10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2022


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

For the transition period from to

Commission File Number: 001-38497

Talos Energy Inc.

(Exact Name of Registrant as Specified in its Charter)


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

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

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


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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of October 26, 2022, the registrant had 82,570,328 shares of common stock, $0.01 par value per share, outstanding.

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		Page
GLOSSARY		3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		5
	PART I — FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements	7
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Operations	8
	Condensed Consolidated Statements of Changes in Stockholders’ Equity	9
	Condensed Consolidated Statements of Cash Flows	10
	Notes to Condensed Consolidated Financial Statements	11
	Note 1 — Organization, Nature of Business and Basis of Presentation	11
	Note 2 — Property, Plant and Equipment	12
	Note 3 — Leases	12
	Note 4 — Financial Instruments	13
	Note 5 — Debt	16
	Note 6 — Employee Benefits Plans and Share-Based Compensation	17
	Note 7 — Income Taxes	18
	Note 8 — Income (Loss) Per Share	19
	Note 9 — Related Party Transactions	19
	Note 10 — Commitments and Contingencies	21
	Note 11 — Subsequent Event	23
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	39
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
	Signatures	43

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GLOSSARY

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

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

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

BOEM — Bureau of Ocean Energy Management.

BSEE — Bureau of Safety and Environmental Enforcement.

Boepd — Barrels of oil equivalent per day.

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

CO2 — Carbon dioxide.

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

Deepwater — Water depths of more than 600 feet.

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

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

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

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

MBoe — One thousand barrels of oil equivalent.

MBoepd — One thousand barrels of oil equivalent per day.

Mcf — One thousand cubic feet of natural gas.

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

MMBoe — One million barrels of oil equivalent.

MMBtu — One million British thermal units.

MMcf — One million cubic feet of natural gas.

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

NGL — Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.

NYMEX — The New York Mercantile Exchange.

NYMEX Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub index.

OPEC — Organization of Petroleum Exporting Countries.

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

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

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

SEC pricing — The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for each month within the 12-month period prior 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 of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

Shelf — Water depths of up to 600 feet.

Working interest — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

WTI or West Texas Intermediate — A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this 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 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:

•

business strategy;

•

reserves;

•

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

•

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

•

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

•

realized oil and natural gas prices;

•

the proposed transaction with EnVen Energy Corporation (”EnVen”) and anticipated future performance of the combined company;

•

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

•

our hedging strategy and results;

•

future drilling plans;

•

availability of pipeline connections on economic terms;

•

competition, government regulations and political developments;

•

our ability to obtain permits and governmental approvals;

•

pending legal, governmental or environmental matters;

•

our marketing of oil, natural gas and NGLs;

•

leasehold or business acquisitions on desired terms;

•

costs of developing properties;

•

general economic conditions, including the impact of continued inflation and associated changes in monetary policy;

•

political and economic conditions and events in foreign oil, natural gas and NGL producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the war in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America and China and acts of terrorism or sabotage;

•

credit markets;

•

impact of new accounting pronouncements on earnings in future periods;

•

estimates of future income taxes;

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•

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

•

the success of our carbon capture and sequestration opportunities;

•

our ongoing strategy with respect to our Zama asset;

•

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

•

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

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility due to the continued impact of the coronavirus disease 2019 (“COVID-19”), including any new strains or variants, and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business; the ability or willingness of OPEC and other state-controlled oil companies (“OPEC Plus”), 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; 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, 2021, filed with the SEC on February 25, 2022 (the “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.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)


	September 30, 2022			December 31, 2021
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	64,490		$	69,852
Accounts receivable:
Trade, net		150,099			173,241
Joint interest, net		42,259			28,165
Other, net		9,450			18,062
Assets from price risk management activities		27,389			967
Prepaid assets		76,397			48,042
Other current assets		1,894			1,674
Total current assets		371,978			340,003
Property and equipment:
Proved properties		5,522,951			5,232,479
Unproved properties, not subject to amortization		213,802			219,055
Other property and equipment		30,601			29,091
Total property and equipment		5,767,354			5,480,625
Accumulated depreciation, depletion and amortization		(3,387,124	)		(3,092,043	)
Total property and equipment, net		2,380,230			2,388,582
Other long-term assets:
Assets from price risk management activities		19,540			2,770
Equity method investments		2,121			—
Other well equipment inventory		27,043			17,449
Operating lease assets		5,518			5,714
Other assets		6,936			12,297
Total assets	$	2,813,366		$	2,766,815
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	109,964		$	85,815
Accrued liabilities		189,743			130,459
Accrued royalties		45,476			59,037
Current portion of long-term debt		—			6,060
Current portion of asset retirement obligations		65,613			60,311
Liabilities from price risk management activities		99,180			186,526
Accrued interest payable		17,537			37,542
Current portion of operating lease liabilities		1,885			1,715
Other current liabilities		26,930			33,061
Total current liabilities		556,328			600,526
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		652,108			956,667
Asset retirement obligations		387,651			373,695
Liabilities from price risk management activities		7,126			13,938
Operating lease liabilities		14,895			16,330
Other long-term liabilities		39,915			45,006
Total liabilities		1,658,023			2,006,162
Commitments and contingencies (Note 10)
Stockholdersʼ equity:
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		1,692,316			1,676,798
Accumulated deficit		(537,799	)		(916,964	)
Total stockholdersʼ equity		1,155,343			760,653
Total liabilities and stockholdersʼ equity	$	2,813,366		$	2,766,815

See accompanying notes.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2022			2021			2022			2021
Revenues:
Oil	$	295,585		$	246,208		$	1,078,800		$	743,759
Natural gas		68,360			31,723			181,747			86,088
NGL		13,183			12,978			49,232			31,738
Total revenues		377,128			290,909			1,309,779			861,585
Operating expenses:
Lease operating expense		81,760			70,034			229,156			208,675
Production taxes		955			764			2,670			2,539
Depreciation, depletion and amortization		92,323			88,596			295,174			290,094
Accretion expense		13,179			13,668			42,400			44,110
General and administrative expense		25,289			20,427			70,742			58,993
Other operating (income) expense		(366	)		5,081			12,142			6,864
Total operating expenses		213,140			198,570			652,284			611,275
Operating income		163,988			92,339			657,495			250,310
Interest expense		(29,265	)		(32,390	)		(91,531	)		(100,036	)
Price risk management activities income (expense)		114,180			(81,479	)		(231,133	)		(405,604	)
Equity method investment income		991			—			14,599			—
Other income (expense)		692			4,475			31,991			(7,916	)
Net income (loss) before income taxes		250,586			(17,055	)		381,421			(263,246	)
Income tax benefit (expense)		(121	)		364			(2,256	)		(718	)
Net income (loss)	$	250,465		$	(16,691	)	$	379,165		$	(263,964	)

Net income (loss) per common share:
Basic	$	3.03		$	(0.20	)	$	4.60		$	(3.23	)
Diluted	$	2.99		$	(0.20	)	$	4.54		$	(3.23	)
Weighted average common shares outstanding:
Basic		82,576			81,901			82,406			81,721
Diluted		83,818			81,901			83,438			81,721

See accompanying notes.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)


											Total
	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
Equity-based compensation		—		—		4,936			—			4,936
Equity-based compensation tax withholdings		—		—		(42	)		—			(42	)
Equity-based compensation stock issuances		8,979		—		—			—			—
Net loss		—		—		—			(16,691	)		(16,691	)
Balance at September 30, 2021		81,881,477	$	819	$	1,671,781		$	(997,976	)	$	674,624

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


											Total
	Common Stock Shares		Common Stock Par Value		Additional Paid-In Capital			Accumulated Deficit			Stockholders' Equity
Balance at December 31, 2020		81,279,989	$	813	$	1,659,800		$	(734,012	)	$	926,601
Equity-based compensation		—		—		15,148			—			15,148
Equity-based compensation tax withholdings		—		—		(3,161	)		—			(3,161	)
Equity-based compensation stock issuances		601,488		6		(6	)		—			—
Net loss		—		—		—			(263,964	)		(263,964	)
Balance at September 30, 2021		81,881,477	$	819	$	1,671,781		$	(997,976	)	$	674,624

Balance at December 31, 2021		81,881,477	$	819	$	1,676,798		$	(916,964	)	$	760,653
Equity-based compensation		—		—		20,128			—			20,128
Equity-based compensation tax withholdings		—		—		(4,603	)		—			(4,603	)
Equity-based compensation stock issuances		688,851		7		(7	)		—			—
Net income		—		—		—			379,165			379,165
Balance at September 30, 2022		82,570,328	$	826	$	1,692,316		$	(537,799	)	$	1,155,343

See accompanying notes.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2022			2021
Cash flows from 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		337,574			334,204
Amortization of deferred financing costs and original issue discount		10,614			10,085
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		(60,304	)		(58,001	)
Loss (gain) on sale of assets		390			(677	)
Changes in operating assets and liabilities:
Accounts receivable		23,783			29,078
Other current assets		(28,576	)		(16,598	)
Accounts payable		16,677			(1,591	)
Other current liabilities		(6,682	)		16,395
Other non-current assets and liabilities, net		6,559			846
Net cash provided by operating activities		538,928			287,648
Cash flows from investing activities:
Exploration, development and other capital expenditures		(209,592	)		(211,580	)
Cash paid for acquisitions, net of cash acquired		(3,500	)		(5,399	)
Proceeds from sale of property and equipment, net		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		(198,652	)		(212,153	)
Cash flows from financing activities:
Issuance of senior notes		—			600,500
Redemption of senior notes and other long-term debt		(6,060	)		(356,803	)
Proceeds from Bank Credit Facility		35,000			75,000
Repayment of Bank Credit Facility		(350,000	)		(315,000	)
Deferred financing costs		(211	)		(26,991	)
Other deferred payments		—			(7,921	)
Payments of finance lease		(19,764	)		(15,925	)
Employee stock awards tax withholdings		(4,603	)		(3,161	)
Net cash used in financing activities		(345,638	)		(50,301	)

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

Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	78,191		$	72,802
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	89,187		$	64,603

See accompanying notes.

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TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2022

(Unaudited)

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.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of carbon capture and sequestration (“CCS”) opportunities. The Company leverages decades of technical and offshore operational expertise 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 industrial emissions through the Company’s CCS initiatives both in and along the coast of the U.S. 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 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. 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 two operating segments: (i) exploration and production of oil, natural gas and 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 for purposes of the Bank Credit Facility (as defined in Note 4 — Financial Instruments) and indenture governing the senior notes.

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The following table presents the CCS Segment asset information (in thousands):


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

The following table presents the CCS Segment income statement information for the respective periods (in thousands):


	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

(1)

The CCS Segment reported a gain related to the partial sale of the Company’s interest in Bayou Bend CCS LLC (“Bayou Bend”) during the three and nine months ended September 30, 2022, respectively. See Note 9 — Related Party Transactions for further information.

Note 2 — Property, Plant and Equipment

Proved Properties

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

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 at December 31, 2021	$	434,006
Obligations incurred		78
Obligations settled		(60,304	)
Obligations divested		(1,572	)
Accretion expense		42,400
Changes in estimate		38,656
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 3 — 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.

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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,
	2022		2021		2022		2021
Finance lease cost - interest on lease liabilities	$	1,386	$	2,749	$	5,179	$	9,017
Operating lease cost, excluding short-term leases(1)		568		702		1,703		2,138
Short-term lease cost(2)		12,982		14,541		24,838		32,393
Variable lease cost(3)		363		350		1,088		994
Total lease cost	$	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.

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, 2022		December 31, 2021
Operating leases:
Operating lease assets	$	5,518	$	5,714

Current portion of operating lease liabilities	$	1,885	$	1,715
Operating lease liabilities		14,895		16,330
Total operating lease liabilities	$	16,780	$	18,045

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

Other current liabilities	$	20,458	$	27,083
Other long-term liabilities		—		13,138
Total finance lease liabilities	$	20,458	$	40,221

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


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

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

Note 4 — Financial Instruments

As of September 30, 2022 and December 31, 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.

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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, 2022				December 31, 2021
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
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	$	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).

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. 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 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,
	2022			2021			2022			2021
Net cash paid on settled derivative instruments	$	(81,162	)	$	(71,634	)	$	(368,483	)	$	(189,252	)
Unrealized gain (loss)		195,342			(9,845	)		137,350			(216,352	)
Price risk management activities income (expense)	$	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, 2022:


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

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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, 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, 2021
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	3,737		$	—	$	3,737
Liabilities:
Oil and natural gas derivatives		—		(200,464	)		—		(200,464	)
Total net liability	$	—	$	(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. 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, 2022				December 31, 2021
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	27,389	$	99,180	$	967	$	186,526
Non-current		19,540		7,126		2,770		13,938
Total gross amounts presented on balance sheet		46,929		106,306		3,737		200,464
Less: Gross amounts not offset on the balance sheet		44,708		44,708		3,737		3,737
Net amounts	$	2,221	$	61,598	$	—	$	196,727

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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, 2022 represent derivative instruments from nine counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and all of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities.

Note 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, 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

(1)

As of September 30, 2022, the Company had outstanding borrowings at a weighted average interest rate of 6.16%.

(2)

At September 30, 2022, the Company was in compliance with all debt covenants.

7.50% Senior Notes

On May 31, 2022, the 7.50% Senior Notes matured and were redeemed at an aggregate principal of $6.1 million plus accrued and unpaid interest.

Bank Credit Facility

The Company maintains the 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”). The Eighth Amendment and the Incremental Agreement, among other things, (i) increased the borrowing base from $950.0 million to $1.1 billion and (ii) increased the commitments from $791.3 million to $806.3 million.

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The Bank Credit Facility no longer bears interest at the applicable London InterBank Offered Rate plus the applicable margin. Interest under the Bank Credit Facility accrues at the Company’s option either at an alternate base rate (“ABR”) plus 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 is based on the borrowing base utilization percentage, ranges from 2.00% to 3.00% for ABR Loans and 3.00% to 4.00% for Term Benchmark Loans and RFR Loans.

Note 6 — Employee Benefits Plans and Share-Based Compensation

Long Term Incentive Plans

Restricted Stock Units (“RSUs”) — The following table summarizes RSU activity under the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”) for the nine months ended September 30, 2022:


	RSUs			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2021		1,983,199		$	13.02
Granted		2,297,465		$	13.23
Vested		(967,269	)	$	14.14
Forfeited		(63,599	)	$	14.05
Unvested RSUs at September 30, 2022(1)		3,249,796		$	12.82

(1)

As of September 30, 2022, 25,257 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Condensed Consolidated Balance Sheet.

Performance Share Units (“PSUs”) — The following table summarizes PSU activity under the 2021 LTIP for the nine months ended September 30, 2022:


	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

(1)

There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return (“PVI”) on the wells included in the 2022 drill program over a three-year performance period. The actual number of PSUs earned ranges between 0% and 200% depending on actual performance over the performance period. For the PVI PSUs, the Company recognizes compensation cost if and when the Company concludes that it is probable that the performance condition will be achieved. The Company reassesses the probability of achieving the performance conditions at each reporting date.

The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the absolute TSR PSUs granted 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

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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,” on the Condensed Consolidated Statements of Operations, net amounts capitalized to “Proved Properties,” on 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” on the Condensed Consolidated Statements of Cash Flows.

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


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

Note 7 — 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 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 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 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% and federal statutory income tax rate of 21% is primarily due to recording a valuation allowance for its deferred tax 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, 2022, the Company maintains a full valuation allowance for U.S. federal, state and foreign net deferred tax assets.

Note 8 — 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,
	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

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 members of management pursuant to which the Company received a private equity capital commitment. On January 3, 2022, the Apollo Funds ceased being a beneficial owner of more than five percent of the Company’s common stock. Riverstone Funds held 14.9% of the Company’s common stock as of September 30, 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. A settlement agreement related to a dispute regarding the decommissioning obligation of a 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.

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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 the Riverstone Funds, 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 2021 Annual Report.

The Company will bear all of the expenses incurred in connection with 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, 2022, the Company did not incur any such fees. For the three and nine months ended September 30, 2021, fees incurred by the Company were nil and $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

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 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.

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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”) 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 was payable at period end.

Bayou Bend CCS LLC

On March 8, 2022, the Company made a $2.3 million cash contribution for 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, 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, 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 as well as all other direct out-of-pocket costs and expenses incurred or paid on behalf of Bayou Bend. The Company had a $0.5 million related party receivable from Bayou Bend as of September 30, 2022.

Note 10 — Commitments and Contingencies

Performance Obligations

Regulations with respect to 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 certain obligations under the production sharing contracts with Mexico.

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As of September 30, 2022, the Company had secured performance bonds from third party sureties totaling $689.5 million. The cost of securing these bonds is reflected as “Interest expense” on the Condensed Consolidated Statements of Operations. Additionally, as of September 30, 2022, the Company had secured letters of credit issued under its Bank Credit 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

From time to time, the Company is involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of business in jurisdictions in which the Company does 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, 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 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. The Company recorded estimated decommissioning obligations of $0.1 million and $4.1 million during the three months ended September 30, 2022 and 2021, respectively, and $10.6 million and $6.9 million during the nine months ended September 30, 2022 and 2021, respectively. These costs are reflected as “Other operating (income) expense” on 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, the Company could incur judgments, enter into settlements or revise its opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on its results of operations in the period in which the amounts are accrued and 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 11 — Subsequent Events

12.00% Notes Consent Solicitation

For additional information, see Note 10 — 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 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 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 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.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of carbon capture and 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 also utilize our expertise to explore opportunities to reduce industrial emissions through our CCS initiatives both in and along the coast of the U.S. 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 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.

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, 2022.

EnVen Acquisition — On September 21, 2022, we executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the 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 consent solicitation to obtain the requisite holders’ consent to certain amendments to the indenture governing its 12.00% Notes (as defined below under “ — Liquidity and Capital Resources — Overview of Debt 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 10 — Commitments and Contingencies” for additional information.

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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 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 project at a later date.

Phoenix Field Update — Production from one of our Tornado wells generated increased water volumes during the third quarter primarily as a result of 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 2023.

Inflation Reduction Act of 2022 (the “IRA”) — On August 16, 2022, President Biden signed the IRA into law. The 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 Interior (”DOI”) to:

•

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

•

move forward with Lease Sales 259 and 261 in the Gulf of Mexico by 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 requirements to offer for sale federal oil and gas leases for a 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 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.

Planned Downtime — 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 are unable to produce the 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 41 days. The shut-in resulted in an estimated deferred production of approximately 6.2 MBoepd and 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 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 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 the shut-in.

Eugene Island Pipeline System — During the first quarter of 2022, we experienced approximately 40 days of unplanned third-party downtime due to maintenance of the 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 approximately 1.5 MBoepd based on production rates prior to the 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. We did not experience any disruptions to our operations from hurricanes or tropical storms during the three and nine months ended September 30, 2022.

Known Trends and Uncertainties

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 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 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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Significant progress has been made to reduce the risk of spreading COVID-19 and its multiple variants, however, certain regions in the world remain negatively impacted by outbreaks of COVID-19 that continue to 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 predict, including the duration and spread of the outbreak and its impact on our personnel, customer activity and third-party providers.

During the period January 1, 2022 through September 30, 2022, the daily spot prices for NYMEX WTI crude oil ranged from a high of $123.64 per Bbl to a low of $75.99 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.85 per MMBtu to a low of $3.73 per MMBtu. 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. 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 4 — Financial Instruments” for additional information regarding our commodity derivative positions as of September 30, 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, 2022 and 2021, we did not recognize an impairment based on the ceiling test computations. At September 30, 2022 our ceiling test computation was based on SEC pricing of $93.61 per Bbl of oil, $6.56 per Mcf of natural gas and $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 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 submission of the Unit Development Plan for the Zama Field to the National Hydrocarbon Commission, which will set out the terms on which the reservoir will be jointly developed, is expected by 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.

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 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 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 fields in the U.S. Gulf of Mexico. Operations in 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

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


	Three Months Ended September 30,							Nine Months Ended September 30,
	2022		2021		Change			2022		2021		Change
Revenues:
Oil	$	295,585	$	246,208	$	49,377		$	1,078,800	$	743,759	$	335,041
Natural gas		68,360		31,723		36,637			181,747		86,088		95,659
NGL		13,183		12,978		205			49,232		31,738		17,494
Total revenues	$	377,128	$	290,909	$	86,219		$	1,309,779	$	861,585	$	448,194

Total Production Volumes:
Oil (MBbls)		3,258		3,609		(351	)		11,020		11,827		(807	)
Natural gas (MMcf)		7,292		6,975		317			24,746		24,055		691
NGL (MBbls)		403		429		(26	)		1,372		1,344		28
Total production volume (MBoe)		4,876		5,200		(324	)		16,516		17,180		(664	)

Daily Production Volumes by Product:
Oil (MBblpd)		35.4		39.2		(3.8	)		40.4		43.3		(2.9	)
Natural gas (MMcfpd)		79.3		75.8		3.5			90.6		88.1		2.5
NGL (MBblpd)		4.4		4.7		(0.3	)		5.0		4.9		0.1
Total production volume (MBoepd)		53.0		56.5		(3.5	)		60.5		62.9		(2.4	)

Average Sale Price Per Unit:
Oil (per Bbl)	$	90.73	$	68.22	$	22.51		$	97.89	$	62.89	$	35.00
Natural gas (per Mcf)	$	9.37	$	4.55	$	4.82		$	7.34	$	3.58	$	3.76
NGL (per Bbl)	$	32.71	$	30.25	$	2.46		$	35.88	$	23.61	$	12.27
Price per Boe	$	77.34	$	55.94	$	21.40		$	79.30	$	50.15	$	29.15
Price per Boe (including realized commodity derivatives)	$	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 sales prices and production volumes (in thousands):


	Three Months Ended September 30, 2022 vs 2021							Nine Months Ended September 30, 2022 vs 2021
	Price		Volume			Total		Price		Volume			Total
Revenues:
Oil	$	73,322	$	(23,945	)	$	49,377	$	385,793	$	(50,752	)	$	335,041
Natural gas		35,195		1,442			36,637		93,185		2,474			95,659
NGL		992		(787	)		205		16,833		661			17,494
Total revenues	$	109,509	$	(23,290	)	$	86,219	$	495,811	$	(47,617	)	$	448,194

Three Months Ended September 30, 2022 and 2021 Volumetric Analysis — Production volumes decreased by 3.5 MBoepd to 53.0 MBoepd. The decrease in production volumes was 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 deferred production, respectively. Additionally, production volumes decreased 4.3 MBoepd and 1.8 MBoepd primarily attributable to well performance and natural production declines in our Phoenix Field and Green Canyon 18 Field, respectively. The decrease was partially offset by an increase of 12.7 MBoepd in deferred production attributable to Hurricane Ida in 2021.

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Nine Months Ended September 30, 2022 and 2021 Volumetric Analysis — Production volumes decreased by 2.4 MBoepd to 60.5 MBoepd. The decrease in production volumes was primarily due to the third party downtime for the HP-I dry-dock in our Phoenix Field, the Eugene Island Pipeline System shut-in primarily impacting HP-I and Green Canyon 18 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 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 temporary shut-ins for repairs and maintenance and natural production declines. The decrease was partially offset by an increase of 4.3 MBoepd in deferred production attributable to Hurricane Ida in 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,
	2022		2021		2022		2021
Lease operating expenses	$	81,760	$	70,034	$	229,156	$	208,675
Lease operating expenses per Boe	$	16.77	$	13.47	$	13.87	$	12.15

Three Months Ended September 30, 2022 and 2021 — Lease operating expense for the three months ended September 30, 2022 increased by approximately $11.7 million, or 17%. The increase is primarily due to a $4.9 million increase in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Pompano Field. Additionally, there was a $1.7 million increase in company and contract labor compared to the same period in 2021 and $1.4 million reduction in production handling fees related to reimbursements for costs from certain third parties.

Nine Months Ended September 30, 2022 and 2021 — Lease operating expense for the nine months ended September 30, 2022 increased by approximately $20.5 million, or 10%. The increase is primarily due to a $19.8 million increase in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Gunflint Field. Additionally, there was a $4.8 million increase in company and contract labor compared to the same period in 2021. This increase was partially offset by $7.0 million in additional production handling fees related to 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,
	2022		2021		2022		2021
Depreciation, depletion and amortization	$	92,323	$	88,596	$	295,174	$	290,094
Depreciation, depletion and amortization per Boe	$	18.93	$	17.04	$	17.87	$	16.89

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

Nine Months Ended September 30, 2022 and 2021 — Depreciation, depletion and amortization expense for the nine months ended September 30, 2022 increased by approximately $5.1 million, or 2%. This was primarily due to an increase of $1.00 per Boe, or 6% in the depletion rate on our proved oil and natural gas properties partially offset by decreased production of 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,
	2022		2021		2022		2021
General and administrative expense	$	25,289	$	20,427	$	70,742	$	58,993
General and administrative expense per Boe	$	5.19	$	3.93	$	4.28	$	3.43

Three Months Ended September 30, 2022 and 2021 — General and administrative expense for the three months ended September 30, 2022 increased by approximately $4.9 million, or 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 $1.26 Boe primarily due to decreased production of 3.5 MBoepd.

Nine Months Ended September 30, 2022 and 2021 — General and administrative expense for the nine months ended September 30, 2022 increased by approximately $11.7 million, or 20%. This increase was primarily related to $5.6 million of expenses incurred by our emerging CCS operating segment during the nine months ended September 30, 2022, an increase of $4.1 million. There was an increase in transaction costs of $2.0 million primarily related to the EnVen Acquisition. Additionally, general and administrative expense includes non-cash equity-based compensation of $11.7 million, or $0.71 per Boe, during the nine months ended September 30, 2022, an increase of $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,
	2022			2021			2022			2021
Accretion expense	$	13,179		$	13,668		$	42,400		$	44,110
Other operating (income) expense	$	(366	)	$	5,081		$	12,142		$	6,864
Interest expense	$	29,265		$	32,390		$	91,531		$	100,036
Price risk management activities (income) expense	$	(114,180	)	$	81,479		$	231,133		$	405,604
Equity method investment income	$	991		$	—		$	14,599		$	—
Other (income) expense	$	(692	)	$	(4,475	)	$	(31,991	)	$	7,916
Income tax (benefit) expense	$	121		$	(364	)	$	2,256		$	718

Three Months Ended September 30, 2022 and 2021 —

Other Operating (Income) Expense — During the three months ended September 30, 2022, we recorded $0.1 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of 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 10 — Commitments and Contingencies.”

Interest 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 — The income of $114.2 million for the three months ended September 30, 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 $81.1 million 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.

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 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 4 — 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 — 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 9 — Related Party Transactions.”

Income Tax (Benefit) Expense — During the three months ended September 30, 2022, we recorded $0.1 million of income tax expense compared to $0.4 million of income tax benefit during the three months ended September 30, 2021. The 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 7 — Income Taxes.”

Nine Months Ended September 30, 2022 and 2021 —

Other Operating (Income) Expense — During the nine months ended September 30, 2022, we recorded $10.6 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of 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 10 — Commitments and Contingencies.”

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 — The expense of $231.1 million for the nine months ended September 30, 2022 consists of $368.5 million in cash settlement losses partially offset by $137.4 million 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.

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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 (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 9 — Related Party Transactions.”

Income Tax (Benefit) Expense — During the nine months ended September 30, 2022, we recorded $2.3 million of income tax expense compared to $0.7 million of income tax expense during the nine months ended September 30, 2021. The change is primarily a result of a discrete tax expense and 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 7 — 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 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 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,
	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 expenses, 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 decreased since December 31, 2021 primarily due to a decrease of $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, 2022, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $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, 2022 (in thousands):


U.S. drilling & completions	$	120,510
Mexico appraisal & exploration		301
Asset management		80,704
Seismic and G&G, land, capitalized G&A and other		35,667
CCS(1)		2,027
Total capital expenditures		239,209
Plugging & abandonment		60,304
Total capital expenditures and plugging & abandonment	$	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 2022 capital spending program of $450.0 million to $480.0 million, 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, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding 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,
	2022			2021
Operating activities	$	538,928		$	287,648
Investing activities	$	(198,652	)	$	(212,153	)
Financing activities	$	(345,638	)	$	(50,301	)

Operating Activities — Net cash provided by operating activities increased $251.3 million in the nine months ended September 30, 2022 compared to the corresponding period in 2021 primarily attributable to an increase in revenues net of the change in lease operating expense of $427.7 million. This was offset by an increase in cash payments on derivative instruments of $179.2 million.

Investing Activities — Net cash used in investing activities decreased $13.5 million in the nine months ended September 30, 2022 compared to the corresponding period in 2021 primarily due to $15.0 million in cash proceeds from a partial sale of our investment in Bayou Bend and decreased capital expenditures of $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 $295.3 million in the nine months ended September 30, 2022 compared to the corresponding period in 2021. During the nine months ended September 30, 2022, net repayments of $315.0 million reduced the Bank Credit Facility. Additionally, we redeemed $6.1 million of 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 reduced further 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 May 4, 2022, our borrowing base increased from $950.0 million to $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 5 — Debt” for more information.

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12.00% Second-Priority Senior Secured Notes — due January 2026 — The 12.00% Second-Priority Senior Secured Notes (the “12.00% Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the “Parent Guarantor”); Talos Production Inc. (the “Issuer”); the Subsidiary Guarantors (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. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Debt” for more information.

7.50% Senior Notes — redeemed May 2022 — The 7.50% Senior Notes matured and were redeemed on May 31, 2022. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Debt” for more information.

Guarantor Financial Information — We own no operating assets and have no operations independent of 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 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 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, 2022		December 31, 2021
Current assets	$	342,980	$	330,415
Non-current assets		2,323,141		2,305,855
Total assets	$	2,666,121	$	2,636,270

Current liabilities	$	552,275	$	598,062
Non-current liabilities		1,101,695		1,405,382
Talos Energy Inc. stockholdersʼ equity		1,012,151		632,826
Total liabilities and stockholdersʼ equity	$	2,666,121	$	2,636,270

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


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

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 2021 Annual Report except:

•

The aggregate principal amount of our Bank Credit Facility decreased from $375.0 million to $60.0 million;

•

Interest expense through the maturity of our debt instruments decreased in the aggregate by approximately $19.1 million primarily due to the lower borrowings under the Bank Credit Facility;

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•

Vessel commitments increased by approximately $33.6 million due to the execution of an offshore drilling rig 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;

•

Derivative net liabilities decreased from $196.7 million to $59.4 million; and

•

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

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

See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” 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. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — 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 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 2021 Annual 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 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 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, 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, 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

There have been no additional material developments with respect to the information previously reported under Part I, Item 3. “Legal Proceedings” of our 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 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 2021 Annual Report or our other SEC 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.

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Item 6. Exhibits


Exhibit Number		Description

2.1#		Merger Agreement, dated as of 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 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 September 22, 2022).

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).

4.3		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).

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).

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., EnVen Energy Corporation and 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).

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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.

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SIGNATURES

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


		Talos Energy Inc.

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