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.

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,~~26, 2022, the registrant had ~~81,881,477~~82,570,328 shares of common stock, $0.01 par value per share, outstanding.

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

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

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

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

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

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.

MBblpd — One thousand barrels of crude oil or other liquid hydrocarbons 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 Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub index.

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

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

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

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%.

The information in this Quarterly Report on Form 10-Q (this ~~"Quarterly Report"~~“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,~~Quarterly 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,~~Quarterly Report, the words “will,” “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:

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,~~other state-controlled oil companies (“OPEC Plus”), such as Saudi Arabia and Russia, to set and maintain oil production levels; the impact of any such actions; the lack of a resolution to the war in Ukraine and its impact on certain commodity markets; 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;~~sustained inflation and the impact of central bank policy in response thereto; 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~~2021, filed with the SEC on ~~March 11, 2021~~February 25, 2022 (the ~~“2020~~“2021 Annual Report”)., Part II, Item 1A. “Risk Factors” of Talos Energy Inc.’s Quarterly Report on Form 10-Q for the period ended March 31, 2022, filed with the SEC on May 5, 2022 and Part II, Item 1A. “Risk Factors” of Talos Energy Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2022, filed with the SEC on August 5, 2022.

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.

Note 1 — Organization, Nature of Business and Basis of Presentation

Organization and Nature of Business

Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017. On May 10, 2018, the Parent Company consummated a combination between Talos Energy LLC and Stone Energy Corporation (“Stone”). Talos Energy LLC, which was the acquirer of Stone for financial reporting and accounting purposes, was formed in 2011 and commenced commercial operations on February 6, 2013. The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on The New York Stock Exchange under the ticker symbol “TALO.”

The Parent Company (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 through upstream ~~through~~ oil and gas exploration and production and ~~downstream through~~ the development of ~~future~~ carbon capture and ~~storage~~sequestration (“CCS”) opportunities. The Company leverages decades of technical and offshore operational expertise ~~towards~~in 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 industrialemissions through the ~~Company's carbon capture~~Company’s CCS initiatives both in and ~~storage collaborative arrangements~~ along the coast of 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~~2021 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 and the reported amounts of revenues and expenses during the reporting ~~periods and the reported amounts of proved oil and natural gas reserves.~~periods. Actual results could differ from those estimates.

Certain reclassifications have been made to the prior year’s presentation to conform to the current year’s presentation. Amounts previously included as income in “Other” within “Revenues and Other” on the Condensed Consolidated Statements of Operations are now reflected in “Other operating (income) expense” as a component of “Total operating expenses” on the Condensed Consolidated Statements of Operations.

Segments

The Company has 1two ~~reportable segment, which is the~~operating segments: (i) exploration and production of oil, natural gas and ~~NGLs. Substantially all~~NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been designated as unrestricted, non-guarantor subsidiaries of the ~~Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States.~~

Note 32 — Property, Plant and Equipment

~~Ceiling Test~~Proved Properties

During the three and nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, the Company’s ceiling test computations did 0not result in a write-down of its U.S. oil and natural gas properties. At September 30, ~~2021,~~2022, the Company’s ceiling test computation was based on SEC pricing of $~~58.25~~93.61 per Bbl of oil, $~~3.02~~6.56 per Mcf of natural gas and $~~20.75~~35.94 per Bbl of NGLs.

~~Table of Contents~~

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
Asset retirement obligations at December 31, 2021				$	434,006
Obligations incurred		52			78
Obligations settled		(58,001	)		(60,304	)
Obligations divested		(340	)		(1,572	)
Accretion expense		44,110			42,400
Changes in estimate		29,440			38,656
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
Asset retirement obligations at September 30, 2022				$	453,264
Less: Current portion at September 30, 2022					65,613
Long-term portion at September 30, 2022				$	387,651

Note 43 — 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.

Table of Contents

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,				Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2022		2021		2022		2021
Finance lease cost - interest on lease liabilities	$	2,749	$	3,848	$	9,017	$	12,153	$	1,386	$	2,749	$	5,179	$	9,017
Operating lease cost, excluding short-term leases(1)		702		815		2,138		2,547		568		702		1,703		2,138
Short-term lease cost(2)		14,541		21,845		32,393		41,128		12,982		14,541		24,838		32,393
Variable lease cost(3)		350		215		994		221		363		350		1,088		994
Total lease cost	$	18,342	$	26,723	$	44,542	$	56,049	$	15,299	$	18,342	$	32,808	$	44,542

(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.

~~Table of Contents~~

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		September 30, 2022		December 31, 2021
Operating leases:
Operating lease assets	$	5,748	$	6,855	$	5,518	$	5,714

Current portion of operating lease liabilities	$	1,651	$	1,793	$	1,885	$	1,715
Operating lease liabilities		16,781		18,554		14,895		16,330
Total operating lease liabilities	$	18,432	$	20,347	$	16,780	$	18,045

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

Other current liabilities	$	25,643	$	21,804	$	20,458	$	27,083
Other long-term liabilities		20,458		40,222		—		13,138
Total finance lease liabilities	$	46,101	$	62,026	$	20,458	$	40,221

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


	Nine Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2022		2021
Operating cash outflow from finance leases	$	9,017	$	12,153	$	5,179	$	9,017
Operating cash outflow from operating leases	$	2,946	$	1,666	$	2,776	$	2,946

Right-of-use assets obtained in exchange for new operating lease liabilities	$	1,020	$	0	$	—	$	1,020

No~~te 5~~Note 4 — Financial Instruments

As of September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, 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.

Table of Contents

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				September 30, 2022				December 31, 2021
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		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
12.00% Second-Priority Senior Secured Notes – due January 2026									$	597,570	$	678,438	$	588,838	$	685,945
7.50% Senior Notes – due May 2022									$	—	$	—	$	6,060	$	6,145
Bank Credit Facility – matures November 2024	$	392,638	$	400,000	$	635,873	$	640,000	$	54,538	$	60,000	$	367,829	$	375,000

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).

~~Table of Contents~~

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~~production. The Company is currently utilizing 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,					Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020		2022			2021			2022			2021
Net cash received (paid) on settled derivative instruments	$	(71,634	)	$	19,030		$	(189,252	)	$	141,529
Net cash paid on settled derivative instruments												$	(81,162	)	$	(71,634	)	$	(368,483	)	$	(189,252	)
Unrealized gain (loss)		(9,845	)		(38,912	)		(216,352	)		13,124		195,342			(9,845	)		137,350			(216,352	)
Price risk management activities income (expense)	$	(81,479	)	$	(19,882	)	$	(405,604	)	$	154,653	$	114,180		$	(81,479	)	$	(231,133	)	$	(405,604	)

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:~~2022:

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


Swap Contracts
Production Period	Settlement Index	Average Daily Volumes		Weighted Average Swap Price
Crude oil:		(Bbls)		(per Bbl)
October 2022 – December 2022	NYMEX WTI CMA		19,326	$	55.05
January 2023 – December 2023	NYMEX WTI CMA		14,863	$	72.18
January 2024 – September 2024	NYMEX WTI CMA		3,989	$	76.59
Natural gas:		(MMBtu)		(per MMBtu)
October 2022 – December 2022	NYMEX Henry Hub		44,000	$	4.21
January 2023 – December 2023	NYMEX Henry Hub		26,395	$	3.76
January 2024 – June 2024	NYMEX Henry Hub		10,000	$	3.25

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

Table of Contents


Collar Contracts
Production Period	Settlement Index	Average Daily Volumes		Weighted Average Put Price		Weighted Average Call Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
July 2023 – September 2023	NYMEX WTI CMA		2,000	$	75.00	$	90.43
January 2024 – March 2024	NYMEX WTI CMA		2,000	$	70.00	$	88.00
Natural gas:		(MMBtu)		(per MMBtu)		(per MMBtu)
January 2023 – December 2023	NYMEX Henry Hub		10,000	$	5.25	$	8.46
January 2024 – December 2024	NYMEX Henry Hub		10,000	$	4.00	$	6.90

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
$
0

$
51

$
0

$
51

Liabilities:

Oil and natural gas swaps and costless collars

0

(284,217
)

0

(284,217
)
Total net liability
$
0

$
(284,166
)
$
0

$
(284,166
)


	September 30, 2022
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	46,929		$	—	$	46,929
Liabilities:
Oil and natural gas derivatives		—		(106,306	)		—		(106,306	)
Total net liability	$	—	$	(59,377	)	$	—	$	(59,377	)


	December 31, 2020										December 31, 2021
	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps and costless collars	$	0	$	7,821		$	0	$	7,821
Oil and natural gas derivatives											$	—	$	3,737		$	—	$	3,737
Liabilities:
Oil and natural gas swaps and costless collars		0		(75,635	)		0		(75,635	)
Oil and natural gas derivatives												—		(200,464	)		—		(200,464	)
Total net liability	$	0	$	(67,814	)	$	0	$	(67,814	)	$	—	$	(196,727	)	$	—	$	(196,727	)

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				September 30, 2022				December 31, 2021
	Assets		Liabilities		Assets		Liabilities		Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	2	$	248,361	$	6,876	$	66,010	$	27,389	$	99,180	$	967	$	186,526
Non-current		49		35,856		945		9,625		19,540		7,126		2,770		13,938
Total gross amounts presented on balance sheet		51		284,217		7,821		75,635		46,929		106,306		3,737		200,464
Less: Gross amounts not offset on the balance sheet		51		51		4,877		4,877		44,708		44,708		3,737		3,737
Net amounts	$	0	$	284,166	$	2,944	$	70,758	$	2,221	$	61,598	$	—	$	196,727

Table of Contents

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~~2022 represent derivative instruments from 9nine 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 8all 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.

~~Table of Contents~~

N~~ote 6~~Note 5 — 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

$
0

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

0

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

0

Long-term debt, net of discount and deferred financing costs
$
978,777

$
985,512


	September 30, 2022			December 31, 2021
12.00% Second-Priority Senior Secured Notes – due January 2026	$	650,000		$	650,000
7.50% Senior Notes – due May 2022		—			6,060
Bank Credit Facility – matures November 2024(1)		60,000			375,000
Total debt, before discount and deferred financing cost		710,000			1,031,060
Discount and deferred financing cost		(57,892	)		(68,333	)
Total debt, net of discount and deferred financing costs(2)		652,108			962,727
Less: Current portion of long-term debt		—			6,060
Long-term debt, net of discount and deferred financing costs	$	652,108		$	956,667

~~12.00% Second-Priority Senior Notes~~

~~The 12.00% Second-Priority Senior Secured Notes due 2026 (the “~~(1)

~~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 certainAs 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,~~September 30, 2022, the Company ~~may redeem up to~~ 40~~% of the principal amount of the 12.00% Notes~~had outstanding borrowings at a ~~redemption~~weighted average interest rate of ~~112.00~~6.16% of.

(2)

At September 30, 2022, 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.~~

covenants.

~~11.00% Second-Priority~~7.50% Senior ~~Secured~~ Notes

On ~~January 13, 2021,~~May 31, 2022, the ~~Company~~7.50% Senior Notes matured and were redeemed at an aggregate principal of $~~347.3~~6.1 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 $~~interest.~~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.~~

~~Table of Contents~~

~~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 athe Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for the 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 of each year. On May 4, 2022, the Company entered into a (i) Borrowing Base Redetermination Agreement and Eighth Amendment to Credit Agreement (the “Eighth Amendment”) and (ii) Incremental Agreement of Increasing Lenders (“Incremental Agreement”). ~~On August 2, 2021, an additional lender was added to~~The Eighth Amendment and the ~~syndicate which~~Incremental Agreement, among other things, (i) increased ~~commitments~~the borrowing base from $~~655.0~~950.0 million to $~~730.0~~1.1 billion and (ii) increased the commitments from $791.3 million to $806.3 million.

Table of Contents

The Bank Credit Facility ~~sets~~no longer bears interest at the ~~interest rate~~applicable London InterBank Offered Rate plus the applicable margin. Interest under the Bank Credit Facility accrues at ~~either (at~~ the Company’s ~~option)~~option either at an ~~alternative~~alternate base rate ~~plus a specified percentage, or London Interbank Offered Rate~~ (“~~LIBOR”~~ABR”) plus ~~a specified percentage. The specified percentage is referred to as~~ the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). The ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5% or (c) the adjusted term SOFR for a one-month interest period plus 1.00%. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months, six-months, and twelve-months) calculated and published by the CME Group Inc. plus 0.10%. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York plus 0.10%. The applicable margin, which ~~varies~~is based on the borrowing base utilization ~~percentage.~~

~~As of September 30, 2021, the Company's borrowing base was $~~percentage, ranges from ~~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~~2.00%. to 3.00% for ABR Loans and 3.00% to 4.00% for Term Benchmark Loans and RFR Loans.

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 under the 2021 LTIP for the nine months ended September 30, ~~2021:~~2022:

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

The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the absolute TSR PSUs granted ~~and modified~~ at the date indicated:


	2022
	Grant			Grant
	September 20			March 5
Expected term (in years)		2.3			2.8
Expected volatility		74.3	%		82.2	%
Risk-free interest rate		3.9	%		1.6	%
Dividend yield		—	%		—	%
Fair value (in thousands)	$	621		$	8,668

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

0
%

0
%
Fair value (in thousands)
$
9,715

$
11,129

Table of Contents

Modification — During March 2022, the outstanding PSUs held by certain executive officers that were awarded in 2020 and 2021 were cancelled and, in connection with this cancellation, 1,147,352 of RSUs were granted (the “Retention RSUs”). The Retention RSUs will vest ratably each year over two years, generally contingent upon continued employment through each such date. The cancellation of the PSUs along with the concurrent grant of the Retention RSUs are accounted for as a modification. The incremental cost of $9.7 million will be recognized prospectively over the modified requisite service period. Additionally, the remaining unrecognized fair value of the original PSUs will be recognized over the original remaining requisite service period.

Share-based Compensation Costs

Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and administrative expense,” inon the Condensed Consolidated Statements of Operations, net amounts capitalized to “Proved Properties,” inon 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” inon the Condensed Consolidated Statements of Cash Flows.

The following table presents the amount of ~~cost~~costs expensed and capitalized ~~(in~~(in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2022		2021		2022		2021
Share-based compensation costs	$	4,993	$	4,386	$	15,534	$	12,053	$	7,626	$	4,993	$	20,597	$	15,534
Less: Amounts capitalized to oil and gas properties		2,380		2,039		7,240		5,732		3,316		2,380		8,920		7,240
Total share-based compensation expense	$	2,613	$	2,347	$	8,294	$	6,321	$	4,310	$	2,613	$	11,677	$	8,294

Note 87 — 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, 2022, the Company recognized an income tax expense of $0.1 million for an effective tax rate of 0.0%. The Company’s effective tax rate of 0.0% is different than the U.S. federal statutory income tax rate of 21% primarily due to recording a valuation allowance for its deferred tax assets. For the three months ended 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~~lower than the U.S. federal statutory income tax rate of 21% ~~and~~primarily due to recording a valuation allowance for its deferred tax assets.

For the nine months ended September 30, 2022, the Company recognized income tax expense of $2.3 million for an effective tax rate of 0.6%. The Company’s effective tax rate of 0.6% is lower than the U.S. federal statutory income tax rate of 21% primarily due to recording a valuation allowance for its deferred tax assets. For the ~~three months ended 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.

~~Table of Contents~~

~~For the~~ nine months ended September 30, 2021, the Company recognized an income tax expense of $0.7 million for an effective tax rate of negative 0.3%. The difference between 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~~recording a valuation allowance for its deferred 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.~~assets.

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.

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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,~~2022, the Company maintains a full valuation allowance for U.S. federal, state and foreign net deferred tax assets.

Note 98 — 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

0

0

0

0

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

~~Table of Contents~~


	Three Months Ended September 30,					Nine Months Ended September 30,
	2022		2021			2022		2021
Net income (loss)	$	250,465	$	(16,691	)	$	379,165	$	(263,964	)

Weighted average common shares outstanding — basic		82,576		81,901			82,406		81,721
Dilutive effect of securities		1,242		—			1,032		—
Weighted average common shares outstanding — diluted		83,818		81,901			83,438		81,721

Net income (loss) per common share:
Basic	$	3.03	$	(0.20	)	$	4.60	$	(3.23	)
Diluted	$	2.99	$	(0.20	)	$	4.54	$	(3.23	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		120		1,516			1,149		2,007

N~~ote 10~~Note 9 — Related Party Transactions

Apollo Funds and Riverstone Funds

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,~~On January 3, 2022, the ~~Sponsors~~Apollo Funds ceased being a beneficial owner of more than five percent of the Company’s common stock. Riverstone Funds held ~~44.6~~14.9% 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~~.2022.

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~~A settlement agreement ~~executed in September 2021~~ related to a dispute regarding the decommissioning obligation of a ~~deep water well.~~Deepwater well was executed in September 2021. 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~~19

— Table of Contents

~~During October 2021, the Company received the payment from~~Registration Rights Agreements

Riverstone Funds as well as ILX Holdings, LLC; ILX Holdings II, LLC; ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate of ~~Apollo~~the Riverstone 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 accompanying Notes to the Consolidated Financial Statements in the ~~2020~~2021 Annual Report.

The Company will bear all of the expenses incurred in connection with ~~the~~any 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~~2022, the Company ~~were~~did ~~NaN~~no ~~and $0.4~~ ~~million, respectively.~~t incur any such fees. For the three and nine months ended September 30, ~~2020,~~2021, fees incurred by the Company ~~incurred~~were ~~NaN~~nil and $~~0.2~~0.4 million, respectively.

In connection with the Company’s entry into a merger agreement on September 21, 2022 to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico, for $1.1 billion (the “EnVen Acquisition”, and such agreement, the “EnVen Merger Agreement”), the Company entered into a registration rights agreement (the “2022 Registration Rights Agreement”) with Adage Capital Partners, L.P. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”). Upon the successful closing of the EnVen Acquisition, it is expected that Adage and Bain will hold approximately 5.1% and 15.2%, respectively, of the Company’s outstanding shares of common stock. Pursuant to the 2022 Registration Rights Agreement, the Company grants to Adage and Bain certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock to be received by such entities in the EnVen Acquisition, subject to certain customary thresholds and conditions. Additionally, the Company agrees to pay certain expenses of the parties incurred in connection with the exercise of their rights under such agreement and to indemnify them for certain securities law matters in connection with any registration statement filed pursuant thereto. The 2022 Registration Rights Agreement will become effective at the closing of the EnVen Acquisition.

Amended and Restated 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 accompanying Notes to Consolidated Financial Statements in the ~~2020~~2021 Annual Report.

On March 29, 2022, the Company and other parties thereto, entered into the Amended and Restated Stockholders’ Agreement, in connection with the resignation of certain members of the Company's Board of Directors (the “Amended and Restated Stockholders’ Agreement”). The Amended and Restated Stockholders’ Agreement, among other things, (i) terminates the rights of the Apollo Funds under the Stockholders’ Agreement and (ii) eliminates the requirement that the Board of Directors consist of ten members.

The Riverstone Funds have agreed to vote their shares of the Company’s common stock in favor of any nominee designated and nominated for election to the Board of Directors in accordance with the terms of the Amended and Restated Stockholders’ Agreement and in a manner consistent with the recommendation of the Nominating and Governance Committee with respect to all other nominees.

In connection with the pending EnVen Acquisition, the Company and the Riverstone Funds have agreed to terminate the Amended and Restated Stockholders’ Agreement, which will eliminate the Riverstone Funds’ designation rights with respect to the Company’s Board of Directors. Subsequent to the termination of the Amended and Restated Stockholders’ Agreement, the Riverstone Funds’ present designee to the Company’s Board of Directors, Mr. Robert M. Tichio, will immediately tender his resignation. The termination of the Amended and Restated Stockholders’ Agreement is contingent upon the successful closing of the EnVen Acquisition.

Table of Contents

Riverstone Support Agreement

In connection with the pending EnVen Acquisition, the Company, EnVen and the Riverstone Funds entered into a support agreement pursuant to which the Riverstone Funds have agreed, among other things, to (i) vote all shares of Company common stock beneficially owned (a) in favor of the share issuance to EnVen equityholders, (b) in favor of the amendment and/or restatement of the Company’s organizational documents as necessary or appropriate to reflect the termination of the Amended and Restated Stockholders’ Agreement, (c) in favor of any other proposals necessary or appropriate in connection with the EnVen Acquisition and (d) against, among other things, (A) any Acquisition Proposal (as defined in the Merger Agreement) with respect to the Company and (B) any other proposal that could reasonably be expected to materially impede or delay the EnVen Acquisition or result in a breach of any representation or covenant of the Company under the EnVen Merger Agreement (as defined herein), (ii) terminate the Amended and Restated Stockholders’ Agreement, and (iii) cause Mr. Tichio to resign from the Company’s Board of Directors, in each case of the foregoing clauses (ii) and (iii), effective immediately prior to, but conditioned on, the occurrence of the closing of the EnVen Acquisition.

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. ("(“V~~&E"~~&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, 2022, the Company incurred fees for legal services performed by V&E of approximately $2.0 million and $3.5 million, respectively, of which $2.5 million was payable at period end. For the three and nine months ended September 30, 2021, the Company incurred fees for legal services performed by V&E of approximately $1.1 million and $2.8 million, respectively, of which $1.9 million ~~were~~was payable at period end.

Bayou Bend CCS LLC

On March 8, 2022, the Company made a $2.3 million cash contribution for ~~legal services performed by V&E as~~a 50% membership interest in Bayou Bend. In May 2022, the Company sold a 25% membership interest to Chevron U.S.A Inc. (“Chevron”) for upfront cash consideration of $15.0 million. Chevron also agreed to fund up to $10.0 million of contributions to Bayou Bend on the Company’s behalf, of which $1.4 million was funded during the three months ended September 30, ~~2021. For~~2022. The Bayou Bend investment will be increased with an offsetting gain as the capital carry is funded by Chevron. The Company recognized a $1.4 million and $15.3 million gain on the partial sale of its investment in Bayou Bend during the three and nine months ended September 30, ~~2020,~~2022, respectively, which is included in “Equity method investment income” on the Condensed Consolidated Statements of Operations.

As of September 30, 2022 the Company owns a 25% membership interest in Bayou Bend, which is a variable interest entity and accounted for using the equity method of accounting. Bayou Bend has a CCS site located offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor that is in the early stages of development. The development of the Bayou Bend CCS hub project is currently being financed through equity contributions from its members. The Company’s maximum exposure to loss as result of its involvement with Bayou Bend is the carrying amount of its investment.

Under an operating agreement, which was amended on May 24, 2022, the Company has agreed to provide certain services to facilitate Bayou Bend’s operations and to fulfill other general and administrative functions relating to the operation and management of Bayou Bend and its business. The Company will invoice Bayou Bend for reimbursement of direct and indirect general and administrative expenses incurred ~~fees~~as well as all other direct out-of-pocket costs and expenses incurred or paid on behalf of ~~approximately~~Bayou Bend. The Company had a $~~0.6~~0.5 million ~~and $4.0~~ ~~million, respectively, of which $2.2~~ ~~million were payable for legal services performed by V&E~~related party receivable from Bayou Bend as of September 30, ~~2020.~~2022.

~~Table of Contents~~

Note 1110 — Commitments and Contingencies

Performance Obligations

Regulations with respect to ~~offshore~~the Company's operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities in the U.S. Gulf of Mexico and ~~to guarantee the execution of the minimum work program~~certain obligations under the ~~Mexico~~ production sharing ~~contracts.~~ contracts with Mexico.

Table of Contents

As of September 30, ~~2021,~~2022, the Company had secured performance bonds from third party sureties totaling ~~approximately~~ $~~810.6~~689.5 million. The cost of securing these bonds ~~are~~is reflected as “Interest expense” inon the Condensed Consolidated Statements of Operations. AsAdditionally, as of September 30, ~~2021,~~2022, the Company had $~~13.6~~ ~~million in~~secured letters of credit issued under its Bank Credit ~~Facility.~~Facility totaling $3.9 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Note 5 — Debt for further information on the Bank Credit Facility.

Legal Proceedings and Other Contingencies

~~The~~From time to time, the Company is ~~named as a party~~involved in ~~certain lawsuits~~litigation, regulatory examinations and ~~regulatory~~administrative proceedings primarily arising in the ordinary course of ~~business. The~~business in jurisdictions in which the Company does ~~not expect that~~business. Although the outcome of these matters cannot be predicted with certainty, the Company’s management believes none of these matters, either individually or in the aggregate, ~~will~~would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on the Company’s results from operations for a specific interim period or year.

On March 23, 2022, the Company entered into a settlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its ~~financial condition.~~claims in the litigation. The settlement is reflected as “Other income (expense)” on the Condensed Consolidated Statements of Operations.

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 Company recorded estimated decommissioning obligations of $0.1 million and $4.1 million during the three ~~and nine~~ months ended September 30, 2022 and 2021, ~~the Company recorded~~respectively, and $~~4.1~~10.6 million and $6.9 million ~~respectively, related to estimated decommissioning obligations~~during the nine months ended September 30, 2022 and 2021, respectively. These costs are reflected inas “Other operating (income) expense” inon the Condensed Consolidated Statements of Operations. As of September 30, 2022 and December 31, 2021, the Company incurred obligations reflected as “Other current liabilities” of $3.3 million and $3.8 million, respectively, and obligations reflected as “Other long-term liabilities” of $29.2 million and $20.6 million, respectively, on the Condensed Consolidated Balance Sheets.

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, wethe Company could incur judgments, enter into settlements or revise ~~our~~its opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on ~~our~~its results of operations in the period in which the amounts are accrued and ~~our~~its cash flows in the period in which the amounts are paid.

Pending EnVen Acquisition

Consideration for the EnVen Acquisition will consist of 43.8 million of the Company’s shares of common stock and $212.5 million in cash, subject to certain adjustments. The closing of the EnVen Acquisition is expected to occur by late December 2022 or early January 2023.

If the EnVen Merger Agreement is terminated under certain specified circumstances, the Company may be required to pay EnVen a termination fee of $42.5 million (or $12.0 million in certain circumstances), or EnVen may be required to pay the Company a termination fee of $28.0 million.

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Subsequent Event —On October 21, 2022, Talos Production Inc. commenced a consent solicitation to obtain the requisite holders’ consent to certain amendments to the indenture governing the Company’s 12.00% Second-Priority Senior Secured Notes due January 2026 (the “12.00% Notes”) to permit the incurrence of indebtedness with respect to EnVen’s 11.75% Senior Secured Second Lien Notes due 2026. Subject to the terms and conditions of the consent solicitation, the Company offered holders of the 12.00% Notes, who have validly delivered (and did not validly revoke) their consents by October 27, 2022, consideration equal to 50 basis points times the principal amount of the 12.00% Notes held by such consenting holder, which the Company expects to pay upon the consummation of the EnVen Acquisition. In connection with the consent solicitation, Talos Production Inc. received consents from holders of 95.8% of the aggregate principal amount of the 12.00% Notes. As a result, Talos Production Inc. entered into a second supplemental indenture to the indenture on October 27, 2022, which became effective upon its execution.

Note 1211 — Subsequent Events

~~Whistler Acquisition~~12.00% Notes Consent Solicitation

For additional information, see Note 10 —~~Related Party Transactions~~Commitments and Contingencies.

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

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.

The following ~~management’s~~ discussion and analysis of our financial condition and results of operations is based on, and 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~~2021 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~~2021 Annual Report.

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 through upstream ~~through~~ oil and gas exploration and production and ~~downstream through~~ the development of ~~future~~ carbon capture and ~~storage~~sequestration (“CCS”) 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~~utilize our expertise to explore opportunities to reduce industrial emissions through our ~~carbon capture~~CCS initiatives both in and ~~storage collaborative arrangements~~ along the coast of 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~~collaborative arrangement 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~~Significant 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.~~2022.

~~TechnipFMC Strategic Alliance —~~ EnVen AcquisitionIn 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,~~September 21, 2022, we ~~announced~~executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the ~~addition~~Deepwater U.S. Gulf of Mexico, for approximately $1.1 billion in stock and cash consideration (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). The EnVen Acquisition is expected to double our operated Deepwater facility footprint by adding key infrastructure in our existing operating areas. Upon closing, we expect this to increase our production by approximately 40% or 24.0 MBoep/d and increase our gross acreage by 35%.

Consideration for the EnVen Acquisition consists of 43.8 million shares of our common stock and $212.5 million in cash, subject to certain adjustments. Following the EnVen Acquisition, our shareholders will own approximately 66% of the pro forma company and EnVen’s equity holders will own the remaining 34%. The closing of the EnVen Acquisition is expected to occur by late December 2022 or early January 2023.

On October 21, 2022, Talos Production Inc. commenced a ~~new lender~~consent solicitation to ~~our Bank Credit Facility~~obtain the requisite holders’ consent to certain amendments to the indenture governing its 12.00% Notes (as defined below under ~~"Liquidity~~“— Liquidity and Capital Resources — Overview of Debt ~~Instruments"~~Instruments”). to permit the incurrence of indebtedness with respect to EnVen’s 11.75% Senior Secured Second Lien Notes due 2026. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 610 — ~~Debt~~Commitments and Contingencies”for ~~more~~additional 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,~~2022 Drilling Program — We recently commenced drilling operations with the Seadrill Sevan Louisiana rig on our Lime Rock prospect near our operated Ram Powell facility and the rig will move to drill the adjacent Venice prospect once the Lime Rock drilling operations are complete. We own a 60% working interest in both prospects and expect first oil within 12-18 months from beginning drilling operations at each prospect. Prior to commencing operations at Lime Rock, we ~~announced our submission of notices of dispute (the "Notices of Dispute")~~encountered issues related to strong looping ocean currents while performing a well recompletion project. The recompletion operation has been suspended and we plan to return to the ~~Government~~project at a later date.

Phoenix Field Update — Production from one of ~~Mexico over decisions taken by SENER, including~~our Tornado wells generated increased water volumes during the ~~designation~~third quarter primarily as a result of ~~PEMEX~~the ongoing sub-surface water flood project in the Phoenix Field. This water breakthrough occurred earlier than originally expected, though within the range of projected outcomes in previous reservoir simulations used for the 2021 year-end reserves. We currently expect minor negative revisions to proved reserves as a result of timing impacts of early water breakthrough.

Oxy Transaction— In August 2022, we entered into an eight block cross assignment (the “Joint Area”) with Occidental Petroleum Corporation (“Oxy”), which resulted in Oxy being the operator with a 70% working interest and we have the remaining 30% working interest. We contributed 100% working interest in two blocks within Green Canyon area to the Joint Area. We and Oxy will commence drilling an exploration well in the Joint Area in the first half of ~~a yet-to-be unitized asset.~~2023.

Inflation Reduction Act of 2022 (the “IRA”)— On August 16, 2022, President Biden signed the IRA into law. The ~~actions taken by SENER constitute violations~~inclusion of several provisions in the IRA is expected to benefit both our upstream and CCS businesses. Specifically, the IRA directs the Department of the ~~Agreement between~~Interior (”DOI”) to:

•

accept the ~~United States~~highest bids received for Lease Sale 257, which was vacated by US District Court for the District of ~~America,~~Columbia in January 2022; and

•

move forward with Lease Sales 259 and 261 in 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 GovernmentGulf of Mexico by ~~seeking~~March 31, 2023 and September 30, 2023, respectively, notwithstanding the June 30, 2022 expiration of the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program.

We were one of the most active bidders in Lease Sale 257 and were the high bidder on 10 blocks and awarded leases on 9 blocks. The IRA also links issuance of federal wind and solar development rights to ~~achieve~~requirements to offer for sale federal oil and gas leases for a ~~fair~~10-year period of time. The IRA requires the federal government to offer for sale a minimum of 60 million acres for offshore oil and ~~mutually beneficial agreement.~~gas leases during the one-year period immediately preceding granting an offshore wind lease on the U.S. Outer Continental Shelf.

The IRA incentivizes additional capital investment in CCS projects by developers and sponsors through the following:

•

increases the Section 45Q tax credit value from $50 per metric ton to $85 per metric ton for qualified carbon oxide captured from an industrial source and stored in secure geologic formations if certain prevailing wage and apprenticeship requirements are met;

•

expands eligibility for carbon capture and sequestration credits under Section 45Q by extending the beginning of the construction deadline from before January 1, 2026 to before January 1, 2033; and

•

allows taxpayers to now claim the value of a Section 45Q tax credit with respect to carbon capture equipment originally placed in service after December 31, 2022 as a direct pay option (i.e.; through a tax refund as if there had been an overpayment of taxes). Both taxable and tax-exempt entities may elect the direct pay option, but any taxable entity may only elect such option for the first 5 years of the tax credit period that is otherwise available.

The IRA also raises the minimum oil and gas royalty rate for new offshore leases from the current 12.5% to 16.7% and caps the royalty rate at 18.8% for 10 years; however this provision does not affect existing offshore leases. The 18.8% cap is commensurate with existing offshore royalty rate for leases in water depth exceeding 200 meters.

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Additionally, the IRA imposes a first-ever federal fee on greenhouse gases through a methane emissions charge. The IRA amends the federal Clean Air Act to impose a charge on emissions of methane from sources required to report their GHG emissions to the U.S. Environmental Protection Agency (“EPA”), including those sources in the offshore and onshore oil and gas production, and onshore processing, transmission and compression, gathering, and boosting station source categories. For such qualifying facilities, the charge starts at $900 per metric ton of methane reported for calendar year 2024, increasing to $1,200 per metric ton of methane for calendar year 2025 and again to $1,500 per metric ton of methane for calendar year 2026 and year thereafter. Calculation of the charge is based on certain thresholds established in the IRA. The charge will be based on the prior year’s emissions, and the charge starts in 2025 based on 2024 data. The methane emissions charge could increase our operating costs and adversely affect our business.

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~~Planned Downtime — ~~On November 16, 2020,~~We are vulnerable to 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 U.S. Coast Guard, during which time we ~~completed~~are unable to produce the ~~acquisition~~Phoenix Field.

During the three months ended September 30, 2022, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-September, resulting in a total shut-in period of ~~select interests~~41 days. The shut-in resulted in ~~oil~~an estimated deferred production of approximately 6.2 MBoepd and ~~natural gas assets from LLOG Exploration & Production Company, LLC (the “LLOG Acquisition”). A discussion~~2.1 MBoepd for the three and nine months ended September 30, 2022, respectively, based on production rates prior to the shut-in.

During the third quarter of 2022, we experienced approximately 17 days of planned third-party downtime due to maintenance of the ~~LLOG Acquisition is included~~Shell Odyssey Pipeline, which carries our production primarily from our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility. Production resumed in October 2022. We estimate the ~~Notes~~shut-in resulted in deferred production of approximately 1.8 MBoepd and 0.6 MBoepd for the three and nine months ended September 30, 2022, respectively, based on production rates prior to ~~Consolidated Financial Statements in~~ the ~~2020 Annual Report.~~shut-in.

~~Castex Energy 2005 Acquisition~~Eugene Island Pipeline System — ~~On August 5, 2020,~~During the first quarter of 2022, we ~~completed~~experienced approximately 40 days of unplanned third-party downtime due to maintenance of the ~~acquisition~~Eugene Island Pipeline System, which carries our production from the Phoenix Field and Green Canyon 18 Field. For the nine months ended September 30, 2022, we estimate the shut-in resulted in deferred production 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~~approximately 1.5 MBoepd based on production rates prior to 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.~~shut-in.

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 damageWe did not experience any disruptions to our ~~facilities, we incurred production downtime associated with the shut-ins for the storms. For~~operations from hurricanes or tropical storms during 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.2022.

Known Trends and Uncertainties

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our ~~2020~~2021 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~~2021 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~~Significant progress has been made to reduce the risk of spreading COVID-19 and its multiple variants, however, certain ~~non-OPEC producers (“OPEC Plus”) agreed~~regions in the world remain negatively impacted by outbreaks of COVID-19 that continue to ~~production cuts intended~~degrade economic activity. Additionally, the risk of a new variant of COVID-19 disrupting global economic activity remains persistent and its impact on our operational and financial performance will depend on developments that are difficult to ~~stabilize~~predict, including the duration and ~~support commodity prices, which resulted in cutting production by a record 9.7 million barrels per day starting~~spread of the outbreak and its impact 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 Februaryour personnel, customer activity 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.third-party providers.

~~Oil prices have benefited from~~During 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~~period January 1, ~~2021~~2022 through September 30, ~~2021,~~2022, the daily spot prices for NYMEX WTI crude oil ranged from a high of ~~$75.54~~$123.64 per Bbl to a low of ~~$47.47~~$75.99 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of ~~$23.86~~$9.85 per MMBtu to a low of ~~$2.43~~$3.73 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~~We 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 54 — Financial Instruments” for ~~more~~ additional information regarding our commodity derivative positions as of September 30, ~~2021.~~2022.

The U.S. Energy Information Administration (“EIA”) published its latest Short-Term Energy Outlook on October 12, 2022. The EIA expects the Henry Hub spot price will average $9.03 per MMBtu in the fourth quarter of 2022 and then fall to an average $6.01 per MMBtu in 2023 as U.S. natural gas production rises. The EIA also expects the WTI spot price will average $91.98 per Bbl in the fourth quarter of 2022 and average $90.91 per Bbl in 2023. The EIA expects average crude oil prices to mostly remain between $90.00 per Bbl – $100.00 per Bbl 2023, with the possibility for significant volatility around those averages. Recent events contributing to increased uncertainty in the crude oil market include: (i) the impact of the OPEC Plus decision to reduce crude oil production by 2.0 MBbl per day beginning in November 2022 and the potential for further production cuts in the future; (ii) the threat of increasing conflict following the outbreak of violent clashes in the Libyan capital of Tripoli; (iii) uncertainty around the potential expiration of the current coordinated petroleum release from the U.S. Strategic Petroleum Reserves to reduce domestic gasoline prices; (iv) the potential re-negotiation of a nuclear agreement with Iran that could lift sanctions on the country and allow Iran’s crude oil exports into the market; and (v) the risk associated with hurricanes and tropical storms.

Inflation of Cost of Goods, Services and Personnel — Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. In addition, the U.S. inflation rate has been steadily increasing since 2021 and into 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation could likely cause the U.S. Federal Reserve and other central banks to further increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business.

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~~2022 and ~~2020,~~2021, we did not recognize an impairment based on the ceiling test computations. At September 30, ~~2021~~2022 our ceiling test computation was based on SEC pricing of ~~$58.25~~$93.61 per Bbl of oil, ~~$3.02~~$6.56 per Mcf of natural gas and ~~$20.75~~$35.94 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~~2021 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.

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With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties, not subject to amortization. The ~~finalization~~submission of the ~~Unitization and~~ Unit ~~Operating Agreement,~~Development Plan for the Zama Field to the National Hydrocarbon Commission, which ~~sets~~will set 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~~is expected by ~~SENER with respect to the Zama discovery~~March 2023 and could adversely affect the value of the Mexico 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.~~properties.

~~Third Party Planned Downtime —~~ Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the 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 current 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~~Deepwater fields in the U.S. Gulf of Mexico. Operations in ~~the deepwater~~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.

Five-Year Offshore Oil and Gas Leasing Program Update — Under the Outer Continental Shelf Lands Act (“OCSLA”), as amended, the BOEM within the DOI must prepare and maintain forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the U.S. Outer Continental Shelf. On May 11, 2022, the DOI cancelled two lease auctions in the Gulf of Mexico, Lease Sales 259 and 261, and one auction in the Cook Inlet, Alaska, Lease Sale 258, under the 2017-2022 national program that was developed under the Obama Administration, which expired on June 30, 2022. The DOI cited “conflicting court rulings” as the primary reason for not holding the two Gulf of Mexico lease sales. As discussed above under “ — Significant Developments,” President Biden signed the IRA into law on August 16, 2022. The IRA reinstates Lease Sale 257 held in November 2021, and requires the DOI to both accept all valid high bids received in Lease Sale 257 and issue leases to the high bidders. We were one of the most active bidders in Lease Sale 257 and we were the the high bidder on 10 blocks and awarded leases on 9 blocks. Furthermore, the DOI must hold Gulf of Mexico lease sales 259 and 261 by March 31, 2023, and September 30, 2023, respectively.

BOEM’s development of a new national program typically takes place over several years, during which successive drafts of the program are published for review and comment. At the end of the process, the Secretary of the Interior must submit the Proposed Final Program to the President and to Congress for a period of at least 60 days, after which the program may be approved by the Secretary of the Interior and may take effect with no further regulatory or legislative action.

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BOEM took the first formal step in pursuit of a new five-year national program in January 2018 by releasing a Draft Proposed Program. The OCSLA and its implementing regulations call for two subsequent drafts, a Proposed Program (“PP”), which is open for public comment for a period of at least 90 days, and then a Proposed Final Program, which is submitted to Congress and the President for 60 days before implementation. These later program stages also are accompanied by publication of a draft and final Programmatic Environmental Impact Statement (“PEIS”), with a period for public comment on the draft PEIS. The PP and a draft PEIS for the 2023-2028 five-year period were published in the Federal Register on July 8, 2022, with a 90-day comment period. The public comment period has now closed, and BOEM is reviewing the comments received. The PP includes no more than ten potential lease sales in the Gulf of Mexico; however, BOEM’s subsequent Proposed Final Program for 2023-2028 could reduce the number of Gulf of Mexico lease sales in the national program.

When the 2023-2028 national program will be approved and implemented remains uncertain. Congress may influence the Biden Administration’s development and implementation of the five-year 2023-2028 national program by submitting public comments during formal comment periods, by evaluating programs in committee oversight hearings, and, more directly, by enacting legislation with program requirements. It is possible that the program could be delayed if opponents of offshore oil and gas production initiate lawsuits challenging BOEM’s actions.

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~~variance 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,							Three Months Ended September 30,							Nine Months Ended September 30,
	2021		2020		Change			2021		2020		Change			2022		2021		Change			2022		2021		Change
Revenues and other:
Revenues:
Oil	$	246,208	$	117,190	$	129,018		$	743,759	$	358,285	$	385,474		$	295,585	$	246,208	$	49,377		$	1,078,800	$	743,759	$	335,041
Natural gas		31,723		12,337		19,386			86,088		35,375		50,713			68,360		31,723		36,637			181,747		86,088		95,659
NGL		12,978		3,409		9,569			31,738		9,674		22,064			13,183		12,978		205			49,232		31,738		17,494
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 revenues															$	377,128	$	290,909	$	86,219		$	1,309,779	$	861,585	$	448,194

Total Production Volumes:
Oil (MBbls)		3,609		3,005		604			11,827		10,010		1,817			3,258		3,609		(351	)		11,020		11,827		(807	)
Natural gas (MMcf)		6,975		6,922		53			24,055		20,961		3,094			7,292		6,975		317			24,746		24,055		691
NGL (MBbls)		429		311		118			1,344		1,028		316			403		429		(26	)		1,372		1,344		28
Total production volume (MBoe)		5,200		4,470		730			17,180		14,532		2,648			4,876		5,200		(324	)		16,516		17,180		(664	)

Daily Production Volumes by Product:
Oil (MBblpd)		39.2		32.7		6.5			43.3		36.5		6.8			35.4		39.2		(3.8	)		40.4		43.3		(2.9	)
Natural gas (MMcfpd)		75.8		75.2		0.6			88.1		76.5		11.6			79.3		75.8		3.5			90.6		88.1		2.5
NGL (MBblpd)		4.7		3.4		1.3			4.9		3.8		1.1			4.4		4.7		(0.3	)		5.0		4.9		0.1
Total production volume (MBoepd)		56.5		48.6		7.9			62.9		53.0		9.9			53.0		56.5		(3.5	)		60.5		62.9		(2.4	)

Average Sale Price Per Unit:
Oil (per Bbl)	$	68.22	$	39.00	$	29.22		$	62.89	$	35.79	$	27.10		$	90.73	$	68.22	$	22.51		$	97.89	$	62.89	$	35.00
Natural gas (per Mcf)	$	4.55	$	1.78	$	2.77		$	3.58	$	1.69	$	1.89		$	9.37	$	4.55	$	4.82		$	7.34	$	3.58	$	3.76
NGL (per Bbl)	$	30.25	$	10.96	$	19.29		$	23.61	$	9.41	$	14.20		$	32.71	$	30.25	$	2.46		$	35.88	$	23.61	$	12.27
Price per Boe	$	55.94	$	29.74	$	26.20		$	50.15	$	27.75	$	22.40		$	77.34	$	55.94	$	21.40		$	79.30	$	50.15	$	29.15
Price per Boe (including realized commodity derivatives)	$	42.17	$	34.00	$	8.17		$	39.13	$	37.49	$	1.64		$	60.70	$	42.17	$	18.53		$	56.99	$	39.13	$	17.86

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


	Three Months Ended September 30, 2021 vs 2020						Nine Months Ended September 30, 2021 vs 2020						Three Months Ended September 30, 2022 vs 2021							Nine Months Ended September 30, 2022 vs 2021
	Price		Volume		Total		Price		Volume		Total		Price		Volume			Total		Price		Volume			Total
Revenues:
Oil	$	105,462	$	23,556	$	129,018	$	320,444	$	65,030	$	385,474	$	73,322	$	(23,945	)	$	49,377	$	385,793	$	(50,752	)	$	335,041
Natural gas		19,292		94		19,386		45,484		5,229		50,713		35,195		1,442			36,637		93,185		2,474			95,659
NGL		8,276		1,293		9,569		19,090		2,974		22,064		992		(787	)		205		16,833		661			17,494
Total revenues	$	133,030	$	24,943	$	157,973	$	385,018	$	73,233	$	458,251	$	109,509	$	(23,290	)	$	86,219	$	495,811	$	(47,617	)	$	448,194

Three Months Ended September 30, ~~2021~~2022 and ~~2020~~2021 Volumetric Analysis — Production volumes ~~increased~~decreased by ~~7.9~~3.5 MBoepd to ~~56.5~~53.0 MBoepd. The ~~increase~~decrease in production volumes was ~~an increase~~primarily due to the third party downtime associated with the HP-I dry-dock in our Phoenix Field and the Shell Odyssey Pipeline shut-in primarily impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility, which resulted in 6.2 MBoepd and 1.8 MBoepd of ~~5.9~~deferred production, respectively. Additionally, production volumes decreased 4.3 MBoepd ~~from the~~and 1.8 MBoepd primarily attributable to well performance and natural production declines in our Phoenix Field and 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.respectively. The ~~increase~~decrease was partially offset by ~~a decrease~~an increase of 12.7 MBoepd in deferred production ~~of 4.1 MBoepd from disruptions from weather events~~attributable to Hurricane Ida in ~~the U.S. Gulf of Mexico when compared to the same period in 2020.~~2021.

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Nine Months Ended September 30, ~~2021~~2022 and ~~2020~~2021 Volumetric Analysis — Production volumes ~~increased~~decreased by ~~9.9~~2.4 MBoepd to ~~62.9~~60.5 MBoepd. The ~~increase~~decrease in production volumes was ~~attributable~~primarily due to ~~6.4 MBoepd from temporary~~the third party downtime ~~as a result of repairs~~for the HP-I dry-dock in our Phoenix Field, the Eugene Island Pipeline System shut-in primarily impacting HP-I and ~~maintenance that occurred in 2020 and 5.6 MBoepd from the~~ Green Canyon 18 Field and the Shell Odyssey Pipeline shut-in primarily ~~attributable~~impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility, which resulted in 4.2 MBoepd of deferred production. Additionally, production volumes decreased 1.7 MBoepd at Delta House, a non-operated facility located in Mississippi Canyon, primarily related to ~~the Kaleidoscope~~temporary shut-ins for repairs and ~~Tokum wells drilled as part of the Green Canyon 18 Field platform rig program.~~maintenance and natural production declines. The ~~increase~~decrease was partially offset by ~~a decrease~~an increase of 4.3 MBoepd in deferred production ~~of 1.0 MBoepd from disruptions from weather events~~attributable to Hurricane Ida in ~~the U.S. Gulf of Mexico when compared to the same period in 2020.~~2021.

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,				Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2022		2021		2022		2021
Lease operating expenses	$	70,034	$	62,064	$	208,675	$	184,187	$	81,760	$	70,034	$	229,156	$	208,675
Lease operating expenses per Boe	$	13.47	$	13.88	$	12.15	$	12.67	$	16.77	$	13.47	$	13.87	$	12.15

Three Months Ended September 30, ~~2021~~2022 and ~~2020~~2021 — ~~Total lease~~Lease operating expense for the three months ended September 30, ~~2021~~2022 increased by approximately ~~$8.0~~$11.7 million, or ~~13%~~17%. ~~This~~The increase ~~was~~is primarily due to a $4.9 million increase in facility and workover expense related to anrepairs and maintenance at the Phoenix Field and the Pompano Field. Additionally, there was a $1.7 million increase in ~~lease operating expenses of $2.0 million incurred in connection with assets acquired in the Castex 2005 Acquisition~~company and ~~LLOG Acquisition when~~contract labor compared to the same period in ~~2020. Additionally, there was an overall increase~~2021 and $1.4 million reduction in ~~direct operating expenses and labor~~production handling fees related to reimbursements for costs ~~primarily due to the temporary shuttering of~~from 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.parties.

Nine Months Ended September 30, ~~2021~~2022 and ~~2020 —~~2021 ~~Total lease~~— Lease operating expense for the nine months ended September 30, ~~2021~~2022 increased by approximately ~~$24.5~~$20.5 million, or ~~13%~~10%.~~This~~ The increase ~~was~~is primarily due to a $19.8 million increase in facility and workover expense related to anrepairs and maintenance at the Phoenix Field and the Gunflint Field. Additionally, there was a $4.8 million increase in ~~lease operating expenses of $11.6 million incurred in connection with assets acquired in the Castex 2005 Acquisition~~company and ~~LLOG Acquisition when~~contract labor compared to the same period in ~~2020. Hurricane related repairs increased $4.3~~2021. This increase was partially offset by $7.0 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~~additional production handling fees 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.reimbursements for costs from certain third parties.

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,				Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2022		2021		2022		2021
Depreciation, depletion and amortization	$	88,596	$	80,547	$	290,094	$	262,533	$	92,323	$	88,596	$	295,174	$	290,094
Depreciation, depletion and amortization per Boe	$	17.04	$	18.02	$	16.89	$	18.07	$	18.93	$	17.04	$	17.87	$	16.89

Three Months Ended September 30, ~~2021~~2022 and ~~2020~~2021 — Depreciation, depletion and amortization expense for the three months ended September 30, ~~2021~~2022 increased by approximately ~~$8.0~~$3.7 million, or ~~10%~~4%. This ~~increase~~ was primarily due to ~~increased production~~an increase of ~~7.9 MBoepd partially offset by a decrease of $0.91~~$1.85 per Boe, or 5%11%, in the depletion rate on our proved oil and natural gas properties ~~as a result~~partially offset by decreased production of ~~the impairment on oil and gas properties in the fourth quarter of 2020.~~3.5 MBoepd.

Nine Months Ended September 30, ~~2021~~2022 and ~~2020 —~~2021 — Depreciation, depletion and amortization expense for the nine months ended September 30, ~~2021~~2022 increased by approximately ~~$27.6~~$5.1 million, or ~~10%~~2%. This ~~increase~~ was primarily due to ~~increased production~~an increase of ~~9.9 MBoepd offset by a decrease of $1.14~~$1.00 per Boe, or 6% in the depletion rate on our proved oil and natural gas properties ~~as a result~~partially offset by decreased production of ~~the impairment on oil and gas properties in the fourth quarter of 2020.~~2.4 MBoepd.

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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,				Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2022		2021		2022		2021
General and administrative expense	$	20,427	$	17,823	$	58,993	$	62,484	$	25,289	$	20,427	$	70,742	$	58,993
General and administrative expense per Boe	$	3.93	$	3.99	$	3.43	$	4.30	$	5.19	$	3.93	$	4.28	$	3.43

Three Months Ended September 30, ~~2021~~2022 and ~~2020~~2021 — General and administrative expense for the three months ended September 30, ~~2021~~2022 increased by approximately ~~$2.6~~$4.9 million, or ~~15%, which~~24%. This increase was primarily related to non-cash equity-based compensation of $4.3 million, or $0.88 per Boe, during the three months ended September 30, 2022, which is an increase of $1.7 million. Additionally, there was an increase in transaction costs of $2.8 million primarily related to the EnVen Acquisition. On a per unit basis, general and administrative expense increased ~~employee and contract labor costs.~~$1.26 Boe primarily due to decreased production of 3.5 MBoepd.

Nine Months Ended September 30, ~~2021~~2022 and ~~2020~~2021 — General and administrative expense for the nine months ended September 30, ~~2021 decreased~~2022 increased by approximately ~~$3.5~~$11.7 million, or 6%20%. ~~Transaction and non-recurring~~This increase was primarily related to $5.6 million of expenses ~~were $4.8 million, or $0.28 per Boe, for~~incurred by our emerging CCS operating segment during the nine months ended September 30, ~~2021, which is a decrease~~2022, an increase of ~~$8.1~~$4.1 million. There was an increase in transaction costs of $2.0 million primarily ~~due~~related 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~~EnVen Acquisition. Additionally, general and administrative expense includes non-cash equity-based compensation of ~~$8.3~~$11.7 million, or ~~$0.48~~$0.71 per Boe, ~~for~~during the nine months ended September 30, ~~2021, which is~~2022, an increase of ~~$2.0~~$3.4 million. On a per unit basis, general and administrative expense increased $0.85 per Boe primarily due to decreased production of 2.4 MBoepd.

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,					Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021		2020			2022			2021			2022			2021
Write-down of oil and natural gas properties	$	—		$	—		$	—	$	57
Accretion expense	$	13,668		$	11,537		$	44,110	$	37,748		$	13,179		$	13,668		$	42,400		$	44,110
Other operating expense	$	5,081		$	—		$	7,864	$	—
Other operating (income) expense												$	(366	)	$	5,081		$	12,142		$	6,864
Interest expense	$	32,390		$	24,124		$	100,036	$	76,164		$	29,265		$	32,390		$	91,531		$	100,036
Price risk management activities (income) expense	$	81,479		$	19,882		$	405,604	$	(154,653	)	$	(114,180	)	$	81,479		$	231,133		$	405,604
Equity method investment income												$	991		$	—		$	14,599		$	—
Other (income) expense	$	(4,475	)	$	(813	)	$	7,916	$	(139	)	$	(692	)	$	(4,475	)	$	(31,991	)	$	7,916
Income tax (benefit) expense	$	(364	)	$	(28,252	)	$	718	$	(22,384	)	$	121		$	(364	)	$	2,256		$	718

Three Months Ended September 30, ~~2021~~2022 and ~~2020~~2021 —

~~Interest~~Other Operating (Income) 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,~~2022, we recorded ~~$4.1~~$0.1 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of ~~divestiture~~divesture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the three months ended September 30, 2021, we recorded $4.1 million of estimated decommissioning obligations. See further discussion in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 1110 — Commitments and Contingencies.”

29Interest Expense — During the three months ended September 30, 2022, we recorded $29.3 million of interest expense compared to $32.4 million during the three months ended September 30, 2021. The change is primarily the result of the decrease in interest associated with the Bank Credit Facility (as defined below under “ — Liquidity and Capital Resources — Overview of Debt Instruments”) with outstanding borrowings of $60.0 million as of September 30, 2022 when compared to $400.0 million as of September 30, 2021.

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Price ~~risk management activities~~Risk Management Activities — ~~Price risk management activities~~The income of $114.2 million for the three months ended September 30, ~~2021 decreased~~2022 consists of $195.3 million in non-cash gains from the increase in the fair value of our open derivative contracts partially offset by ~~approximately $61.6~~$81.1 million ~~or 310%.~~in cash settlement losses. 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,~~December 2024, 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 54 — Financial Instruments.”

Equity Method Investment Income — During the three months ended September 30, 2022, we recorded equity losses of $0.4 million offset by a $1.4 million gain on partial sale of our equity method investment in Bayou Bend. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 9 — Related Party Transactions” for additional information.

Other ~~(income) expense~~(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 109 — Related Party Transactions.”

Income ~~tax (benefit) expense~~Tax (Benefit) Expense — During the three months ended September 30, ~~2021,~~2022, we recorded ~~$0.4~~$0.1 million of income tax ~~benefit~~expense compared to ~~$28.3~~$0.4 million of income tax benefit during the three months ended September 30, ~~2020.~~2021. The ~~change~~income tax expense for each period 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 87 — Income Taxes.”

Nine Months Ended September 30, ~~2021~~2022 and ~~2020~~2021 —

~~Interest~~Other Operating (Income) 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,~~2022, we recorded ~~$6.9~~$10.6 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of ~~divestiture~~divesture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the nine months ended September 30, 2021, we recorded $6.9 million of estimated decommissioning obligations. See further discussion in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 1110 — Commitments and Contingencies.”

~~Price risk management activities~~Interest Expense — During the nine months ended September 30, 2022, we recorded $91.5 million of interest expense compared to $100.0 million during the nine months ended September 30, 2021. The change is primarily a result of the interest associated with the Bank Credit Facility with outstanding borrowings of $60.0 million as of September 30, 2022 when compared to $400.0 million as of September 30, 2021.

Price ~~risk management activities~~Risk Management Activities — The expense of $231.1 million for the nine months ended September 30, ~~2021 decreased~~2022 consists of $368.5 million in cash settlement losses partially offset by ~~approximately $560.3~~$137.4 million ~~or 362%.~~in non-cash gains from the increase in the fair value of our open derivative contracts. 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.

~~Other (income) expense~~33

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Equity Method Investment Income — During the nine months ended September 30, 2022, we recorded equity losses of $0.7 million offset by a $15.3 million gain on partial sale of our equity method investment in Bayou Bend. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 9 — Related Party Transactions” for additional information.

Other (Income) Expense — During the nine months ended September 30, 2022, we recorded a $27.5 million gain as a result of the settlement agreement to resolve a previously pending litigation that was filed in October 2017 that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Commitments and Contingencies.” 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% Second-Priority Senior Secured Notes ~~further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 —~~ ~~Debt~~(the “11.00% Notes”).” 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 109 — Related Party Transactions.”

~~Table of Contents~~

Income ~~tax (benefit) expense~~Tax (Benefit) Expense — During the nine months ended September 30, ~~2021,~~2022, we recorded ~~$0.7~~$2.3 million of income tax expense compared to ~~$22.4~~$0.7 million of income tax ~~benefit~~expense during the nine months ended September 30, ~~2020.~~2021. The change is primarily a result of a discrete tax expense and recording a valuation allowance on our deferred tax ~~assets as of December 31, 2020.~~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 87 — 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~~other (income) 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~~table presents 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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2022			2021			2022			2021
Net income (loss)	$	250,465		$	(16,691	)	$	379,165		$	(263,964	)
Interest expense		29,265			32,390			91,531			100,036
Income tax (benefit) expense		121			(364	)		2,256			718
Depreciation, depletion and amortization		92,323			88,596			295,174			290,094
Accretion expense		13,179			13,668			42,400			44,110
EBITDA		385,353			117,599			810,526			170,994
Transaction and other (income) expenses(1)(3)(4)		3,239			1,370			(28,303	)		7,231
Derivative fair value loss (gain)(2)		(114,180	)		81,479			231,133			405,604
Net cash paid on settled derivative instruments(2)		(81,162	)		(71,634	)		(368,483	)		(189,252	)
Loss on extinguishment of debt		—			—			—			13,225
Non-cash equity-based compensation expense		4,310			2,613			11,677			8,294
Adjusted EBITDA	$	197,560		$	131,427		$	656,550		$	416,096

(1)

Includes ~~transaction related~~transaction-related expenses, ~~restructuring expenses, cost saving initiatives~~decommissioning obligations and other miscellaneous income and expenses. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Commitments and Contingencies” for additional information on decommissioning obligations.

(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.

(3)

Includes a $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation for the nine months ended September 30, 2022 that was filed in October 2017 that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Commitments and Contingencies.”

(4)

Includes a $1.4 million and $15.3 million gain on partial sale of our equity method investment in Bayou Bend for the three and nine months ended September 30, 2022, respectively, that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 9 — Related Party Transactions.”

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~~decreased since December 31, ~~2020~~2021 primarily due to ~~an increase~~a decrease of ~~$182.4~~$87.3 million in liabilities from price risk management activities and an increase of $26.4 million in assets from price risk management activities. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 4 — Financial Instruments.” As of September 30, ~~2021,~~2022, our available liquidity (cash plus available capacity under the Bank Credit Facility) was ~~$375.9~~$806.8 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~~2022 (in thousands):


U.S. drilling & completions	$	115,391	$	120,510
Mexico appraisal & exploration		777		301
Asset management		62,015		80,704
Seismic and G&G, land, capitalized G&A and other		38,366		35,667
CCS(1)				2,027
Total capital expenditures		216,549		239,209
Plugging & abandonment		58,001		60,304
Total capital expenditures and plugging & abandonment	$	274,550	$	299,513

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(1)

Excludes $2.4 million of expenditures reflected as “Other operating (income) expense” on the Condensed Consolidated Statements of Operations.

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~~2022 capital spending program of ~~$340.0~~$450.0 million to ~~$370.0~~$480.0 million, ~~and our working capital deficit.~~of which approximately $30.0 million is allocated to CCS. 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~~issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding ~~debt.~~indebtedness.

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,						Nine Months Ended September 30,
	2021			2020			2022			2021
Operating activities	$	287,648		$	262,067		$	538,928		$	287,648
Investing activities	$	(212,153	)	$	(585,152	)	$	(198,652	)	$	(212,153	)
Financing activities	$	(50,301	)	$	268,440		$	(345,638	)	$	(50,301	)

Operating Activities — Net cash provided by operating activities increased ~~$25.6~~$251.3 million in the nine months ended September 30, ~~2021~~2022 compared to the corresponding period in ~~2020~~2021 primarily attributable to an increase in revenues net of the change in lease operating expense of ~~$426.3~~$427.7 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~~$179.2 million.

Investing Activities — Net cash used in investing activities decreased ~~$373.0~~$13.5 million in the nine months ended September 30, ~~2021~~2022 compared to the corresponding period in ~~2020~~2021 primarily due to $15.0 million in cash proceeds from a ~~decrease~~partial sale of our investment in ~~payments for acquisitions of $299.5 million~~Bayou Bend and ~~a decrease in~~decreased capital expenditures of ~~$68.7~~$2.0 million offset by contributions to equity investees of $2.3 million.See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 9 — Related Party Transactions” for additional information.

Financing Activities — Cash flow from financing activities decreased ~~$318.7~~$295.3 million in the nine months ended September 30, ~~2021~~2022 compared to the corresponding period in ~~2020.~~2021. During the nine months ended September 30, ~~2020,~~2022, net ~~proceeds~~repayments of ~~$300.0~~$315.0 million ~~were received from~~reduced the Bank Credit ~~Facility and used primarily to fund the ILX and Castex Acquisition in the first quarter~~Facility. Additionally, we redeemed $6.1 million of ~~2020.~~ our 7.50% Senior Notes.

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~~reduced 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~~May 4, 2022, our borrowing base increased ~~commitments~~ from ~~$655.0~~$950.0 million to ~~$730.0~~$1.1 billion and commitments increased from $791.3 million to $806.3 million. The next scheduled redetermination is expected to occur in the fourth quarter of 2022. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 65 — Debt” for more information.

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12.00% Second-Priority Senior Secured ~~Notes—~~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"~~“Parent Guarantor”),; Talos Production Inc. ~~(“Issuer”~~(the “Issuer”)~~, and~~; the Subsidiary Guarantors ~~(as defined~~(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 senior secured 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.~~15. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 65 — Debt” for more information.

~~Redemption of the 11.00% Second-Priority~~7.50% Senior ~~Secured Notes—due April~~Notes — redeemed May 2022 — ~~On January 13, 2021, we~~The 7.50% Senior Notes matured and were redeemed ~~the 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) using the proceeds from the issuance of 12.00% Notes.~~on May 31, 2022. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 65 — Debt” for more information.

Guarantor Financial Information — ~~Talos owns~~We own no operating assets and ~~has~~have no operations independent of ~~its~~our 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 restricted 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 and our unrestricted CCS domestic subsidiaries (the “Non-Guarantors”) are 100% owned by ~~Talos~~us 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 of operations 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		September 30, 2022		December 31, 2021
Current assets	$	246,199	$	231,669	$	342,980	$	330,415
Non-current assets		2,384,660		2,444,886		2,323,141		2,305,855
Total assets	$	2,630,859	$	2,676,555	$	2,666,121	$	2,636,270

Current liabilities	$	633,368	$	438,340	$	552,275	$	598,062
Non-current liabilities		1,475,365		1,459,816		1,101,695		1,405,382
Talos Energy Inc. stockholdersʼ equity		522,126		778,399		1,012,151		632,826
Total liabilities and stockholdersʼ equity	$	2,630,859	$	2,676,555	$	2,666,121	$	2,636,270

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

Nine Months Ended
September 30, 2021

Revenues and other
$
862,585

Costs and expenses

(1,122,621
)
Net loss
$
(260,036
)


	Nine Months Ended September 30, 2022
Revenues	$	1,309,779
Costs and expenses		(936,118	)
Net income	$	373,661

~~Table of Contents~~

~~Contractual Obligations~~Material Cash Requirements

We have various contractual obligations in the normal course of our operations. There have been no material changes to our material cash requirements from known contractual obligations since those reported in our ~~2020~~2021 Annual Report except:

•

The aggregate principal amount of our ~~debt increased~~Bank Credit Facility decreased from ~~$993.3~~$375.0 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;~~$60.0 million;

•

Interest expense through the maturity of our debt instruments ~~increased~~decreased in the aggregate by approximately ~~$369.6~~$19.1 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;

Table of Contents

•

Vessel commitments increased by approximately ~~$25.9~~$33.6 million due to the execution of ~~a 2022~~an offshore drilling rig ~~agreement.~~agreement on April 6, 2022. 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 decreased from $196.7 million to $59.4 million; and

•

Purchase obligations increased from ~~$67.8~~$3.2 million to ~~$284.2 million.~~$57.8 million through 2023 primarily due to increased committed purchase orders to execute planned Deepwater drilling activities.

Performance ~~Bonds~~Obligations — As of September 30, ~~2021,~~2022, we had secured performance bonds totaling $689.5 million 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~~certain obligations under the ~~Mexico~~ production sharing contracts with Mexico from third party sureties. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling ~~approximately $810.6~~$3.9 million. Letters of credit that are outstanding reduce the available revolving credit commitments.

See ~~“Known~~the subsection entitled “— 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~~ See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 —

~~We did not have any off-balance sheet arrangements as of September 30, 2021.~~Debt” for further information on the Bank Credit Facility.

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~~2021 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~~2021 Annual ~~Report.~~Report and Part II, Item 3. “Quantitative and Qualitative Disclosures about Market Risk” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2022. Except as disclosed in this Quarterly Report, there have been no material changes from the disclosures presented in our ~~2020~~2021 Annual Report and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2022 regarding our exposures to certain market ~~risks.~~risks except for our minimum hedging requirement under our Bank Credit Facility for each calendar month on a six-full fiscal quarter rolling basis.

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.~~2022.

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~~2022 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,~~March 23, 2022, the Company entered into a ~~lawsuit~~settlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its claims 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.litigation.

There have been no additional material developments with respect to the information previously reported under Part I, Item 3. “Legal Proceedings” of our ~~2020~~2021 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~~2021 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~~2021 Annual Report or our other SEC ~~filings.~~filings, including our Quarterly Report on Form 10-Q for the quarter ended March 31, 2022 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2022.

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.

Table of Contents

Item 6. Exhibits


Exhibit Number		Description

2.1#		~~Purchase and Sale~~Merger Agreement, dated as of ~~December 10, 2019,~~September 21, 2022, by and among Talos Energy Inc., Talos Production Inc., Tide Merger Sub I Inc., Tide Merger Sub II LLC, Tide Merger Sub III LLC, BCC Enven Investments, L.P. and ~~ILX Holdings, LLC~~EnVen Energy Corporation (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)September 22, 2022).

~~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		Amended and Restated Stockholders’ Agreement, dated as of March 29, 2022, by and among Talos Energy Inc. and each of the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.'s Form 8-K (File No. 001-38497) filed with the SEC on March 30, 2022).

4.2		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~~4.3		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).

~~Table of Contents~~


~~4.3~~4.4		Form of 12.00% Second-Priority Senior Secured Note due 2026 (included as Exhibit A to Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

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

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

4.7		Registration Rights Agreement, dated September 21, 2022, by and among Talos Energy Inc. and the Persons listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).
10.1*
4.8		Second Supplemental Indenture, dated as of October 27, 2022, 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 October 28, 2022).

10.1		Form of Support Agreement, by and among Talos Energy Inc. ~~2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice~~, EnVen Energy Corporation and ~~Restricted Stock Unit Agreement (Directors)~~the EnVen Supporting Stockholders (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022)..

Table of Contents


10.2		Form of Support Agreement, by and among Talos Energy Inc., EnVen Energy Corporation and the Talos Supporting Stockholders (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).

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
#		The exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the SEC upon request.

* 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.~~

3942

Table of Contents

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~~2, 2022	By:	/s/ Shannon E. Young III
			Shannon E. Young III
			Executive Vice President and Chief Financial Officer

4043


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)


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


	September 30, 2021			December 31, 2020			September 30, 2022			December 31, 2021
	(Unaudited)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	59,427		$	34,233		$	64,490		$	69,852
Accounts receivable:
Trade, net		111,471			106,220			150,099			173,241
Joint interest, net		21,480			50,471			42,259			28,165
Other		13,606			18,448
Other, net								9,450			18,062
Assets from price risk management activities		2			6,876			27,389			967
Prepaid assets		46,024			29,285			76,397			48,042
Other current assets		1,718			1,859			1,894			1,674
Total current assets		253,728			247,392			371,978			340,003
Property and equipment:
Proved properties		5,190,096			4,945,550			5,522,951			5,232,479
Unproved properties, not subject to amortization		250,629			254,994			213,802			219,055
Other property and equipment		28,904			32,853			30,601			29,091
Total property and equipment		5,469,629			5,233,397			5,767,354			5,480,625
Accumulated depreciation, depletion and amortization		(2,986,142	)		(2,697,228	)		(3,387,124	)		(3,092,043	)
Total property and equipment, net		2,483,487			2,536,169			2,380,230			2,388,582
Other long-term assets:
Assets from price risk management activities		49			945			19,540			2,770
Equity method investments								2,121			—
Other well equipment inventory		21,163			18,927			27,043			17,449
Operating lease assets		5,748			6,855			5,518			5,714
Other assets		21,989			24,258			6,936			12,297
Total assets	$	2,786,164		$	2,834,546		$	2,813,366		$	2,766,815
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	106,098		$	104,864		$	109,964		$	85,815
Accrued liabilities		133,261			163,379			189,743			130,459
Accrued royalties		40,404			27,903			45,476			59,037
Current portion of long-term debt		6,060			0			—			6,060
Current portion of asset retirement obligations		51,488			49,921			65,613			60,311
Liabilities from price risk management activities		248,361			66,010			99,180			186,526
Accrued interest payable		17,812			9,509			17,537			37,542
Current portion of operating lease liabilities		1,651			1,793			1,885			1,715
Other current liabilities		30,697			24,155			26,930			33,061
Total current liabilities		635,832			447,534			556,328			600,526
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		978,777			985,512			652,108			956,667
Asset retirement obligations		406,475			392,348			387,651			373,695
Liabilities from price risk management activities		35,856			9,625			7,126			13,938
Operating lease liabilities		16,781			18,554			14,895			16,330
Other long-term liabilities		37,819			54,372			39,915			45,006
Total liabilities		2,111,540			1,907,945			1,658,023			2,006,162
Commitments and Contingencies (Note 11)
Commitments and contingencies (Note 10)
Stockholdersʼ equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and 0 shares issued or outstanding as of September 30, 2021 and December 31, 2020		0			0
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
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of September 30, 2022 and December 31, 2021								—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 82,570,328 and 81,881,477 shares issued and outstanding as of September 30, 2022 and December 31, 2021, respectively								826			819
Additional paid-in capital		1,671,781			1,659,800			1,692,316			1,676,798
Accumulated deficit		(997,976	)		(734,012	)		(537,799	)		(916,964	)
Total stockholdersʼ equity		674,624			926,601			1,155,343			760,653
Total liabilities and stockholdersʼ equity	$	2,786,164		$	2,834,546		$	2,813,366		$	2,766,815


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2022			2021
Cash flows from operating activities:
Net loss	$	(263,964	)	$	(34,862	)
Adjustments to reconcile net loss to net cash provided by operating activities
Net income (loss)							$	379,165		$	(263,964	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion expense		334,204			300,281			337,574			334,204
Write-down of oil and natural gas properties and other well inventory		0			190
Amortization of deferred financing costs and original issue discount		10,085			5,393			10,614			10,085
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	)
Equity-based compensation expense								11,677			8,294
Price risk management activities expense								231,133			405,604
Net cash paid on settled derivative instruments								(368,483	)		(189,252	)
Equity method investment income								(14,599	)		—
Loss on extinguishment of debt								—			13,225
Settlement of asset retirement obligations		(58,001	)		(34,502	)		(60,304	)		(58,001	)
Gain on sale of assets		(677	)		0
Loss (gain) on sale of assets								390			(677	)
Changes in operating assets and liabilities:
Accounts receivable		29,078			(1,729	)		23,783			29,078
Other current assets		(16,598	)		21,835			(28,576	)		(16,598	)
Accounts payable		(1,591	)		23,500			16,677			(1,591	)
Other current liabilities		16,395			31,826			(6,682	)		16,395
Other non-current assets and liabilities, net		846			(41,418	)		6,559			846
Net cash provided by operating activities		287,648			262,067			538,928			287,648
Cash flows from investing activities:
Exploration, development and other capital expenditures		(211,580	)		(280,273	)		(209,592	)		(211,580	)
Cash paid for acquisitions, net of cash acquired		(5,399	)		(304,879	)		(3,500	)		(5,399	)
Proceeds from sale of property and equipment, net		4,826			0			1,690			4,826
Contributions to equity method investees								(2,250	)		—
Proceeds from sale of equity method investment								15,000			—
Net cash used in investing activities		(212,153	)		(585,152	)		(198,652	)		(212,153	)
Cash flows from financing activities:
Issuance of senior notes		600,500			0			—			600,500
Redemption of senior notes and other long-term debt		(356,803	)		(4,735	)		(6,060	)		(356,803	)
Proceeds from Bank Credit Facility		75,000			300,000			35,000			75,000
Repayment of Bank Credit Facility		(315,000	)		0			(350,000	)		(315,000	)
Deferred financing costs		(26,991	)		(1,287	)		(211	)		(26,991	)
Other deferred payments		(7,921	)		(11,921	)		—			(7,921	)
Payments of finance lease		(15,925	)		(12,790	)		(19,764	)		(15,925	)
Employee stock awards tax withholdings		(3,161	)		(827	)		(4,603	)		(3,161	)
Net cash provided by (used in) financing activities		(50,301	)		268,440
Net cash used in financing activities								(345,638	)		(50,301	)

Net increase (decrease) in cash and cash equivalents		25,194			(54,645	)		(5,362	)		25,194
Cash and cash equivalents:
Balance, beginning of period		34,233			87,022			69,852			34,233
Balance, end of period	$	59,427		$	32,377		$	64,490		$	59,427

Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	72,802		$	97,517		$	78,191		$	72,802
Debt exchanged for common stock	$	0		$	35,960
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	64,603		$	41,188		$	89,187		$	64,603


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


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


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


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


		Page
GLOSSARY		13
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		35
	PART I — FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements	57
	Condensed Consolidated Balance Sheets	57
	Condensed Consolidated Statements of Operations	68
	Condensed Consolidated Statements of Changes in ~~Stockholders'~~Stockholders’ Equity	79
	Condensed Consolidated Statements of Cash Flows	810
	Notes to Condensed Consolidated Financial Statements	911
	Note 1 — Organization, Nature of Business and Basis of Presentation	911
	Note 2 ~~— Acquisitions~~	9
	~~Note 3~~ — Property, Plant and Equipment	1112
	Note 43 — Leases	12
	Note 54 — Financial Instruments	13
	Note 65 — Debt	16
	Note 76 — Employee Benefits Plans and Share-Based Compensation	17
	Note 87 — Income Taxes	18
	Note 98 — Income (Loss) Per Share	19
	Note 109 — Related Party Transactions	2019
	Note 1110 — Commitments and Contingencies	21
	Note 1211 — Subsequent ~~Events~~Event	2123
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2224
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3639
Item 4.	Controls and Procedures	3639
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	3740
Item 1A.	Risk Factors	3740
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3740
Item 3.	Defaults Upon Senior Securities	3740
Item 4.	Mine Safety Disclosures	3740
Item 5.	Other Information	3740
Item 6.	Exhibits	3841
	Signatures	4043


	Shares				Par Value				Additional						Total													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
																		Common Stock Shares		Common Stock Par Value		Additional Paid-In Capital			Accumulated Deficit			Stockholdersʼ Equity
Balance at June 30, 2021		81,872,498		—	$	819	$	—	$	1,666,887		$	(981,285	)		686,421			81,872,498	$	819	$	1,666,887		$	(981,285	)	$	686,421
Equity-based compensation		—		—		—		—		4,936			—			4,936			—		—		4,936			—			4,936
Equity-based compensation tax withholdings		—		—		—		—		(42	)		—			(42	)		—		—		(42	)		—			(42	)
Equity-based compensation stock issuances		8,979		—		—		—		—			—			—			8,979		—		—			—			—
Net loss		—		—		—		—		—			(16,691	)		(16,691	)		—		—		—			(16,691	)		(16,691	)
Balance at September 30, 2021		81,881,477		—	$	819	$	—	$	1,671,781		$	(997,976	)	$	674,624			81,881,477	$	819	$	1,671,781		$	(997,976	)	$	674,624

Balance at June 30, 2022																			82,541,345	$	825	$	1,684,949		$	(788,264	)		897,510
Equity-based compensation																			—		—		7,495			—			7,495
Equity-based compensation tax withholdings																			—		—		(127	)		—			(127	)
Equity-based compensation stock issuances																			28,983		1		(1	)		—			—
Net income																			—		—		—			250,465			250,465
Balance at September 30, 2022																			82,570,328	$	826	$	1,692,316		$	(537,799	)	$	1,155,343


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


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


	September 30, 2022
Current assets	$	17,500
Non-current assets		2,587
Total assets	$	20,087


	Three Months Ended September 30, 2022			Nine Months Ended September 30, 2022
Revenues	$	—		$	—
Operating expenses		(325	)		(8,130	)
Equity method investment income(1)		916			14,594
Other income		29			29
Net income	$	620		$	6,493


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


	Three Months Ended September 30, 2020			Nine Months Ended September 30, 2020
Revenue	$	37,538		$	77,729
Net loss	$	(1,131	)	$	(13,083	)


	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	)


	RSUs			Weighted Average Grant Date Fair Value		RSUs			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2020		1,652,988		$	13.73
Unvested RSUs at December 31, 2021							1,983,199		$	13.02
Granted		1,102,038		$	13.11		2,297,465		$	13.23
Vested		(669,832	)	$	15.01		(967,269	)	$	14.14
Forfeited		(94,922	)	$	12.55		(63,599	)	$	14.05
Unvested RSUs at September 30, 2021(1)		1,990,272		$	13.01
Unvested RSUs at September 30, 2022(1)							3,249,796		$	12.82


	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


	PSUs			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2021		1,015,459		$	16.41
Granted(1)		629,666		$	23.73
Forfeited		(16,486	)	$	17.48
Cancelled		(975,564	)	$	16.42
Unvested PSUs at September 30, 2022		653,075		$	23.42


	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		0	%		0	%
Fair value (in thousands)	$	9,715		$	11,129


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