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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, 2023

OR

☐ | 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 30, 2023, the registrant had 124,080,361 shares of common stock, $0.01 par value per share, outstanding.

TABL E OF CONTENTS

|  | Page
GLOSSARY | 3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS | 5
| PART I — FINANCIAL INFORMATION |
Item 1. | 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 — Acquisitions and Divestitures | 12
| Note 3 — Property, Plant and Equipment | 14
| Note 4 — Leases | 15
| Note 5 — Financial Instruments | 16
| Note 6 — Debt | 18
| Note 7 — Employee Benefits Plans and Share-Based Compensation | 19
| Note 8 — Income Taxes | 20
| Note 9 — Income (Loss) Per Share | 21
| Note 10 — Related Party Transactions | 21
| Note 11 — Commitments and Contingencies | 23
| Note 12 — Segment Information | 24
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 27
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 40
Item 4. | Controls and Procedures | 40
| PART II — OTHER INFORMATION |
Item 1. | Legal Proceedings | 41
Item 1A. | Risk Factors | 41
Item 2. | Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities | 41
Item 3. | Defaults Upon Senior Securities | 41
Item 4. | Mine Safety Disclosures | 41
Item 5. | Other Information | 41
Item 6. | Exhibits | 42
| Signatures | 44

2

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GLOS SARY

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.

CCS — Carbon capture and sequestration.

CO 2 — 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.

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.

3

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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%.

4

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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 and prospective storage resources;
•
drilling prospects, inventories, projects and programs;
•
our ability to replace the reserves that we produce through drilling and property acquisitions;
•
financial strategy, liquidity and capital required for our development program and other capital expenditures;
•
realized oil and natural gas prices;
•
timing and amount of future production of oil, natural gas and NGLs;
•
our hedging strategy and results;
•
future drilling and low carbon solutions plans;
•
availability of pipeline connections on economic terms;
•
competition, government regulations and legislative 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;
•
our integration of acquisitions, including EnVen Energy Corporation, and future performance of the combined company;
•
future 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, increasing 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;
•
estimates of future income taxes;
•
our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;
•
the success of our low carbon solutions opportunities, including as a result of the associated permitting process, our access to capital to finance such opportunities, the timing and amount of revenues therefrom and potential future customers;
•
the uncertainty inherent in estimating subsurface storage resources in our low carbon solutions projects;
•
our ongoing strategy with respect to our Zama asset;
•
uncertainty regarding our future operating results and our future revenues and expenses;

5

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•
impact of new accounting pronouncements on earnings in future periods; 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; global demand for oil and natural gas; the ability or willingness of OPEC and other state-controlled oil companies (“OPEC Plus”) to set and maintain oil production levels and the impact of any such actions; the lack of a resolution to the war in Ukraine and increasing hostilities in the Middle East, and their impact on commodity markets; the impact of any pandemic, and governmental measures related thereto; lack of transportation and storage capacity as a result of oversupply, government and regulations; the effect of a possible U.S. government shutdown and resulting impact on economic conditions and delays in regulatory and permitting approvals; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; 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, risks associated with permitting for—and access to capital to finance—our CCS opportunities; 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, 2022 (the “2022 Annual Report”) and in Part II, Item 1A. “Risk Factors” of Talos Energy Inc.’s Quarterly Report on Form 10-Q for the period ended March 31, 2023 each as filed with the SEC.

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.

6

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PART I—FINANCI AL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

| September 30, 2023 |  | December 31, 2022 |
| (Unaudited) |  |  |
ASSETS |  |  |  |
Current assets: |  |  |  |
Cash and cash equivalents | $ | 13,631 |  | $ | 44,145 |
Accounts receivable: |  |  |  |
Trade, net |  | 181,384 |  |  | 150,598 |
Joint interest, net |  | 93,798 |  |  | 54,697 |
Other, net |  | 10,744 |  |  | 6,684 |
Assets from price risk management activities |  | 11,497 |  |  | 25,029 |
Prepaid assets |  | 86,077 |  |  | 84,759 |
Other current assets |  | 14,457 |  |  | 1,917 |
Total current assets |  | 411,588 |  |  | 367,829 |
Property and equipment: |  |  |  |
Proved properties |  | 7,691,828 |  |  | 5,964,340 |
Unproved properties, not subject to amortization |  | 267,297 |  |  | 154,783 |
Other property and equipment |  | 33,795 |  |  | 30,691 |
Total property and equipment |  | 7,992,920 |  |  | 6,149,814 |
Accumulated depreciation, depletion and amortization |  | (3,985,613 | ) |  | (3,506,539 | )
Total property and equipment, net |  | 4,007,307 |  |  | 2,643,275 |
Other long-term assets: |  |  |  |
Restricted cash |  | 101,760 |  |  | — |
Assets from price risk management activities |  | 4,550 |  |  | 7,854 |
Equity method investments |  | 141,682 |  |  | 1,745 |
Other well equipment inventory |  | 44,643 |  |  | 25,541 |
Notes receivable, net |  | 15,805 |  |  | — |
Operating lease assets |  | 12,313 |  |  | 5,903 |
Other assets |  | 13,452 |  |  | 6,479 |
Total assets | $ | 4,753,100 |  | $ | 3,058,626 |
LIABILITIES AND STOCKHOLDERSʼ EQUITY |  |  |  |
Current liabilities: |  |  |  |
Accounts payable | $ | 125,557 |  | $ | 128,174 |
Accrued liabilities |  | 205,095 |  |  | 219,769 |
Accrued royalties |  | 54,092 |  |  | 52,215 |
Current portion of long-term debt |  | 33,109 |  |  | — |
Current portion of asset retirement obligations |  | 69,288 |  |  | 39,888 |
Liabilities from price risk management activities |  | 55,042 |  |  | 68,370 |
Accrued interest payable |  | 30,536 |  |  | 36,340 |
Current portion of operating lease liabilities |  | 2,859 |  |  | 1,943 |
Other current liabilities |  | 54,221 |  |  | 60,359 |
Total current liabilities |  | 629,799 |  |  | 607,058 |
Long-term liabilities: |  |  |  |
Long-term debt |  | 1,018,774 |  |  | 585,340 |
Asset retirement obligations |  | 747,560 |  |  | 501,773 |
Liabilities from price risk management activities |  | 8,981 |  |  | 7,872 |
Operating lease liabilities |  | 18,888 |  |  | 14,855 |
Other long-term liabilities |  | 267,036 |  |  | 176,152 |
Total liabilities |  | 2,691,038 |  |  | 1,893,050 |
Commitments and contingencies (Note 11) |  |  |  |
Stockholdersʼ equity: |  |  |  |
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of September 30, 2023 and December 31, 2022 |  | — |  |  | — |
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of September 30, 2023 and December 31, 2022, respectively |  | 1,275 |  |  | 826 |
Additional paid-in capital |  | 2,541,906 |  |  | 1,699,799 |
Accumulated deficit |  | (433,615 | ) |  | (535,049 | )
Treasury stock, at cost; 3,400,000 and zero shares as of September 30, 2023 and December 31, 2022, respectively |  | (47,504 | ) |  | — |
Total stockholdersʼ equity |  | 2,062,062 |  |  | 1,165,576 |
Total liabilities and stockholdersʼ equity | $ | 4,753,100 |  | $ | 3,058,626 |

See accompanying notes.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

| Three Months Ended September 30, |  | Nine Months Ended September 30, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Revenues: |  |  |  |  |  |  |  |
Oil | $ | 359,404 |  | $ | 295,585 |  | $ | 995,081 |  | $ | 1,078,800 |
Natural gas |  | 16,871 |  |  | 68,360 |  |  | 53,383 |  |  | 181,747 |
NGL |  | 6,860 |  |  | 13,183 |  |  | 24,463 |  |  | 49,232 |
Total revenues |  | 383,135 |  |  | 377,128 |  |  | 1,072,927 |  |  | 1,309,779 |
Operating expenses: |  |  |  |  |  |  |  |
Lease operating expense |  | 103,548 |  |  | 81,760 |  |  | 286,075 |  |  | 229,156 |
Production taxes |  | 600 |  |  | 955 |  |  | 1,813 |  |  | 2,670 |
Depreciation, depletion and amortization |  | 163,359 |  |  | 92,323 |  |  | 480,476 |  |  | 295,174 |
Accretion expense |  | 21,256 |  |  | 13,179 |  |  | 63,430 |  |  | 42,400 |
General and administrative expense |  | 24,888 |  |  | 25,289 |  |  | 121,257 |  |  | 70,742 |
Other operating (income) expense |  | (57,287 | ) |  | (366 | ) |  | (55,172 | ) |  | 12,142 |
Total operating expenses |  | 256,364 |  |  | 213,140 |  |  | 897,879 |  |  | 652,284 |
Operating income (expense) |  | 126,771 |  |  | 163,988 |  |  | 175,048 |  |  | 657,495 |
Interest expense |  | (45,637 | ) |  | (29,265 | ) |  | (128,850 | ) |  | (91,531 | )
Price risk management activities income (expense) |  | (98,802 | ) |  | 114,180 |  |  | (13,668 | ) |  | (231,133 | )
Equity method investment income (expense) |  | (2,493 | ) |  | 991 |  |  | 2,938 |  |  | 14,599 |
Other income (expense) |  | 2,193 |  |  | 692 |  |  | 10,450 |  |  | 31,991 |
Net income (loss) before income taxes |  | (17,968 | ) |  | 250,586 |  |  | 45,918 |  |  | 381,421 |
Income tax benefit (expense) |  | 15,865 |  |  | (121 | ) |  | 55,516 |  |  | (2,256 | )
Net income (loss) | $ | (2,103 | ) | $ | 250,465 |  | $ | 101,434 |  | $ | 379,165 |
Net income (loss) per common share: |  |  |  |  |  |  |  |
Basic | $ | (0.02 | ) | $ | 3.03 |  | $ | 0.86 |  | $ | 4.60 |
Diluted | $ | (0.02 | ) | $ | 2.99 |  | $ | 0.85 |  | $ | 4.54 |
Weighted average common shares outstanding: |  |  |  |  |  |  |  |
Basic |  | 124,103 |  |  | 82,576 |  |  | 118,459 |  |  | 82,406 |
Diluted |  | 124,103 |  |  | 83,818 |  |  | 119,262 |  |  | 83,438 |

See accompanying notes.

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TA LOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

| Common Stock |  | Additional Paid-In |  | Accumulated |  | Treasury Stock |  | Total Stockholdersʼ |
| Shares Issued |  | Par Value |  | Capital |  | Deficit |  | Shares |  | Amount |  | Equity |
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 (loss) |  | — |  |  | — |  |  | — |  |  | 250,465 |  |  | — |  |  | — |  |  | 250,465 |
Balance at September 30, 2022 |  | 82,570,328 |  | $ | 826 |  | $ | 1,692,316 |  | $ | (537,799 | ) |  | — |  | $ | — |  | $ | 1,155,343 |
Balance at June 30, 2023 |  | 127,455,965 |  | $ | 1,275 |  | $ | 2,539,629 |  | $ | (431,512 | ) |  | 3,400,000 |  | $ | (47,504 | ) | $ | 2,061,888 |
Equity-based compensation |  | — |  |  | — |  |  | 2,353 |  |  | — |  |  | — |  |  | — |  |  | 2,353 |
Equity-based compensation tax withholdings |  | — |  |  | — |  |  | (76 | ) |  | — |  |  | — |  |  | — |  |  | (76 | )
Equity-based compensation stock issuances |  | 24,396 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Net income (loss) |  | — |  |  | — |  |  | — |  |  | (2,103 | ) |  | — |  |  | — |  |  | (2,103 | )
Balance at September 30, 2023 |  | 127,480,361 |  | $ | 1,275 |  | $ | 2,541,906 |  | $ | (433,615 | ) |  | 3,400,000 |  | $ | (47,504 | ) | $ | 2,062,062 |

| Common Stock |  | Additional Paid-In |  | Accumulated |  | Treasury Stock |  | Total Stockholdersʼ |
| Shares Issued |  | Par Value |  | Capital |  | Deficit |  | Shares |  | Amount |  | Equity |
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 (loss) |  | — |  |  | — |  |  | — |  |  | 379,165 |  |  | — |  |  | — |  |  | 379,165 |
Balance at September 30, 2022 |  | 82,570,328 |  | $ | 826 |  | $ | 1,692,316 |  | $ | (537,799 | ) |  | — |  | $ | — |  | $ | 1,155,343 |
Balance at December 31, 2022 |  | 82,570,328 |  | $ | 826 |  | $ | 1,699,799 |  | $ | (535,049 | ) |  | — |  | $ | — |  | $ | 1,165,576 |
Equity-based compensation |  | — |  |  | — |  |  | 17,812 |  |  | — |  |  | — |  |  | — |  |  | 17,812 |
Equity-based compensation tax withholdings |  | — |  |  | — |  |  | (7,454 | ) |  | — |  |  | — |  |  | — |  |  | (7,454 | )
Equity-based compensation stock issuances |  | 1,110,143 |  |  | 11 |  |  | (11 | ) |  | — |  |  | — |  |  | — |  |  | — |
Issuance of common stock for acquisitions (Note 2) |  | 43,799,890 |  |  | 438 |  |  | 831,760 |  |  | — |  |  | — |  |  | — |  |  | 832,198 |
Purchase of treasury stock |  | — |  |  | — |  |  | — |  |  | — |  |  | 3,400,000 |  |  | (47,504 | ) |  | (47,504 | )
Net income (loss) |  | — |  |  | — |  |  | — |  |  | 101,434 |  |  | — |  |  | — |  |  | 101,434 |
Balance at September 30, 2023 |  | 127,480,361 |  | $ | 1,275 |  | $ | 2,541,906 |  | $ | (433,615 | ) |  | 3,400,000 |  | $ | (47,504 | ) | $ | 2,062,062 |

See accompanying notes.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

| Nine Months Ended September 30, |
| 2023 |  | 2022 |
Cash flows from operating activities: |  |  |  |
Net income (loss) | $ | 101,434 |  | $ | 379,165 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |
Depreciation, depletion, amortization and accretion expense |  | 543,906 |  |  | 337,574 |
Amortization of deferred financing costs and original issue discount |  | 11,247 |  |  | 10,614 |
Equity-based compensation expense |  | 9,080 |  |  | 11,677 |
Price risk management activities (income) expense |  | 13,668 |  |  | 231,133 |
Net cash received (paid) on settled derivative instruments |  | (10,474 | ) |  | (368,483 | )
Equity method investment (income) expense |  | (2,938 | ) |  | (14,599 | )
Settlement of asset retirement obligations |  | (71,097 | ) |  | (60,304 | )
(Gain) loss on sale of assets |  | (66,115 | ) |  | 390 |
Changes in operating assets and liabilities: |  |  |  |
Accounts receivable |  | 3,821 |  |  | 23,783 |
Other current assets |  | (12,992 | ) |  | (28,576 | )
Accounts payable |  | (30,063 | ) |  | 16,677 |
Other current liabilities |  | (89,511 | ) |  | (6,682 | )
Other non-current assets and liabilities, net |  | (57,155 | ) |  | 6,559 |
Net cash provided by (used in) operating activities |  | 342,811 |  |  | 538,928 |
Cash flows from investing activities: |  |  |  |
Exploration, development and other capital expenditures |  | (438,506 | ) |  | (209,592 | )
Proceeds from (cash paid for) acquisitions, net of cash acquired |  | 17,617 |  |  | (3,500 | )
Proceeds from (cash paid for) sale of property and equipment, net |  | 66,183 |  |  | 1,690 |
Contributions to equity method investees |  | (29,372 | ) |  | (2,250 | )
Proceeds from sale of equity method investments |  | — |  |  | 15,000 |
Investment in intangible assets |  | (7,796 | ) |  | — |
Net cash provided by (used in) investing activities |  | (391,874 | ) |  | (198,652 | )
Cash flows from financing activities: |  |  |  |
Redemption of senior notes |  | (15,000 | ) |  | (6,060 | )
Proceeds from Bank Credit Facility |  | 675,000 |  |  | 35,000 |
Repayment of Bank Credit Facility |  | (460,000 | ) |  | (350,000 | )
Deferred financing costs |  | (11,775 | ) |  | (211 | )
Other deferred payments |  | (841 | ) |  | — |
Payments of finance lease |  | (12,117 | ) |  | (19,764 | )
Purchase of treasury stock |  | (47,504 | ) |  | — |
Employee stock awards tax withholdings |  | (7,454 | ) |  | (4,603 | )
Net cash provided by (used in) financing activities |  | 120,309 |  |  | (345,638 | )
Net increase (decrease) in cash, cash equivalents and restricted cash |  | 71,246 |  |  | (5,362 | )
Cash, cash equivalents and restricted cash: |  |  |  |
Balance, beginning of period |  | 44,145 |  |  | 69,852 |
Balance, end of period | $ | 115,391 |  | $ | 64,490 |
Supplemental non-cash transactions: |  |  |  |
Capital expenditures included in accounts payable and accrued liabilities | $ | 90,688 |  | $ | 78,191 |
Supplemental cash flow information: |  |  |  |
Interest paid, net of amounts capitalized | $ | 108,931 |  | $ | 89,187 |

See accompanying notes.

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TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2023

(Unaudited)

Not e 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. 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 (“Upstream”) and the development of low carbon solutions opportunities. The Company leverages decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. The Company is also utilizing its expertise to develop CCS projects to help reduce industrial emissions 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 2022 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.

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 5 — Financial Instruments) and indentures governing the senior notes. See additional information in Note 12 — Segment Information.

Summary of Significant Accounting Policies

The Company has provided a discussion of its significant accounting policies, estimates and judgments in Note 2 – Summary of Significant Accounting Policies included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report. The Company has not changed any of its significant accounting policies from those described in our 2022 Annual Report except as set forth below.

Restricted Cash — Any cash that is legally restricted from use is classified as restricted cash. If the purpose of restricted cash relates to acquiring a long-term asset, liquidating a long-term liability, or is otherwise unavailable for a period longer than one year from the balance sheet date, the restricted cash is included in other long-term assets. Otherwise, restricted cash is included in other current assets in the Condensed Consolidated Balance Sheets. The Company acquired funds held in escrow to be used for future plugging and abandonment (“P&A”) obligations assumed through the EnVen Acquisition (as defined in Note 2 — Acquisitions and Divestitures). These escrow accounts required deposits of approximately $100.0 million, which was fully funded by EnVen (as defined in Note 2 — Acquisitions and Divestitures) prior to the consummation of the acquisition. This is reflected as “Restricted cash” within “Other long-term assets” on the Condensed Consolidated Balance Sheets.

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Notes Receivable, net — The Company holds two notes receivable with an aggregate face value of $66.2 million acquired by the Company as part of the EnVen Acquisition (as defined herein), which consist of commitments from the sellers of oil and natural gas properties related to the costs associated with P&A obligations (the “P&A Notes Receivable”). The P&A Notes Receivable are being accreted to their principal amounts and are presented as such, net of the related cumulative estimated credit losses, on the accompanying Condensed Consolidated Balance Sheets. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.”

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of the amount of cash, cash equivalents and restricted cash reported within the Condensed Consolidated Balance Sheets to the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands):

| September 30, 2023 |  | December 31, 2022 |
Cash and cash equivalents | $ | 13,631 |  | $ | 44,145 |
Restricted cash included in Other long-term assets |  | 101,760 |  |  | — |
Total cash, cash equivalent and restricted cash | $ | 115,391 |  | $ | 44,145 |

Note 2 — Acquisitions and Divestitures

Acquisitions — Business Combinations

Acquisitions qualifying as business combinations are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the Consolidated Balance Sheets at their fair values as of the acquisition date.

EnVen Acquisition — On September 21, 2022, the Company executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). On February 13, 2023, the Company completed the EnVen Acquisition for consideration consisting of (i) $207.3 million in cash, (ii) 43.8 million shares of the Company’s common stock valued at $832.2 million and (iii) the effective settlement of an accounts receivable balance of $8.4 million. No gain or loss was recognized on settlement as the payable was effectively settled at the recorded amount. The cash payment was partially funded with borrowings under the Bank Credit Facility.

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

Talos common stock |  | 43,799,890 |
Talos common stock price per share(1) | $ | 19.00 |
Common stock value | $ | 832,198 |
Cash consideration | $ | 207,313 |
Settlement of preexisting relationship | $ | 8,388 |
Total purchase price | $ | 1,047,899 |

(1)
Represents the closing price of the Company’s common stock on February 13, 2023, the date of the closing of the EnVen Acquisition.

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The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on February 13, 2023 (in thousands):

Current assets | $ | 238,293 |
Property and equipment |  | 1,459,916 |
Other long-term assets: |  |
Restricted cash |  | 100,753 |
Notes receivable, net |  | 14,844 |
Other long-term assets |  | 48,899 |
Current liabilities: |  |
Current portion of long-term debt |  | (33,234 | )
Current portion of asset retirement obligations |  | (7,079 | )
Other current liabilities |  | (123,399 | )
Long-term liabilities: |  |
Long-term debt |  | (233,836 | )
Asset retirement obligations |  | (251,779 | )
Deferred tax liabilities |  | (150,504 | )
Other long-term liabilities |  | (14,975 | )
Allocated purchase price | $ | 1,047,899 |

The fair values determined for accounts receivable, accounts payable and other current assets and most current liabilities were equivalent to the carrying value due to their short-term nature. Assumed debt was valued based on observable market prices.

The fair value of proved oil and natural gas properties as of the acquisition date is based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows incorporating market participant assumptions. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments were applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class. These inputs are classified as Level 3 unobservable inputs, including the underlying commodity price assumptions which are based on the five-year NYMEX forward strip prices, escalated for inflation thereafter, and adjusted for price differentials.

The fair value of asset retirement obligations is determined by calculating the present value of estimated future cash flows related to the liabilities. The Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate.

The Company is still finalizing the fair value analysis related to the oil and natural gas properties acquired, asset retirement obligations assumed, certain contingencies and recognized deferred tax liabilities arising from the assets acquired and liabilities assumed. The Company anticipates finalizing the determination of fair values by December 31, 2023.

The Company incurred approximately $21.8 million of acquisition-related costs in connection with the EnVen Acquisition exclusive of severance expense, of which $12.8 million was recognized during the nine months ended September 30, 2023 and $9.0 million was recognized during the year ended December 31, 2022 and reflected in general and administrative expense on the Condensed Consolidated Statements of Operations. Additionally, the Company incurred $0.9 million and $24.9 million in severance expense in connection with the EnVen Acquisition for the three and nine months ended September 30, 2023, respectively. See Note 7 — Employee Benefits Plans and Share-Based Compensation for additional discussion.

The following table presents revenue and net income (loss) attributable to the EnVen Acquisition for the three months ended September 30, 2023 and the period from February 13, 2023 to September 30, 2023 (in thousands):

| Three Months Ended September 30, 2023 |  | Nine Months Ended September 30, 2023 |
Revenue | $ | 126,358 |  | $ | 301,999 |
Net income (loss) | $ | 37,790 |  | $ | 57,578 |

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Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three and nine months ended September 30, 2023 and 2022 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma information was derived from historical statements of operations of the Company and EnVen adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and to adjust the amortization of the premium of the 11.75% Notes (as defined in Note 6 — Debt), (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) other income (expense) to adjust the accretion of the discount on the P&A Notes Receivable and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for the three and nine months ended September 30, 2022 were adjusted to exclude $8.6 million and include $71.1 million of general and administrative expenses, respectively, of which $16.3 million were incurred during the year ended December 31, 2022. Supplemental pro forma earnings for the three and nine months ended September 30, 2023 were adjusted to exclude $0.8 million and $64.9 million of general and administrative expenses, respectively. This information does not purport to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data).

| Three Months Ended September 30, |  | Nine Months Ended September 30, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Revenue | $ | 383,136 |  | $ | 552,168 |  | $ | 1,124,970 |  | $ | 1,888,702 |
Net income (loss) | $ | (1,483 | ) | $ | 334,368 |  | $ | 131,421 |  | $ | 404,026 |
Basic net income (loss) per common share | $ | (0.01 | ) | $ | 2.65 |  | $ | 1.05 |  | $ | 3.20 |
Diluted net income (loss) per common share | $ | (0.01 | ) | $ | 2.62 |  | $ | 1.04 |  | $ | 3.18 |

Divestiture

Mexico Divestiture — On September 27, 2023, the Company closed the sale of a 49.9% equity interest in its subsidiary, Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”) to Zamajal, S.A. de C.V, a wholly owned subsidiary of Grupo Carso, for $74.9 million in cash consideration with an additional $49.9 million contingent on first oil production from the Zama Field (the “Mexico Divestiture”). The contingent consideration will be recognized when regular commercial production from the Zama Field becomes probable. Talos Mexico, through its wholly owned subsidiary, holds a 17.4% unitized interest in the Zama Field.

As a result of the Mexico Divestiture, Talos Mexico was deconsolidated on September 27, 2023 and is now accounted for as an equity method investment. Total assets derecognized included $112.3 million of unproved properties associated with exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. The fair value of the Company’s retained equity method investment in Talos Mexico was $107.6 million. The determination of fair value was based on the implied fair value of Talos Mexico. The implied fair value of Talos Mexico was based on the transaction price of the Mexico Divestiture, which was an orderly transaction between market participants. A gain of $66.2 million was recognized on the Mexico Divestiture during the three and nine months ended September 30, 2023 which is included in “Other operating (income) expense” on the Condensed Consolidated Statements of Operations.

Talos Mexico is a variable interest entity (“VIE”) because its total equity at risk is not sufficient to finance its activities without additional subordinated financial support. Based on the ownership and governance structure of Talos Mexico, the Company is not the primary beneficiary of this VIE. The Company does not have the unilateral power to direct the most significant activities of Talos Mexico.

Note 3 — Property, Plant and Equipment

Proved Properties

During the three and nine months ended September 30, 2023 and 2022, the Company’s ceiling test computations did no t result in a write-down of its U.S. oil and natural gas properties. At September 30, 2023, the Company’s ceiling test computation was based on SEC pricing of $80.46 per Bbl of oil, $3.58 per Mcf of natural gas and $20.44 per Bbl of NGLs.

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Asset Retirement Obligations

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

Asset retirement obligations at December 31, 2022 | $ | 541,661 |
Obligations assumed(1) |  | 258,858 |
Obligations incurred |  | 297 |
Obligations settled |  | (71,097 | )
Obligations divested |  | (19,417 | )
Accretion expense |  | 63,430 |
Changes in estimate |  | 43,116 |
Asset retirement obligations at September 30, 2023 | $ | 816,848 |
Less: Current portion at September 30, 2023 |  | 69,288 |
Long-term portion at September 30, 2023 | $ | 747,560 |

(1)
Assumed in connection with the EnVen Acquisition. See further discussion in Note 2 — Acquisitions and Divestitures.

At September 30, 2023, the Company has (1) restricted cash of $101.8 million inclusive of interest earned to date, held in escrow and (2) the P&A Notes Receivable of $15.8 million to settle future asset retirement obligations. These assets are discussed in Note 1 — Organization, Nature of Business and Basis of Presentation. During the three and nine months ended September 30, 2023, the Company recognized interest income of $0.4 million and $1.0 million, respectively, related to the P&A Notes Receivable.

Note 4 — Leases

The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Additionally, the Company has a finance lease related to the use of the Helix Producer I (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized.

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

| Three Months Ended September 30, |  | Nine Months Ended September 30, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Finance lease cost - interest on lease liabilities | $ | 3,604 |  | $ | 1,386 |  | $ | 10,969 |  | $ | 5,179 |
Operating lease cost, excluding short-term leases(1) |  | 1,323 |  |  | 568 |  |  | 3,419 |  |  | 1,703 |
Short-term lease cost(2) |  | 33,152 |  |  | 12,982 |  |  | 103,001 |  |  | 24,838 |
Variable lease cost(3) |  | 666 |  |  | 363 |  |  | 1,856 |  |  | 1,088 |
Variable and fixed sublease income |  | (207 | ) |  | — |  |  | (276 | ) |  | — |
Total lease cost | $ | 38,538 |  | $ | 15,299 |  | $ | 118,969 |  | $ | 32,808 |

(1)
Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.
(2)
Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the Condensed Consolidated Balance Sheets.
(3)
Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

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The present value of the fixed lease payments recorded as the Company’s right-of-use (“ROU”) assets and lease liabilities, adjusted for initial direct costs and incentives were as follows (in thousands):

| September 30, 2023 |  | December 31, 2022 |
Operating leases: |  |  |  |
Operating lease assets | $ | 12,313 |  | $ | 5,903 |
Current portion of operating lease liabilities | $ | 2,859 |  | $ | 1,943 |
Operating lease liabilities |  | 18,888 |  |  | 14,855 |
Total operating lease liabilities | $ | 21,747 |  | $ | 16,798 |
Finance leases: |  |  |  |
Proved properties | $ | 166,261 |  | $ | 166,261 |
Other current liabilities | $ | 17,426 |  | $ | 16,306 |
Other long-term liabilities |  | 135,826 |  |  | 149,064 |
Total finance lease liabilities | $ | 153,252 |  | $ | 165,370 |

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

| Nine Months Ended September 30, |
| 2023 |  | 2022 |
Operating cash outflow from finance leases | $ | 10,969 |  | $ | 5,179 |
Operating cash outflow from operating leases | $ | 4,880 |  | $ | 2,776 |
ROU assets obtained in exchange for new operating lease liabilities(1) | $ | 12,971 |  | $ | — |
Remeasurement of lease liability arising from modification of ROU asset(2) | $ | (5,124 | ) | $ | — |

(1)
See EnVen Acquisition in Note 2 — Acquisitions and Divestitures.
(2)
Lease termination accounted for as a lease modification based on the modified lease term. The termination did not take effect contemporaneously with the effective date of the modification.

Note 5 — Financial Instruments

As of September 30, 2023 and December 31, 2022, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because they are highly liquid or due to the short-term nature of these instruments.

Debt Instruments

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

| September 30, 2023 |  | December 31, 2022 |
| Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value |
12.00% Second-Priority Senior Secured Notes – due January 2026 | $ | 597,544 |  | $ | 664,523 |  | $ | 590,132 |  | $ | 674,542 |
11.75% Senior Secured Second Lien Notes – due April 2026(1) | $ | 250,006 |  | $ | 248,723 |  | $ | — |  | $ | — |
Bank Credit Facility – matures March 2027 | $ | 204,333 |  | $ | 215,000 |  | $ | (4,792 | ) | $ | — |

(1)
Assumed in connection with the EnVen Acquisition. See further discussion in Note 6 — Debt.

The carrying value of the senior notes are adjusted for discount, premium and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

The carrying amount of the Company’s bank credit facility, as amended and restated (the “Bank Credit Facility”), is presented net of deferred financing costs. The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).

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Oil and Natural Gas Derivatives

The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production. 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. Typical collar contracts 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 (“two-way collar”).

In connection with the EnVen Acquisition, the Company assumed oil and natural gas collar contracts that combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these contracts, when the NYMEX average closing price is below the floor price, the Company receives the difference between the NYMEX average closing price and the floor price, capped at the difference between the floor price and the short put 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, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Net cash received (paid) on settled derivative instruments | $ | (6,313 | ) | $ | (81,162 | ) | $ | (10,474 | ) | $ | (368,483 | )
Unrealized gain (loss)(1) |  | (92,489 | ) |  | 195,342 |  |  | (3,194 | ) |  | 137,350 |
Price risk management activities income (expense) | $ | (98,802 | ) | $ | 114,180 |  | $ | (13,668 | ) | $ | (231,133 | )

(1)
Includes $1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the nine months ended September 30, 2023.

The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of September 30, 2023:

Swap Contracts |
Production Period | Settlement Index | Volumes |  | Swap Price |
Crude oil: |  | (Bbls) |  | (per Bbl) |
October 2023 – December 2023 | NYMEX WTI CMA |  | 12,000 |  | $ | 75.25 |
January 2024 – December 2024 | NYMEX WTI CMA |  | 16,105 |  | $ | 74.37 |
January 2025 – December 2025 | NYMEX WTI CMA |  | 6,986 |  | $ | 74.11 |
Natural gas: |  | (MMBtu) |  | (per MMBtu) |
October 2023 – December 2023 | NYMEX Henry Hub |  | 20,000 |  | $ | 4.22 |
January 2024 – December 2024 | NYMEX Henry Hub |  | 17,459 |  | $ | 3.44 |
January 2025 – December 2025 | NYMEX Henry Hub |  | 12,466 |  | $ | 4.00 |

Two-Way Collar Contracts |
Production Period | Settlement Index | Volumes |  | Floor Price |  | Ceiling Price |
Crude oil: |  | (Bbls) |  | (per Bbl) |  | (per Bbl) |
October 2023 – December 2023 | NYMEX WTI CMA |  | 7,826 |  | $ | 67.76 |  | $ | 86.39 |
January 2024 – December 2024 | NYMEX WTI CMA |  | 1,497 |  | $ | 70.00 |  | $ | 79.32 |
Natural gas: |  | (MMBtu) |  | (per MMBtu) |  | (per MMBtu) |
October 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 |

Three-Way Collar Contracts |
Production Period | Settlement Index | Volumes |  | Short Put Price |  | Floor Price |  | Ceiling Price |
Crude oil: |  | (Bbls) |  | (per Bbl) |  | (per Bbl) |  | (per Bbl) |
October 2023 – December 2023 | NYMEX WTI CMA |  | 9,200 |  | $ | 51.86 |  | $ | 65.11 |  | $ | 109.25 |
January 2024 – March 2024 | NYMEX WTI CMA |  | 3,200 |  | $ | 57.27 |  | $ | 70.00 |  | $ | 98.01 |

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

| September 30, 2023 |
| Level 1 |  | Level 2 |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |
Oil and natural gas derivatives | $ | — |  | $ | 16,047 |  | $ | — |  | $ | 16,047 |
Liabilities: |  |  |  |  |  |  |  |
Oil and natural gas derivatives |  | — |  |  | (64,023 | ) |  | — |  |  | (64,023 | )
Total net asset (liability) | $ | — |  | $ | (47,976 | ) | $ | — |  | $ | (47,976 | )

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| December 31, 2022 |
| Level 1 |  | Level 2 |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |
Oil and natural gas derivatives | $ | — |  | $ | 32,883 |  | $ | — |  | $ | 32,883 |
Liabilities: |  |  |  |  |  |  |  |
Oil and natural gas derivatives |  | — |  |  | (76,242 | ) |  | — |  |  | (76,242 | )
Total net asset (liability) | $ | — |  | $ | (43,359 | ) | $ | — |  | $ | (43,359 | )

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, 2023 |  | December 31, 2022 |
| Assets |  | Liabilities |  | Assets |  | Liabilities |
Oil and natural gas derivatives: |  |  |  |  |  |  |  |
Current | $ | 11,497 |  | $ | 55,042 |  | $ | 25,029 |  | $ | 68,370 |
Non-current |  | 4,550 |  |  | 8,981 |  |  | 7,854 |  |  | 7,872 |
Total gross amounts presented on balance sheet |  | 16,047 |  |  | 64,023 |  |  | 32,883 |  |  | 76,242 |
Less: Gross amounts not offset on the balance sheet |  | 16,047 |  |  | 16,047 |  |  | 32,883 |  |  | 32,883 |
Net amounts | $ | — |  | $ | 47,976 |  | $ | — |  | $ | 43,359 |

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, 2023 represent derivative instruments from nine counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and eight of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities.

Note 6 — Debt

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

| September 30, 2023 |  | December 31, 2022 |
12.00% Second-Priority Senior Secured Notes – due January 2026 | $ | 638,541 |  | $ | 638,541 |
11.75% Senior Secured Second Lien Notes – due April 2026 |  | 242,500 |  |  | — |
Bank Credit Facility – matures March 2027(1) |  | 215,000 |  |  | — |
Total debt, before discount, premium and deferred financing cost |  | 1,096,041 |  |  | 638,541 |
Unamortized discount, premium and deferred financing cost, net |  | (44,158 | ) |  | (53,201 | )
Total debt(2) |  | 1,051,883 |  |  | 585,340 |
Less: Current portion of long-term debt |  | 33,109 |  |  | — |
Long-term debt | $ | 1,018,774 |  | $ | 585,340 |

(1)
As of September 30, 2023, the Company had outstanding borrowings at a weighted average interest rate of 8.42%.
(2)
At September 30, 2023, the Company was in compliance with all debt covenants.

11.75% Senior Secured Second Lien Notes

On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount of $257.5 million. The 11.75% Notes mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.

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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 December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027 and includes a springing maturity commencing on the 91 st day prior to the earliest stated maturity date of any of the junior lien notes if such junior lien notes have not been refinanced, redeemed or repaid in full, (ii) increased the borrowing base from $1.1 billion to $1.5 billion and (iii) increased commitments from $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report. On June 9, 2023, the borrowing base decreased from $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million as part of the most recent biannual redetermination.

Note 7 — Employee Benefits Plans and Share-Based Compensation

EnVen Acquisition Severance

The following table summarizes severance accrual activity in connection the EnVen Acquisition included in “Other current liabilities” and “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of September 30, 2023 (in thousands):

Severance accrual at December 31, 2022 | $ | — |
Accrual additions |  | 24,904 |
Benefit payments |  | (13,915 | )
Severance accrual at September 30, 2023 |  | 10,989 |
Less: Current portion at September 30, 2023 |  | 10,842 |
Long-term portion at September 30, 2023 | $ | 147 |

The above table includes involuntary termination benefits that are being provided pursuant to a one-time benefit arrangement that is being spread over the future service period through the termination date. Involuntary termination benefits are also being provided pursuant to contractual termination benefits required by the terms of existing employment agreements. Pursuant to the EnVen Merger Agreement, a rabbi trust was established and funded with $14.5 million at closing to pay a portion of future severance benefits associated with the contractual termination benefits. As of September 30, 2023, the rabbi trust held $6.5 million in assets of which $6.2 million and $0.3 million are included in “Other current assets” and “Other assets,” respectively, on the Condensed Consolidated Balance Sheets and both of which are included in the severance accrual at September 30, 2023 listed above. The assets of the rabbi trust are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Severance costs are reflected in “General and administrative expense” on the Condensed Consolidated Statements of Operations.

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, 2023:

| RSUs |  | Weighted Average Grant Date Fair Value |
Unvested RSUs at December 31, 2022 |  | 3,215,504 |  | $ | 12.79 |
Granted |  | 1,153,580 |  | $ | 16.24 |
Vested |  | (1,644,828 | ) | $ | 12.06 |
Forfeited |  | (277,400 | ) | $ | 14.07 |
Unvested RSUs at September 30, 2023(1) |  | 2,446,856 |  | $ | 14.77 |

(1)
As of September 30, 2023, 26,975 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Condensed Consolidated Balance Sheets.

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Performance Share Units (“PSUs”) — The following table summarizes PSU activity under the 2021 LTIP for the nine months ended September 30, 2023:

| PSUs |  | Weighted Average Grant Date Fair Value |
Unvested PSUs at December 31, 2022 |  | 638,601 |  | $ | 23.66 |
Granted(1) |  | 593,472 |  | $ | 18.78 |
Forfeited |  | (147,286 | ) | $ | 21.47 |
Unvested PSUs at September 30, 2023 |  | 1,084,787 |  | $ | 21.29 |

(1)
There were 296,736 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 296,736 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.

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:

| 2023 |
| Grant |  | Grant |
| July 1 |  | March 5 |
Expected term (in years) |  | 2.5 |  |  | 2.8 |
Expected volatility |  | 66.2 | % |  | 73.1 | %
Risk-free interest rate |  | 4.6 | % |  | 4.5 | %
Dividend yield |  | — | % |  | — | %
Fair value (in thousands) | $ | 173 |  | $ | 6,165 |

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, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Share-based compensation costs | $ | 2,556 |  | $ | 7,626 |  | $ | 18,038 |  | $ | 20,597 |
Less: Amounts capitalized to oil and gas properties |  | 2,163 |  |  | 3,316 |  |  | 8,958 |  |  | 8,920 |
Total share-based compensation expense | $ | 393 |  | $ | 4,310 |  | $ | 9,080 |  | $ | 11,677 |

Note 8 — Income Taxes

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

For the three months ended September 30, 2023, the Company recognized an income tax benefit of $15.9 million for an effective tax rate of 88.3%. The Company’s effective tax rate of 88.3% is different than the U.S. federal statutory income tax rate of 21% primarily due to the change of its valuation allowance on its federal deferred tax assets. 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 nine months ended September 30, 2023, the Company recognized an income tax benefit of $55.5 million for an effective tax rate of -120.9%. The Company’s effective tax rate of -120.9% is different than the U.S. federal statutory income tax rate of 21% primarily due to a non-cash benefit discrete item of $54.9 million related to the partial release of its valuation allowance on its federal deferred tax assets not subject to separate return limitations offset by the impact of other permanent differences. The release of the valuation allowance is a result of the deferred tax liabilities acquired with the EnVen Acquisition. For the nine months ended September 30, 2022, the Company recognized an 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.

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

Deferred income tax assets and liabilities are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce deductions and income in the future. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. 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. 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. The Company maintains a partial valuation allowance against certain federal deferred tax assets in which it is more likely than not such assets will not be realized in a future period. The Company also maintains a partial valuation allowance against its federal net deferred tax assets subject to separate return limitations, its state net deferred tax assets and its foreign net deferred tax assets. A deferred tax liability of $96.6 million and $2.1 million is included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of September 30, 2023 and December 31, 2022, respectively.

EnVen Acquisition

On February 13, 2023, the Company completed the EnVen Acquisition, which is further discussed in Note 2 — Acquisitions and Divestitures. The Company recognized a net deferred tax liability of $150.5 million in its purchase price allocation as of the acquisition date to reflect differences between tax basis and the fair value of EnVen’s assets acquired and liabilities assumed. The deferred tax balance is based on preliminary calculations and on information available to management at the time such estimates were made. Further analysis will be made upon filing EnVen’s tax returns that will result in a change to the net deferred tax impact recorded.

Note 9 — Income (Loss) Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs and PSUs.

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, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Net income (loss) | $ | (2,103 | ) | $ | 250,465 |  | $ | 101,434 |  | $ | 379,165 |
Weighted average common shares outstanding — basic |  | 124,103 |  |  | 82,576 |  |  | 118,459 |  |  | 82,406 |
Dilutive effect of securities |  | — |  |  | 1,242 |  |  | 803 |  |  | 1,032 |
Weighted average common shares outstanding — diluted |  | 124,103 |  |  | 83,818 |  |  | 119,262 |  |  | 83,438 |
Net income (loss) per common share: |  |  |  |  |  |  |  |
Basic | $ | (0.02 | ) | $ | 3.03 |  | $ | 0.86 |  | $ | 4.60 |
Diluted | $ | (0.02 | ) | $ | 2.99 |  | $ | 0.85 |  | $ | 4.54 |
Anti-dilutive potentially issuable securities excluded from diluted common shares |  | 1,851 |  |  | 120 |  |  | 1,491 |  |  | 1,149 |

Note 10 — 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. On July 5, 2023, the Riverstone Funds ceased being a beneficial owner of more than five percent of the Company’s common stock.

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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 2022 Annual Report. Effective July 5, 2023, the Registration Rights Agreement terminated as there are no Registrable Securities (defined therein) outstanding.

Adage Capital Partners, L.P. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”) are parties to a registration rights agreement entered into in connection with the EnVen Acquisition 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 2022 Annual Report. Adage and Bain held approximately 5.2% and 12.2%, respectively, of the Company’s outstanding shares of common stock as of September 30, 2023 based on SEC beneficial ownership reports filed by each of Adage and Bain.

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, 2023 and 2022, the Company did no t incur any such fees.

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”). On March 29, 2022, the Company and other parties thereto, entered into the Amended and Restated Stockholders’ Agreement, in connection with the termination of the Apollo Funds’ rights thereunder and the resignation of certain members of the Company's Board of Directors (the “Amended and Restated Stockholders’ Agreement”). A discussion of the Stockholders’ Agreement Amendment is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.

On February 13, 2023, in connection with the EnVen Acquisition, the Amended and Restated Stockholders’ Agreement was terminated and Mr. Robert M. Tichio resigned from the Company’s Board of Directors.

Riverstone Funds Support Agreement

On February 13, 2023, in connection with the EnVen Acquisition, the Company, EnVen and the Riverstone Funds entered into a support agreement, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at V&E. For the three and nine months ended September 30, 2023, the Company incurred fees for legal services performed by V&E of approximately $0.1 million and $2.2 million, respectively, of which $0.4 million was payable for legal services performed by 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 for legal services performed by V&E.

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 CCS LLC (“Bayou Bend”). Bayou Bend has a CCS site that is in the early stages of development located offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. 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. The Company recognized a $13.9 million gain on the partial sale of its investment in Bayou Bend during the nine months ended September 30, 2022, which is included in “Equity method investments income (expense)” on the Condensed Consolidated Statements of Operations. Chevron also agreed to fund up to $10.0 million of contributions to Bayou Bend on the Company’s behalf, which was fully funded during the first quarter of 2023. The Bayou Bend investment was increased with an offsetting gain as the capital carry was funded by Chevron. The Company recognized an $8.6 million gain during the nine months ended September 30, 2023 and a $1.4 million gain during the three and nine months ended September 30, 2022 on the funding of the capital carry of its investment in Bayou Bend. This is included in “Equity method investment income (expense)” on the Condensed Consolidated Statements of Operations.

Effective March 1, 2023, Chevron became the operator of Bayou Bend. The Company had a $0.4 million related party receivable from Bayou Bend as of September 30, 2023. This is reflected as “Other, net” within “Accounts receivable” on the Condensed Consolidated Balance Sheets. During March 2023, Bayou Bend expanded its storage footprint through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located within the Houston Ship Channel, Beaumont and Port Arthur region.

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As of September 30, 2023, the Company owns a 25% membership interest in Bayou Bend, which is a VIE and accounted for using the equity method of accounting. 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.

Coastal Bend CCS LLC

As of September 30, 2023, the Company owns a 50% membership interest in Coastal Bend CCS LLC (“Coastal Bend”), which is a VIE and accounted for using the equity method of accounting. Coastal Bend has a CCS point source project site at the Port of Corpus Christi that is in the early stages of development. The development of the Coastal Bend point source project is currently being financed through equity contributions from its members. The Company’s maximum exposure to loss as a result of its involvement with Coastal Bend is the carrying amount of its investment. The Company had a $4.2 million related party receivable from Coastal Bend as of September 30, 2023. This is reflected as “Other, net” within “Accounts receivable” on the Condensed Consolidated Balance Sheets.

Talos Mexico

As of September 30, 2023, the Company owns a 50.1% equity interest in Talos Mexico (see Note 2 - Acquisitions and Divestitures for additional information). The Company had a $0.3 million related party receivable from Talos Mexico as of September 30, 2023. This is reflected as “Other, net” within “Accounts receivable” on the Condensed Consolidated Balance Sheets. The Company’s maximum exposure to loss as a result of its involvement with Talos Mexico is the carrying amount of its investment.

Note 11 — 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.

As of September 30, 2023, the Company had secured performance bonds from third party sureties totaling $1.4 billion. The cost of securing these bonds is reflected as “Interest expense” on the Condensed Consolidated Statements of Operations. Additionally, as of September 30, 2023, the Company had secured letters of credit issued under its Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Note 6 — 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.

The following proceedings represent previous EnVen litigation that was assumed as part of the EnVen Acquisition.

In June 2019, David M. Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favor of Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of Appeal in December 2021. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supreme Court on August 2, 2023. As of September 30, 2023, the Company has recorded $14.1 million as “Other current liabilities” on the Condensed Consolidated Balance Sheets related to the litigation.

In July 2019, EnVen filed a lawsuit against Mr. Dunwoody in Delaware Chancery Court for breach of fiduciary duty and equitable fraud relating to Mr. Dunwoody’s conduct while he was President of EnVen. In January 2020, EnVen filed an amended complaint that added claims against Oilfield Pipe of Texas, LLC for aiding and abetting Mr. Dunwoody’s breach of his fiduciary duty and equitable fraud. On April 21, 2022, the Delaware Chancery Court denied Mr. Dunwoody’s renewed motion to dismiss the suit. The trial was held in the Delaware Chancery Court in late July 2023. The Company agreed to dismiss the litigation with prejudice on September 14, 2023.

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Decommissioning Obligations

The Company, as a co-lessee or predecessor-in-interest in oil and natural gas leases located in the U.S. Gulf of Mexico, is in the chain of title with unrelated third parties either directly or by virtue of divestiture of certain oil and natural gas assets previously owned and assigned by our subsidiaries. Certain 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. Regulations or federal laws could require the Company to assume such obligations. The Company reflects such costs as “Other operating (income) expense” on the Condensed Consolidated Statements of Operations.

The decommissioning obligations are included in the Condensed Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities” and the changes in that liability were as follows (in thousands):

| September 30, 2023 |  | December 31, 2022 |
Balance, beginning of period | $ | 54,269 |  | $ | 24,336 |
Additions |  | 266 |  |  | 8,900 |
Changes in estimate |  | 9,188 |  |  | 22,658 |
Settlements |  | (40,415 | ) |  | (1,625 | )
Balance, end of period | $ | 23,308 |  | $ | 54,269 |
Less: Current portion |  | 7,200 |  |  | 42,069 |
Long-term portion | $ | 16,108 |  | $ | 12,200 |

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.

Note 12 — Segment Information

The Company’s operations are managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The Upstream Segment is the Company’s only reportable segment. The Company’s chief operating decision-maker (“CODM”) is the President and Chief Executive Officer, who reviews operating results to make decisions about allocating resources and assessing performance for the entire company. A reportable segment is an operating segment that meets materiality thresholds. The 10% tests, as prescribed by the segment reporting accounting guidance, are based on the reported measures of revenue, profit, and assets that are used by the CODM to assess performance and allocate resources. The CCS Segment currently does not meet any of the reportable segment quantitative thresholds. The profit or loss metric used to evaluate segment performance is Adjusted EBITDA, which is defined by the Company as net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion, and amortization; accretion expense; non-cash write-down of oil and natural gas properties; transaction and other (income) expenses; decommissioning obligations; 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.

Corporate general and administrative expense include certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each of operating segment. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment. The remaining expenses are included in the reconciliation of reportable segment Adjusted EBITDA to consolidated pre-tax net income (loss) as an unallocated corporate general and administrative expense. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.

The Company’s CODM does not review assets by segment as part of the financial information provided and therefore, no asset information is provided in the table below.

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The following table presents selected segment information for the periods indicated (in thousands):

| Upstream |  | All Other(1) |  | Total |
Revenues from External Customers: |  |  |  |  |  |
Three Months Ended September 30, 2023 | $ | 383,135 |  | $ | — |  | $ | 383,135 |
Three Months Ended September 30, 2022 |  | 377,128 |  |  | — |  |  | 377,128 |
Nine Months Ended September 30, 2023 |  | 1,072,927 |  |  | — |  |  | 1,072,927 |
Nine Months Ended September 30, 2022 |  | 1,309,779 |  |  | — |  |  | 1,309,779 |
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method: |  |  |  |  |  |
Three Months Ended September 30, 2023 | $ | 118 |  | $ | (2,612 | ) | $ | (2,494 | )
Three Months Ended September 30, 2022 |  | 75 |  |  | (497 | ) |  | (422 | )
Nine Months Ended September 30, 2023 |  | 373 |  |  | (6,023 | ) |  | (5,650 | )
Nine Months Ended September 30, 2022 |  | 5 |  |  | (694 | ) |  | (689 | )
Adjusted EBITDA: |  |  |  |  |  |
Three Months Ended September 30, 2023 | $ | 255,228 |  | $ | (5,045 | ) | $ | 250,183 |
Three Months Ended September 30, 2022 |  | 199,675 |  |  | (715 | ) |  | 198,960 |
Nine Months Ended September 30, 2023 |  | 719,326 |  |  | (13,562 | ) |  | 705,764 |
Nine Months Ended September 30, 2022 |  | 669,103 |  |  | (8,659 | ) |  | 660,444 |
Segment Expenditures: |  |  |  |  |  |
Nine Months Ended September 30, 2023 | $ | 559,873 |  | $ | 37,183 |  | $ | 597,056 |
Nine Months Ended September 30, 2022 |  | 297,486 |  |  | 2,027 |  |  | 299,513 |

(1)
The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

Reconciliations

The following table presents the reconciliation of Adjusted EBITDA to the Company’s consolidated totals (in thousands):

| Three Months Ended September 30, |  | Nine Months Ended September 30, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Adjusted EBITDA: |  |  |  |  |  |  |  |
Total for reportable segments | $ | 255,228 |  | $ | 199,675 |  | $ | 719,326 |  | $ | 669,103 |
All other |  | (5,045 | ) |  | (715 | ) |  | (13,562 | ) |  | (8,659 | )
Unallocated corporate general and administrative expense |  | (1,366 | ) |  | (1,400 | ) |  | (4,161 | ) |  | (3,894 | )
Interest expense |  | (45,637 | ) |  | (29,265 | ) |  | (128,850 | ) |  | (91,531 | )
Depreciation, depletion and amortization |  | (163,359 | ) |  | (92,323 | ) |  | (480,476 | ) |  | (295,174 | )
Accretion expense |  | (21,256 | ) |  | (13,179 | ) |  | (63,430 | ) |  | (42,400 | )
Transaction and other income (expenses)(1) |  | 64,321 |  |  | (3,219 | ) |  | 38,799 |  |  | 38,856 |
Decommissioning obligations(2) |  | (7,972 | ) |  | (20 | ) |  | (9,454 | ) |  | (10,553 | )
Derivative fair value gain (loss)(3) |  | (98,802 | ) |  | 114,180 |  |  | (13,668 | ) |  | (231,133 | )
Net cash (received) paid on settled derivative instruments (3) |  | 6,313 |  |  | 81,162 |  |  | 10,474 |  |  | 368,483 |
Non-cash equity-based compensation expense |  | (393 | ) |  | (4,310 | ) |  | (9,080 | ) |  | (11,677 | )
Income (loss) before income taxes | $ | (17,968 | ) | $ | 250,586 |  | $ | 45,918 |  | $ | 381,421 |

(1)
For the three and nine months ended September 30, 2023, transaction expenses includes $1.5 million and $39.4 million, respectively, in costs related to the EnVen Acquisition, inclusive of $0.9 million and $24.9 million, respectively, in severance expense. For the three and nine months ended September 30, 2022, transaction expenses includes $4.3 million and $5.0 million, respectively, in costs related to the EnVen Acquisition. See further discussion in Note 2 — Acquisitions and Divestitures and Note 7 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three and nine months ended September 30, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Note 2 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million for the nine months ended September 30, 2023 and a $1.4 million for the three and nine months ended September 30, 2022. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the nine months ended September 30, 2022. See further discussion in Note 10 — Related Party Transactions. For the nine months ended September 30, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 11 — Commitments and Contingencies.
(2)
Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 11 — Commitments and Contingencies for additional information on decommissioning obligations.
(3)
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.

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The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands):

| Nine Months Ended September 30, |
| 2023 |  | 2022 |
Segment Expenditures: |  |  |  |
Total reportable segments | $ | 559,873 |  | $ | 297,486 |
All other |  | 37,183 |  |  | 2,027 |
Change in capital expenditures included in accounts payable and accrued liabilities |  | 15,085 |  |  | (32,430 | )
Plugging & abandonment |  | (71,097 | ) |  | (60,304 | )
Decommissioning obligations settled |  | (40,415 | ) |  | — |
Investment in CCS intangibles and equity method investees |  | (37,168 | ) |  | (2,027 | )
Deferred payments |  | (841 | ) |  | — |
Non-cash well equipment inventory transfers |  | (24,476 | ) |  | 3,403 |
Other |  | 362 |  |  | 1,437 |
Exploration, development and other capital expenditures | $ | 438,506 |  | $ | 209,592 |

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

Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our,” “Talos” 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. “Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2022 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 2022 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 upstream through oil and gas exploration and production (“Upstream”) and the development of low carbon solutions 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. We are also utilizing our expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico.

We have historically focused our Upstream 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.

We have two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is our only reportable segment. See additional information in Part I, Item 1. “Financial Statements — Note 12 — Segment Information.”

Significant Developments

The following significant development has occurred since the filing of our Quarterly Report on Form 10-Q for the period ended June 30, 2023.

Mexico Divestiture — On September 27, 2023, we sold a 49.9% interest in Talos Energy Mexico 7, S. de R.L. de C.V., a wholly owned subsidiary of the Company, to Zamajal, S.A. de C.V, a wholly owned subsidiary of Grupo Carso. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.

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.

EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for more information.

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 third quarter of 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. The next dry-dock is scheduled for first half of 2024 with a projected shut-in period of approximately 55 days.

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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 the 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.

Known Trends and Uncertainties

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2022 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 2022 Annual Report.

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil, natural gas and NGLs 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.

During the period January 1, 2023 through September 30, 2023, the daily spot prices for NYMEX WTI crude oil ranged from a high of $93.67 per Bbl to a low of $66.61 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.78 per MMBtu to a low of $1.74 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 we realize 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. “Financial Statements — Note 5 — Financial Instruments” for additional information regarding our commodity derivative positions as of September 30, 2023.

The U.S. Energy Information Administration (“EIA”) published its October 2023 Short-Term Energy Outlook on October 11, 2023. The EIA expects natural gas prices to average more than $3.03 per MMBtu in the fourth quarter of 2023 and $3.23 per MMBtu in 2024. The EIA also expects the NYMEX WTI spot price will average $86.65 per Bbl in the fourth quarter of 2023 and $90.91 per Bbl in 2024. The EIA believes crude oil prices will rise in the coming months, reflecting its expectations of tightening balances in global oil markets. The Israel-Hamas war, which commenced in early October, and the threat of increased conflict in the Middle East raises the potential for oil supply disruptions and higher oil prices. Current OPEC Plus production targets are set to expire at the end of 2024. The EIA assumes that continuing voluntary cuts and other factors will keep actual OPEC Plus crude oil production well below targets as the group tries to limit increases in global oil inventories. However, should OPEC Plus produce closer to target levels than the EIA currently assumes, it could reduce forecasted prices in 2024. Also, the rate at which U.S. tight oil producers add drilling rigs and improve well-level efficiency is highly uncertain and could cause global oil production to vary significantly from the EIA forecast. Finally, the global economic outlook remains uncertain, and unexpected changes in gross domestic product, or GDP, growth in the coming months could affect oil demand.

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 increases, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices. In addition, the U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 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 (the “Fed”) 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. The Fed raised rates by a quarter of a percentage point on March 22, 2023; May 3, 2023; and July 26, 2023. The latest interest rate hike increased the federal funds rate to a range of 5.25%-5.50%, its highest level since 2001. The Fed wants inflation to return to its 2% goal over time, and even though inflation is declining, it is still high in absolute terms. Future interest rate hikes remain uncertain.

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, 2023 and 2022, we did not recognize an impairment based on the ceiling test computations. At September 30, 2023 our ceiling test computation was based on SEC pricing of $80.46 per Bbl of oil, $3.58 per Mcf of natural gas and $20.44 per Bbl of NGLs.

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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 2022 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in SEC pricing 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.

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, and, in October 2020, pursued a proposed rule published jointly with the BSEE that sought to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights owners) and rights of use and easement (“RUE”) and rights of way (“ROW”) grant holders conducting operations on the federal outer continental shelf (“OCS”). The Department of the Interior (the “DOI”) under the Biden Administration elected to separate the BOEM and BSEE portions of the supplemental bonding requirements.

In April 2023, BSEE published its Final Rule entitled, “Risk Management, Financial Assurance, and Loss Prevention – Decommissioning Activities and Obligations”, wherein BSEE clarified decommissioning responsibilities for RUE grant holders and formalized BSEE’s policies regarding performance by predecessors ordered to decommission OCS facilities. The final rule withdraws the proposal in the October 2020 proposed rule to amend BSEE’s regulations requiring the agency to proceed in reverse chronological order against predecessor lessees, owners of operating rights and grant holders when requiring such entities to perform their accrued decommissioning obligations upon failure to perform by current lessees, owners, or holders. Under the final rule, BSEE may issue an order to predecessors to perform accrued decommissioning obligations, including beginning maintenance and monitoring within thirty days, designating an operator for decommissioning within ninety days, and submitting a decommissioning plan within one hundred fifty days.

On June 29, 2023, BOEM published a proposed rule that, if adopted as initially proposed, would substantially revise the supplemental financial assurance requirements applicable to offshore oil and gas operations. The proposed rule would change the current criteria used to determine whether OCS lease and grant holders are required to secure supplemental financial assurance. The proposed rule would no longer use the current 5-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead proposes a simplified test: (1) the credit rating of the lessee and, where applicable, (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. Under the proposed rule, the BOEM would no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance should be provided by current lessees and grant holders. The BOEM would not require supplemental financial assurance above the base bond requirements in three cases: (1) where a lessee has an investment grade credit rating (i.e., a credit rating from a Nationally Recognized Statistical Ratings Organizations, or NRSRO, that is greater than or equal to either BBB- from S&P or Baa3 from Moody’s, or its equivalent, or a proxy credit rating greater than or equal to either BBB- or Baa3, as determined by the Regional Director and based upon a company’s audited financial information with an accompanying auditor’s certificate); (2) where there are multiple co-lessees on a lease and any one of those lessees meets the credit rating threshold; and (3) for any lease on which all lessees are rated below investment grade, where the value of the lease’s proved oil and gas reserves is at least three times that of the estimated decommissioning cost estimate. The BOEM proposes to phase in compliance with the new requirements over a three-year period. The extended public comment period closed on September 7, 2023, and BOEM is reviewing the comments received. At this time, we cannot predict whether BOEM will adopt the final rule in its current form or at all, the timing for any final decision, or whether any changes will result from the public notice and comment process, but will continue to monitor this rulemaking.

As discussed in our 2022 Annual Report, including under Part I, Item 1A. “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry — We may be unable to provide the financial assurances in the amounts and under the time periods required by the BOEM if it submits future demands to cover our decommissioning obligations. If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases,” o ur ability to obtain adequate supplemental financial assurance (pursuant to a final BOEM rule that is substantially consistent with the June 2023 proposed rule or otherwise), including the future cost of compliance with respect to supplemental bonding, could materially and adversely affect our liquidity, financial condition, cash flows, business, properties 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. Additionally, in August 2021, the BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM.

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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 biennially, 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, Tropical Storms and Loop Currents — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes, tropical storms and loop currents on production and capital projects. Significant impacts could include reductions and/or deferrals of future production and revenues and increased lease operating expenses for evacuations and repairs.

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 included in 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. President Biden signed the Inflation Reduction Act of 2022 (the “IRA 2022”) into law on August 16, 2022. The IRA 2022 reinstated Lease Sale 257 held in November 2021, and required 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 high bidder on 10 blocks and awarded leases on 9 blocks. In January 2023, BOEM released its final environmental impact statement for Lease Sales 259 and 261 and, in March 2023, announced the results of Lease Sale 259, in which we were the high bidder on four offshore blocks, and were awarded leases on all four blocks. Lease Sale 261 was scheduled to be held on November 8, 2023, pursuant to a September 21, 2023 court order from the United States District Court for the Western District of Louisiana, as amended by a September 25, 2023 order from the United States Court of Appeals for the Fifth Circuit. However, on October 26, 2023, the United States Court of Appeals for the Fifth Circuit stayed its and the District Court’s ruling, scheduling oral arguments for November 13, 2023. On November 2, 2023, BOEM announced that it is postponing Lease Sale 261 as a result of the Appeals Court’s October 26, 2023 order. BOEM stated it will hold Lease Sale 261 after it receives further direction from the Appeals Court.

BOEM’s development of a new five-year 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 (“PFP”) 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.

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 PFP, 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 PP included no more than ten potential lease sales in the Gulf of Mexico. On September 29, 2023, the PFP for 2024-2029 was published and includes a maximum of three potential oil and gas lease sales in the Gulf of Mexico scheduled to be held in years 2025, 2027 and 2029. Release of the PFP and corresponding Final PEIS initiated the 60-day waiting period required before formal approval occurs and a Record of Decision is finalized.

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, except per unit data):

| Three Months Ended September 30, |  |  |  | Nine Months Ended September 30, |  |  |
| 2023 |  | 2022 |  | Change |  | 2023 |  | 2022 |  | Change |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Oil | $ | 359,404 |  | $ | 295,585 |  | $ | 63,819 |  | $ | 995,081 |  | $ | 1,078,800 |  | $ | (83,719 | )
Natural gas |  | 16,871 |  |  | 68,360 |  |  | (51,489 | ) |  | 53,383 |  |  | 181,747 |  |  | (128,364 | )
NGL |  | 6,860 |  |  | 13,183 |  |  | (6,323 | ) |  | 24,463 |  |  | 49,232 |  |  | (24,769 | )
Total revenues | $ | 383,135 |  | $ | 377,128 |  | $ | 6,007 |  | $ | 1,072,927 |  | $ | 1,309,779 |  | $ | (236,852 | )
Production Volumes: |  |  |  |  |  |  |  |  |  |  |  |
Oil (MBbls) |  | 4,451 |  |  | 3,258 |  |  | 1,193 |  |  | 13,358 |  |  | 11,020 |  |  | 2,338 |
Natural gas (MMcf) |  | 6,005 |  |  | 7,292 |  |  | (1,287 | ) |  | 19,769 |  |  | 24,746 |  |  | (4,977 | )
NGL (MBbls) |  | 403 |  |  | 403 |  |  | — |  |  | 1,318 |  |  | 1,372 |  |  | (54 | )
Total production volume (MBoe) |  | 5,855 |  |  | 4,876 |  |  | 979 |  |  | 17,971 |  |  | 16,516 |  |  | 1,455 |
Daily Production Volumes by Product: |  |  |  |  |  |  |  |  |  |  |  |
Oil (MBblpd) |  | 48.4 |  |  | 35.4 |  |  | 13.0 |  |  | 48.9 |  |  | 40.4 |  |  | 8.5 |
Natural gas (MMcfpd) |  | 65.3 |  |  | 79.3 |  |  | (14.0 | ) |  | 72.4 |  |  | 90.6 |  |  | (18.2 | )
NGL (MBblpd) |  | 4.4 |  |  | 4.4 |  |  | 0.0 |  |  | 4.8 |  |  | 5.0 |  |  | (0.2 | )
Total production volume (MBoepd) |  | 63.7 |  |  | 53.0 |  |  | 10.7 |  |  | 65.8 |  |  | 60.5 |  |  | 5.3 |
Average Sale Price Per Unit: |  |  |  |  |  |  |  |  |  |  |  |
Oil (per Bbl) | $ | 80.75 |  | $ | 90.73 |  | $ | (9.98 | ) | $ | 74.49 |  | $ | 97.89 |  | $ | (23.40 | )
Natural gas (per Mcf) | $ | 2.81 |  | $ | 9.37 |  | $ | (6.56 | ) | $ | 2.70 |  | $ | 7.34 |  | $ | (4.64 | )
NGL (per Bbl) | $ | 17.02 |  | $ | 32.71 |  | $ | (15.69 | ) | $ | 18.56 |  | $ | 35.88 |  | $ | (17.32 | )
Price per Boe | $ | 65.44 |  | $ | 77.34 |  | $ | (11.90 | ) | $ | 59.70 |  | $ | 79.30 |  | $ | (19.60 | )
Price per Boe (including realized commodity derivatives) | $ | 64.36 |  | $ | 60.70 |  | $ | 3.66 |  | $ | 59.12 |  | $ | 56.99 |  | $ | 2.13 |

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

| Three Months Ended September 30, 2023 vs 2022 |  | Nine Months Ended September 30, 2023 vs 2022 |
| Price |  | Volume |  | Total |  | Price |  | Volume |  | Total |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Oil | $ | (44,422 | ) | $ | 108,241 |  | $ | 63,819 |  | $ | (312,586 | ) | $ | 228,867 |  | $ | (83,719 | )
Natural gas |  | (39,430 | ) |  | (12,059 | ) |  | (51,489 | ) |  | (91,833 | ) |  | (36,531 | ) |  | (128,364 | )
NGL |  | (6,323 | ) |  | — |  |  | (6,323 | ) |  | (22,831 | ) |  | (1,938 | ) |  | (24,769 | )
Total revenues | $ | (90,175 | ) | $ | 96,182 |  | $ | 6,007 |  | $ | (427,250 | ) | $ | 190,398 |  | $ | (236,852 | )

Three Months Ended September 30, 2023 and 2022 Volumetric Analysis — Production volumes increased by 10.7 MBoepd to 63.7 MBoepd. The increase was primarily due to 19.1 MBoepd in production from the oil and natural gas assets acquired in the EnVen Acquisition. Additionally, production volumes increased 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, during 2022. These increases were partially offset by a decrease of 12.1 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field. Additionally, there was approximately 2.4 MBoepd of deferred production resulting from loop currents requiring intermittent shut-ins of the HP-I and associated infrastructure in the Phoenix Field.

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Nine Months Ended September 30, 2023 and 2022 Volumetric Analysis — Production volumes increased by 5.3 MBoepd to 65.8 MBoepd. The increase was primarily due to 17.0 MBoepd in production from the oil and natural gas assets acquired in the EnVen Acquisition. Additionally, production volumes increased 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 during 2022. These increases were partially offset by a decrease of 14.7 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field.

Operating Expenses

Lease Operating Expense

The following table highlights lease operating expense items in total and on a cost per Boe production basis to our Upstream Segment. 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, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Lease operating expenses | $ | 103,548 |  | $ | 81,760 |  | $ | 286,075 |  | $ | 229,156 |
Lease operating expenses per Boe | $ | 17.69 |  | $ | 16.77 |  | $ | 15.92 |  | $ | 13.87 |

Three Months Ended September 30, 2023 and 2022 — Lease operating expense for the three months ended September 30, 2023 increased by approximately $21.8 million, or 27%. This increase was primarily related to lease operating expenses of $27.3 million incurred in connection with assets acquired from the EnVen Acquisition. This increase was partially offset by a $3.4 million decrease in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Pompano Field compared to the same period in 2022.

Nine Months Ended September 30, 2023 and 2022 — Lease operating expense for the nine months ended September 30, 2023 increased by approximately $56.9 million, or 25%. This increase was primarily related to lease operating expenses of $59.0 million incurred in connection with assets acquired from the EnVen Acquisition. Additionally, there was a $11.3 million decrease in production handling fees related to reimbursements for costs from certain third parties related to our historical operations. This increase was partially offset by a $22.5 million decrease in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Gunflint Field compared to the same period in 2022.

Depreciation, Depletion and Amortization

The following table highlights depreciation, depletion and amortization items. 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, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Depreciation, depletion and amortization | $ | 163,359 |  | $ | 92,323 |  | $ | 480,476 |  | $ | 295,174 |

Three Months Ended September 30, 2023 and 2022 — Depreciation, depletion and amortization expense for the three months ended September 30, 2023 increased by approximately $71.0 million, or 77%. This was due to an increase of $8.88 per Boe, or 47%, in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties primarily related to the assets acquired as part of the EnVen Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” and the extension of the HP-I lease during the fourth quarter of 2022, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.

Nine Months Ended September 30, 2023 and 2022 — Depreciation, depletion and amortization expense for the nine months ended September 30, 2023 increased by approximately $185.3 million, or 63%. This was due to an increase of $8.81 per Boe, or 50%, in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties primarily related to the assets acquired as part of the EnVen Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” and the extension of the HP-I lease during the fourth quarter of 2022, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in our 2022 Annual Report.

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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 for the Upstream Segment. 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, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Upstream Segment | $ | 21,054 |  | $ | 23,606 |  | $ | 108,310 |  | $ | 59,561 |
CCS Segment |  | 2,472 |  |  | (22 | ) |  | 8,246 |  |  | 6,358 |
Unallocated corporate |  | 1,362 |  |  | 1,705 |  |  | 4,701 |  |  | 4,823 |
Total general and administrative expense | $ | 24,888 |  | $ | 25,289 |  | $ | 121,257 |  | $ | 70,742 |
Upstream general and administrative expense per Boe | $ | 3.60 |  | $ | 4.84 |  | $ | 6.03 |  | $ | 3.61 |

Three Months Ended September 30, 2023 and 2022 — General and administrative expense for the three months ended September 30, 2023 decreased by approximately $0.4 million, or 2%. There was a decrease in non-cash equity-based compensation of $3.9 million, primarily due to a forfeiture during the third quarter of 2023. Additionally, Upstream Segment transaction costs related to the closing and continued integration of the EnVen Acquisition decreased $2.8 million or $0.63 per Boe compared to the same period in 2022. This was partially offset by an increase in the CCS Segment’s general and administrative expenses due to the reimbursement of project costs incurred from inception to date from certain partners during the third quarter of 2022. Additionally, payroll expense increased from additional employee headcount primarily related to the EnVen Acquisition.

Nine Months Ended September 30, 2023 and 2022 — General and administrative expense for the nine months ended September 30, 2023 increased by approximately $50.5 million, or 71%. This increase was primarily related to higher Upstream Segment transaction costs for the closing and continued integration of the EnVen Acquisition of $34.5 million or $1.89 per Boe. Additionally, there was an increase in payroll expense due to additional employee headcount primarily related to the EnVen Acquisition and the CCS Segment’s general and administrative expenses due to the reimbursement of project costs incurred from inception to date from certain partners during the third quarter of 2022. These increases were partially offset by a decrease in non-cash equity-based compensation of $2.6 million, primarily due to a forfeiture during the third quarter of 2023.

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, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Accretion expense | $ | 21,256 |  | $ | 13,179 |  | $ | 63,430 |  | $ | 42,400 |
Other operating (income) expense | $ | (57,287 | ) | $ | (366 | ) | $ | (55,172 | ) | $ | 12,142 |
Interest expense | $ | 45,637 |  | $ | 29,265 |  | $ | 128,850 |  | $ | 91,531 |
Price risk management activities (income) expense | $ | 98,802 |  | $ | (114,180 | ) | $ | 13,668 |  | $ | 231,133 |
Equity method investment (income) expense | $ | 2,493 |  | $ | (991 | ) | $ | (2,938 | ) | $ | (14,599 | )
Other (income) expense | $ | (2,193 | ) | $ | (692 | ) | $ | (10,450 | ) | $ | (31,991 | )
Income tax (benefit) expense | $ | (15,865 | ) | $ | 121 |  | $ | (55,516 | ) | $ | 2,256 |

Three Months Ended September 30, 2023 and 2022 —

Accretion Expense — During the three months ended September 30, 2023, we recorded $21.3 million of accretion expense compared to $13.2 million during the three months ended September 30, 2022. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of the EnVen Acquisition. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”

Other Operating (Income) Expense — During the three months ended September 30, 2023, we recognized a gain of $66.2 million on the Mexico Divestiture. See further discussion in See further discussion in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.” This gain was partially offset by $8.0 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 11 — Commitments and Contingencies.”

Interest Expense — During the three months ended September 30, 2023, we recorded $45.6 million of interest expense compared to $29.3 million during the three months ended September 30, 2022. The change is primarily the result of the increase in interest associated with the 11.75% Notes (as defined below under “ — Liquidity and Capital Resources — Overview of Debt Instruments”) assumed as part of the EnVen Acquisition. Additionally, there was an increase in interest associated with the Bank Credit Facility due to increased interest rates and average borrowings when compared to the same period 2022.

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Price Risk Management Activities — The expense of $98.8 million for the three months ended September 30, 2023 consists of $92.5 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $6.3 million in cash settlement losses. 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 $81.2 million in cash settlement losses.

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 2025, 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. “Financial Statements — Note 5 — Financial Instruments.”

Income Tax (Benefit) Expense — During the three months ended September 30, 2023, we recorded $15.9 million of income tax benefit compared to $0.1 million of income tax expense during the three months ended September 30, 2022. The income tax expense is primarily due to a change of its valuation allowance on its deferred tax assets. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 8 — Income Taxes.”

Nine Months Ended September 30, 2023 and 2022 —

Accretion Expense — During the nine months ended September 30, 2023, we recorded $63.4 million of accretion expense compared to $42.4 million during the nine months ended September 30, 2022. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of the EnVen Acquisition. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”

Other Operating (Income) Expense — During the nine months ended September 30, 2023, we recognized a gain of $66.2 million on the Mexico Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.” This gain was partially offset by $9.5 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the nine months ended September 30, 2022, we recorded $10.6 million of estimated decommissioning obligations. See Part I, Item 1. “Financial Statements — Note 11 — Commitments and Contingencies.”

Interest Expense — During the nine months ended September 30, 2023, we recorded $128.9 million of interest expense compared to $91.5 million during the nine months ended September 30, 2022. The change is primarily the result of the increase in interest associated with the 11.75% Notes assumed as part of the EnVen Acquisition. Additionally, there was an increase in interest associated with the Bank Credit Facility due to increased interest rates when compared to the same period 2022.

Price Risk Management Activities — The expense of $13.7 million for the nine months ended September 30, 2023 consists of $10.5 million in cash settlement losses and $3.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts. The expense of $231.1 million for the nine months ended September 30, 2022 consists of $368.5 million in cash settlement losses offset by $137.4 million in non-cash gains from the increase in the fair value of our open derivative contracts.

Equity Method Investment (Income) Expense — During the nine months ended September 30, 2023, we recorded an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron offset by equity losses of $5.6 million. During the nine months ended September 30, 2022, we recorded a $13.9 million gain on the partial sale and $1.4 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron offset by equity losses of $0.7 million. See Part I, Item 1. “Financial Statements — Note 10 — 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. “Financial Statements — Note 11 — Commitments and Contingencies.”

Income Tax (Benefit) Expense — During the nine months ended September 30, 2023, we recorded $55.5 million of income tax benefit compared to $2.3 million of income tax expense during the nine months ended September 30, 2022. The income tax benefit is primarily due to a non-cash tax benefit of $54.9 million related to the partial release of the valuation allowance on our federal deferred tax assets offset by the impact of other permanent differences. The partial release of the valuation allowance is a result of the deferred tax liabilities acquired with the EnVen Acquisition. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 8 — Income Taxes.”

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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, decommissioning obligations, 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.

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, |
| 2023 |  | 2022 |  | 2023 |  | 2022 |
Net income (loss) | $ | (2,103 | ) | $ | 250,465 |  | $ | 101,434 |  | $ | 379,165 |
Interest expense |  | 45,637 |  |  | 29,265 |  |  | 128,850 |  |  | 91,531 |
Income tax (benefit) expense |  | (15,865 | ) |  | 121 |  |  | (55,516 | ) |  | 2,256 |
Depreciation, depletion and amortization |  | 163,359 |  |  | 92,323 |  |  | 480,476 |  |  | 295,174 |
Accretion expense |  | 21,256 |  |  | 13,179 |  |  | 63,430 |  |  | 42,400 |
EBITDA |  | 212,284 |  |  | 385,353 |  |  | 718,674 |  |  | 810,526 |
Transaction and other (income) expenses(1) |  | (64,321 | ) |  | 3,219 |  |  | (38,799 | ) |  | (38,856 | )
Decommissioning obligations(2) |  | 7,972 |  |  | 20 |  |  | 9,454 |  |  | 10,553 |
Derivative fair value (gain) loss(3) |  | 98,802 |  |  | (114,180 | ) |  | 13,668 |  |  | 231,133 |
Net cash received (paid) on settled derivative instruments(3) |  | (6,313 | ) |  | (81,162 | ) |  | (10,474 | ) |  | (368,483 | )
Non-cash equity-based compensation (income) expense |  | 393 |  |  | 4,310 |  |  | 9,080 |  |  | 11,677 |
Adjusted EBITDA | $ | 248,817 |  | $ | 197,560 |  | $ | 701,603 |  | $ | 656,550 |

(1)
For the three and nine months ended September 30, 2023, transaction expenses includes $1.5 million and $39.4 million, respectively, in costs related to the EnVen Acquisition, inclusive of $0.9 million and $24.9 million, respectively, in severance expense. For the three and nine months ended September 30, 2022, transaction expenses includes $4.3 million and $5.0 million, respectively, in costs related to the EnVen Acquisition. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” and “Note 7 — Employee Benefits Plans and Share-Based Compensation.” Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three and nine months ended September 30, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.” The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million for the nine months ended September 30, 2023 and a $1.4 million for the three and nine months ended September 30, 2022. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the nine months ended September 30, 2022. See further discussion in Part I, Item 1. “Financial Statements — Note 10 — Related Party Transactions.” For the nine months ended September 30, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Part I, Item 1. “Financial Statements — Note 11 — Commitments and Contingencies.”
(2)
Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 11 — Commitments and Contingencies.”
(3)
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.

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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, share repurchases and for general corporate purposes. The cost of borrowings under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed is making it more expensive to borrow money. Our working capital deficit has decreased since December 31, 2022 primarily due to an increase in our accounts receivables that was offset by an increase in the current portion of long-term debt of $33.1 million related to the 11.75% Notes assumed as part of the EnVen Acquisition. See Part I, Item 1. “Financial Statements — Note 6 — Debt.” As of September 30, 2023, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $752.9 million.

We fund drilling, completions 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 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. We are continuing to explore a capital raise to finance the accelerated growth of our CCS Segment.

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2023 (in thousands):

U.S. drilling & completions | $ | 317,900 |
Mexico appraisal & exploration |  | 291 |
Asset management(1) |  | 81,677 |
Seismic and G&G, land, capitalized G&A and other |  | 48,493 |
Total Upstream capital expenditures |  | 448,361 |
Plugging & abandonment |  | 71,097 |
Decommissioning obligations settled(2) |  | 40,415 |
Total Upstream |  | 559,873 |
Investment in CCS |  | 37,183 |
Total | $ | 597,056 |

(1)
Asset management consists of capital expenditures for development-related activities primarily associated with recompletions and improvements to our facilities and infrastructure.
(2)
Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 11 — Commitments and Contingencies.”

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 remaining portion of our 2023 Upstream capital spending program of $650.0 million to $675.0 million and plugging & abandonment and decommissioning obligations of $120.0 million to $130.0 million as well as expected investments in our CCS Segment of $70.0 million to $90.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on various operating and economic conditions, many 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.

Common Stock Repurchase Program — Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. In March and June of 2023, we repurchased 1.9 million shares for $26.6 million and 1.5 million shares for $20.9 million, respectively. As of September 30, 2023, there is $52.5 million remaining under the authorized program. All repurchased shares are held in treasury.

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.

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The IRA 2022 provides for, among other things, the imposition of a new 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations such as us after December 31, 2022. Accordingly, the excise tax applies to our share repurchase program. The excise tax payment is non-deductible for income tax purposes. Subject to certain exceptions and adjustments, the excise tax equals 1% of the fair market value of the stock repurchased by a corporation during the applicable tax year. The repurchase amount subject to the excise tax is generally reduced by the fair market value of any stock issued by a corporation during a taxable year, including the fair market value of any stock issued or provided to employees of a corporation or employees of certain of its subsidiaries. The current federal administration has proposed increasing the excise tax amount from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any change can take effect. We do not anticipate paying any excise task in 2023 based on the fair market value of the stock issuance in connection to the EnVen Acquisition.

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, |
| 2023 |  | 2022 |
Operating activities | $ | 342,811 |  | $ | 538,928 |
Investing activities | $ | (391,874 | ) | $ | (198,652 | )
Financing activities | $ | 120,309 |  | $ | (345,638 | )

Operating Activities — Net cash provided by operating activities decreased $196.1 million in the nine months ended September 30, 2023 compared to the corresponding period in 2022 primarily attributable to a decrease from revenues combined with an increase in lease operating expense of $293.8 million.

Investing Activities — Net cash used in investing activities increased $193.2 million in the nine months ended September 30, 2023 compared to the corresponding period in 2022 primarily due to an increase in capital expenditures of $228.9 million and contributions to equity method investees of $27.1 million. Capital expenditures for drilling and completion projects during 2022 generally were budgeted and occurred during the third and fourth quarters. Budgeted capital expenditures for drilling and completion projects for 2023 were more heavily weighted to occur in the first half of 2023. The capital expenditure budget for 2023 also included projects related to the EnVen Acquisition. This was offset by cash proceeds of $74.9 million from the Mexico Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.

Financing Activities — Cash flow from financing activities changed $465.9 million in the nine months ended September 30, 2023 compared to the corresponding period in 2022. We had net borrowings from the Bank Credit Facility of $215.0 million for the nine months ended September 30, 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures. We had net repayments of $315.0 million during the same period in 2022 due to a management goal to reduce our leverage ratio coupled with a commodity price environment that supported debt repayments to achieve such goal. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information. We repurchased $47.5 million of our common stock through our share repurchase program during the nine months ended September 30, 2023. See the subsection entitled “— Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information. Additionally, there was an increase in deferred financing costs of $11.6 million and redemption of senior notes of $8.9 million in each case when compared to the same period in 2022. See Part I, Item 1. “Financial Statements — Note 6 — Debt” for additional information.

Overview of Debt Instruments

Bank Credit Facility — matures March 2027 — 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. See Part I, Item 1. “Financial Statements — Note 6 — Debt” for more information.

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. “Financial Statements — Note 6 — Debt” for more information.

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11.75% Senior Secured Second Lien Notes — due April 2026 — On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, we assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount outstanding of $257.5 million. The 11.75% Notes will mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The 11.75% 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 indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year. We made a payment of $29.2 million on October 16, 2023 for the redemption of outstanding principal and interest incurred. See Part I, Item 1. “Financial Statements — Note 6 — 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 subsidiaries that guarantees the Issuer’s senior reserve-based revolving credit facility (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”). Our non-domestic subsidiaries (other than Talos International Holdings SCS) 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 Issuer and the Guarantors for the respective periods (in thousands):

| September 30, 2023 |  | December 31, 2022 |
Current assets | $ | 400,028 |  | $ | 344,525 |
Non-current assets |  | 4,294,989 |  |  | 2,571,254 |
Total assets | $ | 4,695,017 |  | $ | 2,915,779 |
Current liabilities | $ | 628,020 |  | $ | 599,669 |
Non-current liabilities |  | 2,061,239 |  |  | 1,285,992 |
Talos Energy Inc. stockholdersʼ equity |  | 2,005,758 |  |  | 1,030,118 |
Total liabilities and stockholdersʼ equity | $ | 4,695,017 |  | $ | 2,915,779 |

The following table presents the statement of operations information for the Issuer and the Guarantors (in thousands):

| Nine Months Ended September 30, 2023 |
Revenues | $ | 1,072,927 |
Costs and expenses |  | (968,643 | )
Net income (loss) | $ | 104,284 |

Material Cash Requirements

We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements.

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The following table and discussion summarize our material cash requirements from known contractual obligations as of September 30, 2023 (in thousands):

| 2023 |  | 2024 |  | 2025 |  | 2026 |  | 2027 |  | Thereafter |  | Total(5) |
Long-term financing obligations: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Debt principal | $ | 15,000 |  | $ | 30,000 |  | $ | 30,000 |  | $ | 806,041 |  | $ | 215,000 |  | $ | — |  | $ | 1,096,041 |
Debt interest |  | 11,501 |  |  | 120,798 |  |  | 117,479 |  |  | 65,578 |  |  | 5,529 |  |  | — |  |  | 320,885 |
Vessel commitments(1) |  | 9,537 |  |  | 1,304 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 10,841 |
Derivative liabilities |  | 18,141 |  |  | 45,882 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 64,023 |
Operating lease obligations |  | 1,438 |  |  | 4,748 |  |  | 4,716 |  |  | 4,803 |  |  | 4,708 |  |  | 9,194 |  |  | 29,607 |
Finance lease(2) |  | 11,602 |  |  | 19,336 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 30,938 |
Purchase obligations(3) |  | 53,058 |  |  | 4,579 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 57,637 |
Other commitments(4) |  | 327 |  |  | 2,468 |  |  | 2,468 |  |  | 2,141 |  |  | — |  |  | — |  |  | 7,404 |
Total contractual obligations(5) | $ | 120,604 |  | $ | 229,115 |  | $ | 154,663 |  | $ | 878,563 |  | $ | 225,237 |  | $ | 9,194 |  | $ | 1,617,376 |

(1)
Includes vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs.
(2)
Lease agreement for the HP-I floating production facility in the Phoenix Field.
(3)
Includes committed purchase orders to execute planned future drilling activities.
(4)
Includes commitment to lease acreage and renewals associated with our CCS Segment.
(5)
This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $816.8 million as of September 30, 2023. For additional information regarding these liabilities, please see Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.” Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part I, Item 1. “Financial Statements — Note 11 — Commitment and Contingencies.”

Performance Obligations — As of September 30, 2023, we had secured performance bonds totaling $1.4 billion 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 $10.8 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. “Financial Statements — Note 6 — Debt” for further information on the Bank Credit Facility.

Critical Accounting Estimates

Critical accounting estimates are those estimates made in accordance with GAAP that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations. Except as discussed below, there have been no changes to our critical accounting estimates from those disclosed in our 2022 Annual Report under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates.”

Determination of Fair Value in Business Combinations

We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the acquisition date amounts of the identifiable net assets acquired.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties.

The fair value of proved and oil natural gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments are applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class.

The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. Historically there has been significant volatility in oil, natural gas and NGL prices and estimates of such future prices are inherently imprecise. Additionally, the actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. A higher discount rate decreases the net present value of cash flows.

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The estimated fair value assigned to the assets acquired and liabilities assumed can have a significant effect on our future operating results. For example, a higher fair value measurement of oil and gas properties results in higher depletion expense in future periods which reduces our future earnings.

See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for more information related to the EnVen Acquisition.

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

There were no recently issued accounting standards material to us.

Item 3. Quantitative and Qualitat ive 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 2022 Annual Report. Except as discussed below, there have been no material changes from the disclosures presented in our 2022 Annual Report regarding our exposures to certain market risks.

Price Risk Management Activities

We had commodity derivative instruments in place to reduce the price risk associated with future production of 11,954 MBbls of crude oil and 17,360 MMBtu of natural gas at September 30, 2023, with a net derivative liability position of $48.0 million. For additional information regarding our commodity derivative instruments, see Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments,” included elsewhere in this Quarterly Report. The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at September 30, 2023 (in thousands):

|  |  | Oil and Natural Gas Derivatives |
|  |  | Ten Percent Increase |  | Ten Percent Decrease |
| Fair Value |  | Fair Value |  | Change |  | Fair Value |  | Change |
Price impact(1) | $ | (47,976 | ) | $ | (133,202 | ) | $ | (85,226 | ) | $ | 34,441 |  | $ | 82,417 |

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

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, 2023.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHE R INFORMATION

Item 1. Legal Proceedings

The following proceedings represent previous EnVen litigation that was assumed as part of the EnVen Acquisition.

In June 2019, David M. Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favor of Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of Appeal in December 2021. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supreme Court on August 2, 2023. As of September 30, 2023, the Company has recorded $14.1 million as “Other current liabilities” on the Condensed Consolidated Balance Sheets related to the litigation.

In July 2019, EnVen filed a lawsuit against Mr. Dunwoody in Delaware Chancery Court for breach of fiduciary duty and equitable fraud relating to Mr. Dunwoody’s conduct while he was President of EnVen. In January 2020, EnVen filed an amended complaint that added claims against Oilfield Pipe of Texas, LLC for aiding and abetting Mr. Dunwoody’s breach of his fiduciary duty and equitable fraud. On April 21, 2022, the Delaware Chancery Court denied Mr. Dunwoody’s renewed motion to dismiss the suit. The trial was held in the Delaware Chancery Court in late July 2023. The Company agreed to dismiss the litigation with prejudice on September 14, 2023.

There have been no additional material developments with respect to the information previously reported under Part I, Item 3. “Legal Proceedings” of our 2022 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 2022 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 2022 Annual Report or our other SEC filings including our Quarterly Report on Form 10-Q for the quarter ended March 31, 2023.

Item 2. Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. Repurchases may be made from time to time in the open market, in a privately negotiated transaction, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares. There were no shares of common stock repurchased during the three months ended September 30, 2023. As of September 30, 2023, there is $52.5 million remaining under the authorized program.

Item 3. Defaults Upo n Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

During the three months ended September 30, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

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Item 6. Exhibits

Exhibit Number |  | Description
2.1# |  | Agreement and Plan of Merger, 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 |  | Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
3.2 |  | Second Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
4.1 |  | Indenture, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).
4.2 |  | First Supplemental Indenture, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).
4.3 |  | Form of 12.00% Second-Priority Senior Secured Note due 2026 (included as Exhibit A to Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).
4.4 |  | Registration Rights Agreement, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).
4.5 |  | Registration Rights Agreement, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).
4.6 |  | 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).
4.7 |  | 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).
4.8 |  | Indenture, dated as of April 15, 2021, by and among Energy Ventures GoM LLC, EnVen Finance Corporation, Talos Production Inc. (as successor in interest to EnVen Energy Corporation), the other guarantors party thereto 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 February 14, 2023).
4.9 |  | Second Supplemental Indenture, dated as of February 13, 2023, among Talos Production Inc., each of the other guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
4.10 |  | Third Supplemental Indenture, dated as of February 13, 2023, among Talos Production Inc., Energy Ventures GoM LLC, EnVen Finance Corporation, each of the other guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
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-K (File No. 001-38497) filed with the SEC on March 1, 2023).
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.

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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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SIGNA TURES

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 6, 2023 | By: | /s/ Sergio L. Maiworm, Jr.
|  |  | Sergio L. Maiworm, Jr.
|  |  | Chief Financial Officer and Senior Vice President

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