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, 2023
OR
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number: 001-38497
Talos Energy Inc.
(Exact Name of Registrant as Specified in its Charter)
Delaware
82-3532642
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
333 Clay Street, Suite 3300
Houston, TX
77002
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: (713) 328-3000
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol(s)
Name of Each Exchange on Which Registered
Common Stock
TALO
New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
As of May 01, 2023, the registrant had 125,555,965 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.
Condensed Consolidated 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
12
Note 3 — Property, Plant and Equipment
13
Note 4 — Leases
14
Note 5 — Financial Instruments
15
Note 6 — Debt
17
Note 7 — Employee Benefits Plans and Share-Based Compensation
18
Note 8 — Income Taxes
19
Note 9 — Income (Loss) Per Share
Note 10 — Related Party Transactions
20
Note 11 — Commitments and Contingencies
21
Note 12 — Segment Information
22
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
25
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
36
Item 4.
Controls and Procedures
PART II — OTHER INFORMATION
Legal Proceedings
37
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
38
Defaults Upon Senior Securities
Mine Safety Disclosures
Item 5.
Other Information
Item 6.
Exhibits
39
Signatures
41
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.
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-K.
SEC — The U.S. Securities and Exchange Commission.
SEC pricing — The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for each month within the 12-month period prior to the end of the reporting period, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).
Shelf — Water depths of up to 600 feet.
Working interest — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
WTI or West Texas Intermediate — A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and the sulfur content is approximately 0.3%.
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 due to the continued impact of the coronavirus disease 2019 (“COVID-19”), including any new strains or variants, and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business; the ability or willingness of OPEC and other state-controlled oil companies (“OPEC Plus”), such as Saudi Arabia and Russia, to set and maintain oil production levels; the impact of any such actions; the lack of a resolution to the war in Ukraine and its impact on certain commodity markets; lack of transportation and storage capacity as a result of oversupply, government and regulations; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes and winter storms; cybersecurity threats; sustained inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations, and the other risks discussed in Part I, Item 1A. “Risk Factors” of Talos Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on March 01, 2023 (the “2022 Annual Report”) and Part II, Item IA. “Risk Factors” of this Quarterly 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, 2023
December 31, 2022
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents
$
16,169
44,145
Accounts receivable:
Trade, net
169,850
150,598
Joint interest, net
80,549
54,697
Other, net
17,954
6,684
Assets from price risk management activities
54,553
25,029
Prepaid assets
60,127
84,759
Other current assets
11,901
1,917
Total current assets
411,103
367,829
Property and equipment:
Proved properties
7,368,652
5,964,340
Unproved properties, not subject to amortization
410,932
154,783
Other property and equipment
31,485
30,691
Total property and equipment
7,811,069
6,149,814
Accumulated depreciation, depletion and amortization
(3,653,556
)
(3,506,539
Total property and equipment, net
4,157,513
2,643,275
Other long-term assets:
Restricted cash
100,973
—
12,059
7,854
Equity method investments
22,023
1,745
Other well equipment inventory
40,345
25,541
Notes receivable, net
15,031
Operating lease assets
18,572
5,903
Other assets
18,136
6,479
Total assets
4,795,755
3,058,626
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable
184,471
128,174
Accrued liabilities
201,360
219,769
Accrued royalties
44,340
52,215
Current portion of long-term debt
33,201
Current portion of asset retirement obligations
45,592
39,888
Liabilities from price risk management activities
35,848
68,370
Accrued interest payable
31,210
36,340
Current portion of operating lease liabilities
3,129
1,943
Other current liabilities
92,041
60,359
Total current liabilities
671,192
607,058
Long-term liabilities:
Long-term debt
977,011
585,340
Asset retirement obligations
772,059
501,773
4,286
7,872
Operating lease liabilities
25,981
14,855
Other long-term liabilities
284,385
176,152
Total liabilities
2,734,914
1,893,050
Commitments and contingencies (Note 11)
Stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of March 31, 2023 and December 31, 2022
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,455,965 and 82,570,328 shares issued as of March 31, 2023 and December 31, 2022, respectively
1,275
826
Additional paid-in capital
2,531,402
1,699,799
Accumulated deficit
(445,189
(535,049
Treasury stock, at cost; 1,900,000 and zero shares as of March 31, 2023 and December 31, 2022, respectively
(26,647
Total stockholdersʼ equity
2,060,841
1,165,576
Total liabilities and stockholdersʼ equity
See accompanying notes.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended March 31,
2023
2022
Revenues:
Oil
292,694
353,886
Natural gas
20,183
42,981
NGL
9,705
16,699
Total revenues
322,582
413,566
Operating expenses:
Lease operating expense
81,362
59,814
Production taxes
606
851
Depreciation, depletion and amortization
147,323
98,340
Accretion expense
19,414
14,377
General and administrative expense
63,187
22,528
Other operating expense
2,838
136
Total operating expenses
314,730
196,046
Operating income
7,852
217,520
Interest expense
(37,581
(31,490
Price risk management activities income (expense)
58,937
(281,219
Equity method investment income
7,443
142
Other income
6,666
28,134
Net income (loss) before income taxes
43,317
(66,913
Income tax benefit
46,543
472
Net income (loss)
89,860
(66,441
Net income (loss) per common share:
Basic
0.85
(0.81
Diluted
0.84
Weighted average common shares outstanding:
105,634
82,071
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, 2021
81,881,477
819
1,676,798
(916,964
760,653
Equity-based compensation
5,389
Equity-based compensation tax withholdings
(4,476
Equity-based compensation stock issuances
653,709
(6
Net loss
Balance at March 31, 2022
82,535,186
825
1,677,705
(983,405
695,125
Balance at December 31, 2022
82,570,328
7,232
(7,378
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
Net income
Balance at March 31, 2023
127,455,965
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion expense
166,737
112,717
Amortization of deferred financing costs and original issue discount
4,148
3,415
Equity-based compensation expense
3,938
3,318
Price risk management activities expense (income)
(58,937
281,219
Net cash paid on settled derivative instruments
(12,323
(127,086
(7,443
(142
Settlement of asset retirement obligations
(10,113
(20,023
Changes in operating assets and liabilities:
Accounts receivable
36,821
(56,817
7,735
4,505
(4,894
9,381
(116,637
(26,423
Other non-current assets and liabilities, net
(36,035
(4,013
Net cash provided by operating activities
62,857
113,610
Cash flows from investing activities:
Exploration, development and other capital expenditures
(103,962
(53,978
Proceeds from (payments for) acquisitions, net of cash acquired
17,617
(3,500
Proceeds from sale of property and equipment, net
346
Contributions to equity method investees
(12,835
(2,250
Investment in intangible assets
(7,796
Net cash used in investing activities
(106,976
(59,382
Cash flows from financing activities:
Proceeds from Bank Credit Facility
275,000
35,000
Repayment of Bank Credit Facility
(110,000
(70,000
Deferred financing costs
(11,346
Payments of finance lease
(3,987
(6,256
(25,173
Employee stock awards tax withholdings
Net cash provided by (used in) financing activities
117,116
(45,732
Net increase in cash, cash equivalents and restricted cash
72,997
8,496
Cash, cash equivalents and restricted cash:
Balance, beginning of period
69,852
Balance, end of period
117,142
78,348
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities
174,597
53,317
Supplemental cash flow information:
Interest paid, net of amounts capitalized
40,988
43,352
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 both through oil and gas exploration and production (“Upstream”) and the development of carbon capture and sequestration (“CCS”) opportunities. The Company leverages decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, the Company also utilizes its expertise to explore opportunities to reduce industrial emissions through the Company’s CCS initiatives along the coast of the U.S. Gulf of Mexico.
Basis of Presentation and Consolidation
The Condensed Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Accordingly, certain information and disclosures normally included in complete financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, these financial statements include all adjustments, which unless otherwise disclosed, are of a normal recurring nature, necessary for a fair presentation of the financial position, results of operations, cash flows and changes in equity for the periods presented. The results for interim periods are not necessarily indicative of results for the entire year. The unaudited financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s audited Consolidated Financial Statements and accompanying notes included in the 2022 Annual Report.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
Segments
The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been designated as unrestricted, non-guarantor subsidiaries of the Company for purposes of the Bank Credit Facility (as defined in Note 5 — Financial Instruments) and indentures governing the senior notes. See additional information in Note 12 — Segment Information.
Summary of Significant Accounting Policies
The Company has provided a discussion of its significant accounting policies, estimates and judgements in Note 2 – Summary of Significant Accounting Policies included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report. The Company has not changed any of its other significant accounting policies from those described in our 2022 Annual Report except as set forth below.
Restricted Cash — The Company acquired funds held in escrow to be used for future plugging and abandonment (“P&A”) obligations assumed through the EnVen Acquisition (as defined below). These escrow accounts required deposits of approximately $100.0 million, which was fully funded by EnVen (as defined below) prior to the consummation of the acquisition. As of March 31, 2023, these escrow accounts have a combined balance of $101.0 million, inclusive of interest earned to date, and are reflected as “Restricted cash” within Other long-term assets on the Condensed Consolidated Balance Sheet.
Notes Receivable, net — The Company holds two notes receivables with an aggregate face value of $66.2 million which consist of commitments from the sellers of oil and natural gas properties, acquired by the Company as part of the EnVen Acquisition, related to the costs associated with its performance of the assumed P&A obligations (the “P&A Notes Receivable”). The P&A Notes Receivable are being accreted to their principal amounts and are presented as such, net of the related cumulative estimated credit losses, on the accompanying consolidated balance sheet. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.” During the three months ended March 31, 2023, the Company recognized interest income of $0.2 million and the carrying value of these P&A Notes Receivable, net of current expected credit losses, was $15.0 million as of March 31, 2023.
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 long term assets
Total cash, cash equivalent and restricted cash
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. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation.
EnVen Acquisition — On September 21, 2022, the Company executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). On February 13, 2023, the Company completed the EnVen Acquisition for consideration consisting of (i) $207.3 million in cash and (ii) 43.8 million shares of the Company’s common stock valued at $832.2 million. The cash payment was partially funded with borrowings under the Bank Credit Facility.
The following table summarizes the purchase price (in thousands except per share data):
Talos common stock
Talos common stock price per share(1)
19.00
Common stock value
Cash consideration
207,313
Total purchase price
1,039,511
The Company is still finalizing the fair value analysis related to the oil and natural gas properties acquired and asset retirement obligations assumed. The Company anticipates finalizing the determination of fair values by December 31, 2023.
The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on February 13, 2023 (in thousands):
Current assets
238,293
Property and equipment
1,464,833
100,753
14,844
Other long-term assets
43,981
(33,234
(7,079
(131,787
(233,836
(251,779
Deferred tax liabilities
(150,504
(14,974
Allocated purchase price
The Company incurred approximately $21.6 million of acquisition-related costs in connection with the EnVen Acquisition exclusive of severance expense, of which $12.6 million was recognized in the first quarter of 2023 and $9.0 million was recognized for the year ended December 31, 2022 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. See Note 7 — Employee Benefits Plans and Share-Based Compensation for additional discussion.
The following table presents revenue and net income attributable to the EnVen Acquisition for the period from February 13, 2023 to March 31, 2023:
Three Months Ended March 31, 2023
Revenue
62,059
(6,090
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 and 2022 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma information was derived from historical statements of operations of the Company and EnVen adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and to adjust the amortization of the premium of the 11.75% Notes (as defined below), (iii) general and administrative expense adjusted for transaction related costs incurred, (iv) other income (expense) to adjust the accretion of the discount on the P&A Notes Receivable and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for the three months ended March 31, 2022 were adjusted to include $78.9 million of general and administrative expenses, of which $16.3 million were incurred during the year ended December 31, 2022. 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.
374,625
587,774
118,090
(177,691
Basic net income (loss) per common share
0.93
(1.41
Diluted net income (loss) per common share
0.92
Proved Properties
During the three months ended March 31, 2023 and 2022, 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, 2023, the Company’s ceiling test computation was based on SEC pricing of $91.75 per Bbl of oil, $6.35 per Mcf of natural gas and $29.42 per Bbl of NGLs.
Asset Retirement Obligations
The asset retirement obligations included in the Condensed Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):
Asset retirement obligations at December 31, 2022
541,661
Obligations assumed
258,858
Obligations incurred
69
Obligations settled
Changes in estimate
7,762
Asset retirement obligations at March 31, 2023
817,651
Less: Current portion at March 31, 2023
Long-term portion at March 31, 2023
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
3,708
2,059
Operating lease cost, excluding short-term leases(1)
908
568
Short-term lease cost(2)
32,985
5,762
Variable lease cost(3)
363
Total lease cost
37,964
8,752
The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands):
Operating leases:
Total operating lease liabilities
29,110
16,798
Finance leases:
Proved property
166,261
16,642
16,306
144,740
149,064
Total finance lease liabilities
161,382
165,370
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
1,265
923
Right-of-use assets obtained in exchange for new operating lease liabilities(1)
12,971
As of March 31, 2023 and December 31, 2022, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because they are highly liquid or due to the short-term nature of these instruments.
Debt Instruments
The following table presents the carrying amounts, net of discount, premium and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands):
CarryingAmount
FairValue
12.00% Second-Priority Senior Secured Notes – due January 2026
590,349
678,354
590,132
674,542
11.75% Senior Secured Second Lien Notes – due April 2026(1)
266,629
271,276
Bank Credit Facility – matures March 2027
153,234
165,000
(4,792
The carrying value of the senior notes are adjusted for discount, premium and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.
The carrying amount of the Company’s bank credit facility, as amended and restated (the “Bank Credit Facility”), is presented net of deferred financing costs. The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).
Oil and Natural Gas Derivatives
The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production. The Company is currently utilizing oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Typical collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price (“two-way collar”).
In connection with the EnVen Acquisition, the Company assumed oil and natural gas collar contracts that combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these contracts, when the NYMEX average closing price is below the floor price, the Company receives the difference between the NYMEX average closing price and the floor price, capped at the difference between the floor price and the short put price.
The following table presents the impact that derivatives, not designated as hedging instruments, had on its Condensed Consolidated Statements of Operations (in thousands):
Unrealized gain (loss)(1)
71,260
(154,133
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, 2023:
Swap Contracts
Production Period
Settlement Index
Volumes
Swap Price
Crude oil:
(Bbls)
(per Bbl)
April 2023 – December 2023
NYMEX WTI CMA
16,862
74.04
January 2024 – December 2024
10,235
72.72
January 2025 – March 2025
4,000
67.00
Natural gas:
(MMBtu)
(per MMBtu)
NYMEX Henry Hub
26,287
3.56
16,216
3.46
10,000
4.37
Two-Way Collar Contracts
Floor Price
Ceiling Price
4,507
67.97
88.67
1,497
70.00
79.32
5.25
8.46
4.00
6.90
Three-Way Collar Contracts
Short Put Price
9,200
51.68
64.93
109.05
January 2024 – March 2024
3,200
57.27
98.01
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
66,612
Liabilities:
(40,134
Total net asset
26,478
32,883
(76,242
Total net liability
(43,359
Financial Statement Presentation
Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its Condensed Consolidated Balance Sheets. The following table presents the fair value of derivative financial instruments as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands):
Assets
Liabilities
Oil and natural gas derivatives:
Current
Non-current
Total gross amounts presented on balance sheet
40,134
76,242
Less: Gross amounts not offset on the balance sheet
35,662
Net amounts
30,950
4,472
43,359
16
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, 2023 represent derivative instruments from nine counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and eight of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities. Had the Company’s counterparties failed to perform under existing commodity derivative contracts the maximum loss at March 31, 2023 would have been $31.0 million.
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):
638,541
11.75% Senior Secured Second Lien Notes – due April 2026
257,500
Bank Credit Facility – matures March 2027(1)
Total debt, before discount, premium and deferred financing cost
1,061,041
Unamortized discount, premium and deferred financing cost, net
(50,829
(53,201
Total debt(2)
1,010,212
Less: Current portion of long-term debt
11.75% Senior Secured Second Lien Notes
On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount of $257.5 million. The 11.75% Notes mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.
Bank Credit Facility
The Company maintains the Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extends the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027 and includes a springing maturity commencing on the 91st day prior to the earliest stated maturity date of any of the junior lien notes if such junior lien notes have not been refinanced, redeemed or repaid in full, (ii) increases the borrowing base from $1.1 billion to $1.5 billion and (iii) increases commitments from $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.
EnVen Acquisition Severance
The following table summarizes severance accrual activity in connection the EnVen Acquisition included in “Other current liabilities” and “Other long-term liabilities” on the Condensed Consolidated Balance Sheets for the three months ended March 31, 2023:
Severance accrual at December 31, 2022
Accrual additions
22,630
Benefit payments
(3,186
Severance accrual at March 31, 2023
19,444
17,417
2,027
The above table includes involuntary termination benefits that are being provided pursuant to a one-time benefit arrangement that is being spread over the future service period through the termination date. Involuntary termination benefits are also being provided pursuant to contractual termination benefits required by the terms of existing employment agreements. Pursuant to the EnVen Merger Agreement, a rabbi trust was established and funded with $14.5 million at closing to pay a portion of future severance benefits associated with the contractual termination benefits. As of March 31, 2023, the rabbi trust held $12.0 million in assets of which $10.2 million and $1.8 million are included in “Other current assets” and “Other assets”, respectively, on the Condensed Consolidated Balance Sheets and both of which are included in the severance accrual at March 31, 2023 listed above. The assets of the rabbi trust are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Severance costs are reflected in “General and administrative expense” on the Condensed Consolidated Statements of Operations.
Long Term Incentive Plans
Restricted Stock Units (“RSUs”) — The following table summarizes RSU activity under the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”) for the three months ended March 31, 2023:
RSUs
Weighted AverageGrant Date FairValue
Unvested RSUs at December 31, 2022
3,215,504
12.79
Granted
1,078,062
16.26
Vested
(1,615,488
11.99
Forfeited
(24,258
16.94
Unvested RSUs at March 31, 2023(1)
2,653,820
14.65
Performance Share Units (“PSUs”) — The following table summarizes PSU activity under the 2021 LTIP for the three months ended March 31, 2023:
PSUs
Unvested PSUs at December 31, 2022
638,601
23.66
Granted(1)
569,800
18.97
Unvested PSUs at March 31, 2023
1,208,401
21.45
The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the absolute TSR PSUs granted at the date indicated:
Grant
March 5, 2023
Expected term (in years)
2.8
Expected volatility
73.1
%
Risk-free interest rate
4.5
Dividend yield
Fair value (in thousands)
6,165
Share-based Compensation Costs
Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and administrative expense,” on the Condensed Consolidated Statements of Operations, net amounts capitalized to “Proved Properties,” on the Condensed Consolidated Balance Sheets. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at “Net cash provided by operating activities” on the Condensed Consolidated Statements of Cash Flows.
The following table presents the amount of costs expensed and capitalized (in thousands):
Share-based compensation costs
7,191
5,652
Less: Amounts capitalized to oil and gas properties
3,253
2,334
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, 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 is a result of the deferred tax liabilities acquired with the EnVen Acquisition. For the three months ended March 31, 2022, the Company recognized an income tax benefit of $0.5 million for an effective tax rate of 0.7%. The Company’s effective tax rate of 0.7% is lower than the U.S. federal statutory income tax rate of 21% primarily due to recording a valuation allowance for its deferred tax assets.
The Company evaluates and updates the estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of the Company’s actual earnings compared to annual projections, the effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate. The tax effect of discrete items is recognized in the period in which they occur at the applicable statutory rate.
Deferred income tax assets and liabilities are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce deductions and income in the future. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. In evaluating the Company’s valuation allowance, the Company considers cumulative losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax optimization planning and future taxable income for each of its taxable jurisdictions. The Company assesses the realizability of its deferred tax assets quarterly; changes to the Company’s assessment of its valuation allowance in future periods could materially impact its results of operations. The Company maintains a partial valuation allowance against certain federal deferred tax assets in which it is more likely than not such assets will not be realized in a future period. The Company also maintains a full valuation allowance against its federal net deferred tax assets subject to separate return limitations, its state and its foreign net deferred tax assets. A deferred tax liability of $106.1 million and $2.1 million is included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of March 31, 2023 and December 31, 2022, respectively.
EnVen Acquisition
On February 13, 2023, the Company completed the EnVen Acquisition, which is further discussed in Note 2 — Acquisitions. The Company recognized a net deferred tax liability of $150.5 million in its purchase price allocation as of the acquisition date to reflect differences between tax basis and the fair value of EnVen’s assets acquired and liabilities assumed. The deferred tax balance is based on preliminary calculations and on information available to management at the time such estimates were made. Further analysis will be made upon filing the tax returns that will result in a change to the net deferred tax impact recorded.
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
983
3,329
Apollo Funds and Riverstone Funds
On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”) and members of management pursuant to which the Company received a private equity capital commitment. On January 3, 2022, the Apollo Funds ceased being a beneficial owner of more than five percent of the Company’s common stock. Riverstone Funds held 9.8% of the Company’s outstanding shares of common stock as of March 31, 2023 based on SEC beneficial ownership reports filed by the Riverstone Funds.
Registration Rights Agreements
Riverstone Funds as well as ILX Holdings, LLC; ILX Holdings II, LLC; ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate of the Riverstone Funds, are parties to an amended registration rights agreement relating to the registered resale of the Company’s common stock owned by such parties, a discussion of which is included in the accompanying Notes to the Consolidated Financial Statements in the 2022 Annual Report.
Adage Capital Partners, L.P. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”) are parties to a registration rights agreement entered into in connection with the EnVen Acquisition relating to the registered resale of the Company’s common stock owned by such parties, a discussion of which is included in the accompanying Notes to the Consolidated Financial Statements in the 2022 Annual Report. Adage and Bain held approximately 5.1% and 12.3%, respectively, of the Company’s outstanding shares of common stock as of March 31, 2023 based on SEC beneficial ownership reports filed by each of Adage and Bain.
The Company will bear all of the expenses incurred in connection with any offer and sale, while the selling stockholders will be responsible for paying underwriting fees, discounts and selling commissions. For the three months ended March 31, 2023 and 2022, the Company did not incur any such fees.
Amended and Restated Stockholders’ Agreement
On May 10, 2018, the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020, the Company and the other parties thereto amended the Stockholders’ Agreement (the “Stockholders’ Agreement Amendment”). On March 29, 2022, the Company and other parties thereto, entered into the Amended and Restated Stockholders’ Agreement, in connection with the termination of the Apollo Funds’ rights thereunder and the resignation of certain members of the Company's Board of Directors (the “Amended and Restated Stockholders’ Agreement”). A discussion of the Stockholders’ Agreement Amendment is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.
On February 13, 2023, in connection with the EnVen Acquisition, the Amended and Restated Stockholders’ Agreement was terminated and Mr. Robert M. Tichio resigned from the Company’s Board of Directors.
Riverstone Funds Support Agreement
On February 13, 2023, in connection with the EnVen Acquisition, the Company, EnVen and the Riverstone Funds entered into a support agreement, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.
Legal Fees
The Company has engaged the law firm Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at V&E. For the three months ended March 31, 2023 and 2022, the Company incurred fees for legal services performed by V&E of approximately $1.7 million and $0.5 million, respectively, of which $2.8 million and $0.6 million were payable at each respective balance sheet date.
Bayou Bend CCS LLC
On March 8, 2022, the Company made a $2.3 million cash contribution for a 50% membership interest in Bayou Bend CCS LLC (“Bayou Bend”). Bayou Bend has a CCS site located offshore Jefferson County, Texas, near Beaumont and Port Arthur, Texas industrial corridor that is in the early stages of development. In May 2022, the Company sold a 25% membership interest to Chevron U.S.A. Inc. (“Chevron”) for upfront cash consideration of $15.0 million. Chevron also agreed to fund up to $10.0 million of contributions to Bayou Bend on the Company’s behalf, which was fully funded as of March 31, 2023. The Bayou Bend investment was increased with an offsetting gain as the capital carry was funded by Chevron. The Company recognized an $8.6 million gain on the funding of the capital carry of its investment in Bayou Bend during the three months ended March 31, 2023, which is included in “Equity method investment income” on the Condensed Consolidated Statements of Operations.
Effective March 1, 2023, Chevron became the operator of Bayou Bend. The Company had a $0.1 million related party receivable from Bayou Bend as of March 31, 2023. During March 2023, Bayou Bend expanded its storage footprint through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located in the Houston Ship Channel, Beaumont and Port Arthur region.
As of March 31, 2023 the Company owns a 25% membership interest in Bayou Bend, which is a variable interest entity and accounted for using the equity method of accounting. The development of the Bayou Bend CCS hub project is currently being financed through equity contributions from its members. The Company’s maximum exposure to loss as result of its involvement with Bayou Bend is the carrying amount of its investment.
Performance Obligations
Regulations with respect to the Company's operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities in the U.S. Gulf of Mexico and certain obligations under the production sharing contracts with Mexico.
As of March 31, 2023, the Company had secured performance bonds from third party sureties totaling $1.4 billion. The cost of securing these bonds is reflected as “Interest expense” on the Condensed Consolidated Statements of Operations. Additionally, as of March 31, 2023, the Company had secured letters of credit issued under its Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Note 6 — Debt for further information on the Bank Credit Facility.
Legal Proceedings and Other Contingencies
From time to time, the Company is involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of business in jurisdictions in which the Company does business. Although the outcome of these matters cannot be predicted with certainty, the Company’s management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on the Company’s results from operations for a specific interim period or year.
On March 23, 2022, the Company entered into a settlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its claims in the litigation. The settlement is reflected as “Other income (expense)” on the Condensed Consolidated Statements of Operations.
The following proceedings represent previous EnVen litigation that was assumed as part of the EnVen Acquisition.
In June 2019, David M. Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation constituted “Good Reason” under his employment agreement dated as of November 6, 2015 (the “Employment Agreement”), and entitled him to the severance payments and benefits as set forth in his Employment Agreement for a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favor of Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen had filed a Notice of Appeal in December of 2021. In April 2023, the appellate court affirmed the trial court’s judgment. As of March 31, 2023, the Company has recorded $13.7 million as “Other current liabilities” on the Condensed Consolidated Balance Sheets related to the litigation.
In July 2019, EnVen filed a lawsuit against Mr. Dunwoody in Delaware Chancery Court for breach of fiduciary duty and equitable fraud relating to Mr. Dunwoody’s conduct while he was President of EnVen. In January 2020, EnVen filed an amended complaint that added claims against Oilfield Pipe of Texas, LLC for aiding and abetting Mr. Dunwoody’s breach of his fiduciary duty and equitable fraud. On April 21, 2022, the Delaware Chancery Court denied Mr. Dunwoody’s renewed motion to dismiss and the parties are engaged in discovery. The Delaware Chancery Court has scheduled the trial for July 2023. The Company may recognize additional liabilities and expenses in future periods related to this litigation with Mr. Dunwoody.
Decommissioning Obligations
The Company has divested various leases, wells and facilities located in the U.S. Gulf of Mexico where the purchasers typically assume all abandonment obligations acquired. Certain counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Under certain circumstances, regulations or federal laws could require the Company to assume such obligations. The Company 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):
54,269
24,336
Additions
8,900
741
22,658
Settlements
(708
(1,625
54,302
Less: Current portion
42,334
42,069
Long-term portion
11,968
12,200
Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise its opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on its results of operations in the period in which the amounts are accrued and its cash flows in the period in which the amounts are paid.
The Company’s operations are managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The Upstream Segment is the Company’s only reportable segment. The Company’s chief operating decision-maker (“CODM”) is the President and Chief Executive Officer, who reviews operating results to make decisions about allocating resources and assessing performance for the entire company. The profit or loss metric used to evaluate segment performance is Adjusted EBITDA, which is defined as net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion, and amortization; accretion expense; non-cash write-down of oil and natural gas properties; transaction and other (income) expenses; decommissioning obligations; the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives); (gain) loss on debt extinguishment; non-cash write-down of other well equipment inventory; and non-cash equity-based compensation expense.
Corporate general and administrative expense include certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each of operating segment. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment. The remaining expenses are included in the reconciliation of reportable segment Adjusted EBITDA to consolidated pre-tax net income (loss) as an unallocated corporate general and administrative expense. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.
The Company’s CODM does not review assets by segment as part of the financial information provided and therefore, no asset information is provided in the table below.
The following table presents selected segment information for the periods indicated (in thousands):
E&P
All Other(1)
Revenues from External Customers:
Three Months Ended March 31, 2022
Equity in the Net Income of Investees Accounted for by the Equity Method:
132
(1,277
(1,145
Adjusted EBITDA:
210,483
(6,157
204,326
212,082
(2,531
209,551
Segment Expenditures:
190,024
21,189
211,213
80,845
3,861
84,706
Reconciliations
The following table presents the reconciliation of Adjusted EBITDA to the Company’s consolidated totals (in thousands):
Total for reportable segments
All other
Unallocated corporate general and administrative expense
(1,263
(1,338
(147,323
(98,340
(19,414
(14,377
Transaction and other income (expenses)(1)
(22,009
26,861
Decommissioning obligations(2)
(741
(329
Derivative fair value gain (loss)(3)
Net cash paid on settled derivative instruments (3)
12,323
127,086
Non-cash equity-based compensation expense
(3,938
(3,318
Income (loss) before income taxes
23
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
(55,969
(7,555
Plugging & abandonment
Decommissioning obligations settled
Investment in CCS intangibles and equity method investees
(21,189
(3,861
Non-cash well equipment inventory transfers
(19,402
97
Other
130
614
103,962
53,978
24
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.
The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Condensed Consolidated Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2022 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2022 Annual Report.
Our Business
We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the United States (“U.S.”) and offshore Mexico both through oil and gas exploration and production (“Upstream”) and the development of carbon capture and sequestration (“CCS”) opportunities. We leverage decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, we also utilize our expertise to explore opportunities to reduce industrial emissions through our CCS initiatives both in and along the coast of the U.S. Gulf of Mexico.
We have historically focused our operations in the U.S. Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a large and expanding inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and collaborative arrangement opportunities, among others.
In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organically from our existing acreage, an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible.
We have two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is our only reportable segment. See additional information in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 12 — Segment Information”.
Significant Developments
Below is a cumulative list of significant developments that have occurred since the filing of our 2022 Annual Report.
Common Stock Repurchase Program — On March 20, 2023, we announced that the Board of Directors approved a $100.0 million common stock repurchase program. As of March 31, 2023, we have repurchased 1.9 million shares for a total of $26.6 million resulting in $73.4 million remaining under the authorized program. All repurchased shares are held in treasury. See the subsection entitled “— Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information.
Zama Update — In March 2023, the Zama Unit Development Plan was submitted to Mexico’s National Commission of Hydrocarbons for formal approval by Petróleos Mexicanos (“PEMEX”). Additionally, an Integrated Project Team (“IPT”) comprised of individuals from all four Zama Unit Holders has been established to manage the development and operation of Zama going forward. The IPT is designed to provide technical, operational and execution expertise, leveraging the talents from each of the Zama Unit Holders. The IPT will report to the Zama Unit Operating Committee, which includes representatives from each of the companies. We will co-lead the planning, drilling, construction, and completion of all Zama wells and co-lead the planning, execution, and delivery of Zama’s offshore infrastructure. Additionally, we will co-lead the project management office.
Factors Affecting the Comparability of our Financial Condition and Results of Operations
The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.
EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for more information.
Eugene Island Pipeline System — During the first quarter of 2022, we experienced approximately 40 days of unplanned third-party downtime due to maintenance of the Eugene Island Pipeline System, which carries our production from the Phoenix Field and Green Canyon 18 Field. For the three months ended March 31, 2022, we estimate the shut-in resulted in deferred production of approximately 4.7 MBoepd based on production rates prior to the shut-in.
Known Trends and Uncertainties
See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2022 Annual Report for a detailed discussion of known trends and uncertainties. The following carries forward or provides an update to known trends and uncertainties discussed in our 2022 Annual Report.
Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production.
During the period January 1, 2023 through March 31, 2023, the daily spot prices for NYMEX WTI crude oil ranged from a high of $81.62 per Bbl to a low of $66.61 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.78 per MMBtu to a low of $1.93 per MMBtu. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Financial Instruments” for additional information regarding our commodity derivative positions as of March 31, 2023.
The U.S. Energy Information Administration (“EIA”) published its latest Short-Term Energy Outlook on April 11, 2023. The EIA expects the Henry Hub spot price will average $2.65 per MMBtu in the second quarter of 2023 as inventories begin to rise. Lower-than-average withdrawals of natural gas from storage in the first quarter of 2023 resulted in natural gas inventories rising above the five-year average and contributed to falling natural gas prices. The EIA expects natural gas prices to average less than $3.00 per MMBtu for 2023, a more than 50% decrease from last year, slightly more than $3.00 per MMBtu in third quarter of 2023 and $3.71 per MMBtu in 2024. The EIA also expects the NYMEX WTI spot price will average $79.24 per Bbl in 2023 and $75.21 per Bbl in 2024. On April 3, 2023, OPEC Plus announced plans to cut crude oil production by 1.2 million barrels per day through the end of 2023. The EIA expects the global oil markets will be in relative balance over the coming year. Most of the uncertainty in EIA’s oil price forecast comes from less-than-forecast economic and oil demand growth. Increasing risk in the U.S. and global banking sectors increases uncertainty about macroeconomic conditions and their potential effects on oil demand growth, which has the potential to result in lower oil prices.
Inflation of Cost of Goods, Services and Personnel — Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increases, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices. In addition, the U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation could likely cause the U.S. Federal Reserve (the “Fed”) and other central banks to further increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business. The Fed raised rates again on March 22, 2023, by a quarter of a percentage point to 4.75%-5.00%. On May 3, 2023, the Fed raised rates by another quarter of a percentage point to 5.00%-5.25%. The Fed wants inflation to return to its 2% goal over time, and even though inflation is declining, it is still high in absolute terms. Recent events in the banking system, as discussed below, are likely to result in tighter credit conditions, and future interest rate hikes remain uncertain.
Volatility in Global Banking — Additionally, during the quarter ended March 31, 2023, Silicon Valley Bank (“SVB”) and Signature Bank were placed into receivership with the Federal Deposit Insurance Corporation (“FDIC”), indicating potential instability within the financial sector. Most recently, on May 1, 2023, First Republic Bank (“First Republic”) was placed into receivership with the FDIC and the FDIC sold First Republic’s deposits and most of its assets to JPMorgan Chase Bank, N.A. Although we are not party to any transactions with SVB, Signature Bank, First Republic or any other financial institution currently in receivership, continued instability could impact our financial counterparties.
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, 2023 and 2022, we did not recognize an impairment based on the ceiling test computations. At March 31, 2023 our ceiling test computation was based on SEC pricing of $91.75 per Bbl of oil, $6.35 per Mcf of natural gas and $29.42 per Bbl of NGLs.
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There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 2022 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change in price differentials or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties.
With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties, not subject to amortization. The Unit Development Plan for the Zama Field, which sets out the terms on which the reservoir will be jointly developed, was submitted to the National Hydrocarbon Commission on March 23, 2023 and they have approximately 120 days to respond. The approval of the Unit Development Plan could adversely affect the value of the Mexico oil and natural gas assets and result in an impairment of our unevaluated oil and gas properties.
Planned Downtime — We are vulnerable to downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the Helix Producer I (the “HP-I”) that is operated by Helix Energy Solutions Group, Inc. (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field. During the third quarter of 2022, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-September, resulting in a total shut-in period of 41 days.
BOEM Bonding Requirements — In 2016, the BOEM issued the 2016 Notice to Lessees and Operators (“NTL”), which bolstered supplemental bonding requirements. The NTL was not fully implemented as the BOEM under the Trump Administration first paused, and then in 2020 rescinded, this NTL, and, in October 2020, pursued a proposed rule published jointly with the BSEE that sought to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights owners) and rights of use and easement (“RUE”) and rights of way (“ROW”) grant holders conducting operations on the federal outer continental shelf (“OCS”). The Department of the Interior (the “DOI”) under the Biden Administration elected to separate the BOEM and BSEE portions of the supplemental bonding requirements. In April 2023, BSEE published its Final Rule entitled, “Risk Management, Financial Assurance, and Loss Prevention – Decommissioning Activities and Obligations”, wherein BSEE clarified decommissioning responsibilities for RUE grant holders and formalized BSEE’s policies regarding performance by predecessors ordered to decommission OCS facilities. The final rule withdraws the proposal in the October 2020 proposed rule to amend BSEE’s regulations requiring the agency to proceed in reverse chronological order against predecessor lessees, owners of operating rights and grant holders when requiring such entities to perform their accrued decommissioning obligations upon failure to perform by current lessees, owners, or holders. Under the final rule, BSEE may issue an order to predecessors to perform accrued decommissioning obligations, including beginning maintenance and monitoring within thirty (30) days, designating an operator for decommissioning within ninety (90) days, and submitting a decommissioning plan within one hundred fifty (150) days. BOEM has not yet published its proposed rule that will replace its portion of the October 2020 proposed rule.
The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us, whether as current or predecessor lessee or grant holder, as a result of the implementation of a new NTL analogous to the 2016 NTL to the extent finalized, as well as to the provisions of any other new, more stringent NTLs or final rules on supplemental bonding published by the BOEM under the Biden Administration, could materially and adversely affect our financial condition, cash flows and results of operations. Moreover, the BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements. Additionally, in August 2021, the BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements currently applicable to all sole liability properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM.
Deepwater Operations — We have interests in Deepwater fields in the U.S. Gulf of Mexico. Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.
Oil Spill Response Plan — We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil spill response plans are generally approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.
Hurricanes and Tropical Storms — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes and tropical storms on production and capital projects. Significant impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.
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Five-Year Offshore Oil and Gas Leasing Program Update — Under the Outer Continental Shelf Lands Act (“OCSLA”), as amended, the BOEM within the DOI must prepare and maintain forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the U.S. Outer Continental Shelf. On May 11, 2022, the DOI cancelled two lease auctions in the Gulf of Mexico, Lease Sales 259 and 261 included in the 2017-2022 national program that was developed under the Obama Administration, which expired on June 30, 2022. The DOI cited “conflicting court rulings” as the primary reason for not holding the two Gulf of Mexico lease sales. President Biden signed the Inflation Reduction Act of 2022 (the “IRA 2022”) into law on August 16, 2022. The IRA 2022 reinstates Lease Sale 257 held in November 2021, and requires the DOI to both accept all valid high bids received in Lease Sale 257 and issue leases to the high bidders. We were one of the most active bidders in Lease Sale 257 and we were the high bidder on 10 blocks and awarded leases on 9 blocks. In January 2023, BOEM released its final environmental impact statement for Lease Sales 259 and 261 and, in March 2023, announced the results of Lease Sale 259, in which we were the high bidder on four offshore blocks. The DOI must hold Lease Sale 261 by September 30, 2023.
BOEM’s development of a new five-year national program typically takes place over several years, during which successive drafts of the program are published for review and comment. At the end of the process, the Secretary of the Interior must submit the Proposed Final Program to the President and to Congress for a period of at least 60 days, after which the program may be approved by the Secretary of the Interior and may take effect with no further regulatory or legislative action.
BOEM took the first formal step in pursuit of a new five-year national program in January 2018 by releasing a Draft Proposed Program. The OCSLA and its implementing regulations call for two subsequent drafts, a Proposed Program (“PP”), which is open for public comment for a period of at least 90 days, and then a Proposed Final Program, which is submitted to Congress and the President for 60 days before implementation. These later program stages also are accompanied by publication of a draft and final Programmatic Environmental Impact Statement (“PEIS”), with a period for public comment on the draft PEIS. The PP and a draft PEIS for the 2023-2028 five-year period were published in the Federal Register on July 8, 2022, with a 90-day comment period. The public comment period has now closed, and BOEM is reviewing the comments received. The PP includes no more than ten potential lease sales in the Gulf of Mexico; however, BOEM’s subsequent Proposed Final Program for 2023-2028 could reduce the number of Gulf of Mexico lease sales in the national program.
When the 2023-2028 national program will be approved and implemented remains uncertain. Congress may influence the Biden Administration’s development and implementation of the 2023-2028 five-year national program by submitting public comments during formal comment periods, by evaluating programs in committee oversight hearings, and, more directly, by enacting legislation with program requirements. It is possible that the program could be delayed if opponents of offshore oil and gas production initiate lawsuits challenging BOEM’s actions.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
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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):
Change
(61,192
(22,798
(6,994
(90,984
Total Production Volumes:
Oil (MBbls)
4,106
3,788
318
Natural gas (MMcf)
7,127
8,649
(1,522
NGL (MBbls)
429
457
(28
Total production volume (MBoe)
5,723
5,687
Daily Production Volumes by Product:
Oil (MBblpd)
45.6
42.1
3.5
Natural gas (MMcfpd)
79.2
96.1
(16.9
NGL (MBblpd)
4.8
5.1
(0.3
Total production volume (MBoepd)
63.6
63.2
0.4
Average Sale Price Per Unit:
Oil (per Bbl)
71.28
93.42
(22.14
Natural gas (per Mcf)
2.83
4.97
(2.14
NGL (per Bbl)
22.62
36.54
(13.92
Price per Boe
56.37
(16.35
Price per Boe (including realized commodity derivatives)
54.21
50.37
3.84
The information below provides an analysis of the change in our oil, natural gas and NGL revenues due to changes in sales prices and production volumes (in thousands):
Three Months Ended March 31, 2023 vs 2022
Price
Volume
(90,900
29,708
(15,234
(7,564
(5,971
(1,023
(112,105
21,121
Three Months Ended March 31, 2023 and 2022 Volumetric Analysis — Production volumes increased by 0.4 MBoepd to 63.6 MBoepd. The increase was primarily due to 11.4 MBoepd in production from the oil and natural gas assets acquired in the EnVen Acquisition. Additionally, production volumes increased 4.7 MBoepd in deferred production from the Eugene Island Pipeline System shut-in during 2022 primarily impacting HP-I and Green Canyon 18 Field. The increase was partially offset by a decrease of 15.3 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field.
Operating Expenses
Lease Operating Expense
The following table highlights lease operating expense items in total and on a cost per Boe production basis. 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
14.22
10.52
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Three Months Ended March 31, 2023 and 2022 — Lease operating expense for the three months ended March 31, 2023 increased by approximately $21.5 million, or 36%. This increase was primarily related to lease operating expenses of $8.8 million incurred in connection with assets acquired from the EnVen Acquisition. Additionally, there was a $4.6 million decrease in production handling fees related to reimbursements for costs from certain third parties. Facility and workover expense related to repairs and maintenance at the Ram Powell Field and Ship Shoal area increased $3.1 million when compared to the same period in 2022.
Depreciation, Depletion and Amortization
The following table highlights depreciation, depletion and amortization items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):
Depreciation, depletion and amortization per Boe
25.74
17.29
Three Months Ended March 31, 2023 and 2022 — Depreciation, depletion and amortization expense for the three months ended March 31, 2023 increased by approximately $49.0 million, or 50%. This was due to an increase of $8.40 per Boe, or 49%, in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties primarily related to the assets acquired as part of the EnVen Acquisition, which is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” and the extension of the HP-I lease during the fourth quarter of 2022, which a discussion is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.
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
58,355
18,336
CCS Segment
2,535
Unallocated corporate
1,503
1,657
Total general and administrative expense
Upstream general and administrative expense per Boe
10.20
3.22
Three Months Ended March 31, 2023 and 2022 — General and administrative expense for the three months ended March 31, 2023 increased by approximately $40.7 million, or 180%. This increase was primarily related to the Upstream Segment transaction costs for the EnVen Acquisition of $35.2 million or $6.15 per Boe. General and administrative expense includes non-cash equity-based compensation of $3.9 million during the three months ended March 31, 2023, which is an increase of $0.6 million.
Miscellaneous
The following table highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands):
37,581
31,490
Price risk management activities (income) expense
(6,666
(28,134
(46,543
(472
Three Months Ended March 31, 2023 and 2022 —
Interest Expense — During the three months ended March 31, 2023, we recorded $37.6 million of interest expense compared to $31.5 million during the three months ended March 31, 2022. The change is primarily the result of the increase in interest associated with the 11.75% Notes (as defined below under “ — Liquidity and Capital Resources — Overview of Debt Instruments”) assumed as part of the EnVen Acquisition.
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Price Risk Management Activities — 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 $12.4 million in cash settlement losses. The expense of $281.2 million for the three months ended March 31, 2022 consists of $154.1 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $127.1 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 March 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. “Condensed Consolidated Financial Statements — Note 5 — Financial Instruments.”
Equity Method Investment Income — 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. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Related Party Transactions” for additional information.
Other (Income) Expense — During the three months ended March 31, 2022, we recorded a $27.5 million gain as a result of the settlement agreement to resolve a previously pending litigation that was filed in October 2017 that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 11 — Commitments and Contingencies.”
Income Tax (Benefit) Expense — During the three months ended March 31, 2023, we recorded $46.5 million of income tax benefit compared to $0.5 million of income tax benefit during the three months ended March 31, 2022. The income tax benefit is primarily due to a non-cash tax benefit of $54.9 million related to the partial release of the valuation allowance on our federal deferred tax assets not subject to separate return limitations. The partial release of the valuation allowance is a result of the deferred tax liabilities acquired with the EnVen Acquisition. See additional information on the valuation allowance as described in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 8 — Income Taxes.”
Supplemental Non-GAAP Measure
EBITDA and Adjusted EBITDA
“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.
We define these as the following:
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The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):
EBITDA
247,635
77,294
Transaction and other (income) expenses(1)
22,009
(26,861
329
Derivative fair value (gain) loss(3)
Net cash paid on settled derivative instruments(3)
Adjusted EBITDA
203,063
208,213
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. Our working capital deficit has increased since December 31, 2022 primarily due to an increase in the current portion of long-term debt of $33.2 million related to the 11.75% Notes assumed as part of the EnVen Acquisition. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt.” As of March 31, 2023, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $805.4 million.
We fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.
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Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the three months ended March 31, 2023 (in thousands):
U.S. drilling & completions
112,330
Mexico appraisal & exploration
96
Asset management(1)
44,944
Seismic and G&G, land, capitalized G&A and other
21,833
Total Upstream capital expenditures
179,203
10,113
Decommissioning obligations settled(2)
708
Total Upstream
Investment in CCS
Based on our current level of legacy operations, the recently acquired EnVen operations, and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our board approved 2023 Upstream capital spending program of $650.0 million to $675.0 million as well as expected investments in our CCS operating segment of $70.0 million to $90.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.
Common Stock Repurchase Program — The 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. As of March 31, 2023, we have repurchased 1.9 million shares for a total of $26.6 million, resulting in $73.4 million remaining under the authorized program. All repurchased shares are held in treasury.
Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.
The IRA 2022 provides for, among other things, the imposition of a new 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations such as us after December 31, 2022. Accordingly, the excise tax applies to our share repurchase program. The excise tax payment is non-deductible for income tax purposes. Subject to certain exceptions and adjustments, the excise tax equals 1% of the fair market value of the stock repurchased by a corporation during the applicable tax year. The repurchase amount subject to the excise tax is generally reduced by the fair market value of any stock issued by a corporation during a taxable year, including the fair market value of any stock issued or provided to employees of a corporation or employees of certain of its subsidiaries. The Biden Administration has proposed increasing the amount of the excise tax from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any change can take effect.
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
33
Operating Activities — Net cash provided by operating activities decreased $50.8 million in the three months ended March 31, 2023 compared to the corresponding period in 2022 primarily attributable to a decrease in revenues net of the change in lease operating expense of $112.5 million and a $27.5 million legal settlement to resolve previously pending litigation that was filed in October 2017 received in the three months ended March 31, 2022. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 11 — Commitments and Contingencies” for additional information. This was offset by a decrease in cash payments on derivative instruments of $114.8 million.
Investing Activities — Net cash used in investing activities increased $47.6 million in the three months ended March 31, 2023 compared to the corresponding period in 2022 primarily due to an increase in capital expenditures of $50.0 million and contributions to equity method investees of $10.6 million. This increase was offset by proceeds from the EnVen Acquisition of $17.6 million. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for additional information.
Financing Activities —Cash flow from financing activities increased $162.8 million in the three months ended March 31, 2023 compared to the corresponding period in 2022 primarily due to an increase in net borrowings and repayments from the Bank Credit Facility of $200.0 million and $25.2 million from repurchases of our common stock through our share repurchase program. See the subsection entitled “— Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information.
Overview of Debt Instruments
Bank Credit Facility — matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions (the “Bank Credit Facility”). The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.
12.00% Second-Priority Senior Secured Notes — due January 2026 — The 12.00% Second-Priority Senior Secured Notes (the “12.00% Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the “Parent Guarantor”); Talos Production Inc. (the “Issuer”); the Subsidiary Guarantors (defined below); and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes mature on January 15, 2026 and have interest payable semi-annually each January 15 and July 15. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.
11.75% Senior Secured Second Lien Notes — due April 2026 — On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, we assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount outstanding of $257.5 million. The 11.75% Notes will mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.
Guarantor Financial Information — We own no operating assets and have no operations independent of our subsidiaries. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material restricted subsidiaries that guarantees the Issuer’s senior reserve-based revolving credit facility (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”). Our non-domestic subsidiaries (other than Talos International Holdings SCS) and our unrestricted CCS domestic subsidiaries (the “Non-Guarantors”) are 100% owned by us but do not guarantee the 12.00% Notes.
In lieu of providing separate financial statements for the Issuer and the Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and statement of operations information for the Issuer and the Guarantors on a combined basis after elimination of intercompany transactions and amounts related to investment in any subsidiary that is a Non-Guarantor.
The following table presents the balance sheet information for the respective periods (in thousands):
389,889
344,525
Non-current assets
4,236,733
2,571,254
4,626,622
2,915,779
Current liabilities
666,215
599,669
Non-current liabilities
2,063,722
1,285,992
Talos Energy Inc. stockholdersʼ equity
1,896,685
1,030,118
34
The following table presents the statement of operations information (in thousands):
Revenues
Costs and expenses
(239,638
82,944
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, 2023 (in thousands):
2024
2025
2026
2027
Thereafter
Total(5)
Long-term financing obligations:
Debt principal
30,000
806,041
Debt interest
69,999
116,038
112,718
60,817
4,339
363,911
Vessel commitments(1)
41,578
Derivative liabilities
29,530
10,604
Operating lease obligations
4,459
5,796
5,783
5,891
5,817
12,653
40,399
Finance lease(2)
34,805
19,336
54,141
Purchase obligations(3)
35,838
Other commitments(4)
327
2,468
2,141
7,404
Total contractual obligations(5)
246,536
184,242
150,969
874,890
175,156
1,644,446
Performance Obligations — As of March 31, 2023, we had secured performance bonds totaling $1.4 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico and certain obligations under the production sharing contracts with Mexico from third party sureties. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments.
See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for further information on the Bank Credit Facility.
Critical Accounting Policies and Estimates
We consider accounting policies related to oil and natural gas properties, proved reserve estimates, fair value measure of financial instruments, asset retirement obligations, revenue recognition, imbalances and production handling fees and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting policies, which are summarized in the Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our 2022 Annual Report.
Recently Adopted Accounting Standards
None.
Recently Issued Accounting Standards
There was no recently issued accounting standards material to us.
35
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 2022 Annual Report. There have been no material changes from the disclosures presented in our 2022 Annual Report regarding our exposures to certain market risks.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2023.
Internal Control over Financial Reporting
On February 13, 2023, we completed the EnVen Acquisition. Other than integrating the acquired operations of EnVen 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, 2023 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 2022 Annual Report.
Item 1A. Risk Factors
In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under Part I, Item 1A. “Risk Factors” included in our 2022 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2022 Annual Report or our other SEC filings, except as included herein.
Adverse developments affecting the financial services industry, such as actual events or concerns involving liquidity, defaults or non-performance by financial institutions or transactional counterparties, could adversely affect our current and projected business operations and financial condition and results of operations
Events involving limited liquidity, defaults, non-performance or other adverse developments that affect financial institutions, transactional counterparties or other companies in the financial services industry or the financial services industry generally, or concerns or rumors about any events of these kinds or other similar risks, have in the past and may in the future lead to market-wide liquidity problems. Most recently, on May 1, 2023, First Republic was closed by the California Department of Financial Protection and Innovation (“DFPI”), which appointed the Federal Deposit Insurance Corporation (“FDIC”) as receiver. The FDIC sold First Republic’s deposits and most of its assets to JPMorgan Chase Bank, N.A. On March 10, 2023, SVB was closed by the DFPI, which appointed the FDIC as receiver. Similarly, on March 12, 2023, Signature Bank and Silvergate Capital Corp. were each swept into receivership. Although a statement by the Department of the Treasury, the Fed and the FDIC indicated that all depositors of SVB would have access to all of their money after only one business day of closure, including funds held in uninsured deposit accounts, borrowers under credit agreements, letters of credit and certain other financial instruments with SVB, Signature Bank or any other financial institution that is placed into receivership by the FDIC may be unable to access undrawn amounts thereunder. Access to funding sources and other credit arrangements could be significantly impaired by factors that affect the financial services industry or economy in general. These factors could include, among others, events such as liquidity constraints or failures, the ability to perform obligations under various types of financial, credit or liquidity agreements or arrangements, disruptions or instability in the financial services industry or financial markets, or concerns or negative expectations about the prospects for companies in the financial services industry.
In addition, investor concerns regarding the U.S. or international financial systems could result in less favorable commercial financing terms, including higher interest rates or costs and tighter financial and operating covenants, or systemic limitations on access to credit and liquidity sources, thereby making it more difficult to acquire financing on acceptable terms or at all. Any decline in available funding or access to our cash and liquidity resources could, among other risks, adversely impact our ability to meet our financial or other obligations. Any of these impacts, or any other impacts resulting from the factors described above or other related or similar factors, could have material adverse impacts on our liquidity and our business, financial condition or results of operations.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table sets forth information with respect to our share repurchase of shares of common stock during the three months ended March 31, 2023:
Period
Total Number of Shares Purchased
Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Program(1)
Approximate Dollar Values of Shares that May Yet be Purchased Under the Program (in thousands)
March 1, 2023 - March 31, 2023
14.01
73,382
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
Item 6. Exhibits
Exhibit
Number
Description
2.1#
Agreement and Plan of Merger, dated as of September 21, 2022, by and among Talos Energy Inc., Talos Production Inc., Tide Merger Sub I Inc., Tide Merger Sub II LLC, Tide Merger Sub III LLC, BCC Enven Investments, L.P. and EnVen Energy Corporation (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).
3.1
Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
3.2
Second Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
4.1
Indenture, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).
4.2
First Supplemental Indenture, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).
4.3
Form of 12.00% Second-Priority Senior Secured Note due 2026 (included as Exhibit A to Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).
4.4
Registration Rights Agreement, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).
Registration Rights Agreement, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).
4.6
Registration Rights Agreement, dated September 21, 2022, by and among Talos Energy Inc. and the Persons listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).
4.7
Second Supplemental Indenture, dated as of October 27, 2022, among Talos Production Inc., the Guarantors named therein and Wilmington Trust National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 28, 2022).
Indenture, dated as of April 15, 2021, by and among Energy Ventures GoM LLC, EnVen Finance Corporation, Talos Production Inc. (as successor in interest to EnVen Energy Corporation), the other guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
4.9
Second Supplemental Indenture, dated as of February 13, 2023, among Talos Production Inc., each of the other guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
4.10
Third Supplemental Indenture, dated as of February 13, 2023, among Talos Production Inc., Energy Ventures GoM LLC, EnVen Finance Corporation, each of the other guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
10.1
Incremental Agreement and Ninth Amendment to Credit Agreement, dated as of December 23, 2022, among Talos Energy Inc., Talos Production Inc., each other Credit Party, JPMorgan Chase Bank, N.A., as Administrative Agent, each Issuing Bank, the Swingline Lender and each of the Lenders (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 27, 2022).
10.2
Letter Agreement, dated February 13, 2023, by and between Talos Energy Inc., Riverstone Talos Energy EquityCo LLC, Riverstone Talos Energy DebtCo LLC, ILX Holdings II, LLC and Riverstone V Castex 2014 Holdings, L.P. (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
10.3†
Indemnification Agreement (Shandell Szabo) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
10.4†
Indemnification Agreement (Richard Sherrill) (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
10.5*†
Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors).
22.1
List of Subsidiary Guarantors and Issuers of Guaranteed Securities (incorporated by reference to Exhibit 22.1 to Talos Energy Inc.'s Form 10-K (File No. 001-38497) filed with the SEC on March 1, 2023).
31.1*
Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.
101.INS*
Inline XBRL Instance.
101.SCH*
Inline XBRL Taxonomy Extension Schema.
101.CAL*
Inline XBRL Taxonomy Extension Calculation.
101.DEF*
Inline XBRL Taxonomy Extension Definition.
101.LAB*
Inline XBRL Taxonomy Extension Label.
101.PRE*
Inline XBRL Taxonomy Extension Presentation.
104*
Cover Page Interactive Date File (Embedded within the Inline XBRL document and included in Exhibit 101).
*
Filed herewith.
**
Furnished herewith.
†
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.
40
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 8, 2023
By:
/s/ Shannon E. Young III
Shannon E. Young III
Executive Vice President and Chief Financial Officer