments increased in the aggregate by approximately $369.6 million primarily due to the issuance of the 12.00% Notes, maturity extension of the Bank Credit Facility and lower borrowings under the Bank Credit Facility;



Vessel commitments increased by approximately $25.9 million due to the execution of a 2022 offshore drilling rig agreement. These commitments represent gross contractual obligations and, accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs; and



Derivative net liabilities increased from $67.8 million to $284.2 million.

Performance Bonds — As of September 30, 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 $810.6 million.

See “Known Trends and Uncertainties — BOEM Bonding Requirements” under Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.

Off Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of September 30, 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

There was no recently issued accounting standards material to us.

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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 September 30, 2021.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

On May 29, 2020, a lawsuit was filed in the Delaware Court of Chancery asserting derivative and class action claims against us relating to the ILX and Castex Acquisition (as previously defined in this Quarterly Report). Specifically, the lawsuit, among other things, related to the fairness of the consideration paid for such acquisitions in light of the fact that certain of the sellers were affiliates of Riverstone Energy Partners V, L.P. The lawsuit was dismissed during the third quarter of 2021, and the plaintiffs have appealed the dismissal to the Delaware Supreme Court.

There have been no additional 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

Not applicable.

Item 5. Other Information

None.

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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).

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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).

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

22.1		List of Subsidiary Guarantors and Issuers of Guaranteed Securities (incorporated by reference to Exhibit 22.1 to Talos Energy Inc.'s Form 10-Q (File No. 001-38497) filed with the SEC on August 4, 2021).

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.

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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:	November 3, 2021	By:	/s/ Shannon E. Young III
			Shannon E. Young III
			Executive Vice President and Chief Financial Officer