UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
☒
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2024
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 April 29, 2024, the registrant had 183,919,349 shares of common stock, $0.01 par value per share, outstanding.
TABLE 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
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
Note 2 — Acquisitions and Divestitures
12
Note 3 — Property, Plant and Equipment
14
Note 4 — Leases
Note 5 — Financial Instruments
15
Note 6 — Equity Method Investments
18
Note 7 — Debt
Note 8 — Asset Retirement Obligations
20
Note 9 — Employee Benefits Plans and Share-Based Compensation
21
Note 10 — Income Taxes
22
Note 11 — Income (Loss) Per Share
Note 12 — Related Party Transactions
23
Note 13 — Commitments and Contingencies
Note 14 — Segment Information
25
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
27
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
37
Item 4.
Controls and Procedures
PART II — OTHER INFORMATION
Legal Proceedings
38
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Defaults Upon Senior Securities
Mine Safety Disclosures
Item 5.
Other Information
Item 6.
Exhibits
39
Signatures
42
2
Table of Contents
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.
CO2 — Carbon dioxide.
Completion — The installation of permanent equipment for the production of oil or natural gas.
Deepwater — Water depths of more than 600 feet.
Field — An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
GAAP — Accounting principles generally accepted in the United States of America.
MBbls — One thousand barrels of crude oil or other liquid hydrocarbons.
MBblpd — One thousand barrels of crude oil or other liquid hydrocarbons per day.
MBoe — One thousand barrels of oil equivalent.
MBoepd — One thousand barrels of oil equivalent per day.
Mcf — One thousand cubic feet of natural gas.
Mcfpd — One thousand cubic feet of natural gas per day.
MMBoe — One million barrels of oil equivalent.
MMBtu — One million British thermal units.
MMcf — One million cubic feet of natural gas.
MMcfpd — One million cubic feet of natural gas per day.
NGL — Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.
NYMEX — The New York Mercantile Exchange.
NYMEX Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub index.
OPEC — Organization of Petroleum Exporting Countries.
Proved reserves — Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
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-X.
SEC — The U.S. Securities and Exchange Commission.
SEC pricing — The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for each month within the 12-month period prior to the end of the reporting period, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).
Shelf — Water depths of up to 600 feet.
Working interest — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
WTI or West Texas Intermediate — A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and the sulfur content is approximately 0.3%.
4
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:
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, including the impact of financial assurance requirements; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations; and the other risks discussed in Part I, Item 1A. “Risk Factors” of Talos Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2023 (the “2023 Annual Report”).
Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.
Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.
6
PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
TALOS ENERGY INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
March 31, 2024
December 31, 2023
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents
$
21,001
33,637
Accounts receivable:
Trade, net
248,892
178,977
Joint interest, net
143,801
79,337
Other, net
16,652
19,296
Assets from price risk management activities
18,753
36,152
Prepaid assets
75,776
64,387
Other current assets
16,036
10,389
Total current assets
540,911
422,175
Property and equipment:
Proved properties
9,268,050
7,906,295
Unproved properties, not subject to amortization
654,906
268,315
Other property and equipment
34,440
34,027
Total property and equipment
9,957,396
8,208,637
Accumulated depreciation, depletion and amortization
(4,383,970
)
(4,168,328
Total property and equipment, net
5,573,426
4,040,309
Other long-term assets:
Restricted cash
103,360
102,362
5,355
17,551
Equity method investments
108,036
146,049
Other well equipment
63,507
54,277
Notes receivable, net
16,619
16,207
Operating lease assets
12,676
11,418
Other assets
10,494
5,961
Total assets
6,434,384
4,816,309
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable
136,833
84,193
Accrued liabilities
272,231
227,690
Accrued royalties
71,007
55,051
Current portion of long-term debt
—
33,060
Current portion of asset retirement obligations
71,799
77,581
Liabilities from price risk management activities
74,033
7,305
Accrued interest payable
21,106
42,300
Current portion of operating lease liabilities
3,543
2,666
Other current liabilities
46,310
48,769
Total current liabilities
696,862
578,615
Long-term liabilities:
Long-term debt
1,533,952
992,614
Asset retirement obligations
1,037,533
819,645
3,747
795
Operating lease liabilities
18,271
18,211
Other long-term liabilities
391,834
251,278
Total liabilities
3,682,199
2,661,158
Commitments and contingencies (Note 13)
Stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of March 31, 2024 and December 31, 2023, respectively
Common stock; $0.01 par value; 270,000,000 shares authorized; 187,307,298 and 127,480,361 shares issued as of March 31, 2024 and December 31, 2023, respectively
1,873
1,275
Additional paid-in capital
3,257,972
2,549,097
Accumulated deficit
(460,156
(347,717
Treasury stock, at cost; 3,400,000 and 3,400,000 shares as of March 31, 2024 and December 31, 2023, respectively
(47,504
Total stockholdersʼ equity
2,752,185
2,155,151
Total liabilities and stockholdersʼ equity
See accompanying notes.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
Three Months Ended March 31,
2024
2023
Revenues:
Oil
393,221
292,694
Natural gas
23,698
20,183
NGL
13,013
9,705
Total revenues
429,932
322,582
Operating expenses:
Lease operating expense
135,178
81,362
Production taxes
544
606
Depreciation, depletion and amortization
215,664
147,323
Accretion expense
26,903
19,414
General and administrative expense
69,841
63,187
Other operating (income) expense
(86,043
2,838
Total operating expenses
362,087
314,730
Operating income (expense)
67,845
7,852
Interest expense
(50,845
(37,581
Price risk management activities income (expense)
(87,062
58,937
Equity method investment income (expense)
(8,054
7,443
Other income (expense)
(55,896
6,666
Net income (loss) before income taxes
(134,012
43,317
Income tax benefit (expense)
21,573
46,543
Net income (loss)
(112,439
89,860
Net income (loss) per common share:
Basic
(0.71
0.85
Diluted
0.84
Weighted average common shares outstanding:
158,490
105,634
106,950
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS’ EQUITY
AdditionalPaid-In
Accumulated
Treasury Stock
TotalStockholdersʼ
Shares Issued
Par Value
Capital
Deficit
Shares
Amount
Equity
Balance at December 31, 2022
82,570,328
826
1,699,799
(535,049
1,165,576
Equity-based compensation
7,232
Equity-based compensation tax withholdings
(7,378
Equity-based compensation stock issuances
1,085,747
(11
Issuance of common stock for acquisitions (Note 2)
43,799,890
438
831,760
832,198
Purchase of treasury stock
1,900,000
(26,647
Balance at March 31, 2023
127,455,965
2,531,402
(445,189
2,060,841
Balance at December 31, 2023
127,480,361
3,400,000
4,646
(5,520
977,485
(10
24,349,452
243
322,387
322,630
Issuance of common stock
34,500,000
345
387,372
387,717
Balance at March 31, 2024
187,307,298
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion expense
242,567
166,737
Amortization of deferred financing costs and original issue discount
2,598
4,148
Equity-based compensation expense
2,754
3,938
Price risk management activities (income) expense
87,062
(58,937
Net cash received (paid) on settled derivative instruments
(3,494
(12,323
Equity method investment (income) expense
8,054
(7,443
Loss (gain) on extinguishment of debt
60,256
Settlement of asset retirement obligations
(27,907
(10,113
Loss (gain) on sale of business
(86,940
Changes in operating assets and liabilities:
Accounts receivable
8,020
36,821
(5,818
7,735
10,707
(4,894
(65,249
(116,637
Other non-current assets and liabilities, net
(23,745
(36,035
Net cash provided by (used in) operating activities
96,426
62,857
Cash flows from investing activities:
Exploration, development and other capital expenditures
(146,077
(103,962
Proceeds from (cash paid for) acquisitions, net of cash acquired
(916,045
17,617
Contributions to equity method investees
(17,519
(12,835
Investment in intangible assets
(7,796
Proceeds from sales of businesses
141,997
Net cash provided by (used in) investing activities
(937,644
(106,976
Cash flows from financing activities:
Issuance of senior notes
1,250,000
Redemption of senior notes
(897,116
Proceeds from Bank Credit Facility
670,000
275,000
Repayment of Bank Credit Facility
(545,000
(110,000
Deferred financing costs
(25,505
(11,346
Other deferred payments
(672
Payments of finance lease
(4,324
(3,987
(25,173
Employee stock awards tax withholdings
Net cash provided by (used in) financing activities
829,580
117,116
Net increase (decrease) in cash, cash equivalents and restricted cash
(11,638
72,997
Cash, cash equivalents and restricted cash:
Balance, beginning of period
135,999
44,145
Balance, end of period
124,361
117,142
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities
101,794
174,597
Supplemental cash flow information:
Interest paid, net of amounts capitalized
55,224
40,988
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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. 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.
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 2023 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
From January 1, 2024 through March 18, 2024, the Company had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”), of which the Company’s only reportable segment was the Upstream Segment. Subsequent to the TLCS Divestiture (as defined herein) and sale of the Company’s entire CCS business, the Company had one operating segment. See additional information in Note 14 — 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 2023 Annual Report. The Company has not changed any of its significant accounting policies from those described in our 2023 Annual Report.
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):
Restricted cash included in Other long-term assets
Total cash, cash equivalent and restricted cash
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.
QuarterNorth Acquisition — The Company executed an agreement and plan of merger, dated as of January 13, 2024, by and among Talos, QuarterNorth Energy Inc. (“QuarterNorth”), Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (the “QuarterNorth Merger Agreement”) to acquire QuarterNorth, a privately-held U.S. Gulf of Mexico exploration and production company (such acquisition, the “QuarterNorth Acquisition”). On March 4, 2024, the Company completed the QuarterNorth Acquisition for consideration consisting of (i) $1,247.4 million in cash and (ii) 24.3 million shares of the Company’s common stock valued at $322.6 million. The cash payment was partially funded with an upsized underwritten public offering of 34.5 million shares of the Company’s common stock, borrowings under the Bank Credit Facility and the New Senior Notes (as defined in Note 7 — Debt).
The following table summarizes the purchase price (in thousands except share and per share data):
Shares of Talos common stock
Talos common stock price(1)
13.25
Common stock value
Cash consideration
1,247,419
Total purchase price(2)
1,570,049
The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on March 4, 2024 (in thousands):
331,374
160,978
Property and equipment
1,621,507
Other long-term assets
20,780
(6,748
(194,278
(192,771
Deferred tax liabilities
(168,481
(2,312
Allocated purchase price
The fair values determined for accounts receivable, accounts payable and other current assets and most current liabilities were generally equivalent to the carrying value due to their short-term nature.
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, development and plugging and abandonment 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 and probable 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 three-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 fair values of derivative instruments were estimated using a third-party industry standard pricing model which considers various inputs such as quoted forward commodity prices, discount rates, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant data.
The Company is still finalizing the fair value analysis related to the oil and natural gas properties, other well equipment, asset retirement obligations assumed, certain contingent liabilities and deferred tax liabilities arising from the assets acquired and liabilities assumed. The preliminary purchase price allocation will be subject to further refinement as the Company continues to refine its estimates and assumptions based on further information available at the acquisition date. These refinements may result in material changes to the estimated fair value of assets acquired and liabilities assumed. The Company anticipates finalizing the determination of fair values by December 31, 2024.
The Company incurred approximately $21.8 million of acquisition-related costs in connection with the QuarterNorth Acquisition exclusive of severance expense, of which $18.8 million was recognized during the three months ended March 31, 2024 and $3.0 million was recognized for the year ended December 31, 2023. These costs were reflected in “General and administrative expense” on the Condensed Consolidated Statements of Operations except for $4.9 million of fees associated with an unutilized bridge loan that was included in “Interest expense” on the Condensed Consolidated Statements of Operations during the three months ended March 31, 2024. Additionally, the Company incurred $14.2 million in severance expense in connection with the QuarterNorth Acquisition for the three months ended March 31, 2024. See Note 9 — Employee Benefits Plans and Share-Based Compensation for additional discussion.
The following table presents revenue and net income attributable to the QuarterNorth Acquisition for the period from March 4, 2024 to March 31, 2024:
Three Months Ended March 31, 2024
Revenue
43,949
6,749
Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three months ended March 31, 2024 and 2023 as if the QuarterNorth Acquisition had occurred on January 1, 2023. The unaudited pro forma information was derived from historical statements of operations of the Company and QuarterNorth 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 New Senior Notes, (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) weighted average basic and diluted shares of common stock outstanding from the issuance of 24.3 million shares of common stock to QuarterNorth and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 34.5 million shares of common stock from the upsized underwritten public offering in January 2024 that partially funded the cash portion of the QuarterNorth Acquisition. Supplemental pro forma earnings for the three months ended March 31, 2023 were adjusted to include $31.7 million of general and administrative expenses. Supplemental pro forma earnings for the three months ended March 31, 2024 were adjusted to exclude $25.0 million of general and administrative expenses. This information does not purport to be indicative of results of operations that would have occurred had the QuarterNorth Acquisition occurred on January 1, 2023, nor is such information indicative of any expected future results of operations.
557,201
482,951
(110,459
74,320
Basic net income (loss) per common share
(0.60
0.45
Diluted net income (loss) per common share
EnVen Acquisition — On February 13, 2023, the Company completed the acquisition of EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition,” and the merger agreement related thereto, the “EnVen Merger Agreement”) 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 Company incurred approximately $21.8 million of acquisition-related costs in connection with the EnVen Acquisition exclusive of severance expense, of which $12.6 million was recognized during the three months ended March 31, 2023 and reflected in “General and administrative expense” on the Condensed Consolidated Statements of Operations. Additionally, the Company incurred $22.6 million in severance expense in connection with the EnVen Acquisition for the three months ended March 31, 2023.
The following table presents revenue and net income (loss) attributable to the EnVen Acquisition for the period from February 13, 2023 to March 31, 2023 (in thousands):
Three Months Ended March 31, 2023
62,059
(6,090
13
Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three months ended March 31, 2023 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 7 — 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 two notes receivable to settle future asset retirement obligations 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 months ended March 31, 2023 were adjusted to exclude $62.6 million of general and administrative expenses. 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).
374,625
118,090
0.93
0.92
Divestiture
Talos Low Carbon Solutions Divestiture — On March 18, 2024, the Company entered into a definitive agreement relating to and subsequently completed the sale of its wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. for a purchase price of $125.0 million plus customary reimbursements and adjustments, combined totaling approximately $142.0 million (the “TLCS Divestiture”). The TLCS Divestiture includes the Company’s entire CCS business including its equity investments in three projects along the U.S. Gulf Coast: Bayou Bend CCS LLC, Harvest Bend CCS LLC, and Coastal Bend CCS LLC. A gain of $86.9 million was recognized on the TLCS Divestiture during the three months ended March 31, 2024, which is presented as “Other operating income (expense)” on the Condensed Consolidated Statements of Operations.
The Company incurred approximately $6.7 million of costs in connection with the TLCS Divestiture exclusive of severance expense, of which $6.1 million was recognized during the during the three months ended March 31, 2024 and reflected in “General and administrative expense” on the Condensed Consolidated Statements of Operations. Additionally, the Company incurred $3.7 million in severance expense in connection with the TLCS Divestiture for the three months ended March 31, 2024. See Note 9 — Employee Benefits Plans and Share-Based Compensation for additional discussion.
Proved Properties
During the three months ended March 31, 2024 and 2023, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At March 31, 2024, the Company’s ceiling test computation was based on SEC pricing of $78.19 per Bbl of oil, $2.50 per Mcf of natural gas and $17.08 per Bbl of NGLs.
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):
Finance lease cost - interest on lease liabilities
3,372
3,708
Operating lease cost, excluding short-term leases(1)
897
908
Short-term lease cost(2)
12,652
32,985
Variable lease cost(3)
616
363
Variable and fixed sublease income
(359
Total lease cost
17,178
37,964
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):
Operating leases:
Total operating lease liabilities
21,814
20,877
Finance leases:
166,261
18,279
17,834
126,461
131,230
Total finance lease liabilities
144,740
149,064
The table below presents the supplemental cash flow information related to leases (in thousands):
Operating cash outflow from finance leases
Operating cash outflow from operating leases
1,217
1,265
ROU assets obtained in exchange for new operating lease liabilities(1)
1,601
12,971
As of March 31, 2024 and December 31, 2023, 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):
CarryingAmount
FairValue
9.000% Second-Priority Senior Secured Notes – due February 2029
609,107
663,894
9.375% Second-Priority Senior Secured Notes – due February 2031
608,985
666,175
12.00% Second-Priority Senior Secured Notes – due January 2026
601,353
655,130
11.75% Senior Secured Second Lien Notes – due April 2026
234,221
233,410
Bank Credit Facility – matures March 2027
315,860
325,000
190,100
200,000
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 and, where such prices are not available, other observable (Level 2) inputs are used such as quoted prices for similar liabilities in the active market.
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 since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).
Oil and Natural Gas Derivatives
The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production. The Company is currently utilizing oil and natural gas swaps, costless collars and put options. 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”). Put options give the owner the right but not the obligation, to sell the underlying commodity at a specified price (i.e. strike price) within a specific period. Certain of the Company’s put options have a deferred premium, which is presented net of the derivative asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement.
The following table presents the impact that derivatives, not designated as hedging instruments, had on its Condensed Consolidated Statements of Operations (in thousands):
Unrealized gain (loss)
(83,568
71,260
The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of March 31, 2024:
Swap Contracts
Production Period
Settlement Index
Volumes
Swap Price
Crude oil:
(Bbls)
(per Bbl)
April 2024 – December 2024
NYMEX WTI CMA
28,147
73.47
January 2025 – December 2025
19,679
73.19
Natural gas:
(MMBtu)
(per MMBtu)
NYMEX Henry Hub
34,455
2.91
38,644
3.60
16
Two-Way Collar Contracts
Floor Price
Ceiling Price
1,000
70.00
75.00
January 2025 – March 2025
3,000
65.00
84.35
10,000
4.00
6.90
Long Puts
Strike Price
Deferred Premium Price
4,000
(6.28
May 2024 – December 2024
13,660
2.90
(0.40
Swaps with Sold Puts
72.20
60.00
The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):
Level 1
Level 2
Level 3
Total
Assets:
Oil and natural gas derivatives
24,108
Liabilities:
(77,780
Total net asset (liability)
(53,672
53,703
(8,100
45,603
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):
Assets
Liabilities
Oil and natural gas derivatives:
Current
Non-current
Total gross amounts presented on balance sheet
77,780
8,100
Less: Gross amounts not offset on the balance sheet
18,601
Net amounts
5,507
59,179
17
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 March 31, 2024 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. Had the Company’s counterparties failed to perform under existing commodity derivative contracts the maximum loss at March 31, 2024 would have been $5.5 million.
The following table presents the Company’s investments in unconsolidated affiliates by segment as of the dates indicated below. The Company accounts for these investments using the equity method of accounting.
Ownership Interest at
Upstream:
Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”)
50.1
%
106,922
107,259
SP 49 Pipeline LLC
33.3
1,114
861
CCS(1):
Bayou Bend CCS LLC
28,183
Harvest Bend CCS LLC
9,746
Coastal Bend CCS LLC
Total Equity Method Investments
Talos Mexico is a variable interest entity. The Company’s maximum exposure to loss as a result of its involvement with Talos Mexico is the carrying amount of its investment.
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):
625,000
638,541
227,500
Bank Credit Facility – matures March 2027(1)
Total debt, before discount, premium and deferred financing cost
1,575,000
1,066,041
Unamortized discount, premium and deferred financing cost, net
(41,048
(40,367
Total debt(2)
1,025,674
Less: Current portion of long-term debt
9.000% Second-Priority Senior Secured Notes—due February 2029
The 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024.
At any time prior to February 1, 2026, the Company may redeem up to 40% of the principal amount of the 9.000% Notes at a redemption rate of 109.00% of the principal amount plus accrued and unpaid interest. At any time prior to February 1, 2026, the Company may also redeem some or all of the 9.000% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 9.000% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 1 of the years set forth below:
Period
Redemption Price
2026
104.500
2027
102.250
2028 and thereafter
100.000
As of March 31, 2024, the Company has incurred debt issuance costs of $16.2 million related to the 9.000% Notes issued as part of the debt offering that partially funded the cash portion of the QuarterNorth Acquisition. The debt issue costs reduced the proceeds from the debt issued. See Note 2 — Acquisitions and Divestitures for further discussion on the QuarterNorth Acquisition.
9.375% Second-Priority Senior Secured Notes—due February 2031
The 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “New Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024.
At any time prior to February 1, 2027, the Company may redeem up to 40% of the principal amount of the 9.375% Notes at a redemption rate of 109.375% of the principal amount plus accrued and unpaid interest. At any time prior to February 1, 2027, the Company may also redeem some or all of the 9.375% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 9.375% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 1 of the years set forth below:
104.688
2028
102.344
2029 and thereafter
19
As of March 31, 2024, the Company has incurred debt issuance costs of $16.2 million related to the 9.375% Notes issued as part of the debt offering that partially funded the cash portion of the QuarterNorth Acquisition. The debt issue costs reduced the proceeds from the debt issued. See Note 2 — Acquisitions and Divestitures for further discussion on the QuarterNorth Acquisition.
12.00% Second-Priority Senior Secured Notes
On February 7, 2024, the Company redeemed $638.5 million aggregate principal amount of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) at 103.000% plus accrued and unpaid interest using the proceeds from the issuance of the New Senior Notes. The debt redemption resulted in a loss on extinguishment of debt of $54.9 million, which is presented as “Other income (expense)” on the Condensed Consolidated Statements of Operations.
11.75% Senior Secured Second Lien Notes
The Company redeemed $227.5 million aggregate principal amount of the 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) at 102.938% plus accrued and unpaid interest using the proceeds from the issuance of the New Senior Notes. On February 7, 2024, the Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee. As a result, the transferred assets and long-term debt were derecognized from the balance sheet as of February 7, 2024. On April 15, 2024, the 11.75% Notes were redeemed using the funds irrevocably deposited in the trust with the trustee on February 7, 2024. The debt redemption resulted in a loss on extinguishment of debt of $5.4 million, which is presented as “Other income (expense)” on the Condensed Consolidated Statements of Operations.
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 January 13, 2024, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”). The Tenth Amendment, among other things, (i) permitted the incurrence of additional indebtedness in order to fund the QuarterNorth Acquisition, with such indebtedness excluded from any reduction of the borrowing base that would otherwise result from such incurrence, (ii) reaffirmed the borrowing base at approximately $1.1 billion and (iii) reaffirmed commitments at $965.0 million effective upon the amendment effective date.
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, 2023
897,226
Obligations assumed(1)
199,519
Obligations incurred
36
Obligations settled
Changes in estimate
13,555
Asset retirement obligations at March 31, 2024
1,109,332
Less: Current portion at March 31, 2024
Long-term portion at March 31, 2024
At March 31, 2024, the Company has (1) restricted cash of $103.4 million held in escrow and (2) two notes receivable with an aggregated face value of $66.2 million to settle future asset retirement obligations. A discussion of these assets is included in the accompanying Notes to the Consolidated Financial Statements in the 2023 Annual Report.
Severance
The following table summarizes severance accrual activity in connection the EnVen Acquisition, QuarterNorth Acquisition and TLCS Divestiture included in “Other current liabilities” and “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of March 31, 2024 (in thousands):
Severance accrual at December 31, 2023
6,295
Accrual additions
17,914
Benefit payments
(10,258
Severance accrual at March 31, 2024
13,951
13,876
75
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. The Company expects to incur an additional $7.4 million in severance expense related to the QuarterNorth Acquisition. Involuntary termination benefits are also being provided pursuant to contractual termination benefits required by the terms of existing employment agreements. 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 three months ended March 31, 2024:
RestrictedStock Units
Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2023
2,306,361
14.89
Granted
1,435,516
13.27
Vested
(1,357,605
13.56
Forfeited
(41,691
15.14
Unvested RSUs at March 31, 2024(1)
2,342,581
14.66
Performance Share Units (“PSUs”) — The following table summarizes PSU activity under the 2021 LTIP for the three months ended March 31, 2024:
PerformanceShare Units
Unvested PSUs at December 31, 2023
1,016,649
21.30
(48,995
20.16
Unvested PSUs at March 31, 2024
967,654
21.36
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 (used in) operating activities” on the Condensed Consolidated Statements of Cash Flows.
The following table presents the amount of costs expensed and capitalized (in thousands):
Share-based compensation costs
4,615
7,191
Less: Amounts capitalized to oil and gas properties
1,861
3,253
Total share-based compensation expense
The Company is a corporation that is subject to U.S. federal, state and foreign income taxes.
For the three months ended March 31, 2024, the Company recognized an income tax benefit of $21.6 million for an effective tax rate of 16.1%. The Company’s effective tax rate of 16.1% is different than the U.S. federal statutory income tax rate of 21% primarily due to permanent differences. For the three months ended March 31, 2023, the Company recognized an income tax benefit of $46.5 million for an effective tax rate of -107.4%. The Company’s effective tax rate of -107.4% 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. The release of the valuation allowance was a result of the deferred tax liabilities acquired with the EnVen Acquisition.
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’s valuation allowance primarily relates to various state operating loss carryforwards. A deferred tax liability of $240.6 million and $92.2 million is included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of March 31, 2024 and December 31, 2023, respectively.
QuarterNorth Acquisition
On March 4, 2024, the Company completed the QuarterNorth Acquisition, which is further discussed in Note 2 — Acquisitions and Divestitures. The Company recognized a net deferred tax liability of $168.5 million in its purchase price allocation as of the acquisition date to reflect differences between tax basis and the fair value of QuarterNorth’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. The Company recorded a current tax payable of $11.9 million related to QuarterNorth’s 2023 U.S. federal income tax liability, which is included in “Accounts payable” on the Condensed Consolidated Balance Sheets.
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):
Weighted average common shares outstanding — basic
Dilutive effect of securities
1,316
Weighted average common shares outstanding — diluted
Anti-dilutive potentially issuable securities excluded from diluted common shares
2,789
983
Registration Rights Agreements
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 2023 Annual Report. Bain held approximately 8.2% of the Company’s outstanding shares of common stock as of March 31, 2024 based on SEC beneficial ownership reports filed by Bain. Adage ceased being a beneficial owner of more than five percent of the Company’s common stock as of December 31, 2023 based on a SEC beneficial ownership report filed by Adage in February 2024.
In connection with the Company’s entry into the QuarterNorth Merger Agreement, on March 4, 2024, the Company entered into a registration rights agreement (the “QNE Registration Rights Agreement”) with certain stockholders of QuarterNorth listed on Schedule A attached thereto (collectively, the “RRA Holders”). Pursuant to the QNE Registration Rights Agreement, the Company granted the RRA Holders certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock received in connection with the QuarterNorth Acquisition, subject to certain customary thresholds and conditions. The shelf registration statement on Form S-3 (File No 333-277867), including the prospectus forming part thereof, was filed with the SEC shortly after the closing of the QuarterNorth Acquisition. The selling stockholders named in the prospectus collectively beneficially owned approximately 13.5% of the Company’s common stock outstanding as of March 8, 2024, a majority of which was held by the RRA Holders. No individual selling stockholder named in the prospectus owned more than five percent of the Company’s common stock.
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 months ended March 31, 2024 and 2023, the Company did not incur any such fees.
Slim Family
Carlos Slim Helú, Carlos Slim Domit, Marco Antonio Slim Domit, Patrick Slim Domit, María Soumaya Slim Domit, Vanessa Paola Slim Domit and Johanna Monique Slim Domit (collectively, the “Slim Family”) are beneficiaries of a Mexican trust which in turn owns all of the outstanding voting securities of Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial” together with the Slim Family, the “Slim Family Office”). Control Empresarial, a sociedad anónima de capital variable organized under the laws of the United Mexican States, is a holding company with portfolio investments in various companies. Control Empresarial and the Slim Family became related parties on November 7, 2023 when they accumulated greater than ten percent of the Company’s outstanding shares of common stock. In connection with the Company’s upsized underwritten public offering during January 2024 of 34.5 million shares of the Company’s common stock, Control Empresarial increased their holding of the Company’s outstanding stock. Control Empresarial held approximately 19.5% of the Company’s outstanding shares of common stock as of March 31, 2024 based on SEC beneficial ownership reports filed by Control Empresarial.
In connection with the Debt Offering in February 2024, the Company consummated a firm commitment debt offering consisting of $1,250.0 million in aggregate principal amount of second-priority senior secured notes in a private offering to eligible purchasers that was exempt from registration under the Securities Act. In connection with the Debt Offering, and after expressing a non-binding indication of interest after commencement of the offering, entities and/or persons related to the Slim Family Office purchased an aggregate principal amount of $312.5 million of such notes from the initial purchasers of such offering. In connection with such transaction, the Company expects to pay Inbursa, a banking institution controlled by the Slim Family Office, an advisory fee of approximately $2.7 million. See Note 7 – Debt for additional information regarding the Debt Offering.
The Slim Family own a majority stake in Grupo Carso, which indirectly has an ownership interest in Talos Mexico. The Company had no related party receivable from affiliates of the Slim Family as of March 31, 2024.
Equity Method Investments
The Company had a $2.3 million and $5.5 million related party receivable from various equity method investments as of March 31, 2024 and December 31, 2023, respectively. This is reflected as “Other, net” within “Accounts Receivable” on the Consolidated Balance Sheets. See Note 6 – Equity Method Investments for additional information on the Company’s equity method investments.
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 and removal of facilities in the U.S. Gulf of Mexico.
As of March 31, 2024, the Company had secured performance bonds from third party sureties totaling $1.5 billion. The cost of securing these bonds is reflected as “Interest expense” on the Condensed Consolidated Statements of Operations. Additionally, as of March 31, 2024, 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 7 — Debt for further information on the Bank Credit Facility.
Firm Transportation Commitments
In connection with the QuarterNorth Acquisition, the Company assumed a firm transportation agreement with a pipeline carrier for future transportation of oil production from the Katmai Field. Under the firm agreement, we are obligated to transport a minimum monthly oil volume or pay for any deficiencies. The future minimum transportation under the Company’s commitment totals approximately $22.0 million for years 2025 through 2028. Our production is currently expected to exceed the minimum monthly volume in the periods provided in the agreement.
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.
U.S. Specialty Insurance Company (“USSI”) has issued approximately $80.0 million in surety bonds on behalf of QuarterNorth, as Principal. USSI claims that collateral equivalent to the amount of the bonds is now required due to the merger of QuarterNorth into the Company. On March 20, 2024, USSI filed suit to require QuarterNorth to provide collateral in the amount of the bonds to secure QuarterNorth’s alleged obligations owed to USSI. Furthermore, USSI has notified certain purchasers of QuarterNorth’s production that USSI believes QuarterNorth is in default of its obligations and has requested that payment for production that is owed to QuarterNorth be made to USSI. Certain buyers of QuarterNorth’s production have withheld payment to QuarterNorth until this matter is resolved. The Company expects to replace most or all of the bonds issued by USSI during the second quarter of 2024, which will substantially or fully resolve this matter.
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.” The litigation was assumed as part of the EnVen Acquisition. The Company paid the judgment of $14.4 million, inclusive of Mr. Dunwoody’s legal fees and interest, during the three months ended March 31, 2024.
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):
15,564
54,269
Additions
266
Obligations assumed
1,326
855
11,613
Settlements
(3,506
(50,584
14,239
Less: Current portion
3,280
Long-term portion
10,239
12,284
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.
24
From January 1, 2024 through March 18, 2024, the Company’s operations were managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The CCS Segment was divested in March 2024. The Upstream Segment was 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. During the quarter ended March 31, 2024, the CCS Segment did not meet any of the reportable segment quantitative thresholds. The profit or loss metric used to evaluate segment performance was 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; and non-cash equity-based compensation expense.
Corporate general and administrative expense includes certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each operating segment. A portion of these expenses were 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. From January 1, 2024 through March 18, 2024, the accounting policies of the segments were the same as those described in Note 2 – Summary of Significant Accounting Policies included in the accompanying Notes to Consolidated Financial Statements in the 2023 Annual Report.
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.
The following table presents selected segment information for the periods indicated (in thousands):
Upstream
All Other(1)
Revenues from External Customers:
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method:
(84
(7,970
132
(1,277
(1,145
Adjusted EBITDA:
269,334
(9,872
259,462
210,483
(6,157
204,326
Segment Expenditures:
143,848
17,519
161,367
190,024
21,189
211,213
Reconciliations
The following table presents the reconciliation of Adjusted EBITDA to the Company’s consolidated totals (in thousands):
Total for reportable segments
All other
(1,786
(1,263
(215,664
(147,323
(26,903
(19,414
Transaction and other income (expenses)(1)
49,157
(22,009
Decommissioning obligations(2)
(855
(741
Derivative fair value gain (loss)(3)
Net cash (received) paid on settled derivative instruments (3)
3,494
12,323
Gain (loss) on debt extinguishment
(60,256
Non-cash equity-based compensation expense
(2,754
(3,938
Income (loss) before income taxes
The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands):
Total reportable segments
Change in capital expenditures included in accounts payable and accrued liabilities
34,262
(55,969
Plugging & abandonment
Decommissioning obligations settled
(708
Investment in CCS intangibles and equity method investees
(21,189
Deferred Payments
Non-cash well equipment transfers
(19,402
Other
52
130
146,077
103,962
26
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our,” “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 2023 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 2023 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. 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 have historically focused our oil and gas exploration and production 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.
From January 1, 2024 through March 18, 2024, we had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”), of which the Company’s only reportable segment was the Upstream Segment. Subsequent to the TLCS Divestiture (as defined herein) and our sale of the entire CCS business, we had one operating segment. See additional information in Part I, Item 1. “Financial Statements — Note 14 — Segment Information.”
Significant Developments
The following significant developments have occurred since the filing of our 2023 Annual Report.
Talos Low Carbon Solutions Divestiture— On March 18, 2024, we entered into a definitive agreement relating to and subsequently completed the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC, to TotalEnergies E&P USA, Inc. for a purchase price of $125.0 million plus customary reimbursements and adjustments, combined totaling approximately $142.0 million (the “TLCS Divestiture”). The TLCS Divestiture includes Talos’s entire CCS business, including its equity investments in three projects along the U.S. Gulf Coast: Bayou Bend CCS LLC; Harvest Bend CCS LLC; and Coastal Bend CCS LLC. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for more information.
QuarterNorth Acquisition — We executed an agreement and plan of merger, dated as of January 13, 2024, by and among Talos, QuarterNorth Energy Inc. (“QuarterNorth”), Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (the “QuarterNorth Merger Agreement”) to acquire QuarterNorth, a privately-held U.S. Gulf of Mexico exploration and production company (such acquisition, the “QuarterNorth Acquisition”). On March 4, 2024, the Company completed the QuarterNorth Acquisition for consideration consisting of (i) $1,247.4 million in cash and (ii) 24.3 million shares of the Company’s common stock valued at $322.6 million. The cash payment was partially funded with an upsized underwritten public offering of 34.5 million shares of the Company’s common stock, borrowings under the Bank Credit Facility and the New Senior Notes (each as defined below). 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.
QuarterNorth Acquisition — On March 4, 2024, we acquired QuarterNorth, a private operator in the Deepwater U.S. Gulf of Mexico. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for more information.
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.
Known Trends and Uncertainties
See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2023 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 2023 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, 2024 through March 31, 2024, the daily spot prices for NYMEX WTI crude oil ranged from a high of $84.39 per Bbl to a low of $70.62 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $13.20 per MMBtu to a low of $1.25 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 March 31, 2024.
The U.S. Energy Information Administration (“EIA”) published its April 2024 Short-Term Energy Outlook on April 9, 2024. The EIA expectations for global oil prices have increased since its last short-term energy outlook report reflecting its expectation of strong global oil inventory draws during the second quarter of 2024 and ongoing geopolitical risks. Oil prices continued to increase in March because of heightened geopolitical risk related to the attacks targeting commercial ships transiting the Red Sea shipping channel and general elevated tensions around the region, including the Israel-Hamas war. In addition, the recent extension of OPEC Plus voluntary production cuts, which expire at the end of June 2024, add to upward price pressure at a time of the year when oil demand typically increases because of the spring and summer driving seasons in the Northern Hemisphere. The EIA expects the NYMEX WTI spot price will average $85.30 per Bbl in the second quarter of 2024 and $83.78 per Bbl for all of 2024. The U.S. winter natural gas withdrawal season ended with more natural gas in storage compared with the five-year average. The large storage surplus contributed to low natural gas prices throughout the first quarter of 2024. From April through October this year, the EIA forecasts less natural gas will be injected into storage than is typical, largely because they expect the United States will produce less natural gas on average in the second and third quarter of 2024 compared with the first quarter of 2024. Despite lower production, the EIA still expects the United States will have the most natural gas in storage on record when the winter withdrawal season begins in November 2024. As a result of high inventories, the EIA expects spot natural gas prices to average less than $2.00 per MMBtu in the second quarter of 2024 and $2.15 per MMBtu for all of 2024.
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. In 2022 and 2023, the Fed raised its benchmark interest rate 11 times. The latest interest rate hike in July 2023 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 it is still high in absolute terms. Future changes to the benchmark interest rate 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 months ended March 31, 2024 and 2023, we did not recognize an impairment based on the ceiling test computations. At March 31, 2024 our ceiling test computation was based on SEC pricing of $78.19 per Bbl of oil, $2.50 per Mcf of natural gas and $17.08 per Bbl of NGLs.
If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning April 1, 2023 and ending March 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $70.45 per Bbl of oil, $2.25 per Mcf of natural gas and $15.37 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $446.5 million.
28
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 2023 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.
Third Party Planned Downtime — Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the HP-I that is operated by Helix Energy Solutions Group, Inc. (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field. The next dry-dock is scheduled for the second quarter of 2024 with an estimated shut-in lasting approximately 55 days.
BOEM Bonding Rule — On April 15, 2024, BOEM issued its final rule, entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations,” which significantly increases the amount of new supplemental financial assurance required from lessees and grant holders conducting operations on the federal outer continental shelf (“OCS”). The final rule replaces the prior five-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead requires lessees to meet one of two criteria based on: (1) the credit rating of the lessee or (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. As a result of the new rule, BOEM will no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders. The final rule, effective 60 days following publication in the Federal Register, adopts a three-year phased compliance period for full payment of a supplemental financial assurance demand.
As discussed in our 2023 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 new rule. If we are unable to comply with these requirements, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including assessing civil penalties, commencing proceedings to suspend our production and other operations or cancelling our affected federal offshore leases. In addition, as a result of continuing adverse developments in restructurings and bankruptcies of companies operating in the OCS, a number of bonding companies have left the offshore surety market over the last nine months, which has materially reduced the availability of surety bonds for projects in the OCS. As a result, there may not be sufficient surety bonds capacity available for companies in the OCS to comply with the new financial assurances rule. Our inability to obtain adequate supplemental financial assurance in order to comply with BOEM’s final rule, including the future cost of compliance with respect to supplemental bonding, could materially and adversely affect our financial condition, cash flows, business, properties, liquidity and results of operations.
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, BOEM prepares and maintains 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. As required by the Inflation Reduction Act of 2022, BOEM held Lease Sale 261 under the 2017-2022 national program on December 20, 2023, in which we were the high bidder on thirteen offshore blocks and QuarterNorth was the high bidder on four offshore blocks. We and QuarterNorth were awarded leases on all seventeen of these high-bid blocks.
The 2024-2029 national program starts on July 1, 2024, and continues through June 30, 2029. It is possible, however, that the final program could be delayed by opposing lawsuits that were filed on February 12, 2024, by the American Petroleum Institute and by Earthjustice representing multiple environmental groups, both of which are challenging BOEM’s actions. Despite these challenges, on April 1, 2024, BOEM announced the availability of the Area Identification for proposed lease sales 262, 263 and 264 pursuant to the 2024-2029 national program. Lease Sale 262 is tentatively scheduled for 2025.
29
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:
Results of Operations
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):
Change
100,527
3,515
3,308
107,350
Production Volumes:
Oil (MBbls)
5,173
4,106
1,067
Natural gas (MMcf)
8,659
7,127
1,532
NGL (MBbls)
632
429
203
Total production volume (MBoe)
7,248
5,723
1,525
Daily Production Volumes by Product:
Oil (MBblpd)
56.8
45.6
11.2
Natural gas (MMcfpd)
95.2
79.2
16.0
NGL (MBblpd)
6.9
4.8
2.1
Total production volume (MBoepd)
79.6
63.6
Average Sale Price Per Unit:
Oil (per Bbl)
76.02
71.28
4.74
Natural gas (per Mcf)
2.74
2.83
(0.09
NGL (per Bbl)
20.59
22.62
(2.03
Price per Boe
59.32
56.37
2.95
Price per Boe (including realized commodity derivatives)
58.84
54.21
4.63
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 March 31, 2024 vs 2023
Price
Volume
24,471
76,056
(821
4,336
(1,284
4,592
22,366
84,984
30
Three Months Ended March 31, 2024 and 2023 Volumetric Analysis — Production volumes increased by 16.0 MBoepd to 79.6 MBoepd. The increase was primarily due to 7.4 MBoepd of production from the oil and natural gas assets acquired from the QuarterNorth Acquisition that closed in early March 2024 as well as 6.9 MBoepd from the EnVen Acquisition that closed mid-first quarter of 2023. Additionally, there was 10.2 MBoepd production from the Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023. These increases were partially offset by a decrease of 6.9 MBoepd due to well performance and natural production declines. Additionally, there was approximately 2.0 MBoepd of deferred production resulting from third party infrastructure downtime primarily from our Lobster Field located in our Mississippi Canyon core area.
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):
Lease operating expenses
Lease operating expenses per Boe
18.65
14.22
Three Months Ended March 31, 2024 and 2023 — Lease operating expense for the three months ended March 31, 2024 increased by approximately $53.8 million, or 66%. This was related to an increase of $34.0 million primarily due to major well workover expenses at the Phoenix Field and the Garden Banks 506 Field. Additionally, there was a $12.8 million increase in lease operating expenses incurred in connection with assets acquired from the QuarterNorth Acquisition as well as a $8.8 million increase in direct lease operating expenses due to the EnVen Acquisition that closed mid-first quarter of 2023.
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 March 31, 2024 and 2023 — Depreciation, depletion and amortization expense for the three months ended March 31, 2024 increased by approximately $68.3 million, or 46% due to increased production volumes, which are described above. Additionally, the depletion rate increased by $4.07 per Boe, or 16%, on our proved oil and natural gas properties.
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):
Upstream Segment
56,082
58,355
CCS Segment
1,965
3,329
Unallocated corporate
11,794
1,503
Total general and administrative expense
Upstream general and administrative expense per Boe
7.74
10.20
Three Months Ended March 31, 2024 and 2023 — General and administrative expense for the three months ended March 31, 2024 increased by approximately $6.7 million, or 11%. This increase was primarily related to first quarter 2024 Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $30.6 million or $4.22 per Boe. Additionally, unallocated corporate had an increase during the first quarter 2024 in transaction costs and severance costs of $9.8 million related to the TLCS Divestiture. These increases were partially offset by a decrease in the Upstream Segment transaction costs for the EnVen Acquisition of $35.4 million or $6.19 per Boe. Additionally, the CCS Segment expenses decreased by $1.4 million due to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for further discussion.
31
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):
50,845
37,581
Other (income) expense
55,896
(6,666
Income tax (benefit) expense
(21,573
(46,543
Three Months Ended March 31, 2024 and 2023 —
Accretion Expense — During the three months ended March 31, 2024, we recorded $26.9 million of accretion expense compared to $19.4 million during the three months ended March 31, 2023. The change is primarily the result of a $4.2 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition and EnVen Acquisition. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”
Other Operating (Income) Expense — During the three months ended March 31, 2024, we recognized a gain of $86.9 million on the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for further discussion.
Interest Expense — During the three months ended March 31, 2024, we recorded $50.8 million of interest expense compared to $37.6 million during the three months ended March 31, 2023. The change is primarily the result of an increase in incremental debt outstanding offset by a lower rate of interest on these instruments. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information. Additionally, there was an increase of $4.9 million of fees associated with the unutilized bridge loan. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for more information.
Price Risk Management Activities — The expense of $87.1 million for the three months ended March 31, 2024 consists of $83.6 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $3.5 million in cash settlement losses. The income of $58.9 million for the three months ended March 31, 2023 consists of $71.3 million in non-cash gains from the increase in the fair value of our open derivative contracts partially offset by $12.3 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.”
Equity Method Investment Income — During the three months ended March 31, 2024, we recorded equity losses of $8.1 million. During the three months ended March 31, 2023, we recorded equity losses of $1.1 million offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron.
Other (Income) Expense — During the three months ended March 31, 2024, we recorded a $60.3 million loss on extinguishment of debt because of the redemption of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) and 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”). See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.
Income Tax (Benefit) Expense — During the three months ended March 31, 2024, we recorded $21.6 million of income tax benefit primarily due to current year activity inclusive of permanent differences compared to $46.5 million of income tax benefit during the three months ended March 31, 2023. The income tax benefit recorded during the three months ended March 31, 2023 is primarily due to a non-cash tax benefit related to the partial release of the valuation allowance on our U.S. federal deferred tax assets. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 — 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:
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):
EBITDA
159,400
247,635
Transaction and other (income) expenses(1)
(49,157
22,009
741
Derivative fair value (gain) loss(3)
Net cash received (paid) on settled derivative instruments(3)
(Gain) loss on debt extinguishment
Adjusted EBITDA
257,676
203,063
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 made it more expensive to borrow money. As of March 31, 2024, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $650.2 million.
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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.
Our liquidity could be impacted in the future by financial assurance requirements. See “Known Trends and Uncertainties — BOEM Bonding Rule.”
Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the three months ended March 31, 2024 (in thousands):
U.S. drilling & completions
44,081
Asset management(1)
24,982
Seismic and G&G, land, capitalized G&A and other
43,372
Total Upstream capital expenditures
112,435
27,907
Decommissioning obligations settled(2)
3,506
Total Upstream
Investment in CCS
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 2024 Upstream capital spending program of $570.0 million to $600.0 million and plugging & abandonment and decommissioning obligations of $90.0 million to $100.0 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. There were no shares of common stock repurchased during the three months ended March 31, 2024. As of March 31, 2024, there is $52.5 million remaining under the authorized program. All repurchased shares are held in treasury. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022 applies to our share repurchase program.
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.
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):
Operating activities
Investing activities
Financing activities
Operating Activities — Net cash provided by operating activities increased $33.6 million in the three months ended March 31, 2024 compared to the corresponding period in 2023 primarily attributable to an increase from revenues offset with an increase in lease operating expense of $53.5 million. Additionally, there was an increase in settlements of asset retirement obligations of $17.8 million.
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Investing Activities — Net cash used in investing activities increased $830.7 million in the three months ended March 31, 2024 compared to the corresponding period in 2023 primarily due to cash paid for the QuarterNorth Acquisition of $916.0 million, net of cash acquired. This was offset by cash proceeds of $142.0 million from the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information. Additionally, there was an increase in capital expenditures of $42.1 million.
Financing Activities — Cash flow from financing activities changed $712.5 million in the three months ended March 31, 2024 compared to the corresponding period in 2023. During the three months ended March 31, 2024, the issuance of the New Senior Notes in February 2024 generated $1,224.5 million after deferred financing costs. The net proceeds from the New Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information. Additionally, on January 17, 2024, we entered into upsized underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition.
Overview of Debt Instruments
9.000% Second-Priority Senior Secured Notes — due February 2029 — The 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.
9.375% Second-Priority Senior Secured Notes — due February 2031 — The 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “New Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.
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 7 — Debt” for more information.
Redemption of the 12.00% Second-Priority Senior Secured Notes — due January 2026 — On February 7, 2024, we redeemed $638.5 million aggregate principal amount of the 12.00% Notes using the proceeds from the issuance of the New Senior Notes. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.
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Redemption of the 11.75% Senior Secured Second Lien Notes — due April 2026 — We redeemed $227.5 million aggregate principal amount of the 11.75% Notes using the proceeds from the issuance of the New Senior Notes. On February 7, 2024, the Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee. Concurrently, the Company elected to satisfy and discharge the 11.75% Notes in accordance with its terms and the trustee acknowledged such discharge and satisfaction. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.
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.
The following table and discussion summarize our material cash requirements from known contractual obligations as of March 31, 2024 (in thousands):
2025
Thereafter
Total(4)
Long-term financing obligations:
Debt principal
Debt interest
85,569
144,904
122,359
114,844
174,609
787,189
Vessel commitments(1)
35,748
14,210
49,958
Derivative liabilities
63,991
13,789
Operating lease obligations
4,220
5,531
4,983
4,753
4,610
4,583
28,680
Finance lease(2)
35,136
19,520
54,656
Purchase obligations(3)
118,251
550
118,801
Other commitments
2,108
Total contractual obligations(4)
345,023
198,504
149,887
452,112
119,454
1,429,192
2,694,172
Performance Obligations — As of March 31, 2024, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico. 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 7 — Debt” for further information on the Bank Credit Facility.
Critical Accounting Estimates
We consider accounting policies related to oil and natural gas properties, proved reserve estimates, fair value measure of financial instruments, asset retirement obligations, revenue recognition, imbalances and production handling fees and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting estimates from those disclosed in our 2023 Annual Report under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates.”
Recently Adopted Accounting Standards
None.
Recently Issued Accounting Standards
No recently issued accounting standards were material to us.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2023 Annual Report. Except as discussed below, there have been no material changes from the disclosures presented in our 2023 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 16,569 MBbls of crude oil and 29,677 MMBtu of natural gas at March 31, 2024, with a net derivative liability position of $53.7 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 March 31, 2024 (in thousands):
Ten Percent Increase
Ten Percent Decrease
Fair Value
Price impact(1)
(175,027
(121,355
68,688
122,360
Item 4. Controls and Procedures
Disclosure Controls and Procedures
Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2024.
Internal Control over Financial Reporting
On March 4, 2024, we completed the QuarterNorth Acquisition. Other than integrating the acquired operations of QuarterNorth into our overall internal control over financial reporting and related processes, there were no other 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 March 31, 2024 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II – OTHER INFORMATION
Item 1. Legal Proceedings
There have been no additional material developments with respect to the information previously reported under Part I, Item 3. “Legal Proceedings” of our 2023 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 2023 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 2023 Annual Report or our other SEC filings.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
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 March 31, 2024. As of March 31, 2024, there is $52.5 million remaining under the authorized program.
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
During the three months ended March 31, 2024, 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.
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).
2.2#
Agreement and Plan of Merger, dated as of January 13, 2024, by and among Talos Energy Inc., QuarterNorth Energy Inc., Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024).
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
Indenture, dated as of February 7, 2024, and by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee, pursuant to which the 2029 Notes were issued. (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 7, 2024).
4.4
First Supplemental Indenture, dated as of March 4, 2024, by and among Talos Production Inc., each of the guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (9.000% Senior Notes) (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 5, 2024).
4.5
Indenture, dated as of February 7, 2024, and by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee, pursuant to which the 2031 Notes were issued. (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 7, 2024).
4.6
First Supplemental Indenture, dated as of March 4, 2024, by and among Talos Production Inc., each of the guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (9.375% Senior 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 March 5, 2024).
4.7
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).
Form of 9.000% Second-Priority Senior Secured Note due 2029 (included as Exhibit A to Exhibit 4.4 hereto) (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 7, 2024).
4.9
Form of 9.375% Second-Priority Senior Secured Note due 2031 (included as Exhibit A in Exhibit 4.5 hereto) (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 7, 2024).
4.10
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).
4.11
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).
4.12
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).
4.13
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).
4.14
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).
4.15
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).
4.16
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).
4.17
Registration Rights Agreement, dated as of March 4, 2024, by and among Talos Energy Inc. and each of 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 March 5, 2024).
10.1#
Form of QuarterNorth Support Agreement, by and among QuarterNorth Energy Inc., Talos Energy Inc. and the other parties thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024).
10.2†
Form of Indemnification Agreement (Directors and Officers) (incorporated by reference to Exhibit 10.12 to Talos Energy’s Inc. 10-K (File No. 001-38497) filed with the SEC on February 28, 2024).
10.3
Tenth Amendment to Credit Agreement, dated January 13, 2024, by and among Talos Energy Inc., as Holdings and a Guarantor, Talos Production Inc., as the Borrower, the other Guarantors party thereto, JPMorgan Chase, N.A., as the Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.33 to Talos Energy’s Inc. 10-K (File No. 001-38497) filed with the SEC on February 28, 2024).
10.4†*
Form of Separation and Release Agreement.
31.1*
Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.
101.INS*
Inline XBRL Instance.
101.SCH*
Inline XBRL Taxonomy Extension Schema.
101.CAL*
Inline XBRL Taxonomy Extension Calculation.
101.DEF*
Inline XBRL Taxonomy Extension Definition.
101.LAB*
Inline XBRL Taxonomy Extension Label.
101.PRE*
Inline XBRL Taxonomy Extension Presentation.
104*
Cover Page Interactive Date File (Embedded within the Inline XBRL document and included in Exhibit 101).
40
*
Filed herewith.
**
Furnished herewith.
†
Identifies management contracts and compensatory plans or arrangements.
#
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.
41
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Date:
May 6, 2024
By:
/s/ Sergio L. Maiworm, Jr.
Sergio L. Maiworm, Jr.
Chief Financial Officer and Executive Vice President