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 ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ such files). Yes☒ No ☐

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

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

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

As of August ~~3, 2018,~~1, 2023, the registrant had ~~54,155,768~~124,055,965 shares of common stock, $0.01 par value per share, outstanding.

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

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

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

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

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

~~Deepwater.~~ Deepwater —Water depths of more than 600 ~~feet where there is clearly defined infrastructure, production history and geological well control to reduce operational and investment risk in development and exploitation activities.~~feet.

~~Developed acres.~~ ~~The number of acres that are allocated or assignable to producing wells or wells capable of production.~~

~~Field.~~ 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.

~~Gross acres or gross wells.~~ ~~The total acres or wells~~GAAP — Accounting principles generally accepted in ~~which~~ the ~~Company owns a working interest.~~United States of America.

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

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

~~Net acres or net wells.~~ ~~The sum of the fractional working interests the Company owns in gross acres or gross wells.~~

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

NYMEX Henry ~~Hub.~~ 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.~~index.

~~Productive well.~~ ~~A well that is found to be capable~~OPEC — Organization of ~~producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.~~Petroleum Exporting Countries.

Proved ~~developed reserves.~~ ~~In general, proved~~ reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The Securities and Exchange Commission provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.

~~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.~~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 ~~Securities and Exchange Commission~~SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation ~~S-X.~~S-K.

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

~~Undeveloped acreage.~~ Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working ~~interest.~~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.~~ Intermediate —A light crude oil produced in the United States with an ~~API~~American Petroleum Institute gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

The information in this ~~report~~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 ~~report,~~Quarterly Report, regarding ~~the Company’s~~our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this ~~report,~~Quarterly Report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” ~~“project”~~“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 ~~the Company’s~~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, inflation,~~volatility; 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; continued impact of the coronavirus disease 2019 (“COVID-19”), including any new strains or variants, and governmental measures related thereto; lack of transportation and storage capacity as a result of oversupply, government and regulations; lack of availability of drilling and production equipment and ~~services,~~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,~~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,~~risks; well control ~~risk,~~risk; regulatory ~~changes,~~changes; the uncertainty inherent in estimating reserves and in projecting future rates of ~~production,~~production; cash flow and access to ~~capital,~~capital; the timing of development ~~expenditures,~~expenditures; potential adverse reactions or ~~changes to business or employee relations resulting from the business combination between Talos Energy LLC and Stone Energy Corporation,~~ competitive responses to ~~such business combination,~~our acquisitions and other transactions; the possibility that the anticipated benefits of ~~such business combination~~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 ~~the two companies, litigation relating to the business combination,~~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 (the “2022 Annual Report”) and Part II, Item ~~1A,~~IA. “Risk Factors” ~~herein.~~of Talos Energy Inc.’s Quarterly Report on Form 10-Q for the period ended March 31, 2023, each as filed with the SEC.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in ~~these financial statements~~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 ~~report.~~Quarterly Report.

June 30, 2018

December 31, 2017

(Unaudited)

ASSETS

Current assets:

Cash and cash equivalents

$
78,860

$
32,191

Restricted cash

1,244

1,242

Accounts receivable

Trade, net

100,824

62,871

Joint interest, net

8,394

13,613

Other

7,091

12,486

Assets from price risk management activities

499

1,563

Prepaid assets

51,698

17,931

Inventory

—

840

Income tax receivable

16,212

—

Other current assets

3,910

2,148

Total current assets

268,732

144,885

Property and equipment:

Proved properties

3,412,875

2,440,811

Unproved properties, not subject to amortization

103,836

72,002

Other property and equipment

28,884

8,857

Total property and equipment

3,545,595

2,521,670

Accumulated depreciation, depletion and amortization

(1,547,656
)

(1,430,890
)
Total property and equipment, net

1,997,939

1,090,780

Other long-term assets:

Assets from price risk management activities

234

345

Other well equipment

9,021

2,577

Other assets

8,143

706

Total assets

$
2,284,069

$
1,239,293

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

Current liabilities:

Accounts payable

$
38,731

$
72,681

Accrued liabilities

155,902

87,973

Accrued royalties

28,508

24,208

Current portion of long-term debt

434

24,977

Current portion of asset retirement obligations

94,334

39,741

Liabilities from price risk management activities

154,722

49,957

Accrued interest payable

7,454

8,742

Other current liabilities

15,541

15,188

Total current liabilities

495,626

323,467

Long-term liabilities:

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

627,968

672,581

Asset retirement obligations

320,044

174,992

Liabilities from price risk management activities

31,766

18,781

Other long-term liabilities

122,820

103,559

Total liabilities

1,598,224

1,293,380

Commitments and contingencies (Note 11)

Equity:

Preferred stock, $0.01 par value; 30,000,000 shares authorized; no shares issued or
outstanding as of June 30, 2018 and December 31, 2017

—

—

Common stock $0.01 par value; 270,000,000 shares authorized; 54,155,768 and 31,244,085 shares issued
and outstanding as of June 30, 2018 and December 31, 2017, respectively

542

312

Additional paid-in capital

1,323,604

489,870

Accumulated deficit

(638,301
)

(544,269
)
Total stockholders' equity (deficit)

685,845

(54,087
)
Total liabilities and equity

$
2,284,069

$
1,239,293

~~The accompanying notes are an integral part of these condensed consolidated financial statements.~~

Three Months Ended June 30,

Six Months Ended June 30,

2018

2017

2018

2017

Revenues:

Oil revenue

$
180,161

$
78,719

$
307,854

$
162,487

Natural gas revenue

16,448

12,888

29,171

26,062

NGL revenue

7,297

3,436

12,731

7,069

Other

—

383

—

1,632

Total revenue

203,906

95,426

349,756

197,250

Operating expenses:

Direct lease operating expense

34,060

28,871

58,975

56,735

Insurance

4,259

2,688

6,934

5,409

Production taxes

564

380

955

645

Total lease operating expense

38,883

31,939

66,864

62,789

Workover and maintenance expense

17,714

8,225

24,619

17,047

Depreciation, depletion and amortization

67,726

36,157

116,766

76,088

Accretion expense

9,492

5,321

14,252

10,509

General and administrative expense

30,880

7,470

39,460

17,216

Total operating expenses

164,695

89,112

261,961

183,649

Operating income

39,211

6,314

87,795

13,601

Interest expense

(21,678
)

(20,805
)

(41,420
)

(39,577
)
Price risk management activities income (expense)

(91,176
)

38,995

(143,152
)

84,888

Other income (expense)

(1,269
)

103

(1,078
)

157

Total other income (expense)

(114,123
)

18,293

(185,650
)

45,468

Income (loss) before income taxes

(74,912
)

24,607

(97,855
)

59,069

Income tax expense (benefit)

—

—

—

—

Net income (loss)

$
(74,912
)

$
24,607

$
(97,855
)

$
59,069

Net income (loss) per common share:

Basic

$
(1.69
)

$
0.79

$
(2.59
)

$
1.89

Diluted

$
(1.69
)

$
0.79

$
(2.59
)

$
1.89

Weighted average common shares outstanding:

Basic

44,336

31,244

37,826

31,244

Diluted

44,336

31,244

37,826

31,244

~~The accompanying notes are an integral part of these condensed consolidated financial statements.~~

Six Months Ended June 30,

2018

2017

Cash flows from operating activities:

Net income (loss)

$
(97,855
)

$
59,069

Adjustments to reconcile net income (loss) to net cash provided by operating activities

Depreciation, depletion, amortization and accretion expense

131,018

86,597

Amortization of deferred financing costs and original issue discount

2,607

1,629

Equity based compensation, net of amounts capitalized

1,559

495

Price risk management activities (income) expense

143,152

(84,888
)
Net cash receipts (payments) on settled derivative instruments

(54,056
)

13,668

Settlement of asset retirement obligations

(43,896
)

(10,915
)
Changes in operating assets and liabilities:

Accounts receivable

19,462

27,814

Other current assets

(13,576
)

1,127

Accounts payable

(53,126
)

10,885

Other current liabilities

52,543

(16,961
)
Other non-current assets and liabilities, net

19,279

(3,257
)
Net cash provided by operating activities

107,111

85,263

Cash flows from investing activities:

Exploration, development and other capital expenditures

(140,968
)

(62,535
)
Cash acquired in (paid for) acquisitions

293,001

(2,244
)
Net cash provided by (used in) investing activities

152,033

(64,779
)
Cash flows from financing activities:

Redemption of Senior Notes and other long-term debt

(25,046
)

(1,000
)
Proceeds from Bank Credit Facility

294,000

—

Repayment of Bank Credit Facility

(54,000
)

—

Proceeds from Old Bank Credit Facility

—

10,000

Repayment of Old Bank Credit Facility

(403,000
)

(15,000
)
Deferred financing costs

(17,469
)

—

Payments of capital lease

(6,958
)

(5,870
)
Net cash used in financing activities

(212,473
)

(11,870
)

Net increase in cash, cash equivalents and restricted cash

46,671

8,614

Cash, cash equivalents and restricted cash:

Balance, beginning of period

33,433

33,433

Balance, end of period

$
80,104

$
42,047

Supplemental Non-Cash Transactions:

Capital expenditures included in accounts payable and accrued liabilities

$
38,205

$
30,712

Supplemental Cash Flow Information:

Interest paid, net of amounts capitalized

$
23,635

$
25,405

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

~~Formation~~Organization and Nature of Business

Talos Energy Inc. ~~(“Talos”~~(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 ~~with~~focused on safely and efficiently maximizing long-term value through its operations, currently in the United States ~~Gulf~~(“U.S.”) and offshore Mexico both through oil and gas exploration and production (“Upstream”) and the development of ~~Mexico~~CCS opportunities. The Company leverages decades of technical and offshore operational expertise in the ~~shallow waters off~~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 ~~Mexico. The Company’s focus in~~ the U.S. Gulf of Mexico is the exploration, acquisition, exploitation and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide the Company high impact exploration opportunities in an emerging basin. The Company uses its access to an extensive seismic database and its deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. The Company’s management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico.

On May 10, 2018 (the “Closing Date”), the Company (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), among Stone Energy Corporation (“Stone”), the Company, Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC, pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (the “Stone Combination”). Prior to the Closing Date, Sailfish Energy Holdings Corporation did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. Substantially concurrent with the consummation of the transactions, the name of the Company was changed from Sailfish Energy Holdings Corporation to Talos Energy Inc.

Pursuant to the Transaction Agreement, a series of transactions occurred on the Closing Date (the “Closing”), including the following: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and a direct wholly-owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of the Company’s common stock, par value $0.01 (the “Common Stock”) and (ii) in a series of contributions, entities related to Apollo Management VII, L.P. and Apollo Commodities Management, L.P. with respect to Series I (“Apollo Funds”), and Riverstone Energy Partners V, L.P. (“Riverstone Funds”) contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”).

Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by the certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% senior notes due 2022 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Senior Secured Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes.

As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.

Unless otherwise indicated or the context otherwise requires, references in this report to “us,” “we,” “our” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

Basis of Presentation and Consolidation

The ~~condensed consolidated~~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 ~~have been~~ prepared in accordance with ~~accounting principles generally accepted~~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 ~~United States~~periods presented. The results for interim periods are not necessarily indicative of ~~America (“GAAP”) as applied to interim~~results for the entire year. The unaudited financial statements and ~~include each subsidiary from the date of inception. Because~~related notes included in this is an interim periodic report presented using a condensed format, it does not include all of the annual disclosures required by GAAP. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which cover periods prior to the Closing Date, reflects the assets, liabilities and operations of Talos Energy LLC prior to the Closing Date and does not reflect the assets, liabilities and operations of Stone prior to the Closing Date. These condensed consolidated financial statementsQuarterly Report should be read in conjunction with ~~Talos Energy LLC’s~~the Company’s audited ~~financial statements~~Consolidated Financial Statements and ~~the~~accompanying notes thereto for the year ended December 31, 2017, which were filed by the Company on May 18, 2018 with the SEC on a Current Report on Form 8-K. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC receivedincluded in the business combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos. All intercompany transactions have been eliminated. All adjustments that are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the interim periods are reflected herein. The results for any interim period are not necessarily indicative of the expected results for the entire year. The Company has evaluated subsequent events through the date the condensed consolidated financial statements were issued.2022 Annual Report.

For presentation purposes, as of June 30, 2018, certain balances previously disclosed as “Accounts payable” and “Other current assets” have been reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The corresponding balances as of December 31, 2017 of $73.5 million and $7.3 million were reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The balance reclass between “Accounts payable” and “Accrued liabilities” is related to estimates of operating costs incurred but not yet invoiced.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting ~~periods and the reported amounts of proved oil and natural gas reserves.~~periods. Actual results could differ from those estimates.

Segments

During September 2015, the Company expanded its acreage position to include two shallow water exploration blocks off the coast of Mexico and drilled its first well in those blocks in July 2017. The business activities in Mexico, which are currently deemed immaterial, have been combined with the United States and reported as one segment. See additional information in Note 4 – ~~Property, Plant and Equipment~~.

~~Recently Adopted Accounting Standards~~

~~Impact of the Adoption of ASC 606 – Revenue from Contracts with Customers~~

~~On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606,~~ ~~Revenue from Contracts with Customers~~ ~~using the modified retrospective approach. ASC 606 supersedes the revenue recognition requirements in Topic 615,~~ ~~Revenue Recognition, and industry-specific guidance in Subtopic 932-605,~~ ~~Extractive Activities – Oil and Gas – Revenue Recognition.~~ The new standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for these goods and services.

The Company ~~records revenues from the sale~~has two operating segments: (i) exploration and production of oil, natural gas and NGLs ~~based on quantities~~(“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 ~~production sold~~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 ~~purchasers under short-term contracts (less than twelve months) at market prices when delivery~~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 in Note 2 — Acquisitions and Divestitures). These escrow accounts required deposits of approximately $100.0 million, which was fully funded by EnVen (as defined in Note 2 — Acquisitions and Divestitures) prior to the ~~customer has occurred, title has transferred, prices are fixed and determinable and collection~~consummation of the acquisition. This is ~~reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred.~~reflected as “Restricted cash” within “Other long-term assets” on the Condensed Consolidated Balance Sheets.

Notes Receivable, net —The Company ~~does not disclose the~~holds two notes receivable with an aggregate face value of ~~unsatisfied performance obligations for contracts with an original expected length~~$66.2 million which consist of ~~one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.~~

~~Gas Imbalances.~~ Under previous accounting guidance, the Company used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on the Company’s entitled share of production with any difference recorded as an imbalance on the condensed consolidated balance sheet. Upon the adoption of ASC 606, revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. The change in accounting methodcommitments from the ~~entitlements method to the sales method resulted in an immaterial cumulative-effect adjustment to members’ deficit on the date~~sellers of ~~adoption.~~

~~Production Handling Fees.~~ Under previous accounting guidance, the Company presented certain reimbursements for costs from certain third parties as other revenue on the condensed consolidated statement of operations. Upon the adoption of ASC 606, the reimbursements are presented as a reduction of direct lease operating expense on the condensed consolidated statement of operations. The impact of the reclassification for the three and six months ended June 30, 2018 was immaterial.

~~Recently Issued Accounting Standards~~

~~In February 2016, the Financial Accounting Standards Boards (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02,~~ ~~Leases (Topic 842).~~ ~~This ASU supersedes the lease requirements in Topic 840,~~ ~~Leases~~, and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within the Company’s condensed consolidated statements of operations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to leases for oil and natural gas properties, ~~but does apply~~acquired by the Company as part of the EnVen Acquisition, related to ~~equipment used~~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 ~~explore~~their principal amounts and ~~develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.~~are presented as such, net of the related cumulative estimated credit losses, on the accompanying Condensed Consolidated Balance Sheets. The Company ~~is currently assessing~~estimates the ~~impact~~current expected credit losses related to its P&A Notes Receivable using the probability of ~~ASU 2016-02 which includes an analysis of existing contracts and current accounting policies and disclosures that will change as a result~~default method based on the long-term credit ratings of the ~~adoption. Appropriate systems, controls and processes to support the recognition and disclosure requirements~~counterparties of the ~~ASU 2016-02~~notes, which are ~~also being evaluated.~~ currently considered “investment grade.”

Table of Contents

Cash, Cash Equivalents and Restricted Cash

The ~~Company is currently evaluating~~following table provides a reconciliation of the ~~impact~~amount of ~~this ASU on its condensed consolidated financial statements. The Company plans~~cash, cash equivalents and restricted cash reported within the Condensed Consolidated Balance Sheets to ~~adopt ASU 2016-02 effective January 1, 2019.~~the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands):


	June 30, 2023		December 31, 2022
Cash and cash equivalents	$	17,525	$	44,145
Restricted cash included in Other long-term assets		100,973		—
Total cash, cash equivalent and restricted cash	$	118,498	$	44,145

Note 2 — ~~Summary of Significant Accounting Policies~~Acquisitions and Divestitures

Acquisitions qualifying as business combinations are ~~the Company’s significant accounting policies that have been implemented or changed since December 31, 2017.~~

Prior to the Stone Combination, Talos Energy LLC was a partnership for federal income tax purposes and was not subject to federal income tax or state income tax (in most states). As such, Talos Energy LLC was not a taxpaying entity for federal income tax purposes and accordingly, did not recognize any expenses for such states. In connection with completing the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to federal and state income taxes. The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the consolidated balance sheets.

The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, and the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations.

~~The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively.~~

Basic earnings per common share (“EPS”) 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 EPS includes the impact of restricted stock unit grants and outstanding warrants. See Note 9 – ~~Earnings Per Share~~ ~~for additional information.~~

The Company records share-based compensation associated with restricted stock units in general and administrative expense on the condensed consolidated statement of operations, net of amounts capitalized to oil and gas properties. Share-based compensation expense is based on the grant date fair value of issued restricted stock units recognized over the vesting period of the instrument. For each restricted stock unit grant, the Company determines whether the awards represent equity or liability based awards. The fair value of equity awards are determined based on the close price of the stock on the grant date. The fair value of the liability awards are remeasured at each reporting date based on the close price of the stock at such date, until the date of settlement. See Note 7 – ~~Employee Benefits Plans and Share Based Compensation~~ ~~for additional information~~.

On May 10, 2018, the Company consummated the Transactions contemplated by the Transaction Agreement and the Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-owned subsidiaries of the Company. Substantially concurrent with the consummation of the Transactions, the name of the Company was changed from Sailfish Energy Holdings Corporation to Talos Energy Inc. The combination was executed as an all-stock transaction whereby the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.

The purchase price of $732.0 million is based on the closing price of Stone common stock and common warrants immediately prior to closing. The following table summarizes the purchase price (in thousands, except per share data):

The Company incurred approximately $76.2 million of transaction related costs, of which, $20.1 million was expensed and reflected in general and administrative expense on the condensed consolidated statement of operations. The remaining $56.1 million was the result of (i) $9.3 million in work fees paid to holders of the 11.00% Senior Secured Notes reflected as a debt discount reducing long-term debt on the condensed consolidated balance sheet and (ii) $46.8 million in fees for seismic use agreements for change in control provisions and reflected in proved properties on the condensed consolidated balance sheet.

~~The Stone Combination qualified as a business combination and was~~ accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the ~~condensed consolidated balance sheet~~Consolidated Balance Sheets at their fair values as of the acquisition ~~date, May 10, 2018. The fair value measurements~~date.

EnVen Acquisition — On September 21, 2022, the Company executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). On February 13, 2023, the Company completed the EnVen Acquisition for consideration consisting of (i) $207.3 million in cash, (ii) 43.8 million shares of the ~~oil~~Company’s common stock valued at $832.2 million and ~~natural gas properties acquired and asset retirement obligations assumed were derived utilizing~~(iii) effective settlement of an ~~income approach and based, in part,~~accounts receivable balance of $8.4 million. No gain or loss was recognized on ~~significant inputs not observable in~~settlement as 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 estimatespayable was effectively settled at the ~~time~~recorded amount. The cash payment was partially funded with borrowings under the Bank Credit Facility.

The ~~following supplemental pro forma information (in thousands, except per common share amounts), presents the condensed consolidated results of operations~~fair values determined for ~~the three~~accounts receivable, accounts payable and ~~six months ended June 30, 2018~~other current assets and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited proforma information was derived from historical combined statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense appliedmost current liabilities were equivalent to the ~~adjusted basis~~carrying value due to their short-term nature. Assumed debt was valued based on observable market prices.

The fair value of proved oil and natural gas properties ~~acquired (ii) interest expense~~as of the acquisition date is based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows incorporating market participant assumptions. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments were applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the ~~debt transactions contemplated by~~relative uncertainty of each reserve class. These inputs are classified as Level 3 unobservable inputs, including the ~~Exchange Agreement~~underlying commodity price assumptions which are based on the five-year NYMEX forward strip prices, escalated for inflation thereafter, and ~~(iii) general and administrative expense~~ adjusted for ~~transaction related costs incurred. This information does not purport to be indicative~~price differentials.

The fair value of ~~results of operations that would have occurred had the Stone Combination occurred on January 1, 2017, nor~~asset retirement obligations is ~~such information indicative of any expected future results of operations.~~

~~Material, non-recurring adjustments included in pro forma net income (loss) above consist of historical Stone results adjusted to exclude a divestiture of oil and natural gas properties during 2017.~~

~~Proved Properties.~~ The Company’s interests in oil and natural gas properties are located in the United States (“U.S.”) primarily in the Gulf of Mexico deep and shallow waters. The Company follows the full cost method of accounting for its oil and natural gas exploration and development activities.

Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, the Company’s capitalized oil and natural gas costs, net of related deferred taxes, are limited to a ceiling based ondetermined by calculating the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. The Company performs this ceiling test calculation each quarter utilizing SEC pricing. At June 30, 2018, the Company’s ceiling test computation of its U.S. oil and natural gas properties was based on SEC pricing of $60.03 per Bbl of oil, $2.90 per Mcf of natural gas and $28.26 per Bbl of NGLs. During the three and six months ended June 30, 2018 and 2017, the Company’s ceiling test computation did not result in a write-down of its U.S. oil and natural gas properties.

~~Unproved Properties.~~ Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the Gulf of Mexico federal lease sales, certain geological and geophysical costs, costs associated with certain exploratory wells in progress and capitalized interest. Unproved properties also include costs associated with two blocks awarded on September 4, 2015cash flows related to the Company, together with the Company’s working interest partners, located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, by the National Hydrocarbons Commission (“CNH”).

~~Capitalized Overhead.~~ ~~General and administrative expense in the Company’s financial statements is reflected net of capitalized overhead.~~liabilities. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. Capitalized overhead for the three months ended June 30, 2018 and 2017 was $4.5 million and $3.1 million, respectively. Capitalized overhead for the six months ended June 30, 2018 and 2017 was $7.5 million and $6.5 million, respectively.

~~Asset Retirement Obligations.~~ The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when it no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount it will incur to plug, abandon, replace, remove and/or remediate the associated assets at the end of their productive lives. See Note 11 – ~~Commitments and Contingencies~~ ~~relating to performance bonds associated with plugging and abandoning wells.~~

~~In estimating the liability associated with its asset retirement obligations, the~~ Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. ~~Changes in estimate in~~

The Company is still finalizing the ~~table below represent changes~~fair value analysis related to the expected amount and timing of payments to settle the Company’s asset retirement obligations. Typically, these changes result from obtaining new information about the timing of the Company’s obligations to plug, abandon and remediate oil and natural gas ~~wells~~properties acquired, asset retirement obligations assumed, certain contingencies and ~~related infrastructure~~deferred tax liabilities assumed. The Company anticipates finalizing the determination of fair values by December 31, 2023.

The Company incurred approximately $21.8 million of acquisition-related costs in connection with the EnVen Acquisition exclusive of severance expense, of which $0.2 million and $12.8 million were recognized in the ~~costs to do so. After initial recording, the liability is increased~~three and six months ended June 30, 2023, respectively, and $9.0 million were recognized for the ~~passage of time, with the increase being~~year ended December 31, 2022 and reflected ~~as accretion~~in general and administrative expense on the Condensed Consolidated Statements of Operations. Additionally, the Company incurred $1.4 million and $24.0 million in severance expense in connection with the EnVen Acquisition for the three and six months ended June 30, 2023, respectively. See Note 7 — Employee Benefits Plans and Share-Based Compensation for additional discussion.

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three and six months ended June 30, 2023 and 2022 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma information was derived from historical statements of ~~operations. If~~operations of the Company ~~incurs an amount different~~and EnVen adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and to adjust the amortization of the premium of the 11.75% Notes (as defined in Note 6 — Debt), (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) other income (expense) to adjust the accretion of the discount on the P&A Notes Receivable and (v) weighted average basic and diluted shares of common stock outstanding from the ~~amount accrued~~issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for ~~decommissioning obligations,~~the three and six months ended June 30, 2022 were adjusted to exclude $1.5 million and include $78.9 million of general and administrative expenses, respectively, of which $16.3 million were incurred during the year ended December 31, 2022. Supplemental pro forma earnings for the three and six months ended June 30, 2023 were adjusted to exclude $1.4 million and $64.1 million of general and administrative expenses, respectively.This information does not purport to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data).

Mexico Divestiture — On May 25, 2023, the Company ~~recognizes~~executed an equity interest purchase agreement to sell a 49.9% interest in Talos Energy Mexico 7, S. de R.L. de C.V., a wholly owned subsidiary of the ~~difference as an adjustment~~Company (“Talos Mexico”), to ~~proved~~Zamajal, S.A. de C.V, a wholly owned subsidiary of Grupo Carso, for approximately $74.9 million in cash consideration (the “Mexico Divestiture”) due at closing. An additional $49.9 million of cash consideration is contingent on first oil production from the Zama field. As of June 30, 2023, Talos Mexico holds a 17.4% interest in the Zama field. The Mexico Divestiture is expected to close during the third quarter of 2023, subject to approval by Mexico’s Federal Economic Competition Commission.

Note 4 — Leases

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

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

Asset retirement obligations at January 1, 2018

$
214,733

Fair value of asset retirement obligations assumed

220,637

Obligations settled

(43,896
)
Accretion expense

14,252

Obligations incurred

120

Changes in estimate

8,532

Asset retirement obligations at June 30, 2018

$
414,378

Less: Current portion

94,334

Long-term portion

$
320,044


	Three Months Ended June 30,					Six Months Ended June 30,
	2023			2022		2023			2022
Finance lease cost - interest on lease liabilities	$	3,657		$	1,734	$	7,365		$	3,793
Operating lease cost, excluding short-term leases(1)		1,188			567		2,096			1,135
Short-term lease cost(2)		36,864			6,094		69,849			11,856
Variable lease cost(3)		827			362		1,190			725
Variable and fixed sublease income		(69	)		—		(69	)		—
Total lease cost	$	42,467		$	8,757	$	80,431		$	17,509

(1)

Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.

(2)

Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the Condensed Consolidated Balance Sheets.

(3)

Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

Table of Contents

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


	June 30, 2023		December 31, 2022
Operating leases:
Operating lease assets	$	18,104	$	5,903

Current portion of operating lease liabilities	$	3,136	$	1,943
Operating lease liabilities		25,173		14,855
Total operating lease liabilities	$	28,309	$	16,798

Finance leases:
Proved property	$	166,261	$	166,261

Other current liabilities	$	17,028	$	16,306
Other long-term liabilities		140,317		149,064
Total finance lease liabilities	$	157,345	$	165,370

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


	Six Months Ended June 30,
	2023		2022
Operating cash outflow from finance leases	$	7,365	$	3,793
Operating cash outflow from operating leases	$	2,787	$	1,845

Right-of-use assets obtained in exchange for new operating lease liabilities(1)	$	12,971	$	—

(1)

See EnVen Acquisition in Note 2 — Acquisitions and Divestitures.

Note 5 — Financial Instruments

~~The following table presents the carrying amounts and estimated fair values of financial instruments (in thousands):~~

June 30, 2018

December 31, 2017

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

11.00% Second-Priority Senior Secured Notes – due April 2022⁽¹⁾

$
380,042

$
410,411

$
—

$
—

7.50% Senior Secured Notes – due May 2022

$
6,060

$
5,999

$
—

$
—

Bank Credit Facility – due May 2022⁽¹⁾

$
231,522

$
240,000

$
—

$
—

11.00% Bridge Loans – due April 2022⁽¹⁾

$
—

$
—

$
169,838

$
172,023

9.75% Senior Notes – due July 2022⁽¹⁾

$
—

$
—

$
100,681

$
102,000

9.75% Senior Notes – due February 2018

$
—

$
—

$
24,977

$
24,977

Old Bank Credit Facility - due February 2019⁽¹⁾

$
—

$
—

$
402,062

$
403,000

Oil and Natural Gas Derivatives

$
(185,755
)

$
(185,755
)

$
(66,830
)

$
(66,830
)

~~(1)~~

~~The carrying amounts are net of discount and deferred financing costs.~~

As of June 30, ~~2018~~2023 and December 31, ~~2017,~~2022, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because ofthey are highly liquid or due to the short-term nature of these instruments.

~~11.00% Second-Priority Senior Secured Notes – due April 2022.~~ Debt Instruments

The ~~$390.9 million aggregate principal amount of 11.00% Senior Secured Notes are reported on~~following table presents the ~~condensed consolidated balance sheet as of June 30, 2018 at their~~ carrying ~~value,~~amounts, net of ~~original issue~~ discount, premium and deferred financing costs, ~~(see~~and estimated fair values of the Company’s debt instruments (in thousands):


	June 30, 2023				December 31, 2022
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
12.00% Second-Priority Senior Secured Notes – due January 2026	$	593,878	$	674,459	$	590,132		$	674,542
11.75% Senior Secured Second Lien Notes – due April 2026(1)	$	250,822	$	248,723	$	—		$	—
Bank Credit Facility – matures March 2027	$	188,565	$	200,000	$	(4,792	)	$	—

(1)

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

The ~~fair~~carrying value of the ~~11.00% Senior Secured Notes~~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.

~~7.50% Senior Secured Notes – due May 2022~~. The ~~$6.1 million aggregate principal~~carrying amount of ~~7.50% Stone Senior Notes are reported on the condensed consolidated balance sheet as of June 30, 2018 at their carrying value (see Note 6 –~~ ~~Debt). The fair value of the 7.50% Senior Secured Notes are estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.~~

~~Bank Credit Facility – due May 2022.~~ ~~On May 10, 2018, in connection with the Stone Combination,~~ the Company’s ~~senior reserve-based revolving credit facility (“Old Bank Credit Facility”) was repaid and terminated, and the Company executed a new~~ bank credit facility, ~~with an initial borrowing base of $600.0 million (“Bank~~as amended and restated (the “Bank Credit Facility”)~~. The Old Bank Credit Facility was repaid with borrowings from the Bank Credit Facility and cash acquired in the Stone Combination. The Company’s Bank Credit Facility~~, is ~~reported on the condensed consolidated balance sheet as of June 30, 2018 at its carrying value~~presented net of deferred financing ~~costs (see Note 6 –~~ ~~Debt~~).costs. The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the ~~Company’s~~ 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.~~Natural Gas Derivatives

The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas ~~production through the use of~~production. The Company is currently utilizing oil and natural gas swaps ~~put contracts~~ 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 ~~counterparties. The~~ Company ~~has elected not~~if the NYMEX average closing price is above the ceiling price or payments to ~~designate any~~the Company if the NYMEX average closing price is below the floor price (“two-way collar”).

Table of ~~its derivative~~Contents

In connection with the EnVen Acquisition, the Company assumed oil and natural gas collar contracts ~~for hedge accounting. Accordingly, commodity derivatives are recorded on~~that combine a two-way collar with a short put that holds an exercise price below the ~~condensed consolidated balance sheet~~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 ~~fair value with settlements of such contracts~~the difference between the floor price and ~~changes in~~ the ~~unrealized fair value recorded as price risk management activities income (expense) on the condensed consolidated statements of operations in each period.~~short put price.

The following table presents the impact that derivatives, not ~~qualifying~~designated as hedging instruments, had on ~~the Company’s condensed consolidated statements~~its Condensed Consolidated Statements of ~~operations~~Operations (in thousands):


	Three Months Ended June 30,					Six Months Ended June 30,
	2023		2022			2023			2022
Net cash received (paid) on settled derivative instruments	$	8,162	$	(160,235	)	$	(4,161	)	$	(287,321	)
Unrealized gain (loss)(1)		18,035		96,141			89,295			(57,992	)
Price risk management activities income (expense)	$	26,197	$	(64,094	)	$	85,134		$	(345,313	)

Three Months Ended June 30,

Six Months Ended June 30,

2018

2017

2018

2017

Price risk management activities income (expense)⁽¹⁾

$
(91,176
)

$
38,995

$
(143,152
)

$
84,888

(1)

Includes $1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the six months ended June 30, 2023.

~~(1)~~

The Company paid $33.6 million and received $9.2 million in net cash settlements for the three months ended June 30, 2018 and 2017, respectively, and paid $54.1 million and received $13.7 million in net cash settlements for the six months ended June 30, 2018 and 2017, respectively.

The following ~~table reflects~~tables reflect the contracted average daily volumes and weighted average prices under the ~~Company will receive under its~~terms of the Company's derivative contracts as of June 30, ~~2018:~~2023:


Swap Contracts
Production Period	Settlement Index	Volumes		Swap Price
Crude oil:		(Bbls)		(per Bbl)
July 2023 – December 2023	NYMEX WTI CMA		13,174	$	74.53
January 2024 – December 2024	NYMEX WTI CMA		12,100	$	72.32
January 2025 – March 2025	NYMEX WTI CMA		4,000	$	67.00
Natural gas:		(MMBtu)		(per MMBtu)
July 2023 – December 2023	NYMEX Henry Hub		20,000	$	3.79
January 2024 – December 2024	NYMEX Henry Hub		17,459	$	3.44
January 2025 – March 2025	NYMEX Henry Hub		10,000	$	4.37


Two-Way Collar Contracts
Production Period	Settlement Index	Volumes		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
July 2023 – December 2023	NYMEX WTI CMA		6,163	$	68.78	$	87.71
January 2024 – December 2024	NYMEX WTI CMA		1,497	$	70.00	$	79.32
Natural gas:		(MMBtu)		(per MMBtu)		(per MMBtu)
July 2023 – December 2023	NYMEX Henry Hub		10,000	$	5.25	$	8.46
January 2024 – December 2024	NYMEX Henry Hub		10,000	$	4.00	$	6.90


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

Production Period

Instrument
Type

Average
Daily
Volumes

Weighted
Average
Swap Price

Weighted
Average
Put Price

Weighted
Average
Call Price

Crude Oil – WTI:

(Bbls)

(per Bbl)

(per Bbl)

(per Bbl)

July 2018 - December 2018

Swap

29,615

$
54.06

$
—

$
—

July 2018 - December 2018

Collar

1,000

$
—

$
45.00

$
55.35

July 2018 - December 2018

Put

2,000

$
—

$
49.50

$
—

January 2019 - December 2019

Swap

23,130

$
54.14

$
—

$
—

Natural Gas – Henry Hub NYMEX:

(MMBtu)

(per MMBtu)

(per MMBtu)

(per MMBtu)

July 2018 - December 2018

Swap

23,747

$
3.01

$
—

$
—

July 2018 - December 2018

Collar

6,000

$
—

$
2.75

$
3.24

January 2019 - December 2019

Swap

10,146

$
2.99

$
—

$
—

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


	June 30, 2023
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	54,177		$	—	$	54,177
Liabilities:
Oil and natural gas derivatives		—		(9,664	)		—		(9,664	)
Total net asset	$	—	$	44,513		$	—	$	44,513


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

June 30, 2018

Level 1

Level 2

Level 3

Total

Assets:

Oil and natural gas derivatives

$
—

$
733

$
—

$
733

Liabilities:

Oil and natural gas derivatives

—

(186,488
)

—

(186,488
)
Total net liability

$
—

$
(185,755
)

$
—

$
(185,755
)

Table of Contents

December 31, 2017

Level 1

Level 2

Level 3

Total

Assets:

Oil and natural gas derivatives

$
—

$
1,908

$
—

$
1,908

Liabilities:

Oil and natural gas derivatives

—

(68,738
)

—

(68,738
)
Total net liability

$
—

$
(66,830
)

$
—

$
(66,830
)

Financial Statement ~~Presentation.~~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 onin its ~~condensed consolidated balance sheets. On derivative contracts recorded as assets in the table below, the Company is exposed to the risk the counterparties may not perform.~~ Condensed Consolidated Balance Sheets. The following table presents the fair value of derivative financial instruments ~~at June 30, 2018~~as well as the potential effect of netting arrangements on the Company's recognized derivative asset and ~~December 31, 2017~~liability amounts (in thousands):


	June 30, 2023				December 31, 2022
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	45,522	$	8,247	$	25,029	$	68,370
Non-current		8,655		1,417		7,854		7,872
Total gross amounts presented on balance sheet		54,177		9,664		32,883		76,242
Less: Gross amounts not offset on the balance sheet		9,275		9,275		32,883		32,883
Net amounts	$	44,902	$	389	$	—	$	43,359

Credit Risk

June 30, 2018

December 31, 2017

Assets from price risk management activities – current:

Oil and natural gas derivatives

$
499

$
1,563

Assets from price risk management activities – non-current:

Oil and natural gas derivatives

$
234

$
345

Liabilities from price risk management activities – current:

Oil and natural gas derivatives

$
154,722

$
49,957

Liabilities from price risk management activities – non-current:

Oil and natural gas derivatives

$
31,766

$
18,781

~~Credit Risk.~~The Company is subject to the risk of loss on its financial instruments as a result of ~~non-performance~~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 June 30, ~~2018~~2023 represent derivative instruments from ~~eight~~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 ~~six~~eight of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these ~~third parties~~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 June 30, 2023 would have been $44.9 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):


	June 30, 2023			December 31, 2022
12.00% Second-Priority Senior Secured Notes – due January 2026	$	638,541		$	638,541
11.75% Senior Secured Second Lien Notes – due April 2026		242,500			—
Bank Credit Facility – matures March 2027(1)		200,000			—
Total debt, before discount, premium and deferred financing cost		1,081,041			638,541
Unamortized discount, premium and deferred financing cost, net		(47,776	)		(53,201	)
Total debt(2)		1,033,265			585,340
Less: Current portion of long-term debt		33,156			—
Long-term debt	$	1,000,109		$	585,340

Description

June 30, 2018

December 31, 2017

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

Principal

$
390,868

$
—

Original issue discount, net of amortization

(8,906
)

—

Deferred financing costs, net of amortization

(1,920
)

—

7.50% Senior Secured Notes – due May 2022

Principal

6,060

—

Bank Credit Facility – due May 2022

Principal

240,000

—

Deferred financing costs, net of amortization

(8,478
)

—

4.20% Building Loan – due November 2030

Principal

10,778

—

11.00% Bridge Loans – due April 2022

Principal

—

172,023

Deferred financing costs, net of amortization

—

(2,185
)
9.75% Senior Notes – due July 2022

Principal

—

102,000

Deferred financing costs, net of amortization

—

(1,319
)
9.75% Senior Notes – due February 2018

Principal

—

24,977

Old Bank Credit Facility – due February 2019

—

403,000

Deferred financing costs, net of amortization

—

(938
)
Total debt

$
628,402

$
697,558

Less: current portion of long-term debt

(434
)

(24,977
)
Long-term debt, net of discount and deferred financing costs

$
627,968

$
672,581

~~In connection with the Stone Combination,~~(1)

As of June 30, 2023, the Company consummated the Transactions contemplated by the Exchange Agreement, pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes to the Company in exchange for Common Stock; (ii) the holders of 11.00% Bridge Loans exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Senior Secured Notes and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Stone Senior Notes for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes. An additional $81.5 million of 7.50% Stone Senior Notes held by non-affiliates were also exchanged for 11.00% Senior Secured Notes pursuant to an exchange offer and consent solicitation in connection with the Stone Combination.

~~The exchange of 7.50% Stone Senior Notes for 11.00% Senior Secured Notes was accounted for as~~had outstanding borrowings at a ~~debt modification. Under a debt modification, a new effective~~weighted average interest rate ~~that equates the revised cash flows to the carrying amount~~ of the 11.00% Senior Secured Notes is computed and applied prospectively. Costs incurred with third parties directly related to the modification are expensed as incurred. The Company incurred approximately $3.9 million and $4.5 million of transaction fees related to the modification which were expensed and reflected in general and administrative expense during the three months and six months ended7.93%.

~~7.50%~~11.75% Senior Secured Second Lien Notes ~~– due May 2022. The 7.50% Stone Senior Notes represent~~

On February 13, 2023, in conjunction with the ~~remaining $6.1 million~~closing of ~~long-term debt~~the EnVen Acquisition, the Company assumed ~~in the Stone Combination that were not exchanged for 11.00%~~EnVen’s 11.75% Senior Secured Second Lien Notes ~~pursuant to the exchange offer and consent solicitation, and thus remain outstanding. As~~due 2026 (the “11.75% Notes”) with a ~~result~~principal amount of the exchange offer and consent solicitation, substantially all of the restrictive covenants relating to the 7.50% Stone Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes have been released.$257.5 million. The ~~7.50% Stone Senior~~11.75% Notes mature ~~May 31, 2022~~on April 15, 2026 and ~~have~~ interest ~~payable semiannually~~accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each ~~May 31 and November 30. Prior to May 31, 2020,~~year. The indenture governing the ~~Company may, at its option, redeem all or a portion~~11.75% Notes requires the redemption of ~~the 7.50% Stone Senior Notes at 100%~~$15.0 million of the principal amount ~~plus accrued~~outstanding at par value on April 15th and ~~unpaid interest and~~October 15th of each year, a ~~make-whole premium. Thereafter,~~discussion of which is included in the ~~Company may redeem all or a portion~~accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.

The Company ~~executed~~maintains the Bank Credit Facility ~~in conjunction with the Stone Combination~~ with a syndicate of financial ~~institutions, with an initial borrowing base of $600.0 million. The Bank Credit Facility matures on May 10, 2022.~~

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unfunded portion of the commitments under the Bank Credit Facility. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 each quarter beginning on or after September 30, 2018. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter beginning on or after September 30, 2018. According to the Bank Credit Facility, undrawn commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by certain of the Company’s wholly-owned subsidiaries and each direct parent of the Company.

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 ~~its~~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. In June 2018,~~quarter of each year. On December 23, 2022, the Company ~~completed~~entered into the ~~first redetermination~~Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extends the ~~borrowing base was reaffirmed at $600.0 million. The next redetermination will occur in October 2018 and scheduled redeterminations will occur each April and October thereafter.~~

As of June 30, 2018, the Company’s borrowing base was set at $600.0 million, of which no more than $200 million can be used as letters of credit. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisionsmaturity date of the Bank Credit ~~Facility. The Company was~~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 ~~compliance with all debt covenants at June 30, 2018. As of June 30, 2018,~~full, (ii) increases the ~~Bank Credit Facility had approximately $354.0~~borrowing base from $1.1 billion to $1.5 billion and (iii) increases commitments from $806.3 million ~~of undrawn commitments (taking into account $6.0 million letters of credit and $240.0 million drawn from the Bank Credit Facility). The $294.0~~to $965.0 million, in ~~cash received from~~each case went into effect upon the Company’s initial drawdown under the Bank Credit Facility was used to partially repay outstanding borrowings under the Old Bank Credit Facility upon its termination in connection with the Stone Combination.

~~Building Loan – due November 2030~~. In connection with the Stone Combination, the Company assumed Stone’s 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million. As of June 30, 2018, the outstanding balance under the Building Loan totaled $10.8 million. The Building Loan is collateralized by the Company’s two Lafayette, Louisiana office buildings. Under the financial covenantsclosing of the Building Loan, the Company must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. The Company is in compliance with all covenants under the Building Loan as of June 30, 2018.

~~9.75% Senior Notes – due February 2018. The 9.75% Senior Notes were issued pursuant to an indenture dated February 6, 2013 among the Talos Issuers, the subsidiaries, as issuers, the subsidiary guarantors party thereto~~EnVen Acquisition and the ~~trustee.~~occurrence of certain events related thereto, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report. On ~~February 15, 2018,~~June 9, 2023, the ~~Talos Issuers redeemed the remaining $25.0~~borrowing base decreased from $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million ~~principal amount~~as part of the ~~9.75% Senior Notes at par.~~most recent biannual redetermination.

Note 7 — Employee Benefits Plans and Share-Based Compensation

~~Stone Change~~EnVen Acquisition Severance

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


Severance accrual at December 31, 2022	$	—
Accrual additions		24,075
Benefit payments		(8,494	)
Severance accrual at June 30, 2023		15,581
Less: Current portion at June 30, 2023		15,006
Long-term portion at June 30, 2023	$	575

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 ~~Severance Plans~~

~~In connection~~funded with $14.5 million at closing to pay a portion of future severance benefits associated with the ~~Transactions,~~contractual termination benefits. As of June 30, 2023, the ~~Company maintains the Stone Energy Corporation Executive Severance Plan~~rabbi trust held $9.3 million in assets of which $8.7 million and ~~Stone Energy Corporation Employee Severance Plan, which provides for the payment of severance~~$0.6 million are included in “Other current assets” and ~~change in control benefits to certain individuals who, prior to the transaction, were executive officers of Stone and all full-time employees of Talos Petroleum LLC (f/k/a Stone Energy Corporation)~~“Other assets”, ~~in each case upon an involuntary termination within twelve months of Closing. The Company incurred $7.5 million of severance expense reflected in general and administrative expense~~respectively, on the ~~condensed consolidated statement~~Condensed Consolidated Balance Sheets and both of ~~operations for~~which are included in the ~~three and six months ended June 30, 2018. Approximately $5.1 million of such expense remained unpaid~~severance accrual at June 30, ~~2018.~~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 ~~Plan~~Plans

~~Overview. In connection with the Closing, the Company adopted~~Restricted Stock Units (“RSUs”) — The following table summarizes RSU activity under the Talos Energy Inc. 2021 Long Term Incentive Plan (the “LTIP”), pursuant to which the Company may issue to its employees, directors and consultants various forms of share-based compensation including stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards or any combination of the foregoing. The Company is authorized to grant awards of up to 5,415,576 shares of the Company’s common stock for awards under the LTIP. As of June 30, 2018, no shares have been issued.

~~Restricted Stock Units.~~ ~~On May 21, 2018, the Company granted 22,963 restricted stock units (“RSUs”~~“2021 LTIP”) to non-employee directors. These RSUs will vest on May 19, 2019, subject to such non-employee director’s continued service. These RSUs represent a contingent right to receive 60% in Common Stock and the remaining 40% in cash following vesting. The total unrecognized compensation cost related to these RSUs at June 30, 2018 was approximately $0.7 million, which is expected to be recognized over a weighted average period of eleven months. Of the $0.7 million in unrecognized compensation cost, $0.3 million relates to liability awards and will be subsequently remeasured at each reporting period.

~~Talos Energy LLC Series B Units~~

Prior to the Stone Combination, the Limited Liability Company Agreement of Talos Energy LLC (the “LLC Agreement”) established Series A, Series B and Series C Units. Series B Units were generally intended to be used as incentives for Company employees. Series B Units do not participate in distributions prior to vesting or until Series A Units have received cumulative distributions equal to (i) the original cash contributed to the Company for such Series A Units and (ii) an 8% return, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received $25.0 million in distributions. In connection with the Transactions, the Series A, Series B and Series C Units were exchanged for an equivalent number of units in each of an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock of the Company. The modification did not result in incremental value to the Series B Units.

For accounting and financial reporting purposes, the Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to “Accumulated deficit” on the condensed consolidated balance sheet. During the six months ended June 30, ~~2018~~2023:


	RSUs			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2022		3,215,504		$	12.79
Granted		1,078,062		$	16.26
Vested		(1,615,488	)	$	11.99
Forfeited		(53,991	)	$	16.59
Unvested RSUs at June 30, 2023(1)		2,624,087		$	14.63

(1)

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

Table of Contents

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


	PSUs		Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2022		638,601	$	23.66
Granted(1)		569,800	$	18.97
Unvested PSUs at June 30, 2023		1,208,401	$	21.45

(1)

There were 284,900 PSUs granted that are eligible to vest based on continued employment and ~~2017,~~the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 284,900 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.

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


	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):


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Share-based compensation costs	$	8,291	$	7,319	$	15,482	$	12,971
Less: Amounts capitalized to oil and gas properties		3,542		3,270		6,795		5,604
Total share-based compensation expense	$	4,749	$	4,049	$	8,687	$	7,367

Note 10 — Related Party Transactions

~~Contributions and Distributions~~.~~During the six months ended June 30, 2018 and 2017, the Company did not receive any cash contributions or make any distributions to~~ Apollo ~~Global Management LLC~~Funds and Riverstone ~~Holdings, LLC (the “Sponsors”).~~

~~Transaction Fee Agreement~~. As part of the agreements with Sponsors, the Company paid a transaction fee equal to 2% of capital contributions made by each Sponsor. For the six months ended June 30, 2018 and 2017, the Sponsors did not make any capital contributions and thus the Company did not incur or pay transaction fees related to capital contributions. In connection with the Stone Combination on May 10, 2018, the Transaction Fee Agreement was terminated.Funds

~~Service Fee Agreement.~~ The Company entered into service fee agreements with each of its Sponsors for the provision of certain management consulting and advisory services. Under each agreement, the Company pays a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however, such fees shall not exceed in each case $0.5 million, in aggregate, for any calendar year. For the six months ended June 30, 2018 and 2017, the Company incurred approximately $0.5 million and $0.3 million, respectively, for these services. For the three months ended June 30, 2018 and 2017, the Company incurred $0.4 million and $0.2 million, respectively, for these services. These fees are recognized in general and administrative expense on the condensed consolidated statements of operations. In connection with the Stone Combination on May 10, 2018, the Service Fee Agreement was terminated.

~~Debt Modification Work Fees.~~ The Company paid $9.3 million in work fees to holders of the 11.00% Bridge Loans and 7.50% Stone Senior Notes to exchange into 11.00% Senior Secured Notes. The Sponsors received $4.1 million and the Franklin Noteholders and McKay Noteholders received $3.3 million, respectively, as a result of the work fees paid.

~~Note 11 — Commitments and Contingencies~~

~~Capital Lease~~

As of June 30, 2018, the balance of the capital lease obligation on the condensed consolidated balance sheet was $99.7 million, of which $12.7 million is included in “other current liabilities” and $87.0 million is included in “other long-term liabilities”.

~~Performance Obligations~~

As of June 30, 2018, the Company had secured performance bonds primarily related to plugging and abandonment of wells, removal of facilities and to guarantee the completion of the minimum work program related to the Mexico Production Sharing Contracts (“PSCs”) totaling approximately $569.3 million. The Mexico PSCs govern the exploration and extraction of the hydrocarbons in Mexico with the CNH. As of June 30, 2018, the Company has not posted any collateral on the outstanding performance bonds.

~~Legal Proceedings~~

The Company is named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. The Company does not expect that these matters, individually or in the aggregate, will have a material adverse effect on its financial condition.

~~Other Commitments~~

On February 8, 2018, the Company amended a previous agreement to use the Ensco 75, a jackup drilling rig, to execute a portion of its 2018 drilling program. Under the terms of the amended agreement, the Company will pay Ensco a base vessel day work rate based on the number of days contracted for a minimum of 120 days during 2018, for approximately $7.8 million. On June 1, 2018, the Company exercised its option for an additional 90 days during 2018 for approximately $6.3 million. Total commitments for 2018 for the Ensco 75 are $14.1 million.

On June 18, 2018, the Company entered into an agreement for the Ensco 8503 drilling rig to execute a portion of its 2018 deepwater drilling program commencing November 1, 2018. Under the terms of the agreement, the Company will pay Ensco an operating day work rate based on the number of days contracted for a minimum of 100 days. Total commitments for 2018 and 2019 are $7.9 million and $5.1 million, respectively.

In connection with the Stone Combination, the Company entered into seismic use agreements totaling $46.8 million. As of June 30, 2018, the outstanding payments due are approximately $29.8 million consisting of $6.6 million, $10.9 million, $9.9 million and $2.4 million for the remainder of 2018, 2019, 2020 and 2021, respectively.

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

~~Overview~~

~~Our Business~~

We are a technically driven independent exploration and production company with operations in the United States Gulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the Gulf of Mexico is the exploration, acquisition, exploitation and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide us high impact exploration opportunities in an emerging basin. We use our access to an extensive seismic database and our deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. Our management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico.

On May 10, 2018 (the “Closing Date”), we (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), among Stone Energy Corporation (“Stone”), Sailfish Merger Sub Corporation (“Merger Sub”),3, 2012, Talos Energy LLC completed a transaction with funds and Talos Production LLC, pursuant to which each of Stone and Talos Energy LLC became our wholly-owned subsidiaries (the “Stone Combination”). Substantially concurrent with the consummation of the transactions, we changed our name from Sailfish Energy Holdings Corporation to Talos Energy Inc.

Pursuant to the Transaction Agreement, a series of transactions occurred on the Closing Date (the “Closing”), including: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and a direct wholly owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares heldother alternative investment vehicles managed by Stone, which were cancelled for no consideration) was converted into the right to receive one share of our common stock, par value $0.01 (the “Common Stock”); and (ii) in a series of contributions, entities related to Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I ~~( “Apollo~~(“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”) ~~contributed~~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 9.9% of the Company’s outstanding shares of common stock as of June 30, 2023 based on SEC beneficial ownership reports filed by the Riverstone Funds. On July 5, 2023, the Riverstone Funds ceased being a beneficial owner of more than five percent of the Company’s common stock.

Registration Rights Agreements

Riverstone Funds as well as ILX Holdings, LLC; ILX Holdings II, LLC; ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate of the Riverstone Funds, are parties to an amended registration rights agreement relating to the registered resale of the Company’s common stock owned by such parties, a discussion of which is included in the accompanying Notes to the Consolidated Financial Statements in the 2022 Annual Report. Effective July 5, 2023, the Registration Rights Agreement terminated as there are no Registrable Securities (defined therein) outstanding.

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Adage Capital Partners, L.P. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”) are parties to a registration rights agreement entered into in connection with the EnVen Acquisition relating to the registered resale of the Company’s common stock owned by such parties, a discussion of which is included in the accompanying Notes to the Consolidated Financial Statements in the 2022 Annual Report. Adage and Bain held approximately 5.2% and 12.2%, respectively, of the Company’s outstanding shares of common stock as of June 30, 2023 based on SEC beneficial ownership reports filed by each of Adage and Bain.

The Company will bear all of the ~~equity interests~~expenses incurred in ~~Talos Production LLC (which at that time owned 100%~~connection with any offer and sale, while the selling stockholders will be responsible for paying underwriting fees, discounts and selling commissions. For the three and six months ended June 30, 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 ~~equity interests~~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 ~~Talos Energy LLC)~~the accompanying Notes to usConsolidated Financial Statements in ~~exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”).~~the 2022 Annual Report.

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

Riverstone Funds Support Agreement

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

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at V&E. For the three and six months ended June 30, 2023, the Company incurred fees for legal services performed by V&E of approximately $0.4 million and $2.1 million, respectively, of which $0.7 million was payable for legal services performed by V&E. For the three and six months ended June 30, 2022, the Company incurred fees for legal services performed by V&E of approximately $1.0 million and $1.5 million, respectively, of which $1.2 million was payable for legal services performed by V&E.

Bayou Bend CCS LLC

On March 8, 2022, the Company made a $2.3 million cash contribution for a 50% membership interest in Bayou Bend CCS LLC (“Bayou Bend”). Bayou Bend has a CCS site 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. The Company recognized a $13.9 million gain on the partial sale of its investment in Bayou Bend during the three and six months ended June 30, 2022, which is included in “Equity method investments income” on the Condensed Consolidated Statements of Operations. Chevron also agreed to fund up to $10.0 million of contributions to Bayou Bend on the Company’s behalf, which was fully funded during the first quarter of 2023. The Bayou Bend investment was increased with an offsetting gain as the capital carry was funded by Chevron. The Company recognized an $8.6 million gain on the funding of the ~~Transaction Agreement,~~capital carry of its investment in Bayou Bend during the six months ended June 30, 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 $0.2 million related party receivable from Bayou Bend as of June 30, 2023. During March 2023, Bayou Bend expanded its storage footprint through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located within the Houston Ship Channel, Beaumont and Port Arthur region.

As of June 30, 2023, the Company ~~consummated~~owns a 25% membership interest in Bayou Bend, which is a variable interest entity and accounted for using the ~~transactions contemplated by~~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.

Note 12 — Segment Information

The Company’s operations are managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The Upstream Segment is the Company’s only reportable segment. The Company’s chief operating decision-maker (“CODM”) is the President and Chief Executive Officer, who reviews operating results to make decisions about allocating resources and assessing performance for the entire company. A reportable segment is an operating segment that meets materiality thresholds. The 10% tests, as prescribed by the segment reporting accounting guidance, are based on the reported measures of revenue, profit, and assets that are used by the CODM to assess performance and allocate resources. The CCS Segment currently does not meet any of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuantreportable segment quantitative thresholds. The profit or loss metric used to evaluate segment performance is Adjusted EBITDA, which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% senior notes due 2022 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to us in exchange for an aggregate of 2,874,049 shares of Common Stock; (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issuedis defined by the ~~Talos Issuers exchanged~~Company as net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion, and amortization; accretion expense; non-cash write-down of oil and natural gas properties; transaction and other (income) expenses; decommissioning obligations; the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives); (gain) loss on debt extinguishment; non-cash write-down of other well equipment inventory; and non-cash equity-based compensation expense.

Corporate general and administrative expense include certain shared costs such ~~11.00% Bridge Loans for $172.0 million aggregate principal amount~~as finance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each of ~~11.00% Second-Priority Senior Secured Notes due 2022~~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 ~~Talos Issuers (“11.00% Senior Secured Notes”)~~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 ~~(iii) Franklin Noteholders~~therefore, no asset information is provided in the table below.

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


	Upstream			All Other(1)			Total
Revenues from External Customers:
Three Months Ended June 30, 2023	$	367,210		$	—		$	367,210
Three Months Ended June 30, 2022		519,085			—			519,085
Six Months Ended June 30, 2023		689,792			—			689,792
Six Months Ended June 30, 2022		932,651			—			932,651
Equity in the Net Income of Investees Accounted for by the Equity Method:
Three Months Ended June 30, 2023	$	123		$	(2,134	)	$	(2,011	)
Three Months Ended June 30, 2022		(212	)		(197	)		(409	)
Six Months Ended June 30, 2023		255			(3,411	)		(3,156	)
Six Months Ended June 30, 2022		(70	)		(197	)		(267	)
Adjusted EBITDA:
Three Months Ended June 30, 2023	$	253,615		$	(2,360	)	$	251,255
Three Months Ended June 30, 2022		257,346			(5,413	)		251,933
Six Months Ended June 30, 2023		464,098			(8,517	)		455,581
Six Months Ended June 30, 2022		469,428			(7,944	)		461,484
Segment Expenditures:
Six Months Ended June 30, 2023	$	379,361		$	23,057		$	402,418
Six Months Ended June 30, 2022		168,048			2,585			170,633

(1)

The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and ~~MacKay Noteholders exchanged their 7.500% Senior Secured Notes due~~the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

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Reconciliations

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Adjusted EBITDA:
Total for reportable segments	$	253,615		$	257,346		$	464,098		$	469,428
All other		(2,360	)		(5,413	)		(8,517	)		(7,944	)
Unallocated corporate general and administrative expense		(1,532	)		(1,156	)		(2,795	)		(2,494	)
Interest expense		(45,632	)		(30,776	)		(83,213	)		(62,266	)
Depreciation, depletion and amortization		(169,794	)		(104,511	)		(317,117	)		(202,851	)
Accretion expense		(22,760	)		(14,844	)		(42,174	)		(29,221	)
Transaction and other income (expenses)(1)		(3,513	)		15,214			(25,522	)		42,075
Decommissioning obligations(2)		(741	)		(10,204	)		(1,482	)		(10,533	)
Derivative fair value gain (loss)(3)		26,197			(64,094	)		85,134			(345,313	)
Net cash (received) paid on settled derivative instruments (3)		(8,162	)		160,235			4,161			287,321
Non-cash equity-based compensation expense		(4,749	)		(4,049	)		(8,687	)		(7,367	)
Income (loss) before income taxes	$	20,569		$	197,748		$	63,886		$	130,835

(1)

For the three and six months ended June 30, 2023, transaction expenses includes $2.7 million and $37.9 million, respectively, in costs related to the EnVen Acquisition, inclusive of $1.4 million and $24.0 million, respectively, in severance expense. See further discussion in Note 2 — Acquisitions and Divestitures and Note 7 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. It includes an $8.6 million gain on the funding of the capital carry of its investment in Bayou Bend by Chevron for the six months ended June 30, 2023 and a $13.9 million gain on the partial sale of its investment in Bayou Bend by Chevron for the three and six months ended June 30, 2022, ~~issued by Stone (“7.50% Stone Senior Notes”) for $137.4~~that is further discussed in Note 10 — Related Party Transactions. For the six months ended June 30, 2022, the amount includes $27.5 million ~~aggregate principal amount of 11.00% Senior Secured Notes.~~

Asgain as a result of the ~~closing~~settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 11 — Commitments and Contingencies.

(2)

Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the ~~transactions contemplated by~~required abandonment obligations due to bankruptcy or insolvency. See Note 11 — Commitments and Contingencies for additional information on decommissioning obligations.

(3)

The adjustments for the ~~Transaction Agreement~~derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the ~~Exchange Agreement (the “Transactions”)~~effect of adjusting net loss for changes in the ~~former stakeholders~~fair value of ~~Talos Energy LLC held approximately 63%~~derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

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


	Six Months Ended June 30,
	2023			2022
Segment Expenditures:
Total reportable segments	$	379,361		$	168,048
All other		23,057			2,585
Change in capital expenditures included in accounts payable and accrued liabilities		(7,546	)		(1,592	)
Plugging & abandonment		(47,683	)		(39,768	)
Decommissioning obligations settled		(2,047	)		—
Investment in CCS intangibles and equity method investees		(23,057	)		(2,585	)
Deferred payments		(462	)		—
Insurance recovery proceeds		12,500			—
Non-cash well equipment inventory transfers		(35,793	)		143
Other		328			1,251
Exploration, development and other capital expenditures	$	298,658		$	128,082

Item 2. Management’s Discussion and ~~the former stockholders~~Analysis of ~~Stone held approximately 37%~~Financial Condition and Results of ~~the Company’s outstanding common stock as of the Closing Date.~~Operations

Unless otherwise indicated or the context otherwise requires, references in this ~~report~~Quarterly Report to “us,” “we,” ~~“our”~~“our,” “Talos” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2022 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2022 Annual Report.

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 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, ~~or are~~an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy ~~our~~ capital as efficiently as possible.

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

Below is a cumulative list of significant developments that have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended March 31, 2023.

Mexico Pending Divestiture— On May 25, 2023, the Company executed an equity interest purchase agreement to ~~opportunistically expand our asset base by evaluating~~sell a 49.9% interest in Talos Energy Mexico 7, S. de R.L. de C.V., a wholly owned subsidiary of the ~~robust supply~~Company, to Zamajal, S.A. de C.V, a wholly owned subsidiary of ~~acquisition opportunities in the Gulf~~Grupo Carso. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures”for more information.

Freeport LNG CCS— The exclusivity letter of ~~Mexico. The acquisition strategy is focused on deep and shallow water assets~~intent with ~~a geological setting which we believe can benefit from our access to~~ an extensive seismic database and our reprocessing expertise to reevaluate the acquired assets. We expect to target acquisitions involving assets with physical infrastructure that will allow us to focus on additional drilling opportunities. By applying a disciplined valuation methodology, we seek to reduce the riskaffiliate of acquired property underperformance while maintaining potential for higher returns on our investment. In addition, we may consider acquisition opportunities in other offshore basins with analogous geologies that are suitable for our operational and technical expertiseFreeport LNG Development, L.P., relating to the ~~extent~~development of a CCS point source project in Freeport, Texas, expired during the second quarter of 2023. As of June 30, 2023, we ~~believe it will increase our reserves and enhance returns on our investment and long-term growth prospects.~~

Factors Affecting the Comparability of ~~Our~~our Financial Condition and Results of Operations

~~As previously described, Stone~~The following items affect the comparability of our financial condition and Talos Energy LLC became our wholly-owned subsidiaries on the Closing Date. Prior to the Closing Date, we had not conducted any material activities other than those incident to our formation and certain matters contemplated by the Transaction Agreement. Talos Energy LLC is the acquirer of Stone for financial reporting and accounting purposes. Talos Energy LLC was considered the accounting acquirer in the Transactions under accounting principles generally accepted in the United States of America (“GAAP”). Accordingly, our historical financial and operating data, which cover periods prior to May 10, 2018, reflects the assets, liabilities and operations of Talos Energy LLC prior to the Closing Date and does not reflect the assets, liabilities and operations of Stone prior to the Closing Date. In addition, we incurred material costs associated with the Transactions that are reflected in our historical results of operations for periods ~~prior~~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 ~~Closing Date,~~Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and ~~Talos Energy LLC did not incur United States federal income tax expense or~~Divestitures”for more information.

Eugene Island Pipeline System — During the ~~incremental expenses associated with being a public company.~~

~~Comparison~~2022, we experienced approximately 40 days of unplanned third-party downtime due to maintenance of the ~~Three Months Ended June 30, 2018 and 2017~~

~~The information below provides the financial results and an analysis of significant variances in these results for the three months ended June 30, 2018 and 2017 (in thousands):~~

Three Months Ended June 30,

2018

2017

Change

% Change

Revenues:

Oil revenue

$
180,161

$
78,719

$
101,442

129
%
Natural gas revenue

16,448

12,888

3,560

28
%
NGL revenue

7,297

3,436

3,861

112
%
Other

—

383

(383
)

(100
)%
Total revenue

203,906

95,426

108,480

114
%
Operating expenses:

Direct lease operating expense

34,060

28,871

5,189

18
%
Insurance

4,259

2,688

1,571

58
%
Production taxes

564

380

184

48
%
Total lease operating expense

38,883

31,939

6,944

22
%
Workover and maintenance expense

17,714

8,225

9,489

115
%
Depreciation, depletion and amortization

67,726

36,157

31,569

87
%
Accretion expense

9,492

5,321

4,171

78
%
General and administrative expense

30,880

7,470

23,410

313
%
Total operating expenses

164,695

89,112

75,583

85
%
Operating income

39,211

6,314

32,897

521
%
Interest expense

(21,678
)

(20,805
)

873

4
%
Price risk management activities income (expense)

(91,176
)

38,995

(130,171
)

(334
)%
Other income (expense)

(1,269
)

103

(1,372
)

(1332
)%
Total other income (expense)

(114,123
)

18,293

(132,416
)

(724
)%
Income (loss) before income taxes

(74,912
)

24,607

(99,519
)

(404
)%
Income tax expense (benefit)

—

—

—

—
%
Net income (loss)

$
(74,912
)

$
24,607

$
(99,519
)

(404
)%

~~The table below provides additional detail of~~Eugene Island Pipeline System, which carries our ~~oil, natural gas and NGL production volumes and sales prices per unit.~~

Three Months Ended June 30,

2018

2017

Change

Oil production volume (MBbls)

2,651

1,712

939

Average daily oil production volume (MBblpd)

29.1

18.8

10.3

Oil sales revenue (in thousands)

$
180,161

$
78,719

$
101,442

Average oil sales price per Bbl
     (including commodity derivatives)

$
55.12

$
51.69

$
3.43

Average oil sales price per Bbl
     (excluding commodity derivatives)

$
67.96

$
45.98

$
21.98

Average NYMEX WTI price per Bbl

$
67.88

$
48.28

$
19.60

Increase in oil sales revenue due to:

Change in net realized prices (in thousands)

$
58,267

Change in production volume (in thousands)

43,175

Total increase in oil sales revenue (in thousands)

$
101,442

Natural gas production volume (MMcf)

5,948

4,209

1,739

Average daily natural gas production volume (MMcfpd)

65.4

46.3

19.1

Natural gas sales revenue (in thousands)

$
16,448

$
12,888

$
3,560

Average natural gas sales price per Mcf
      (including commodity derivatives)

$
2.84

$
2.92

$
(0.08
)
Average natural gas sales price per Mcf
     (excluding commodity derivatives)

$
2.77

$
3.06

$
(0.29
)
Average NYMEX Henry Hub price per MMBtu

$
2.80

$
3.18

$
(0.38
)
Increase in natural gas sales revenue due to:

Change in net realized prices (in thousands)

$
(1,761
)

Change in production volume (in thousands)

5,321

Total increase in natural gas sales revenue
     (in thousands)

$
3,560

NGL production volume (MBbls)

273

166

107

Average daily NGL production volume (MBblpd)

3.0

1.8

1.2

NGL sales revenue (in thousands)

$
7,297

$
3,436

$
3,861

Average NGL sales price per Bbl

$
26.73

$
20.70

$
6.03

Increase in NGL sales revenue due to:

Change in net realized prices (in thousands)

$
1,646

Change in production volume (in thousands)

2,215

Total increase in NGL sales revenue (in thousands)

$
3,861

Total production volume (MBoe)⁽¹⁾

3,915

2,579

1,336

Average daily total production volume (MBoepd)⁽¹⁾

43.0

28.3

14.7

Price per Boe⁽¹⁾ (including commodity derivatives)

$
43.49

$
40.41

$
3.08

Price per Boe⁽¹⁾(excluding commodity derivatives)

$
52.08

$
36.85

$
15.23

The following table highlights 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 for the three months ended June 30, 2018 and 2017 (in thousands, except per Boe data):

~~Revenue.~~ Total revenue for the three months ended June 30, 2018 was $203.9 million compared to $95.4 million for the three months ended June 30, 2017, an increase of approximately $108.5 million, or 114%. Oil revenue increased approximately $101.4 million, or 129%, during the three months ended June 30, 2018. This increase was primarily due to an increase of $21.98 per Bbl in our realized oil sales price and a 10.3 MBblpd increase in oil production volumes. The increase in oil production volumes was attributable to 9.6 MBblpd from the Stone Combination and 3.3 MBblpd from the Tornado II well in the Phoenix Field which commenced initial production in December 2017. This was partially offset by 1.1 MBblpd deferred production from the Phoenix Field ~~for unplanned third party downtime for the Helix Producer I (“HP-I”) as determined by Helix Energy Solutions Group, Inc. (Helix”).~~

Natural gas revenue increased approximately $3.6 million, or 28%, during the three months ended June 30, 2018. This increase was primarily due to a 19.1 MMcfpd increase in gas volumes, 22.6 MMcfpd of which was attributable to the Stone Combination. This is partially offset by a $0.29 per Mcf decrease in our realized gas sales price.

~~NGL revenue increased approximately $3.9 million, or 112%, during the three months ended June 30, 2018. This increase was due to an increase of $6.03 per Bbl in our realized NGL sales price~~ and ~~a 1.2 MBblpd increase in NGL volumes, all of which was attributable to the Stone Combination.~~

~~Lease operating expense.~~ Total lease operating expense for three months ended June 30, 2018 was $38.9 million compared to $31.9 million for the three months ended June 30, 2017, an increase of approximately $6.9 million, or 22%. This increase was primarily related to $9.9 million of lease operating expense in connection with the Stone Combination, partially offset by a $2.9 million decrease due to additional reimbursements related to our production handling agreements in the PhoenixGreen Canyon 18 Field.

~~Depreciation, depletion and amortization.~~ Depreciation, depletion and amortization expense for the three months ended June 30, 2018 was $67.7 million compared to $36.2 million for the three months ended June 30, 2017, an increase of approximately $31.6 million, or 87%. This increase is primarily due to a $3.33 per Boe, or 24%, increase in the depletion rate on our proved oil and natural gas properties during the three months ended June 30, 2018. Depletion on a per Boe basis increased primarily due to an increase in proved properties related to the Stone Combination and higher estimated future development costs related to proved undeveloped reserves in the Phoenix Field.

~~General and administrative expense.~~ General and administrative expense for the three months ended June 30, 2018 was $30.9 million compared to $7.5 million for the three months ended June 30, 2017, an increase of approximately $23.4 million, or 313%. This increase was primarily attributable to $18.3 million in transaction related costs related to the Stone Combination and additional general and administrative expenses as a result of the combined company.

~~Other operating expense.~~ Other operating expense for the three months ended June 30, 2018 was $27.2 million compared to $13.5 million for the three months ended June 30, 2017, an increase of approximately $13.7 million, or 101%. This increase was primarily related to an increase of $4.5 million and $4.1 million in workover and maintenance expense and accretion expense, respectively, in connection with the Stone Combination. This increase also relates to a $5.0 million increase in repairs and maintenance during the three months ended June 30, 2018 primarily related to $1.3 million in repairs on SMI 130 and inspection and reconnection support in the Phoenix Field of $1.2 million.

~~Price risk management activities.~~ Price risk management activities for the three months ended June 30, 2018 resulted in a $91.2 million expense compared to income of $39.0 million for the three months ended June 30, 2017. The change of approximately $130.2 million was attributable to a $87.4 million decrease in the fair value of our open derivative contracts and a $42.8 million decrease in cash settlement gains for the three months ended June 30, 2018. 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 2019, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

~~The information below provides the financial results and an analysis of significant variances in these results for~~ For the six months ended June 30, ~~2018 and 2017 (in thousands):~~

Six Months Ended June 30,

2018

2017

Change

% Change

Revenues:

Oil revenue

$
307,854

$
162,487

$
145,367

89
%
Natural gas revenue

29,171

26,062

3,109

12
%
NGL revenue

12,731

7,069

5,662

80
%
Other

—

1,632

(1,632
)

(100
)%
Total revenue

349,756

197,250

152,506

77
%
Operating expenses:

Direct lease operating expense

58,975

56,735

2,240

4
%
Insurance

6,934

5,409

1,525

28
%
Production taxes

955

645

310

48
%
Total lease operating expense

66,864

62,789

4,075

6
%
Workover and maintenance expense

24,619

17,047

7,572

44
%
Depreciation, depletion and amortization

116,766

76,088

40,678

53
%
Accretion expense

14,252

10,509

3,743

36
%
General and administrative expense

39,460

17,216

22,244

129
%
Total operating expenses

261,961

183,649

78,312

43
%
Operating income

87,795

13,601

74,194

546
%
Interest expense

(41,420
)

(39,577
)

1,843

5
%
Price risk management activities income (expense)

(143,152
)

84,888

(228,040
)

(269
)%
Other income (expense)

(1,078
)

157

(1,235
)

(787
)%
Total other income (expense)

(185,650
)

45,468

(231,118
)

(508
)%
Income (loss) before income taxes

(97,855
)

59,069

(156,924
)

(266
)%
Income tax expense (benefit)

—

—

—

—
%
Net income (loss)

$
(97,855
)

$
59,069

$
(156,924
)

(266
)%

~~The table below provides additional detail of our oil, natural gas and NGL~~2022, we estimate the shut-in resulted in deferred production ~~volumes and sales prices per unit.~~

Six Months Ended June 30,

2018

2017

Change

Oil production volume (MBbls)

4,682

3,468

1,214

Average daily oil production volume (MBblpd)

25.9

19.2

6.7

Oil sales revenue (in thousands)

$
307,854

$
162,487

$
145,367

Average oil sales price per Bbl (including commodity derivatives)

$
54.12

$
51.28

$
2.84

Average oil sales price per Bbl (excluding commodity derivatives)

$
65.75

$
46.85

$
18.90

Average NYMEX WTI price per Bbl

$
65.37

$
50.10

$
15.27

Increase in oil sales revenue due to:

Change in net realized prices (in thousands)

$
88,491

Change in production volume (in thousands)

56,876

Total increase in oil sales revenue (in thousands)

$
145,367

Natural gas production volume (MMcf)

10,069

8,498

1,571

Average daily natural gas production volume (MMcfpd)

55.6

47.0

8.6

Natural gas sales revenue (in thousands)

$
29,171

$
26,062

$
3,109

Average natural gas sales price per Mcf (including commodity derivatives)

$
2.94

$
2.87

$
0.07

Average natural gas sales price per Mcf (excluding commodity derivatives)

$
2.90

$
3.07

$
(0.17
)

Average NYMEX Henry Hub price per MMBtu

$
2.90

$
3.25

$
(0.35
)

Increase in natural gas sales revenue due to:

Change in net realized prices (in thousands)

$
(1,714
)

Change in production volume (in thousands)

4,823

Total increase in natural gas sales revenue (in thousands)

$
3,109

NGL production volume (MBbls)

471

337

134

Average daily NGL production volume (MBblpd)

2.6

1.9

0.7

NGL sales revenue (in thousands)

$
12,731

$
7,069

$
5,662

Average NGL sales price per Bbl

$
27.03

$
20.98

$
6.05

Increase in NGL sales revenue due to:

Change in net realized prices (in thousands)

$
2,851

Change in production volume (in thousands)

2,811

Total increase in NGL sales revenue (in thousands)

$
5,662

Total production volume (MBoe)⁽¹⁾

6,831

5,222

1,609

Average daily total production volume (MBoepd)⁽¹⁾

37.7

28.9

8.8

Price per Boe⁽¹⁾(including commodity derivatives)

$
43.29

$
40.08

$
3.21

Price per Boe⁽¹⁾ (excluding commodity derivatives)

$
51.20

$
37.46

$
13.74

The following table highlights 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 for the six months ended June 30, 2018 and 2017 (in thousands, except per Boe data):

~~Revenue.~~ ~~Total revenue for the six months ended June 30, 2018 was $349.8 million compared to $197.3 million for the six months ended June 30, 2017, an increase~~ of approximately $152.5 million, or 77%. Oil revenue increased approximately $145.4 million, or 89%, during the six months ended June 30, 2018. This increase was primarily due to an increase of $18.90 per Bbl in our realized oil sales price and a 6.7 MBblpd increase in oil2.3 MBoepd based on production volumes. The increase in oil production volumes was attributable to 4.8 MBblpd from the Stone Combination and 3.3 MBblpd from the Tornado II well in the Phoenix Field which commenced initial production in December 2017. This was partially offset by 0.6 MBblpd deferred production from the Phoenix Field for unplanned third party downtime for the HP-I as determined by Helix.

Natural gas revenue increased approximately $3.1 million, or 12%, during the six months ended June 30, 2018. This increase was due to an 8.7 MMcfpd increase in gas volumes, 11.4 MMcfpd of which was attributablerates prior to the ~~Stone Combination. This was partially offset by a $0.17 per Mcf decrease in our realized gas sales price.~~shut-in.

~~NGL revenue increased approximately $5.7 million, or 80%, during the six months ended June 30, 2018. This increase was due to an increase~~25

~~Lease operating expense.~~ Total lease operating expense for the six months ended June 30, 2018 was $66.9 million compared to $62.8 million for the six months ended June 30, 2017, an increase of approximately $4.1 million, or 6%. This increase was primarily related to $9.9 million of lease operating expense in connection with the Stone Combination, partially offset by a $6.6 million decrease due to additional reimbursements related to our production handling agreements primarily in the Phoenix Field.

~~Depreciation, depletion and amortization.~~ Depreciation, depletion and amortization expense for the six months ended June 30, 2018 was $116.8 million compared to $76.1 million for the six months ended June 30, 2017, an increase of approximately $40.7 million, or 53%. This increase is primarily due to a $2.56 per Boe, or 18% increase in the depletion rate on our proved oil and natural gas properties during the six months ended June 30, 2018. Depletion on a per Boe basis increased primarily due to an increase in proved properties related to the Stone Combination and higher estimated future development costs related to proved undeveloped reserves in the Phoenix Field.

~~General and administrative expense.~~ General and administrative expense for the six months ended June 30, 2018 was $39.5 million compared to $17.2 million for the six months ended June 30, 2017, an increase of approximately $22.2 million, or 129%. This increase was primarily attributable to $20.1 million in transaction related costs related to the Stone Combination and additional general and administrative expenses as a result of the combined company.

~~Other operating expense.~~ Other operating expense for the six months ended June 30, 2018 was $38.9 million compared to $27.6 million for the six months ended June 30, 2017, an increase of approximately $11.3 million, or 41%. This increase was primarily related to an increase of $4.5 million and $4.1 million in workover and maintenance expense and accretion expense, respectively, in connection with the Stone Combination. This increase also relates to a $3.0 million increase in repairs and maintenance during the six months ended June 30, 2018 primarily related to $1.3 million in repairs on SMI 130 and inspection and reconnection support in the Phoenix Field of $1.2 million.

~~Price risk management activities.~~ Price risk management activities for the six months ended June 30, 2018 resulted in a $143.2 million expense compared to income of $84.9 million for the six months ended June 30, 2017. The change of approximately $228.0 million was attributable to a $160.3 million decrease in the fair value of our open derivative contracts and a $67.7 million decrease in cash settlement gains for the six months ended June 30, 2018. These unrealized gains 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 2019, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

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 June 30, 2023, the daily spot prices for NYMEX WTI crude oil ranged from a high of $83.26 per Bbl to a low of $66.61 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.78 per MMBtu to a low of $1.74 per MMBtu. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments” for additional information regarding our commodity derivative positions as of June 30, 2023.

The U.S. Energy Information Administration (“EIA”) published its July 2023 Short-Term Energy Outlook on July 11, 2023. The EIA expects the Henry Hub spot price will rise in the coming months as declining natural gas production narrows the existing surplus of natural gas inventories compared with the five-year average. The EIA expects natural gas prices to average more than $2.80 per MMBtu in the second half of 2023, up from about $2.40 per MMBtu in the first half of the year, and $3.29 per MMBtu in 2024. The EIA also expects the NYMEX WTI spot price will average $74.43 per Bbl in 2023 and $78.51 per Bbl in 2024. The EIA believes crude oil prices will gradually increase because there is an expectation that global oil inventories will decline over the next five quarters due to production cuts and rising demand. On June 4, 2023, OPEC Plus agreed to extend oil production cuts they announced in April 2023 through the end of 2024. On July 3, 2023, Saudi Arabia announced it was extending voluntary cuts through August 2023.

Inflation of Cost of Goods, Services and Personnel — Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increases, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices. In addition, the U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation could likely cause the U.S. Federal Reserve (the “Fed”) and other central banks to further increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business. The Fed raised rates by a quarter of a percentage point on March 22, 2023; May 3, 2023; and July 26, 2023. The latest interest rate hike nudged the federal funds rate to a range of 5.25%-5.50%, its highest level since 2001. The Fed wants inflation to return to its 2% goal over time, and even though inflation is declining, it is still high in absolute terms. Future interest rate hikes remain uncertain.

Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three and six months ended June 30, 2023 and 2022, we did not recognize an impairment based on the ceiling test computations. At June 30, 2023 our ceiling test computation was based on SEC pricing of $83.23 per Bbl of oil, $5.11 per Mcf of natural gas and ~~NGL prices~~$24.85 per Bbl of NGLs.

There is a significant degree of uncertainty with the assumptions used to estimate the present value offuture net cash flows from estimated production of proved oil and gas reservesdue 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 ~~wide fluctuations~~amortization. The Unit Development Plan for the Zama Field, which sets out the terms on which the reservoir will be jointly developed, was approved by the National Hydrocarbon Commission on June 14, 2023. The execution of the Unit Development Plan could adversely affect the value of the Mexico oil and natural gas assets and result in ~~response~~an impairment of our unevaluated oil and gas properties.

Planned Downtime — We are vulnerable to ~~relatively minor changes~~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 ~~supply and demand.~~mid-September, resulting in a total shut-in period of 41 days. The next dry-dock is scheduled for second quarter of 2024 with a projected shut-in period of approximately 55 days.

BOEM Bonding Requirements. — In order to cover the various decommissioning obligations of lessees on the Outer Continental Shelf (“OSC”), the Bureau of Ocean Energy Management (“BOEM”) generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. As many BOEM regulations are being reviewed by the agency, we may be subject to additional financial assurance requirements in the future. For example, in July 2016, the BOEM issued the 2016 Notice to Lessees and Operators ~~(NTL) #2016-N01 (the “2016~~ (“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 ~~the procedures~~ and ~~guidelines that BOEM Regional Directors use~~provide greater transparency to ~~determine if~~decommissioning and ~~when additional~~related financial ~~assurances may be required for OCS leases,~~assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights ~~of way (“ROWs”)~~owners) and rights of use and easement (“~~RUEs”~~RUE”) and rights of way (“ROW”) grant holders conducting operations on the federal outer continental shelf (“OCS”). The ~~2016 NTL became effective in September 2016, but~~Department of the Interior (the “DOI”) under the Biden Administration elected to separate the BOEM and BSEE portions of the supplemental bonding requirements.

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

On June 29, 2023, BOEM published a proposed rule that, if adopted as initially proposed, would substantially revise the supplemental financial assurance requirements applicable to offshore oil and gas operations. The proposed rule would change the current criteria used to determine whether OCS lease and grant holders are required to secure supplemental financial assurance. The proposed rule would no longer use the current 5-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead proposes a simplified test: (1) the credit rating of the lessee and, where applicable, (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. Under the proposed rule, the BOEM would no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance should be provided by current lessees and grant holders. The BOEM would not require supplemental financial assurance above the base bond requirements in three cases: (1) where a lessee has ~~since extended indefinitely~~an investment grade credit rating (i.e., a credit rating from a Nationally Recognized Statistical Ratings Organizations, or NRSRO, that is greater than or equal to either BBB- from S&P or Baa3 from Moody’s, or its equivalent, or a proxy credit rating greater than or equal to either BBB- or Baa3, as determined by the ~~start date~~Regional Director and based upon a company’s audited financial information with an accompanying auditor’s certificate); (2) where there are multiple co-lessees on a lease and any one of those lessees meets the credit rating threshold; and (3) for ~~implementing~~any lease on which all lessees are rated below investment grade, where the value of the lease’s proved oil and gas reserves is at least three times that of the estimated decommissioning cost estimate. The BOEM proposes to phase in compliance with the new requirements over a three-year period. Comments on the proposed rule are due by August 28, 2023. At this ~~NTL so as~~time, we cannot predict whether BOEM will adopt the final rule in its current form or at all, the timing for any final decision, or whether any changes will result from the public notice and comment process, but will continue to monitor this rulemaking.

As discussed in our 2022 Annual Report, including under Part I, Item 1A. “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry — We may be unable to provide the financial assurances in the amounts and under the time periods required by the BOEM if it submits future demands to cover our decommissioning obligations. If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with ~~time~~such future orders, the BOEM could elect to ~~review its complex~~take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases,” our ability to obtain adequate supplemental financial assurance ~~program. This extension currently remains in effect. We remain in active discussions~~(pursuant to a final BOEM rule that is substantially consistent with ~~government regulators and industry peers with regard to any future rulemaking and financial assurance requirements. Notwithstanding~~ the ~~BOEM’s 2016 NTL,~~June 2023 proposed rule or otherwise), including the ~~BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The~~ future cost of compliance with respect to supplemental bonding, including the obligations imposed on the Company as a result of the 2016 NTL, to the extent implemented, as well as any other future BOEM directives, or any other changes to the BOEM’s rules applicable to the Company or its subsidiaries’ properties, could materially and adversely affect ~~its~~our liquidity, financial condition, cash flows, business, properties and results of operations. Moreover, the BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements. Additionally, in August 2021, the BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM.

Deepwater Operations. — We have interests in ~~six deepwater~~Deepwater fields in the U.S. Gulf of ~~Mexico, only five of which we operate (the Bushwood, Phoenix Fields, Amberjack, Pompano and Ram Powell).~~Mexico. Operations in ~~the deepwater~~Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

Oil Spill Response ~~Plan.~~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~~spill response plans are generally approved by the ~~Bureau of Safety and Environmental Enforcement (“BSEE”)~~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.~~Hurricanes, Tropical Storms and Loop Currents — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes, tropical storms and loop currents on ~~production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes has become less effective due to rising retentions~~production and ~~limitations on named windstorm coverage and has been difficult to obtain at times in recent years.~~capital projects. Significant ~~hurricane~~ impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs.

Five-Year Offshore Oil and Gas Leasing Program Update — Under the Outer Continental Shelf Lands Act (“OCSLA”), as amended, the BOEM within the DOI must prepare and maintain forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the U.S. Outer Continental Shelf. On May 11, 2022, the DOI cancelled two lease auctions in the Gulf of Mexico, Lease Sales 259 and 261 included in the 2017-2022 national program that was developed under the Obama Administration, which expired on June 30, 2022. The DOI cited “conflicting court rulings” as the primary reason for not holding the two Gulf of Mexico lease sales. President Biden signed the Inflation Reduction Act of 2022 (the “IRA 2022”) into law on August 16, 2022. The IRA 2022 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, and were awarded leases on all four blocks. BOEM proposes to hold Lease Sale 261 on September 27, 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.

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

~~For a further discussion of our commitments and contingencies, see “Item 1, Condensed Consolidated Financial Statements, Note 11 –~~ ~~Commitments and Contingencies.~~”

~~For~~2022 —Lease operating expense for the ~~three and~~ six months ended June 30, ~~2018, our effective tax rate~~2023 increased by approximately $35.1 million, or 24%.This increase was ~~0%. Our effective tax rate~~primarily related to lease operating expenses of $31.7 million incurred in ~~2018 differed~~connection with assets acquired from the ~~statutory~~EnVen Acquisition. Additionally, there was a $10.2 million decrease in production handling fees related to reimbursements for costs from certain third parties related to our historical operations. This increase was partially offset by a $13.9 million decrease in facility and workover expense related to repairs and maintenance at the Phoenix Field compared to the same period in 2022.

The following table highlights depreciation, depletion and amortization items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

Three Months Ended June 30, 2023 and 2022 —Depreciation, depletion and amortization expense for the three months ended June 30, 2023 increased by approximately $65.3 million, or 62%. This was due to an increase of $8.95 per Boe, or 51%, in the depletion rate ~~of 21%, as a result of recognition of a full valuation allowance~~ on our ~~deferred tax assets. For~~proved oil and natural gas properties due to an increase in our proved properties primarily related to the ~~three~~assets acquired as part of the EnVen Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” and the extension of the HP-I lease during the fourth quarter of 2022, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.

Six Months Ended June 30, 2023 and 2022 —Depreciation, depletion and amortization expense for the six months ended June 30, ~~2018,~~2023 increased by approximately $114.3 million, or 56%. This was due to an increase of $8.69 per Boe, or 50%, in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties primarily related to the assets acquired as part of the EnVen Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” and the extension of the HP-I lease during the fourth quarter of 2022, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.

The following table highlights general and administrative expense items in total and on a cost per Boe production basis for the Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

Three Months Ended June 30, 2023 and 2022 — General and administrative expense for the three months ended June 30, 2023 increased by approximately $10.3 million, or 45%. This increase was primarily related to the Upstream Segment transaction costs for the closing and continued integration of the EnVen Acquisition of $2.7 million or $0.42 per Boe. Additionally, there was an increase in payroll expenses due to an increase in employee headcount primarily related to the EnVen Acquisition. General and administrative expense includes non-cash equity-based compensation of $4.7 million during the three months ended June 30, 2023, which is an increase of $0.7 million, most of which is attributable to the Upstream Segment for both periods.

Six Months Ended June 30, 2023 and 2022 — General and administrative expense for the six months ended June 30, 2023 increased by approximately $50.9 million, or 112%. This increase was primarily related to the Upstream Segment transaction costs for the closing and continued integration of the EnVen Acquisition of $37.9 million or $3.13 per Boe. Additionally, there was an increase in payroll expenses due to an increase in employee headcount primarily related to the EnVen Acquisition. General and administrative expense includes non-cash equity-based compensation of $8.7 million during the six months ended June 30, 2023, which is an increase of $1.3 million, most of which is attributable to the Upstream Segment for both periods.

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):

Accretion Expense — During the three months ended June 30, 2023, we recorded ~~a full valuation allowance against our net deferred tax assets.~~$22.8 million of accretion expense compared to $14.8 million during the three months ended June 30, 2022. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of the EnVen Acquisition. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”

~~“Adjusted EBITDA” is not a measure~~Other Operating (Income) Expense — During the three months ended June 30, 2022, we recorded $10.2 million of ~~net income (loss) as determined by GAAP. We use this measure~~estimated decommissioning obligations primarily as a ~~supplemental measure because~~result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 11 — Commitments and Contingencies.”

Interest Expense — During the three months ended June 30, 2023, we ~~believe it provides meaningful information to our investors. We define Adjusted EBITDA as net income (loss) plus~~recorded $45.6 million of interest expense ~~depreciation, depletion~~compared to $30.8 million during the three months ended June 30, 2022. The change is primarily the result of the increase in interest associated with the 11.75% Notes (as defined below under “ — Liquidity and ~~amortization, accretion expense, loss on debt extinguishment, transaction related costs,~~Capital Resources — Overview of Debt Instruments”) assumed as part of the ~~net change~~EnVen Acquisition.

Price Risk Management Activities — The income of $26.2 million for the three months ended June 30, 2023 consists of $18.0 million in non-cash gains from the increase in the fair value of ~~derivatives (mark~~our open derivative contracts and $8.2 million in cash settlement gains. The expense of $64.1 million for the three months ended June 30, 2022 consists of $160.2 million in cash settlement losses partially offset by $96.1 million in non-cash gains from the increase in the fair value of our open derivative contracts.

These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through March 2025, we expect these activities to continue to impact net income (loss) based on fluctuations in market ~~effect, net of cash settlements and premiums related to these derivatives), non-cash write-down of~~prices for oil and natural ~~gas properties,~~gas. See Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments.”

Equity Method Investment (Income) Expense — During the three months ended June 30, 2023, we recorded equity losses of $2.0 million. During the three months ended June 30, 2022, we recorded equity losses of $0.4 million offset by $13.9 million gain on the partial sale of our investment in Bayou Bend. See Part I, Item 1. “Financial Statements — Note 10 — Related Party Transactions” for additional information.

Income Tax (Benefit) Expense — During the three months ended June 30, 2023, we recorded $6.9 million of income tax expense compared to $2.6 million of income tax expense during the three months ended June 30, 2022. The income tax expense is primarily due to state income taxes, permanent differences and a change of its valuation allowance on its deferred tax assets. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 8 — Income Taxes.”

Accretion Expense — During the six months ended June 30, 2023, we recorded $42.2 million of accretion expense compared to $29.2 million during the six months ended June 30, 2022. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of the EnVen Acquisition. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”

Other Operating (Income) Expense — During the six months ended June 30, 2022, we recorded $10.5 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 11 — Commitments and Contingencies.”

Interest Expense — During the six months ended June 30, 2023, we recorded $83.2 million of interest expense compared to $62.3 million during the six months ended June 30, 2022. The change is primarily the result of the increase in interest associated with the 11.75% Notes assumed as part of the EnVen Acquisition.

Price Risk Management Activities — The income of $85.1 million for the six months ended June 30, 2023 consists of $89.3 million in non-cash ~~write-down~~gains from the increase in the fair value of our open derivative contracts partially offset by $4.2 million in cash settlement losses. The expense of $345.3 million for the six months ended June 30, 2022 consists of $287.3 million in cash settlement losses and $58.0 million in non-cash losses from the decrease in the fair value of our open derivative contracts.

These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through 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. “Financial Statements — Note 5 — Financial Instruments.”

Equity Method Investment (Income) Expense — During the six months ended June 30, 2023, we recorded equity losses of $3.2 million offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron. During the six months ended June 30, 2022, we recorded equity losses of $0.3 million offset by $13.9 million gain on the partial sale of our investment in Bayou Bend. See Part I, Item 1. “Financial Statements — Note 10 — Related Party Transactions” for additional information.

Other Income — During the six months ended June 30, 2022, we recorded a $27.5 million gain as a result of the settlement agreement to resolve a previously pending litigation that was filed in October 2017 that is further discussed in Part I, Item 1. “Financial Statements — Note 11 — Commitments and Contingencies.”

Income Tax (Benefit) Expense — During the six months ended June 30, 2023, we recorded $39.7 million of income tax benefit compared to $2.1 million of income tax expense during the six months ended June 30, 2022. The income tax benefit is primarily due to a non-cash tax benefit of $54.9 million related to the partial release of the valuation allowance on our federal deferred tax assets offset by the impact of other ~~well equipment inventory~~permanent differences. The partial release of the valuation allowance is a result of the deferred tax liabilities acquired with the EnVen Acquisition. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 8 — Income Taxes.”

EBITDA and ~~non-cash equity based compensation expense. We believe the presentation of~~ Adjusted EBITDA ~~is important~~

“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 ~~has~~have limitations as an analytical ~~tool~~tools and should not be considered in isolation or as ~~a substitute~~substitutes for analysis of our results as reported under GAAP or as ~~an alternative~~alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

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, except~~thousands):

Our primary sources of liquidity are cash generated by our operations and borrowings under our ~~newly established~~ Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service, share repurchases and for general corporate purposes. The cost of borrowings under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed is making it more expensive to borrow money. Our working capital deficit has increased since December 31, 2022 primarily due to a decrease of $60.1 million in liabilities from price risk management activities and an increase of $20.5 million in assets from price risk management activities. See Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments.” This was offset by 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. “Financial Statements — Note 6 — Debt.” As of June 30, ~~2018,~~2023, our available liquidity (cash plus available capacity under the Bank Credit Facility) was ~~$432.9~~$771.8 million.

AsWe fund drilling, completions and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant acquisitions with the issuance of ~~June 30, 2018, total debt, net of discount and deferred financing costs, was approximately $628.4 million, comprised of our $380.0 million aggregate principal amount of~~senior notes, borrowings under the ~~11.00% Senior Secured Notes and $6.1 million aggregate principal amount of our 7.50% Stone Senior Notes, $231.5 million outstanding under our~~ Bank Credit Facility and ~~$10.8 million aggregate principal amount~~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 ~~Stone 4.20% term loan maturing on November 20, 2030 (the “Building Loan”).~~results of our exploration and development activities. We ~~were in compliance with all debt covenants at~~are continuing to explore a capital raise to finance the accelerated growth of our CCS Segment.

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the six months ended June 30, ~~2018. For additional details on~~2023 (in thousands):

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our board approved ~~2018~~2023 Upstream capital spending ~~project~~program of ~~$430.0~~$650.0 million to ~~$450.0~~$675.0 million and plugging & abandonment and decommissioning obligations of $75.0 million to $85.0 million as well as expected investments in our CCS Segment of $70.0 million to $90.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on various operating and economic conditions, ~~some~~many of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g., by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, ~~raising~~issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding ~~debt.~~indebtedness.

Common Stock Repurchase Program —Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. In March and June of 2023, we repurchased 1.9 million shares for $26.6 million and 1.5 million shares for $20.9 million, respectively. As of June 30, ~~2018, we had secured performance bonds primarily related~~2023, there is $52.5 million remaining under the authorized program. All repurchased shares are held in treasury.

Repurchases may be made from time to ~~plugging and abandonment of wells and removal of facilities~~time in the ~~United States Gulf~~open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of ~~Mexico~~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 ~~guarantee~~repurchase any dollar amount or number of shares.

The IRA 2022 provides for, among other things, the ~~completion~~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 minimum work program under the Mexico Production Sharing Contracts (“PSCs”) totaling approximately $569.3 million. In July 2016, the BOEM issued Notice to Lessees #2016-N01 (“2016 NTL”) to clarify the procedures and guidelines the BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”) to meet the BOEM’s estimatefair market value of the ~~lessees’ decommissioning obligations.~~stock repurchased by a corporation during the applicable tax year. The ~~2016 NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07. The 2016 NTL allows qualifying operators~~repurchase amount subject to ~~self-insure for an amount up to 10% of their tangible net worth. In addition,~~ the 2016 NTL implements a phase-in period for establishing compliance with additional security obligations for certain categories of properties covered under the NTL, whereby a lessee may seek compliance with its additional financial security requirements under a “tailored plan” thatexcise tax is ~~approved~~generally reduced by the ~~BOEM and would require securing phased-in compliance in three approximately equal installments~~fair market value of any stock issued by a corporation during a ~~one-year period~~taxable year, including the fair market value of any stock issued or provided to employees of a corporation or employees of certain of its subsidiaries. The current federal administration has proposed increasing the excise tax amount from ~~the date of the BOEM’s approval of the tailored plan. However, in June 2017, the BOEM announced that~~1% to 4%; however, it ~~will extend the implementation timeline for NTL #2016-N01 beyond June 30, 2017, except in certain circumstances where there~~ is unclear whether such a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, to allow the BOEM time to reconsider a number of regulatory initiatives. This extension currently remains in effect. We received notice from the BOEM on December 29, 2016 ordering us to secure financial assurances in the form of additional securitychange in the amount of ~~$0.5 million. Subsequent~~the excise tax will be enacted and, if enacted, how soon any change can take effect. We do not anticipate paying any excise task in 2023 based on the fair market value of the stock issuance in connection to the December 29, 2016 order, the BOEM has rescinded that order and all others dated December 29, 2016 until further notice. However, the BOEM reserved the right to re-issue sole liability orders in the future, including in the event that it determines there is a substantial riskEnVen Acquisition.

Overview of nonperformance of the interest holders’ decommissioning sole liabilities. We remain in active discussion with our government regulators and industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding the BOEM’s July 2016 NTL, the BOEM may also increase its financial assurance requirements mandated by rule for all companies operating in federal waters. Cash Flow Activities —The future cost of compliance with our existing supplemental bonding requirements, the NTL #2016-N01, as well as any other future directives or any other changes to the BOEM’s rules applicable to us or our subsidiaries’ properties, could materially and adversely affect our financial condition,following table summarizes cash flows ~~and results~~provided by (used in) by type of ~~operations.~~activity, for the following periods (in thousands):

~~In connection with the Stone Combination, we consummated the transactions contemplated~~Operating Activities — Net cash provided by ~~the Exchange Agreement, pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0~~operating activities decreased $77.3 million in ~~aggregate principal amount of 9.75% senior notes (9.75% Senior Notes) to us in exchange for Common Stock; (ii)~~ the holders of 11.00% Bridge Loans exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Senior Secured Notes and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Stone Senior Notes for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes. An additional $81.5 million of 7.50% Stone Senior Notes held by non-affiliates were also exchanged for 11.00% Senior Secured Notes pursuant to an exchange offer and consent solicitation in connection with the Stone Combination.

The exchange of 7.50% Stone Senior Notes for 11.00% Senior Secured Notes was accounted for as a debt modification. Under a debt modification, a new effective interest rate that equates the revised cash flows to the carrying amount of the 11.00% Senior Secured Notes is computed and applied prospectively. Costs incurred with third parties directly related to the modification are expensed as incurred. We incurred approximately $3.9 million and $4.5 million of transaction fees related to the exchange of 11.00% Bridge Loans and 7.50% Stone Senior Notes into 11.00% Senior Secured Notes, which were expensed and reflected in general and administrative expense during the three months and six months ended June 30, ~~2018, respectively. We also paid $9.3~~2023 compared to the corresponding period in 2022 primarily attributable to a decrease from revenues combined with an increase in lease operating expense of $278.0 million and a $27.5 million legal settlement to resolve previously pending litigation that was filed in October 2017 received in the six months ended June 30, 2022. See Part I, Item 1. “Financial Statements — Note 11 — Commitments and Contingencies” for additional information. Additionally, there was an increase in settlement of asset retirement obligations of $7.9 million offset by a decrease in cash payments on derivative instruments of $283.2 million in ~~work fees~~each case when compared to ~~debt holders, which are reflected as debt discount reducing long-term debt on~~ the ~~condensed consolidated balance sheet at~~same period in 2022.

Investing Activities — Net cash used in investing activities increased $195.4 million in the six months ended June 30, ~~2018.~~

~~11.00% Second-Priority Senior Secured Notes –~~2023 compared to the corresponding period in 2022 primarily due ~~April 2022. The 11.00% Senior Secured Notes were issued pursuant~~ to an ~~indenture dated May 10, 2018, between~~increase in capital expenditures of $170.6 million and contributions to equity method investees of $13.0 million. Capital expenditures for drilling and completion projects during 2022 generally were budgeted and occurred during the ~~Talos Issuers, the subsidiary guarantors party thereto~~third and ~~Wilmington Trust, National Association, as trustee~~fourth quarters. Budgeted capital expenditures for drilling and ~~collateral agent. The 11.00% Senior Secured Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15, commencing October 15, 2018. Prior~~completion projects for 2023 were more heavily weighted to May 10, 2019, we may, at our option, redeem all or a portion of the 11.00% Senior Secured Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the 11.00% Senior Secured Notes at redemption prices decreasing annually from 105.5% to 100.0% plus accrued and unpaid interest.

~~7.50% Senior Secured Notes – due May 2022. The 7.50% Stone Senior Notes represent the remaining $6.1 million of long-term debt assumed~~occur in the ~~Stone Combination that were not exchanged~~first half of 2023. The capital expenditure budget for ~~11.00% Senior Secured Notes pursuant~~2023 also included projects related to the ~~exchange offer and consent solicitation, and thus remain outstanding. As a result of~~EnVen Acquisition.

Financing Activities — Cash flow from financing activities changed $308.4 million in the ~~exchange offer and consent solicitation, substantially all of the restrictive covenants relating~~six months ended June 30, 2023 compared to the 7.50% Stone Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes have been released. The 7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semiannually each May 31 and November 30. Prior to May 31, 2020, we may, at our option, redeem all or a portion of the 7.50% Stone Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the 7.50% Stone Senior Notes at redemption prices decreasing annuallycorresponding period in 2022. We had net borrowings from ~~105.625% to 100.0% plus accrued and unpaid interest.~~

~~We executed~~ the Bank Credit Facility of $200.0 million for the six months ended June 30, 2023 primarily due to the funding of the EnVen Acquisition compared to net repayments of $175.0 million during the same period in ~~conjunction with~~2022. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information. We repurchased $47.5 million of our common stock through our share repurchase program during the ~~Stone Combination~~six months ended June 30, 2023. See the subsection entitled “— Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information. Additionally, there was an increase in deferred financing costs of $11.6 million and redemption of senior notes of $8.9 million in each case when compared to the same period in 2022. See Part I, Item 1. “Financial Statements — Note 6 — Debt” for additional information.

Bank Credit Facility — matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions ~~with an initial borrowing base of $600.0 million. The Bank~~(the “Bank Credit ~~Facility matures on May 10, 2022.~~

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. In June 2018, we completed the redetermination and the borrowing base was reaffirmed at $600.0 million.~~quarter each year. See Part I, Item 1. “Financial Statements — Note 6 — Debt”for more information.

12.00% Second-Priority Senior Secured Notes — due January 2026 — The ~~next redetermination is in October 2018.~~

As of June 30, 2018, our borrowing base was set at $600.0 million, of which no more than $200 million can be used as letters of credit. The amount that we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. We were in compliance with all debt covenants at June 30, 2018. As of June 30, 2018, the Bank Credit Facility had approximately $354.0 million of undrawn commitments (taking into account $6.0 million letters of credit and $240.0 million drawn from the Bank Credit Facility). The $294.0 million in cash received from our initial drawdown under the Bank Credit Facility was used to partially repay outstanding borrowings under the Old Bank Credit Facility upon its termination in connection with the Stone Combination.

In connection with the Stone Combination, we assumed Stone’s Building Loan maturing on November 20, 2030. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million. As of June 30, 2018, the outstanding balance under the Building Loan totaled $10.8 million. The Building Loan is collateralized by our two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. We are in compliance with all covenants under the Building Loan as of June 30, 2018.

~~9.75% Senior~~Secured Notes ~~– due February 2018. The 9.75% Senior Notes~~(the “12.00% Notes”) were issued pursuant to an indenture dated ~~February 6, 2013 among the Talos Issuers, the subsidiary guarantors party thereto~~January 4, 2021 and the ~~trustee.~~ 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. We made an interest payment of $38.3 million on July 17, 2023. See Part I, Item 1. “Financial Statements — Note 6 — Debt”for more information.

11.75% Senior Secured Second Lien Notes — due April 2026 — On February ~~15, 2018,~~13, 2023, in conjunction with the ~~Talos Issuers redeemed~~closing of the ~~remaining $25.0 million~~EnVen Acquisition, we assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount outstanding of $257.5 million. The 11.75% Notes will mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The 11.75% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the ~~9.75% Senior~~principal amount outstanding at par value on April 15th and October 15th of each year. See Part I, Item 1. “Financial Statements — Note 6 — Debt”for more information.

Guarantor Financial Information —We own no operating assets and have no operations independent of our subsidiaries. The 12.00% Notes ~~at par.~~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.

~~Overview~~In lieu of ~~Cash Flow Activities~~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 ~~summarizes cash flows provided by (used in) by type of activity,~~presents the balance sheet information for the ~~following~~Issuer and the Guarantors for the respective periods (in thousands):

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

~~Operating Activities.~~ ~~Net cash provided by operating activities increased $21.8 million~~We have various contractual obligations in the six months ended June 30, 2018 from 2017 primarily attributable to an increase in revenue, partially offset by a decrease in cash settlements on derivatives instruments and transaction related costs related to the Stone Combination.

~~Investing Activities.~~ Net cash provided by investing activities increased $216.8 million in the six months ended June 30, 2018 from 2017 primarily attributable to $293.0 million cash acquired for the Stone Combination, partially offset by a $78.4 million increase in capital expenditures.

~~Financing Activities.~~ Net cash used in financing activities increased $200.6 million in the six months ended June 30, 2018 from 2017 primarily attributable to the repayment of $403.0 million related to the Old Bank Credit Facility, $54.0 million related to the repayment of the Bank Credit Facility, $25.0 million related to the redemptionnormal course of our ~~2018 Senior Notes and $17.5 million in deferred financing cost, partially offset by proceeds received from the Bank Credit Facility of $294.0 million.~~

~~Capital Expenditures.~~ We fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under our Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions through the issuance of senior notes, borrowings under the bank credit facility and through additional equity transactions. 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.

For the six months ended June 30, 2018, our additions to property and equipment, excluding acquisitions, plugging and abandonment spend and asset retirement costs, on an accrual basis were $88.3 million, an increase of $9.3 million, or 12%, from the six months ended June 30, 2017. Our additions for the six months ended June 30, 2018 were as follows (in thousands):

~~Additionally, we incurred $43.9 million on plugging and abandonment and $46.8 for the change in control related to seismic during the six months ended June 30, 2018.~~

Capital expenditures for the remainder of 2018 are estimated to be approximately $240.0 million to $260.0 million, which we plan to fund through cash flows from operations and borrowings under our Bank Credit Facility.

~~We are party to various contractual obligations.~~operations. Some of these obligations may be reflected in our accompanying ~~consolidated financial statements,~~Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying ~~consolidated financial statements.~~Condensed Consolidated Financial Statements.

The following table and discussion ~~summarizes~~summarize our material cash requirements from known contractual ~~cash~~ obligations as of June 30, ~~2018~~2023 (in thousands):

Performance ~~Bonds.~~ Obligations — As of June 30, ~~2018 and December 31, 2017,~~2023, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico and ~~executing~~certain obligations under the ~~minimum work program in~~production sharing contracts with Mexico ~~totaling approximately $569.3 million and $287.8 million, respectively. As of June 30, 2018 and December 31, 2017,~~from third party sureties. Additionally, we had ~~$6.0 million and $4.9 million, respectively, in~~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 ~~Old~~future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition. See Part I, Item 1. “Financial Statements — Note 6 — Debt” for further information on the Bank Credit Facility.

Critical accounting estimates are those estimates made in accordance with GAAP that involve a significant level of estimation uncertainty and have had or ~~additional information about certain~~are reasonably likely to have a material impact on our financial condition or results of operations. Except as discussed below, there have been no changes to our ~~obligations~~critical accounting estimates from those disclosed in our 2022 Annual Report under Part II, Item 7. “Management’s Discussion and ~~contingencies, see Item 1, Notes to Condensed Consolidated~~Analysis of Financial ~~Statements, Note 11 –~~ ~~Commitments~~Condition and ~~Contingencies~~.

Results of Operations — Critical Accounting Policies and ~~Estimates~~Estimates.”

~~The preparation~~Determination of ~~financial statements~~Fair Value in ~~conformity with GAAP requires our management~~Business Combinations

We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to ~~make estimates and assumptions that affect the reported~~their estimated acquisition date fair values. The amount of ~~assets, liabilities, revenue and expense, and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex~~goodwill or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates. Our significant accounting policies that have been implemented or changed since December 31, 2017 are described in “Part I, Item 1, Condensed Consolidated Financial Statements, Note 2 – ~~Summary of Significant Accounting Policies~~” of our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. Our other significant accounting policies that are not referenced in Note 2 can be found within Talos Energy LLC’s audited financial statements and the notes thereto for the year ended December 31, 2017, which we filed on May 18, 2018 with the SEC on a Current Report on Form 8-K.

We follow the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, whichbargain purchase gain recognized, if any, is ~~subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.~~

Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, wells currently drilling and capitalized interest are initially excluded from the amortizable base. We transfer unproved property costs into the amortizable base when properties are determined to have proved reserves or when we have completed an evaluation of the unproved properties resulting in an impairment. We evaluate each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which we own a direct interest.

~~Our capitalized costs are limited to a ceiling~~ based on the ~~present~~consideration transferred compared to the acquisition date amounts of the identifiable net assets acquired.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value ~~of future net revenues from proved reserves, discounted at 10 %, plus~~is a market-based measurement, it is determined based on the ~~lower of cost or~~assumptions that market participants would use. The most significant assumptions relate to the estimated fair ~~value~~values of proved and unproved oil and natural gas ~~properties not being amortized. Any costs in excess~~properties.

The fair value of ~~the ceiling are recognized as a non-cash impairment expense on our consolidated statement of operations~~proved and ~~an increase to accumulated depreciation, depletion and amortization on our consolidated balance sheet. The expense may not be reversed in future periods, even though higher~~ oil natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with SEC rules and regulations, we utilize SEC Pricing when performing the ceiling test. We also hold prices and costs constant over the lifeproperties as of the ~~reserves, even though actual prices and costs of oil and natural gas~~acquisition date are often volatile and may change from period to period. The ceiling test computation did not result in a write-down of our oil and natural gas properties during the three and six months ended June 30, 2018 and 2017.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When we sell or convey interests in oil and natural gas properties, we reduce our oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or lossbased on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. We treat sales proceeds on non-significant sales as reductions to the cost of our oil and natural gas properties.

We recognize transportation costs as a component of direct lease operating expense when we are the shipper of the product. Such costs during the three and six months ended June 30, 2018 were $5.8 million and $2.7 million, respectively, and $5.0 million and $2.7 million during the three and six months ended June 30, 2017, respectively.

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

The estimates used in ~~accordance with~~determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the ~~guidelines established by the SEC. Proved~~projected results used to determine fair value. Historically there has been significant volatility in oil, natural gas and NGL ~~reserves are those quantities of oil, natural gas~~prices and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC Pricing.

~~Our~~ estimates of ~~proved reserves~~such future prices are ~~made using available geological and reservoir data, as well as~~inherently imprecise. Additionally, the actual timing of the production performance data. The estimates of proved reserves are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse changecould be different than the projection. Cash flows realized later in the ~~estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments.~~

Our financial instruments generally consisted of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt as of June 30, 2018. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair valueprojection period are less valuable than those realized earlier due to the ~~highly liquid nature~~time value of ~~these instruments.~~

~~Fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate~~money. A higher discount rate decreases the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value as an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

~~Level 1—Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.~~

~~Level 2~~—Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.

~~Level 3—Inputs to the valuation methodology are unobservable (little or no market data), which require us to develop our own assumptions, and are significant to the fair value measurement.~~

~~Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:~~

~~Market Approach—Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.~~

~~Cost Approach—Amount that would be required to replace the service capacity of an asset (replacement cost).~~

~~Income Approach—Techniques to convert expected future cash flows to a single~~net present value ~~amount based on market expectations (including present value techniques, option-pricing and excess earnings models).~~of cash flows.

~~Authoritative guidance on financial instruments requires certain fair value disclosures to be presented.~~ The estimated fair value ~~amounts have been determined using available market information~~assigned to the assets acquired and ~~valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may~~liabilities assumed can have a ~~material~~significant effect on ~~the estimated~~our future operating results. For example, a higher fair value ~~amounts.~~

~~We are required to record our asset retirement obligations at fair value in the period such obligations are incurred with the associated asset retirement costs being capitalized as part~~measurement of ~~the carrying cost of the asset. Our asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our~~ oil and ~~natural~~ gas ~~properties. The estimate of the asset retirement cost is determined, inflated to an estimated~~properties results in higher depletion expense in future ~~value using a three year average of the Consumer Price Index~~periods which reduces our future earnings.

See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and ~~discounted to present value using our credit-adjusted risk-free rate. Accretion of the liability is recognized~~ Divestitures”for ~~changes in the value of the liability as a result of the passage of time over the estimated productive life of the~~more information related ~~assets as the discounted liabilities are accreted to their expected settlement values.~~

~~We record revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery~~ to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred.EnVen Acquisition.

We have interests with other producers in certain properties. In these cases, we use the entitlement method to account for sales of production. Under the entitlement method, revenue is recorded when title passes based on our net interest. We may receive more or less than our entitled share of production, and we record our entitled share of revenues based on entitled volumes and contracted sales prices. If we receive more than our entitled share of production, the imbalance is recorded as a liability in accrued liabilities on the consolidated balance sheets. If we receive less than our entitled share, the imbalance is recorded as an asset in other current assets on the consolidated balance sheets. Our imbalances are recorded gross on our consolidated balance sheets. At June 30, 2018, our imbalance receivable was approximately $1.7 million and imbalance payable was approximately $2.5 million. At December 31, 2017, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.7 million.

We record the gross amount of reimbursements for costs from third parties as other revenues whenever the Company is the primary obligor with respect to the source of such costs, has discretion in the selection of how the related costs are incurred and when it has assumed the credit risk associated with the reimbursement for such costs. The costs associated with these third-party reimbursements are also recorded within the applicable cost and expenses line item in the consolidated statements of operations. Our other revenues have been generated primarily through fees for processing third-party production through some of our production facilities.

Our provision for income taxes includes both state, federal and foreign taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of June 30, 2018, we believe it is more likely than not that the net deferred tax asset will not be realized and therefore have recorded a valuation allowance.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

~~See “Part I, Item 1, Condensed Consolidated Financial Statements, Note 1~~ – ~~Formation and Basis of Presentation” for Recently Adopted Accounting Standards by the Company.~~ None.

~~See “Part I, Item 1, Condensed Consolidated Financial Statements, Note 1~~ – ~~Formation and Basis of Presentation” for Recently Issued Accounting Standards applicable~~There was no recently issued accounting standards material to ~~the Company.~~us.

~~We are currently exposed~~For information regarding our exposures to certain market ~~risk~~risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in ~~two areas: commodity prices and,~~our 2022 Annual Report. Except as discussed below, there have been no material changes from the disclosures presented in our 2022 Annual Report regarding our exposures to ~~a lesser extent, interest rate risk. Our risk management activities involve the use of derivative financial instruments to mitigate the impact of~~certain market price risk exposures primarily related to our oil and natural gas production. All derivatives are recorded on the condensed consolidated balance sheet at fair value with settlements of such contracts and, changes in the unrealized fair value recorded as price risk management activities income (expense) on the condensed consolidated statements of operations in each period.risks.

Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and cash flow. During the six months ended June 30, 2018, our average oil price realizations after the effect of derivatives increased 6% to $54.12 per Bbl from $51.28 per Bbl in the comparable 2017 period. Our average natural gas prices realizations after the effect of derivatives increased 2% during the six months ended June 30, 2018 to $2.94 per Mcf from $2.87 per Mcf in the comparable 2017 period.

We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production through the use of oil and natural gas swaps. These contracts will impact our earnings as the fair value of these derivatives changes. Our derivatives will not mitigate all of the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production.

We had commodity derivative instruments in place to reduce the price risk associated with future production of ~~14,444~~10,879 MBbls of crude oil and ~~9,177~~16,470 MMBtu of natural gas at June 30, ~~2018,~~2023, with a net derivative ~~liability~~asset position of ~~$185.8~~$44.5 million. For additional information regarding our commodity derivative instruments, see “Part I, Item 1, ~~Condensed Consolidated~~ ~~Financial~~1. “Financial Statements, — Note 5 – — Financial ~~Instruments.~~Instruments”, included elsewhere in this Quarterly Report. The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at June 30, ~~2018~~2023 (in thousands):

We had total debt outstanding of $628.4 million at June 30, 2018, net of unamortized original issue discount and deferred financing costs. Of this, $396.9 million was from our 11.00% Senior Secured Notes, 7.50% Stone Senior Notes and Building Loan, which bear interest at fixed rates. The remaining $231.5 million is from borrowings under our Bank Credit Facility with variable interest rates. Therefore, we are subject to the risk of changes in interest rates under our Bank Credit Facility. In addition, the terms of our Bank Credit Facility require us to pay higher interest rates as we utilize a larger percentage of our available borrowing base. We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of marketfair values arising from changes in ~~interest rates. We believe our interest rate risk exposure is partially mitigated as a result~~oil and natural gas prices.

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 on Form 10-Q.~~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 June 30, ~~2018.~~2023.

~~There~~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 ~~that occurred~~identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended June 30, ~~2018~~2023 that ~~have~~ materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

On January 4, 2018 and February 2, 2018, two putative class action complaints challenging the Transactions were filed on behalf of purported Stone stockholders in the U.S. District Court for the District of Delaware. The complaints are captioned John Heinrich v. Stone Energy Corporation, et al., Case 1:18-cv-00054-GMS and Allen Miskowiec v. Stone Energy Corporation, et al., Case 1:18-cv-00202-RGA. On February 8, 2018, a third putative class action complaint challenging the Transactions was filed on behalf of purported Stone stockholders in the U.S. District Court for the Western District of Louisiana and is captioned Anthony Franchi v. Stone Energy Corporation, et al., Case 6:18-cv-00167. The complaints assert, among other things, claims under Sections 14(a) and 20(a) of the Exchange Act against Stone and certain members of its board of directors and challenges the adequacy of the disclosures made in the version of this consent solicitation statement/prospectus filed with the SEC on December 29, 2017. The Miskowiec and Franchi lawsuits also name Talos Energy LLC as an additional defendant and the Franchi lawsuit names Talos Production LLC as additional defendant. The defendants believe that the claims asserted against them in the lawsuits are without merit and intend to defend vigorously against all claims asserted. The Heinrich lawsuit was dismissed on June 6, 2018. The Miskowiec lawsuit was dismissed on May 15, 2018. The Franchi lawsuit was dismissed on July 25, 2018.

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

OnIn June 2019, David M. Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November ~~17, 2014,~~6, 2015 as a resignation for “Good Reason.” In September 2021, the ~~Pennsylvania Department~~trial court entered a judgment in favor of ~~Environmental Protection (“PADEP”) issued~~Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of ~~Violation (“NOV”)~~Appeal in December 2021. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supreme Court on August 2, 2023.As of June 30, 2023, the Company has recorded $13.9 million as “Other current liabilities” on the Condensed Consolidated Balance Sheets related to ~~Stone alleging releases~~the litigation.

In July 2019, EnVen filed a lawsuit against Mr. Dunwoody in Delaware Chancery Court for breach of ~~production fluid~~fiduciary duty and equitable fraud relating to Mr. Dunwoody’s conduct while he was President of EnVen. In January 2020, EnVen filed an ~~improper closure~~amended complaint that added claims against Oilfield Pipe of ~~a drill cuttings pit at Stone’s Loomis No. 1 well site~~Texas, LLC for aiding and abetting Mr. Dunwoody’s breach of his fiduciary duty and equitable fraud. On April 21, 2022, the Delaware Chancery Court denied Mr. Dunwoody’s renewed motion to dismiss the suit. The trial was held in ~~Susquehanna County, Pennsylvania. Prior~~the Delaware Chancery Court in late July 2023. A decision is expected in 2024. The Company may recognize additional liabilities and expenses in future periods related to this in September 2014, Stone had transferred ownership of the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”). PADEP approved the transfer on November 24, 2014, after issuing the NOV to Stone. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. Reclamation of the site by Southwestern,litigation with ~~the participation of the PADEP and Stone, was completed. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.~~Mr. Dunwoody.

On November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damagesThere have been no additional material developments with respect to the ~~Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration~~information previously reported under Part I, Item 3. “Legal Proceedings” of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The Plaquemines Parish lawsuit has been stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. The Plaquemines Parish lawsuit has been removed to federal district court in the Eastern District of Louisiana.

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in two of the three Jefferson Parish Coastal Zone Management lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The Jefferson Parish lawsuits have been removed to federal district court in the Eastern District of Louisiana.our 2022 Annual Report.

Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters. See “Item 1, Condensed Consolidated Financial Statements, Note 11 – ~~Commitments and Contingencies.”~~

~~Certain~~In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors ~~may have a material adverse effect on~~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 and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Quarterly Report on Form 10-Q, including our condensed consolidated financial statements and related notes. The risks and uncertainties described below are not the only ones we face.or future results. Additional risks and uncertainties ~~that we are unaware of,~~not currently known to us or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occurs, our business, financial condition, results of operations, and future prospects coulddeem to be ~~materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment.~~

~~The integration of Stone and Talos Energy LLC will present challenges that may result in a decline in the anticipated benefits of the Stone Combination.~~

The Stone Combination involved the combination of two businesses that historically operated as independent businesses, and we will be required to continue to devote management attention and resources to integrating our business practices and operations. We could be adversely affected by the diversion of management’s attention, the loss of key employees and skilled workers, and any delays or difficulties encountered in connection with this integration process. If we experience difficulties with the integration process, the anticipated benefits of the Stone Combination may not be realized fully or at all, or may take longer to realize than expected. These integration matters could have an adverse effect on our business, results of operations, financial condition or prospects for an undetermined period of time.

~~The market price of our common stock may decline as a result of the Stone Combination.~~

The market price of our common stock may decline as a result of the Stone Combination if, among other things, we are unable to achieve the expected benefits of the transaction, or if the transaction costs related to the Stone Combination and integration are greater than expected. The market priceimmaterial also may decline if we do not achieve the perceived benefits of the Stone Combination as rapidly or to the extent anticipated by financial or industry analysts or if the effect of the Stone Combination on our financial results is not consistent with the expectations of financial or industry analysts.

~~We are controlled by Apollo Funds and Riverstone Funds. The interests of Apollo Funds and Riverstone Funds may differ from the interests of our other stockholders.~~

Immediately following the closing of the Stone Combination, the stakeholders of Talos Energy LLC beneficially owned and possessed voting power over 63% of our common stock. Under the Stockholders’ Agreement, the Apollo Funds and the Riverstone Funds may acquire additional shares of our common stock without the approval of the Company Independent Directors.

Through their ownership of a majority of our voting power and the provisions set forth in our charter, bylaws and the Stockholders’ Agreement, the Apollo Funds and the Riverstone Funds have the ability to designate and elect a majority of our directors. As a result of the Apollo Funds’ and the Riverstone Funds’ ownership of a majority of the voting power of our common stock, we are a “controlled company” as defined in NYSE listing rules and, therefore, we are not be subject to NYSE requirements that would otherwise require us to have (i) a majority of independent directors, (ii) a nominating committee composed solely of independent directors, (iii) director nominees selected, or recommended for the board’s selection, either by a majority of the independent directors or a nominating committee composed solely of independent directors, and (iv) the compensation of our executive officers determined by a majority of the independent directors or a compensation committee composed solely of independent directors. Under the Stockholders’ Agreement, our board of directors has four directors not designated by the Apollo Funds and the Riverstone Funds and six directors designated by the Apollo Funds and the Riverstone Funds.

Apollo Funds and Riverstone Funds also have control over all other matters submitted to stockholders for approval, including changes in capital structure, transactions requiring stockholder approval under Delaware law, and corporate governance, subject to the terms of the Stockholders’ Agreement that require the Apollo Funds and the Riverstone Funds to vote in a specified manner on certain actions, including their agreement to vote in favor of director nominees not designated by the Apollo Funds and the Riverstone Funds. Apollo Management and Riverstone may have different interests than other holders of our common stock and may make decisions adverse to your interests.

Among other things, Apollo Funds’ and Riverstone Funds’ control could delay, defer, or prevent a sale of us that our other stockholders support, or, conversely, this control could result in the consummation of such a transaction that other stockholders do not support. This concentrated control could discourage a potential investor from seeking to acquire our common stock and, as a result, might harm the market price of our common stock.

~~We will continue to incur, transaction-related and restructuring costs in connection with the Stone Combination and the integration of the two businesses.~~

We will continue to incur, transaction-related and restructuring costs in connection with the Stone Combination and the integration of the businesses of Stone and Talos Energy LLC. These expenses could, particularly in the near term, reduce the expected pre-tax synergies related to the integration of the businesses following the completion of the Stone Combination, and accordingly, any net synergies may not be achieved in the near term or at all. These integration expenses may result in us taking significant charges against earnings following the completion of the Stone Combination.

~~The corporate opportunity provisions in our charter could enable others to benefit from corporate opportunities that might otherwise be available to us.~~

~~Subject to the limitations of applicable law, our charter, among other things:~~

~~These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of others.~~

Our charter designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees, or agents.

Our charters provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of us, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, employees, agents or stockholders (including a beneficial owner of stock) to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our charter or bylaws, or (iv) any action asserting a claim governed by the internal affairs doctrine, in each case subject to the Court of Chancery having personal jurisdiction over the indispensable parties named as defendants in the case. Any person or entity purchasing or otherwise acquiring any interest in any share of our capital stock will be deemed to have notice of and consent to these provisions of our charter. This exclusive forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which couldmaterially adversely affect our business, financial condition or ~~results of operations.~~

The Apollo Funds and the Riverstone Funds are prohibited from transferring shares of our common stock until the first anniversary of the Closing Date, after which, subject to restrictions, they will be permitted to transfer their shares of our common stock, which could have a negative impact on our stock price.

For 12 months following the completion of the Stone Combination, the Apollo Funds and the Riverstone Funds are prohibited from transferring their shares of our common stock other than to their respective affiliates, unless such transfer is approved by a majority of the Company Independent Directors. The lockup will cease to apply to 50% of our common stock that was issued to the Apollo Funds and the Riverstone Funds, respectively, at the closing of the Stone Combination on the six-month anniversary of the Closing Date and will cease to apply to an additional 25% of our common stock that was issued to the Apollo Funds and the Riverstone Funds, respectively, at the closing of the Stone Combination on the nine-month anniversary of the Closing Date. Following such 12-month lockup period, the Apollo Funds and the Riverstone Funds will be permitted, subject to certain restrictions, to transfer shares of our common stock, including in public offerings pursuant to registration rights granted by us. Any such transfer could significantly increase the number of shares of our common stock available in the market, which could cause a decrease in the price of our common stock.

Additionally, pursuant to the Stockholders’ Agreement, until the first anniversary of the Closing Date, each of the Apollo Funds and the Riverstone Funds will be prohibited from transferring any shares of our common stock in any transaction that would result in the transferee owning more than 35% of the outstanding shares of our common stock without the prior approval of a majority of the Company Independent Directors, unless such transferee agrees in writing to be bound by substantially the same provisions as the stockholders are bound by pursuant to the Stockholders’ Agreement. Following the first anniversary of the Closing Date, the Apollo Funds and the Riverstone Funds could sell a significant percentage of our common stock to a third party that is not subject to provisions similar to the provisions in the Stockholders’ Agreement.

~~Oil and natural gas prices are volatile. Significant declines in commodity prices in the~~ future ~~may adversely affect our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.~~

Our revenues, cash flows, profitability, and future rate of growth substantially depend upon the market prices of oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to access funds under our Bank Credit Facility and through the capital markets. The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves, and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such time. Oil and natural gas prices significantly declined in the second half of 2014, with sustained lower prices continuing throughout 2015, 2016 and 2017. Despite a modest recovery in late 2017, commodity prices could remain suppressed or decline further in the future, which will likely have material adverse effects on our proved reserves and borrowing base. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, which is impacted by declining prices. Significant price declines could cause us to take ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See the Risk Factor entitled “—Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values” for further discussion.

In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

~~The markets for oil and natural gas~~results. There have been volatile historically and are likely to remain volatile in the future. For example, during the period January 1, 2015 through June 30, 2018, the NYMEX West Texas Intermediate (“WTI”) crude oil price per Bbl ranged from a low of $30.62 to a high of $69.98, and the NYMEX natural gas price per MMBtu ranged from a low of $1.71 to a high of $3.93. The high, low and average prices for NYMEX WTI and NYMEX Henry Hub are monthly contract prices. The prices we receive for our oil and natural gas depends upon many factors beyond our control, including, among others:

These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.

We are required to meet a minimum work program expressed in work units during a four-year exploration period according to one of our PSCs with the National Hydrocarbons Commission of Mexico (the “CNH”).

On September 4, 2015, our subsidiary Talos Energy LLC, together with its consortium partners Sierra Oil & Gas S. de R.L de C.V. (“Sierra”) and Premier Oil Plc (“Premier” and, together with Talos Energy and Sierra, the “Consortium”) executed two PSCs with the CNH for the development of the Mexican acreage—one for each of Blocks 2 and 7. PSCs require that the Consortium execute a minimum work program expressed in work units during a four-year exploration period. The work units represent the performance of exploration studies and seismic and drilling activities. The aggregate value of the minimum work program under the PSCs is approximately $143.0 million (gross), of which we are responsible for a pro rata portion based on our participation interest—35% in Block 7 and 45% in Block 2. In order to guarantee the execution of the minimum work program under the PSCs, the Consortium was required to post a financial guarantee to the CNH of approximately $143 million (gross), of which Talos Energy’s share was $48.7 million. We satisfied our share through a performance bond. As the Consortium completes the minimum work program under the PSCs, the amount of the financial guarantee will be reduced accordingly beginning after the second anniversary of entering into the PSCs. Effective January 23, 2018, the activities already performed on Block 7 have satisfied the minimum work program on Block 7, reducing the $143 million (gross) in outstanding letters of credit by $65.7 million (gross). Activities on Block 2 are in the planning phase and the Consortium is on schedule to satisfy the minimum work program on Block 2 by September 4, 2019. If we or the Consortium is unable to meet the minimum work program, we could be liable along with the other members in the Consortium for the remaining financial guarantee, and the CNH could rescind the Block 2 PSC for a default.

Our debt level and the covenants in our current or future agreements governing our debt, including our Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, could negatively impact our financial condition, results of operations, and business prospects. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

~~The terms of the agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including:~~

Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, have important consequences on our operations, including:

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which have declined significantly since mid-2014.

We depend on our Bank Credit Facility for a portion of our future capital needs. We are required to comply with certain debt covenants and, beginning with the fiscal quarter ending September 30, 2018, certain financial ratios under the Bank Credit Facility. Our borrowing base under the Bank Credit Facility, which is redetermined semi-annually, is based on an amount established by the lenders after their evaluation of our proved oil and natural gas reserve values. If, due to a redetermination of our borrowing base, our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency. Our Bank Credit Facility allows us to cure a borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding sufficient to cure the borrowing base deficiency within 30 days after the existence of such deficiency; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first installment due within 30 days after the existence of such deficiency; or (iv) any combination of the above. We are required to elect one of the foregoing options within 10 days after the existence of such deficiency.

We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings, or proceeds from the sale of assets are available to pay or refinance such debt. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our debt,SEC filings including our Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, may also prohibit us from taking such actions. Factors that affects our ability to raise cash through offerings of our capital stock, a refinancing of our debt, or a sale of assets include financial market conditions and our market value and operating performance at the time of such offerings, refinancing, or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing, or sale of assets would be successfully completed.

Regulatory requirements and permitting procedures imposed by the Bureau of Ocean Energy Management (“BOEM”) and the BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

BSEE and BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response, and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, are continuing to develop and implement new, more restrictive requirements. For example, in April 2016, BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation, and maintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements. Pursuant to President Trump’s Executive Orders dated March 28, 2017, and April 28, 2017 (the “~~Executive Orders~~”), respectively, BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. One consequence of this review is that on December 29, 2017, the BSEE published proposed revisions to its regulations regarding offshore drilling safety equipment, which proposal includes the removal of the requirement for offshore operators to certify through an independent third party that their critical safety and pollution prevention equipment (~~e.g.~~, subsea safety equipment, including blowout preventers) is operational and functioning as designed in the most extreme conditions. The December 2017 proposed rule has not been finalized and there remains substantial uncertainty as to the scope and extent of any revisions to existing oil and gas safety and performance-related regulations and other regulatory initiatives that ultimately will be adopted by BSEE pursuant to its review process.

Also, in April 2016, BOEM published a proposed rule that would update existing air emissions requirements relating to offshore oil and natural gas activity on the OCS. BOEM regulates these air emissions in connection with its review of exploration and development plans, rights of way and rights of use, and/or easement applications. The proposed rule would bolster existing air emissions requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the U.S. Environmental Protection Agency (the “EPA”) to affect human health and public welfare. Pursuant to the Executive Orders, BOEM has ceased rulemaking activities for and is reviewing the proposed air quality rule. On October 24, 2017, the Department of the Interior announced that it is currently reviewing recommendations on how to proceed, including promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw certain provisions and seek additional input on others.

Compliance with new and future regulations could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Furthermore, among other adverse impacts, to the extent that the BOEM and BSEE do not reduce the stringency of existing oil and gas safety and performance-related regulations and other regulatory initiatives, the regulatory requirements imposed by such existing or future, more stringent regulations or other regulatory initiatives could delay operations, disrupt our operations, or increase the risk of leases expiring before exploration and development efforts have been completed due to the time required to develop new technology. Additionally, if left unchanged, the existing, or future, more stringent oil and gas safety and performance-related regulations and other regulatory initiatives imposed by the BOEM and BSEE could result in increased financial assurance requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties or shut-in production at one or more of our facilities. Also, if material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

New guidelines issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS may have a material adverse effect on our business, financial condition, or results of operations.

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In July 2016, the BOEM issued the 2016 NTL to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs or RUEs. The 2016 NTL became effective in September 2016, but the BOEM has since extended indefinitely the start date for implementing this NTL so as to provide the BOEM with time to review its complex financial assurance program.

In December 2016, we received an order to provide additional security from BOEM totaling approximately $0.5 million for our sole liability properties (the “December 2016 Order”). However, following the BOEM’s action in January 2017 to extend the implementation date of the 2016 NTL for a period of six months, the BOEM elected to include sole liability properties as being covered under the extension and thus rescinded the December 2016 Order while BOEM reviewed the financial assurance program. In June 2017, the BOEM further extended the start date for implementing the 2016 NTL indefinitely beyond June 30, 2017. This extension currently remains in effect; however, the BOEM reserved the right to re-issue sole liability orders in the future, including in the event that it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning sole liabilities.

~~As of the filing date of this~~ Quarterly Report on Form 10-Q we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders for financial assurance obligations. Following completion of its review, the BOEM may elect to retain the 2016 NTL in its current form or may make revisions thereto and, thus, until the review is completed and BOEM determines what additional financial assurance may be required by us, we cannot provide any assurance that such financial assurance coverage can be obtained. Moreover, the BOEM could in the future make other demands for additional financial assurances covering our obligations under sole liability properties and/or our non-sole liability properties. The BOEM may reject our proposals and make demands that exceed our capabilities.

If we fail to comply with the current or future orders of the BOEM to provide additional surety bonds or other financial assurances, the BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.

In addition, if fully implemented, the new 2016 NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator’s collateral. Moreover, depressed oil prices could result in sureties seeking additional collateral to support existing bonds, such as cash or letters of credit, and we cannot provide assurance that we are able to satisfy collateral demands for future bonds to comply with supplemental bonding requirements of BOEM. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

We have a subsidiary that is subject to a plea agreement with the Department of Justice (“DOJ”) pursuant to which certain exploration and production activities must comply with a Safety and Environmental Compliance Program (“SECP”). Noncompliance with the SECP could result in a violation of the plea agreement and provide a basis for revocation or modification of probation.

In February 2014, we received a grand jury subpoena from the DOJ addressing activities that occurred on the Ship Shoal 225A production platform operated by one of our subsidiaries, Energy Resource Technology GOM, LLC (“ERT”). On November 30, 2015, ERT was charged with two violations of the Outer Continental Shelf Lands Act in connection with hot work and blowout preventer testing activities, and with two violations of the Clean Water Act for self-reported activities surrounding overboard discharge sampling and unpermitted discharges. On January 6, 2016, ERT pled guilty to these charges. On April 6, 2016, the United States District Court for the Eastern District of Louisiana (the “Court”) accepted ERT’s plea and sentenced ERT, consistent with the plea agreement, to pay a penalty of $4.2 million, which ERT has paid. The Court placed ERT on probation for three years. The conditions of probation include compliance with an agreed SECP, pursuant to which ERT and another subsidiary of ours must implement enhanced safety and environmental compliance inspections, reviews and audits, implement a comprehensive training program, implement enhanced operational controls to better manage, detect and prevent safety and environmental violations, and preparation and implementation of schedule for decommissioning. we believe that we are in substantial compliance with the SECP, a failure to comply with the SECP could result in a violation of the plea agreement and provide a basis for revocation or modification of probation, which could adversely our financial condition and operations.quarter ended March 31, 2023.

~~A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our new Bank Credit Facility or in the capital markets.~~

We use our cash flows from operating activities and borrowings under our new Bank Credit Facility to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. However, we may not be able to access adequate funding under our Bank Credit Facility as a result of (i) a decrease in its borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. In addition, we may face limitations on our ability to access the debt and equity capital markets and complete asset sales, an increased counterparty credit risk on our derivatives contracts, and the requirement by our contractual counterparties to post collateral guaranteeing performance.

We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

We spend a substantial amount of capital for the acquisition, exploration, exploitation, development, and production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash flows, cash on hand and borrowings under our Bank Credit Facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A further reduction in commodity prices may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

~~Our cash flow from operations and access to capital is subject to a number of variables, including:~~

If low oil and natural gas prices, operating difficulties, declines in reserves, or other factors, many of which are beyond our control, cause our revenues, cash flows from operating activities, and the borrowing base under our Bank Credit Facility to decrease, we may be limited in our ability to fund the capital necessary to complete our capital expenditure program. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot be sure that additional debt or equity financing will be available, and we cannot be sure that cash flows provided by operations will be sufficient to meet these requirements. For example, the ability of oil and gas companies to access the equity and high yield debt markets has been significantly limited since the significant decline in commodity prices since mid-2014.

Our production, revenue, and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

Our production, revenue, and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, the Gulf of Mexico. Unlike other entities that are geographically diversified, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may subject us to numerous economic, competitive, and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate, and result in our dependency upon a single or limited number of hydrocarbon basins. In addition, the geographic concentration of our properties in the Gulf of Mexico and the Gulf Coast means that some or all of the properties could be affected should the region experience:

Because all or a number of our properties could experience many of the same conditions at the same time, these conditions may have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

~~We may experience significant shut-ins and losses of production due to the effects of hurricanes in the Gulf of Mexico.~~

Our production is primarily associated with our properties in the Gulf of Mexico and the Gulf Coast. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes and tropical storms in the Gulf of Mexico. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production.

A significant portion of our production, revenue and cash flow is concentrated in our Phoenix Field. Because of this concentration, any production problems, impacts of adverse weather or inaccuracies in reserve estimates could have a material adverse impact on our business.

For the six months ended June 30, 2018, approximately 51% of our production and 63% of our oil, natural gas, and NGL revenue was attributable to our Phoenix Field, which is located offshore Louisiana. This concentration in the Phoenix Field means that any impact on our production from the Phoenix Field, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment, or otherwise, could have a material effect on our business. We produce the Phoenix Field through the Helix Producer I (“HP-1”) a dynamically positioned floating production facility that is operated by Helix Energy Solutions Group, Inc. (“Helix”). The HP-I interconnects the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as in the event of a mechanical problem with the dynamic positioning system or the approach of a hurricane. Because the HP-I may have to be disconnected from the Phoenix Field if circumstances require, our production from the Phoenix Field may be subject to more frequent interruptions than if the Phoenix Field was produced by a more conventional platform. We are also required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field. On September 10, 2016, the HP-I was disconnected from the production buoy and released for dry dock for 28 days. Upon completion of the dry dock, the HP-I remained disconnected from the buoy connecting it to the Phoenix Field due to Federal Emergency Management Agency testing of test upgrades to the power management system, preventing us from reconnecting the HP-I to the Phoenix Field for a further five days. Once the buoy was connected, Phoenix Field production remained shut-in for an additional five days to conduct buoy remediation of the swivel piping. In addition, for 25 days in March 2015, we were required to disconnect the HP-I from the production buoy due to upgrades to the power management system of the vessel, which is an integral part of the dynamic positioning system. The upgrade work was followed by sea trials that tested the dynamic positioning system and were required by various regulatory groups, including the United States Coast Guard.

The HP-I is part of the Helix Well Containment Group (“HWCG”), which is a consortium that is available to respond to any deepwater well control event, such as the Macondo well oil spill. If such an event were to occur and the HWCG was to be utilized for well control, the HP-I, which is the vessel that would be used to respond to the deepwater well control event, would be required to disconnect from the Phoenix Field until such time as the well control event was resolved and the HP-I could return to the Phoenix Field. During such time period, we would not be able to produce the Phoenix Field. In the event the HP-I has to disconnect from the Phoenix Field, our production, revenue, and cash flow could be adversely affected, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, all of our production from the Phoenix Field flows through the Boxer facility operated by Shell Pipeline Company LP. To the extent Shell Pipeline Company LP temporarily shuts in its Boxer facility, whether for maintenance or otherwise, we would not able to produce the Phoenix Field during this period of time, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

If the actual reserves associated with the Phoenix Field are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

~~We are not insured against all of the operating risks to which our business is exposed.~~

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, oil pollution, construction all risk, workers’ compensation and employers’ liability, and other coverage. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses.

We are expected to have general liability insurance coverage with an annual aggregate limit of $500 million. We selectively purchase physical damage insurance coverage for our pipelines, platforms, facilities, and umbilicals for losses resulting from named windstorms and operational activities.

Our operational control of well coverage is expected to provide limits that vary by well location and depth and range from a combined single limit of $25 million to $500 million per occurrence. Exploratory deepwater wells have a coverage limit of up to $500 million per occurrence. Additionally, we maintain up to $150 million in oil pollution liability coverage. Our operational control of well and physical damage policy limits is scaled proportionately to our working interests. Our general liability program utilizes a combination of assured’s interest and scalable limits. All of our policies described above are subject to deductibles, sub-limits, or self-insurance. Under our service agreements, including drilling contracts, we expect to be indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

An operational or hurricane or other adverse weather-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have production interruption insurance.

We reevaluate the purchase of insurance, policy limits, and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe is economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the Gulf of Mexico, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

~~Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values.~~

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, we compare, at the end of each financial reporting period for each cost center, the present value of estimated future net cash flows from proved reserves (based on a trailing 12-month average, hedge-adjusted commodity price and excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the estimated discounted future net cash flows. A write-down of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we are required to write-down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

~~Our oil and gas operations are subject to various international and U.S. federal, state and local governmental regulations that materially affects our operations.~~

Our oil and gas operations are subject to various international and U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can discharge materials into the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment and other decommissioning costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; regulations regarding the rate, terms and conditions of transportation service or the price, terms, and conditions related to the purchase and sale of oil and natural gas; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations. In addition, because we hold federal leases, the federal government requires that we comply with numerous additional regulations applicable to government contractors.

In July 2017, we, along with partners Sierra and Premier, reported the discovery of a significant reservoir of crude oil in the Sureste basin offshore Mexico through the Zama-1 well. Data from the Zama-1 well indicates that it is possible the deposit could be part of a field that extends into an exploration block in which the state entity Pemex holds exploration and development rights.

The Ministry of Energy of Mexico has promulgated guidelines to establish procedures for conducting the unitization of shared reservoirs and approving the terms and conditions of unitization and unit operating agreements, as well as the authority to direct parties holding rights in a potentially shared reservoir to appraise and potentially form a unit for development of such reservoir.

Even with the final regulations in place, there are still some uncertainties regarding the unitization process, including the selection of a unit operator and the exact length of time that will take to obtain approvals of any unit agreements. Any unit operating agreement eventually reached by relevant parties or any unit order issued by a governmental entity in Mexico could be adverse to us and affect the value that we are able to recognize from the reservoir discovery, including but not limited to an agreement or unit order that would require us to allow a third party to develop and produce the crude oil reservoir identified through the Zama-1 well.

In addition, the Oil Pollution Act of 1990 (“OPA”) requires operators of U.S. offshore facilities to prove that they have the financial capability to respond to costs that may be incurred in connection with potential oil spills. Under the OPA and other environmental statutes such as the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, owners and operators of certain defined onshore and offshore facilities are strictly liable for spills of oil and other regulated substances, subject to certain limitations. Consequently, a spill from one of our facilities subject to laws such as the OPA, CERCLA and RCRA could require the expenditure of additional, and potentially significant, amounts of capital, or could have a material adverse effect on our earnings, results of operations, competitive position or financial condition. We cannot predict the ultimate cost of compliance with these requirements or their impact on our earnings, operations or competitive position.

Production periods or reserve lives for Gulf of Mexico properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

The vast majority of our operations are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.

Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves or make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and natural gas. We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, current market conditions may adversely impact our ability to obtain financing to fund acquisitions, and they have lowered the level of activity and depressed values in the oil and natural gas property sales market.

~~Our actual recovery of reserves may substantially differ from our proved reserve estimates.~~

Estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that any present value of future net cash flows from our proved reserves represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2017 on historical 12-month average prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues are affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties affects the timing of actual future net cash flows from reserves, and thus their actual present value. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.

At June 30, 2018, approximately 31% of our estimated proved reserves (by volume) were undeveloped and approximately 23% were non-producing. Any or all of our proved undeveloped or proved developed non-producing reserves may not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developed non-producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumptions that we incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as estimated. Any material inaccuracies in these reserve estimates or underlying assumptions materially affects the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

~~Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present produces in economic quantities.~~

We rely on 3D seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or, if present, produce in economic quantities, and seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock. These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition.

~~SEC rules could limit our ability to book additional proved undeveloped reserves in the future.~~

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

Our acreage has to be drilled before lease expiration in order to hold the acreage by production. If commodity prices become depressed for an extended period of time, it might not be economical for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an adverse effect on our business.

Unless production is established as required by the leases covering the undeveloped acres, the leases for such acreage may expire. As of June 30, 2018, we had leases on 20,860 gross (20,775 net) acres that could potentially expire during the remainder of the 2018 fiscal year.

Our drilling plans for areas not held by production are subject to change based upon various factors. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. On the acreage that we do not operate, we have less control over the timing of drilling, and therefore there is additional risk of expirations occurring in those sections.

~~The marketability of our production depends mostly upon the availability, proximity, and capacity of oil and natural gas gathering systems, pipelines and processing facilities.~~

The marketability of our production depends upon the availability, proximity, operation, and capacity of oil and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity of these gathering systems, pipelines and processing facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. The disruption of these gathering systems, pipelines and processing facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. Federal, state, and local regulation of oil and natural gas production and transportation, general economic conditions, and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors changed dramatically, the financial impact could be substantial. The availability of markets and the volatility of product prices are beyond our control and represents a significant risk.

From time to time, we may provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. In addition, our forecasts may assume that none of the risks associated with our oil and natural gas operations summarized in this section would occur, such as facility or equipment malfunctions, adverse weather effects, or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.

~~Our operations are subject to numerous risks of oil and natural gas drilling and production activities.~~

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves are found. The cost of drilling and completing wells is often uncertain. To the extent we drill additional wells in the Gulf of Mexico deepwater and/or in the Gulf Coast deep gas, our drilling activities increases capital cost. In addition, the geological complexity of the areas in which we have oil and natural gas operations make it more difficult for us to sustain the historical rates of drilling success. Oil and natural gas drilling and production activities may be shortened, delayed, or cancelled as a result of a variety of factors, many of which are beyond our control. These factors include:

The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment, and related services. We cannot assure you that the wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient cash flows to recoup drilling costs.

The exploration, development and production of oil and gas properties involves a variety of operating risks, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. We are also involved in completion operations that utilize hydraulic fracturing, which may potentially present additional operational and environmental risks. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions, including the effects of hurricanes.

In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for containment and oil removal costs and a variety of public and private damages, including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we could be liable for costs and damages, which costs and damages could be material to our results of operations and financial position.

Our business is also subject to the risks and uncertainties normally associated with the exploration for and development and production of oil and natural gas that are beyond our control, including uncertainties as to the presence, size and recoverability of hydrocarbons. We may not encounter commercially productive oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and/or result in a total loss of our investment, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, we may be uncertain as to the future cost or timing of drilling, completing and operating wells.

We have an interest in six deepwater fields: the Phoenix Field, the Bushwood Field, the Gunnison Field, the Pompano Field, the Amberjack Field and the Ram Powell Field, and may attempt to pursue additional operational activity in the future and acquire additional fields and leases in the deepwaters of the Gulf of Mexico. Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the Gulf of Mexico Conventional Shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. For example, the drilling of deepwater wells requires specific types of drilling rigs with significantly higher day rates and limited availability as compared to the rigs used in shallower water. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the Gulf of Mexico Conventional Shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.

If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and production and repairs to resume operations. Any of these industry operating risks could have a material adverse effect on our business, results of operations, and financial condition.

~~Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks, and other disruptions.~~

As an oil and gas producer, we have various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business. In particular, the implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls are sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure, or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business, or potential liability.

The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers or vendors, could have a material adverse effect on our financial condition and operations.

Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs. As a result, we may significantly increase or decrease our estimated asset retirement obligations in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions. The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimates of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster. Also, a sustained lower commodity price environment may cause our non-operator partners to be unable to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs.

Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the Gulf of Mexico following BSEE’s issuance of an NTL that established a more stringent regimen for the timely decommissioning of what is known as “idle iron” wells, which are platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease in the Gulf of Mexico. The idle iron NTL requires decommissioning of any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities, which must then be permanently plugged or temporarily abandoned within three years’ time. Similarly, platforms or other facilities no longer useful for operations must be removed within five years of the cessation of operations. We may have to draw on funds from other sources to satisfy decommissioning costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations. Moreover, as a result of the implementation of the idle iron NTL, there is expected to be increased demand for salvage contractors and equipment operating in the Gulf of Mexico, resulting in increased estimates of plugging, abandonment, and removal costs and associated increases in operators’ asset retirement obligations.

In addition, we could become responsible for decommissioning liabilities related to offshore facilities we no longer own or operate. Federal regulations allow the government to call upon predecessors in interest of oil and natural gas leases to pay for plugging, abandonment, restoration, and decommissioning obligations if the current operator fails to fulfill those obligations and regardless of any indemnification agreements, the costs of which could be significant. Moreover, several onshore and offshore exploration and production companies have sought bankruptcy protection over the past several years. The government may seek to impose a bankrupt entity’s plugging and abandonment obligations on us or other predecessors-in-interest, which could be significant and adversely affect our business, results of operations, financial condition and cash flows.

We may not receive payment for a portion of our future production. We attempt to diversify our sales and obtain credit protections, such as parent guarantees, from certain of our purchasers. The tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by customers. We are unable to predict what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.

~~We may not realize all of the anticipated benefits from our future acquisitions, and we may be unable to successfully integrate future acquisitions.~~

Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. We expect to grow in the future by expanding the exploitation and development of our existing assets, in addition to growing through targeted acquisitions in the Gulf of Mexico or in other basins. We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings, and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, inexperience with operating in new geographic regions, unknown liabilities, inaccurate reserve estimates, and fluctuations in market prices.

In addition, integrating acquired businesses and properties involves a number of special risks and unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. These difficulties include, among other things:

Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results. The process of integrating our operations could cause an interruption of or loss of momentum in the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage our business. If our management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

~~Our future acquisitions could expose us to potentially significant liabilities, including plugging and abandonment liabilities.~~

~~We expect that future acquisitions will contribute to our growth. In connection with potential future acquisitions, we may only be able to perform limited due diligence.~~

Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs, and potential environmental, regulatory and other liabilities, including plugging and abandonment liabilities. Such assessments are inexact and may not disclose all material issues or liabilities. In connection with its assessments, we perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.

There may be threatened, contemplated, asserted, or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation, or other matters of which we are unaware, which could materially and adversely affect our production, revenues, and results of operations. We may be successful in obtaining contractual indemnification for preclosing liabilities, including environmental liabilities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and could potentially expose us to unindemnified liabilities, which could materially adversely affect our production, revenues, and results of operations.

~~We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act (the “FCPA”).~~

We are subject to the FCPA and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business. We may do business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, or private entities. Thus, we face the risk of unauthorized payments or offers of payments by one of our employees or consultants, given that these parties may not always be subject to our control. Our existing safeguards and any future improvements may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible.

Under the PSCs with the CNH, we work as a consortium with two other partners—Sierra and Premier. Violations of the FCPA, by any consortium partner, may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the CNH has the authority to rescind the PSCs if these violations occur.

~~Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.~~

Our oil and gas exploration, development, and production activities are subject to political and economic uncertainties (including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them), expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions, currency fluctuations, royalty and tax increases, and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to acts of terrorism, piracy, disease, illegal cartel activities, and other political risks, including tension and confrontations among political parties. Some of these risks may be higher in the developing countries in which we conduct our activities, namely, Mexico. Mexico’s most recent presidential election was held in July 2018. Presidential reelection is not permitted in Mexico. The President-elect, Andrés Manuel López Obrador, will take office on December 1, 2018, and his political party, ~~Movimiento Regeneración Nacional~~ will have a majority in both houses of Mexico’s congress. Mr. Lopez Obrador, and certain members of his cabinet have, in the past, made statements that would call into question the degree of support their administration will have for Mexico’s energy reforms. However, at this time we cannot predict what changes (if any) will result from this change in administration. Political events in Mexico could adversely affect economic conditions and/or the oil and gas industry and, by extension, our results of operations and financial position.

~~Our operations may be exposed to risks of illegal cartel activities, local economic conditions, political disruption, and governmental policies that may:~~

Disruptions may occur in the future, and losses caused by these disruptions may not be covered by insurance. Consequently, our exploration, development, and production activities may be substantially affected by factors that could have a material adverse effect on our financial condition and results of operations. Furthermore, in the event of a dispute arising from non-U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the outcome of such dispute.

Our operations are adversely affected by laws and policies of the jurisdictions, including Mexico, the United States, the Netherlands and other jurisdictions, in which we do business that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof could have a material adverse effect on our results of operations and financial position.

~~New technologies may cause our current exploration and drilling methods to become obsolete, and we may not be able to keep pace with technological developments in our industry.~~

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We rely heavily on the use of seismic technology to identify low-risk development and exploitation opportunities and to reduce our geological risk. Seismic technology or other technologies that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.

~~We may not be in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves from our non-operated properties.~~

As we carry out our drilling program, we may not serve as operator of all planned wells. We may have limited ability to exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could prevent the realization of anticipated results in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depends upon a number of factors that could be largely outside of our control, including:

In addition, with respect to oil and natural gas projects that we do not operate, we have limited influence over operations, including limited control over the maintenance of safety and environmental standards. The operators of those properties may, depending on the terms of the applicable joint operating agreement:

~~The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.~~

Competition within our industry is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than our budget, which may adversely affect our ability to compete. If other companies relocate to the Gulf of Mexico region, levels of competition may increase and our business could be adversely affected. In the exploration and production business, some of the larger integrated companies may be better able than we are to respond to industry changes including price fluctuations, oil and gas demand, political change and government regulations.

We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. The competitors may also have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the current decline in oil prices, and to absorb the burden of current and future governmental regulations and taxation. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe impacts attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

~~The loss of our larger customers could materially reduce our revenue and materially adversely affect our business, financial condition and results of operations.~~

We have a limited number of customers that provide a substantial portion of our revenue. The loss of our larger customers, including Shell Trading (US) Company, could adversely affect our current and future revenue, and could have a material adverse effect on our business, financial condition and results of operations.

~~Our business depends on access to oil and natural gas processing, gathering and transportation systems and facilities.~~

The marketability of our oil and natural gas production depends in large part on the operation, availability, proximity, capacity and expansion of processing, gathering and transportation facilities owned by third parties. We can provide no assurance that sufficient processing, gathering and/or transportation capacity exists or that we will be able to obtain sufficient processing, gathering and/or transportation capacity on economic terms. A lack of available capacity on processing, gathering and transportation facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these facilities for an extended period of time could negatively impact our revenues. In addition, we enter into contracts for firm transportation, and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above. In addition, the rates charged for processing, gathering and transportation services may increase over time.

Our industry has lost a significant number of experienced professionals over the years due to its cyclical nature, which is attributable, among other reasons, to the volatility in commodity prices. Our operations are dependent upon key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have an adverse effect on us and our operations.

In addition, our exploration, production and decommissioning activities require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable depends upon our ability to employ and retain skilled workers. Our ability to expand operations depends in part on our ability to increase the size of our skilled labor force, including geologists and geophysicists, field operations managers and engineers, to handle all aspects of our exploration, production and decommissioning activities. The demand for skilled workers in our industry is high, and the supply is limited. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our labor force, increases in the wage rates that we will have to pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

~~Resolution of litigation could materially affect our financial position and results of operations.~~

Resolution of litigation could materially affect our financial position and results of operations. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we may incur losses that could be material to our financial position or results of operations in future periods.

~~Future regulations relating to and interpretations of recently enacted U.S. federal income tax legislation may vary from our current interpretation of such legislation.~~

The U.S. federal income tax legislation recently enacted in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Cuts and Jobs Act. In the future, the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Cuts and Jobs Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases. These efforts have included consideration of cap-and-trade programs, carbon taxes, greenhouse gas reporting and tracking programs, and regulations that directly limit greenhouse gas emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented. The EPA, however, has adopted regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act (the “CAA”). The EPA adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources through preconstruction and operating permit requirements.

The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, on an annual basis. Recent regulation of emissions of greenhouse gases has focused on fugitive methane emissions. For example, in June 2016, the EPA finalized rules that established new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities. However, in June 2017, the EPA published a proposed rule to stay certain portions of the 2016 rule for two years and to reconsider the entirety of the 2016 rule, but the agency has not yet published a final rule and, as a result, the 2016 rule is currently in effect but future implementation of the 2016 rule is uncertain. Compliance with these rules if fully or partially implemented could result in increased compliance costs on our operations.

In addition, while the United States Congress has not taken any legislative action to reduce emissions of greenhouse gases, many states have established greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

Additionally, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country uses to achieve its greenhouse gas emissions targets. The Paris Agreement entered into force on November 4, 2016. However, in August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Substantial limitations on greenhouse gas emissions could also adversely affect demand for the oil and natural gas we produce and lowers the value of our reserves. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Additionally, with concerns over GHG emissions, certain non-governmental activists have recently directed their efforts at advocating the shifting of funding away from companies with energy-related assets, which could result in limitations or restrictions on certain sources of funding for the energy sector.

In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damage, or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such climate changes were to occur, they could have an adverse effect on our financial condition and results of operations.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), enacted on July 21, 2010, expanded federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Act requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the Act. Although the CFTC and the SEC have finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this is accomplished.

In one of its rulemaking proceedings still pending under the Act, the CFTC issued on December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also requires us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or to take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps to be entered into to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for, and to utilize, the end-user exception from such margin requirements for swaps to be entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows.

The full impact of the Act and related regulatory requirements upon our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted. The Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we may encounter, or reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Act and regulations implementing the Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

In addition, the European Union and other non-U.S. jurisdictions have implemented and continue to implement new regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become directly subject to such regulations and in any event the global derivatives market are affected to the extent that foreign counterparties are affected by such regulations. At this time, the impact of such regulations is not clear.

In order to manage our exposure to price risks in the marketing of our oil, natural gas, and natural gas liquids, we periodically enter into oil, natural gas, and natural gas liquids price hedging arrangements with respect to a portion of our expected production. Our hedging policy is expected to provide that we enter into hedging arrangements covering up to the following maximum percentages of volumes: (i) 90% of the reasonably anticipated quarterly production of oil, natural gas, and natural gas liquids of proved developed producing volumes during months January through July and November through December, (ii) 65% of the reasonably anticipated quarterly production of oil, natural gas, and natural gas liquids of proved developed producing volumes during months August through October, (iii) 50% of the reasonably anticipated quarterly production of oil, natural gas, and natural gas liquids of proved developed non-producing volumes during months January through July and November through December and (iv) 0% of the reasonably anticipated quarterly production of oil, natural gas and natural gas liquids of its proved developed non-producing volumes during months August through October. These arrangements may include futures contracts on the NYMEX. While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

All of our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our Bank Credit Facility. Our derivative agreements with the lenders are secured by the security documents executed by the parties under the Bank Credit Facility. Future collateral requirements for our commodity hedging activities are uncertain and depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions.

~~We have not made any unregistered sales~~Purchases of ~~securities~~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 ~~period covered~~three months ended June 30, 2023:

~~None.~~During the three months ended June 30, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

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.


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)


Large accelerated filer	☒	☐	Accelerated filer		☒☐
Non-accelerated filer	☐		Smaller reporting company	☐
~~Non-accelerated filer~~		~~☐ (Do not check if a smaller reporting company)~~	~~Smaller reporting company~~		☐

Emerging growth company	☐	☐


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Revenues:
Oil	$	342,983		$	429,329		$	635,677		$	783,215
Natural gas		16,329			70,406			36,512			113,387
NGL		7,898			19,350			17,603			36,049
Total revenues		367,210			519,085			689,792			932,651
Operating expenses:
Lease operating expense		101,165			87,582			182,527			147,396
Production taxes		607			864			1,213			1,715
Depreciation, depletion and amortization		169,794			104,511			317,117			202,851
Accretion expense		22,760			14,844			42,174			29,221
General and administrative expense		33,182			22,925			96,369			45,453
Other operating (income) expense		(723	)		12,372			2,115			12,508
Total operating expenses		326,785			243,098			641,515			439,144
Operating income		40,425			275,987			48,277			493,507
Interest expense		(45,632	)		(30,776	)		(83,213	)		(62,266	)
Price risk management activities income (expense)		26,197			(64,094	)		85,134			(345,313	)
Equity method investment income (expense)		(2,012	)		13,466			5,431			13,608
Other income		1,591			3,165			8,257			31,299
Net income before income taxes		20,569			197,748			63,886			130,835
Income tax benefit (expense)		(6,892	)		(2,607	)		39,651			(2,135	)
Net income	$	13,677		$	195,141		$	103,537		$	128,700

Net income per common share:
Basic	$	0.11		$	2.36		$	0.90		$	1.56
Diluted	$	0.11		$	2.33		$	0.89		$	1.55
Weighted average common shares outstanding:
Basic		125,436			82,566			115,590			82,320
Diluted		125,667			83,665			116,363			83,247


	Common Stock				Additional Paid-In		Accumulated			Treasury Stock					Total Stockholdersʼ
	Shares Issued		Par Value		Capital		Deficit			Shares		Amount			Equity
Balance at March 31, 2022		82,535,186	$	825	$	1,677,705	$	(983,405	)		—	$	—		$	695,125
Equity-based compensation		—		—		7,244		—			—		—			7,244
Equity-based compensation stock issuances		6,159		—		—		—			—		—			—
Net income		—		—		—		195,141			—		—			195,141
Balance at June 30, 2022		82,541,345	$	825	$	1,684,949	$	(788,264	)		—	$	—		$	897,510

Balance at March 31, 2023		127,455,965	$	1,275	$	2,531,402	$	(445,189	)		1,900,000	$	(26,647	)	$	2,060,841
Equity-based compensation		—		—		8,227		—			—		—			8,227
Purchase of treasury stock		—		—		—		—			1,500,000		(20,857	)		(20,857	)
Net income		—		—		—		13,677			—		—			13,677
Balance at June 30, 2023		127,455,965	$	1,275	$	2,539,629	$	(431,512	)		3,400,000	$	(47,504	)	$	2,061,888


	Six Months Ended June 30,
	2023			2022
Cash flows from operating activities:
Net income	$	103,537		$	128,700
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion expense		359,291			232,072
Amortization of deferred financing costs and original issue discount		7,629			6,952
Equity-based compensation expense		8,687			7,367
Price risk management activities expense (income)		(85,134	)		345,313
Net cash paid on settled derivative instruments		(4,161	)		(287,321	)
Equity method investment income		(5,431	)		(13,608	)
Settlement of asset retirement obligations		(47,683	)		(39,768	)
Loss on sale of assets		—			390
Changes in operating assets and liabilities:
Accounts receivable		35,127			(57,394	)
Other current assets		(23,790	)		(31,435	)
Accounts payable		(3,890	)		23,360
Other current liabilities		(22,975	)		33,284
Other non-current assets and liabilities, net		(44,124	)		6,453
Net cash provided by operating activities		277,083			354,365
Cash flows from investing activities:
Exploration, development and other capital expenditures		(298,658	)		(128,082	)
Proceeds from (cash paid for) acquisitions, net of cash acquired		17,617			(3,500	)
Proceeds from (cash paid for) sale of property and equipment, net		(8,488	)		1,597
Contributions to equity method investees		(15,260	)		(2,250	)
Proceeds from sale of equity method investments		—			15,000
Investment in intangible assets		(7,796	)		—
Net cash used in investing activities		(312,585	)		(117,235	)
Cash flows from financing activities:
Redemption of senior notes		(15,000	)		(6,060	)
Proceeds from Bank Credit Facility		505,000			35,000
Repayment of Bank Credit Facility		(305,000	)		(210,000	)
Deferred financing costs		(11,775	)		(129	)
Other deferred payments		(462	)		—
Payments of finance lease		(8,026	)		(12,836	)
Purchase of treasury stock		(47,504	)		—
Employee stock awards tax withholdings		(7,378	)		(4,476	)
Net cash provided by (used in) financing activities		109,855			(198,501	)

Net increase in cash, cash equivalents and restricted cash		74,353			38,629
Cash, cash equivalents and restricted cash:
Balance, beginning of period		44,145			69,852
Balance, end of period	$	118,498		$	108,481

Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	113,319		$	47,354
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	63,492		$	47,570


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


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


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

		~~Page~~
		Page
GLOSSARY			1
			3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			35
	PART I — FINANCIAL INFORMATION
~~PART I – FINANCIAL INFORMATION~~Item 1.	Financial Statements	7
	Condensed Consolidated Balance Sheets	7
~~Item 1.~~	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		511
	Note 1 — Organization, Nature of Business and Basis of Presentation		11
~~Item 2.~~	Note 2 — Acquisitions and Divestitures	12
	Note 3 — Property, Plant and Equipment	14
	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	20
	Note 10 — Related Party Transactions	20
	Note 11 — Commitments and Contingencies	21
	Note 12 — Segment Information	23
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		2425

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		4337
Item 4.	Controls and Procedures		38
~~Item 4.~~	~~Controls and Procedures~~PART II — OTHER INFORMATION		44
Item 1.	Legal Proceedings		39
~~PART II – OTHER INFORMATION~~Item 1A.	Risk Factors	39

Item 1.2.	~~Legal Proceedings~~		45

~~Item 1A.~~	~~Risk Factors~~		46

~~Item 2.~~	Unregistered Sales of Equity Securities and Use of Proceeds		7239
Item 3.	Defaults Upon Senior Securities		39
Item 3.4.	~~Defaults upon Senior Securities~~Mine Safety Disclosures		7239
Item 5.	Other Information		39
Item 4.6.	~~Mine Safety Disclosures~~Exhibits		7240

~~Item 5.~~	~~Other Information~~Signatures		72

~~Item 6.~~	~~Exhibits~~		73

	~~Signatures~~		7642


	June 30, 2023			December 31, 2022
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	17,525		$	44,145
Accounts receivable:
Trade, net		157,329			150,598
Joint interest, net		86,615			54,697
Other, net		30,233			6,684
Assets from price risk management activities		45,522			25,029
Prepaid assets		85,697			84,759
Other current assets		17,251			1,917
Total current assets		440,172			367,829
Property and equipment:
Proved properties		7,526,625			5,964,340
Unproved properties, not subject to amortization		401,710			154,783
Other property and equipment		32,088			30,691
Total property and equipment		7,960,423			6,149,814
Accumulated depreciation, depletion and amortization		(3,822,916	)		(3,506,539	)
Total property and equipment, net		4,137,507			2,643,275
Other long-term assets:
Restricted cash		100,973			—
Assets from price risk management activities		8,655			7,854
Equity method investments		22,436			1,745
Other well equipment inventory		44,645			25,541
Notes receivable, net		15,413			—
Operating lease assets		18,104			5,903
Other assets		17,508			6,479
Total assets	$	4,805,413		$	3,058,626
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	184,177		$	128,174
Accrued liabilities		220,417			219,769
Accrued royalties		51,248			52,215
Current portion of long-term debt		33,156			—
Current portion of asset retirement obligations		57,551			39,888
Liabilities from price risk management activities		8,247			68,370
Accrued interest payable		42,351			36,340
Current portion of operating lease liabilities		3,136			1,943
Other current liabilities		91,599			60,359
Total current liabilities		691,882			607,058
Long-term liabilities:
Long-term debt		1,000,109			585,340
Asset retirement obligations		741,501			501,773
Liabilities from price risk management activities		1,417			7,872
Operating lease liabilities		25,173			14,855
Other long-term liabilities		283,443			176,152
Total liabilities		2,743,525			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 June 30, 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 June 30, 2023 and December 31, 2022, respectively		1,275			826
Additional paid-in capital		2,539,629			1,699,799
Accumulated deficit		(431,512	)		(535,049	)
Treasury stock, at cost; 3,400,000 and zero shares as of June 30, 2023 and December 31, 2022, respectively		(47,504	)		—
Total stockholdersʼ equity		2,061,888			1,165,576
Total liabilities and stockholdersʼ equity	$	4,805,413		$	3,058,626

	June 30, 2018			December 31, 2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	78,860		$	32,191
Restricted cash		1,244			1,242
Accounts receivable
Trade, net		100,824			62,871
Joint interest, net		8,394			13,613
Other		7,091			12,486
Assets from price risk management activities		499			1,563
Prepaid assets		51,698			17,931
Inventory		—			840
Income tax receivable		16,212			—
Other current assets		3,910			2,148
Total current assets		268,732			144,885
Property and equipment:
Proved properties		3,412,875			2,440,811
Unproved properties, not subject to amortization		103,836			72,002
Other property and equipment		28,884			8,857
Total property and equipment		3,545,595			2,521,670
Accumulated depreciation, depletion and amortization		(1,547,656	)		(1,430,890	)
Total property and equipment, net		1,997,939			1,090,780
Other long-term assets:
Assets from price risk management activities		234			345
Other well equipment		9,021			2,577
Other assets		8,143			706
Total assets	$	2,284,069		$	1,239,293
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	38,731		$	72,681
Accrued liabilities		155,902			87,973
Accrued royalties		28,508			24,208
Current portion of long-term debt		434			24,977
Current portion of asset retirement obligations		94,334			39,741
Liabilities from price risk management activities		154,722			49,957
Accrued interest payable		7,454			8,742
Other current liabilities		15,541			15,188
Total current liabilities		495,626			323,467
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		627,968			672,581
Asset retirement obligations		320,044			174,992
Liabilities from price risk management activities		31,766			18,781
Other long-term liabilities		122,820			103,559
Total liabilities		1,598,224			1,293,380
Commitments and contingencies (Note 11)
Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized; no shares issued or outstanding as of June 30, 2018 and December 31, 2017		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 54,155,768 and 31,244,085 shares issued and outstanding as of June 30, 2018 and December 31, 2017, respectively		542			312
Additional paid-in capital		1,323,604			489,870
Accumulated deficit		(638,301	)		(544,269	)
Total stockholders' equity (deficit)		685,845			(54,087	)
Total liabilities and equity	$	2,284,069		$	1,239,293

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Oil revenue	$	180,161		$	78,719		$	307,854		$	162,487
Natural gas revenue		16,448			12,888			29,171			26,062
NGL revenue		7,297			3,436			12,731			7,069
Other		—			383			—			1,632
Total revenue		203,906			95,426			349,756			197,250
Operating expenses:
Direct lease operating expense		34,060			28,871			58,975			56,735
Insurance		4,259			2,688			6,934			5,409
Production taxes		564			380			955			645
Total lease operating expense		38,883			31,939			66,864			62,789
Workover and maintenance expense		17,714			8,225			24,619			17,047
Depreciation, depletion and amortization		67,726			36,157			116,766			76,088
Accretion expense		9,492			5,321			14,252			10,509
General and administrative expense		30,880			7,470			39,460			17,216
Total operating expenses		164,695			89,112			261,961			183,649
Operating income		39,211			6,314			87,795			13,601
Interest expense		(21,678	)		(20,805	)		(41,420	)		(39,577	)
Price risk management activities income (expense)		(91,176	)		38,995			(143,152	)		84,888
Other income (expense)		(1,269	)		103			(1,078	)		157
Total other income (expense)		(114,123	)		18,293			(185,650	)		45,468
Income (loss) before income taxes		(74,912	)		24,607			(97,855	)		59,069
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(74,912	)	$	24,607		$	(97,855	)	$	59,069

Net income (loss) per common share:
Basic	$	(1.69	)	$	0.79		$	(2.59	)	$	1.89
Diluted	$	(1.69	)	$	0.79		$	(2.59	)	$	1.89
Weighted average common shares outstanding:
Basic		44,336			31,244			37,826			31,244
Diluted		44,336			31,244			37,826			31,244

	Common Stock		Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)			Total Stockholders' Equity (Deficit)
Balance at January 1, 2018	$	312	$	489,870	$	(544,269	)	$	(54,087	)
Cumulative effect adjustment (Note 1)		—		—		(325	)		(325	)
Sponsor Debt Exchange		29		101,971		—			102,000
Stone Combination		201		731,763		—			731,964
Equity based compensation		—		—		4,148			4,148
Net loss		—		—		(97,855	)		(97,855	)
Balance at June 30, 2018	$	542	$	1,323,604	$	(638,301	)	$	685,845

Stone Energy common stock - issued and outstanding as of May 9, 2018		20,038
Stone Energy common stock price	$	35.49
Common stock value	$	711,149
Stone Energy common stock warrants - issued and outstanding as of May 9, 2018		3,528
Stone Energy common stock warrants price	$	5.90
Common stock warrants value	$	20,815
Total consideration and fair value	$	731,964


Talos common stock		43,799,890
Talos common stock price per share(1)	$	19.00
Common stock value	$	832,198

Cash consideration	$	207,313
Settlement of preexisting relationship	$	8,388

Total purchase price	$	1,047,899

Current assets⁽¹⁾	$	377,155

Current assets				$	238,293
Property and equipment		876,500			1,455,358
Other long-term assets:
Restricted cash					100,753
Notes receivable, net					14,844
Other long-term assets		18,928			53,457
Current liabilities		(130,121	)
Current liabilities:
Current portion of long-term debt					(33,234	)
Current portion of asset retirement obligations					(7,079	)
Other current liabilities					(123,399	)
Long-term liabilities:
Long-term debt		(235,416	)		(233,836	)
Asset retirement obligations					(251,779	)
Deferred tax liabilities					(150,504	)
Other long-term liabilities		(175,082	)		(14,975	)
Allocated purchase price	$	731,964		$	1,047,899


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
Revenue	$	113,582	$	175,641
Net income	$	25,878	$	19,788


Asset retirement obligations at December 31, 2022	$	541,661
Obligations assumed(1)		258,858
Obligations incurred		220
Obligations settled		(47,683	)
Obligations divested		(19,417	)
Accretion expense		42,174
Changes in estimate		23,239
Asset retirement obligations at June 30, 2023	$	799,052
Less: Current portion at June 30, 2023		57,551
Long-term portion at June 30, 2023	$	741,501


Asset retirement obligations at January 1, 2018	$	214,733
Fair value of asset retirement obligations assumed		220,637
Obligations settled		(43,896	)
Accretion expense		14,252
Obligations incurred		120
Changes in estimate		8,532
Asset retirement obligations at June 30, 2018	$	414,378
Less: Current portion		94,334
Long-term portion	$	320,044

Production Period	Instrument Type	Average Daily Volumes		Weighted Average Swap Price		Weighted Average Put Price		Weighted Average Call Price
Crude Oil – WTI:		(Bbls)		(per Bbl)		(per Bbl)		(per Bbl)
July 2018 - December 2018	Swap		29,615	$	54.06	$	—	$	—
July 2018 - December 2018	Collar		1,000	$	—	$	45.00	$	55.35
July 2018 - December 2018	Put		2,000	$	—	$	49.50	$	—
January 2019 - December 2019	Swap		23,130	$	54.14	$	—	$	—
Natural Gas – Henry Hub NYMEX:		(MMBtu)		(per MMBtu)		(per MMBtu)		(per MMBtu)
July 2018 - December 2018	Swap		23,747	$	3.01	$	—	$	—
July 2018 - December 2018	Collar		6,000	$	—	$	2.75	$	3.24
January 2019 - December 2019	Swap		10,146	$	2.99	$	—	$	—

Description	June 30, 2018			December 31, 2017
11.00% Second-Priority Senior Secured Notes – due April 2022
Principal	$	390,868		$	—
Original issue discount, net of amortization		(8,906	)		—
Deferred financing costs, net of amortization		(1,920	)		—
7.50% Senior Secured Notes – due May 2022
Principal		6,060			—
Bank Credit Facility – due May 2022
Principal		240,000			—
Deferred financing costs, net of amortization		(8,478	)		—
4.20% Building Loan – due November 2030
Principal		10,778			—
11.00% Bridge Loans – due April 2022
Principal		—			172,023
Deferred financing costs, net of amortization		—			(2,185	)
9.75% Senior Notes – due July 2022
Principal		—			102,000
Deferred financing costs, net of amortization		—			(1,319	)
9.75% Senior Notes – due February 2018
Principal		—			24,977
Old Bank Credit Facility – due February 2019		—			403,000
Deferred financing costs, net of amortization		—			(938	)
Total debt	$	628,402		$	697,558
Less: current portion of long-term debt		(434	)		(24,977	)
Long-term debt, net of discount and deferred financing costs	$	627,968		$	672,581

Deferred tax asset	$	213,029
Deferred tax liability		(82,805	)
Net deferred tax asset		130,224
Valuation allowance		(130,224	)
Net deferred tax asset	$	—


	Three Months Ended June 30, 2023 vs 2022									Six Months Ended June 30, 2023 vs 2022
	Price			Volume			Total			Price			Volume			Total
Revenues:
Oil	$	(175,687	)	$	89,341		$	(86,346	)	$	(263,069	)	$	115,531		$	(147,538	)
Natural gas		(36,733	)		(17,344	)		(54,077	)		(52,890	)		(23,985	)		(76,875	)
NGL		(10,469	)		(983	)		(11,452	)		(16,437	)		(2,009	)		(18,446	)
Total revenues	$	(222,889	)	$	71,014		$	(151,875	)	$	(332,396	)	$	89,537		$	(242,859	)


U.S. drilling & completions	$	232,661
Mexico appraisal & exploration		197
Asset management(1)		60,728
Seismic and G&G, land, capitalized G&A and other		36,045
Total Upstream capital expenditures		329,631
Plugging & abandonment		47,683
Decommissioning obligations settled(2)		2,047
Total Upstream		379,361
Investment in CCS		23,057
Total	$	402,418


	Six Months Ended June 30, 2023
Revenues	$	689,792
Costs and expenses		(590,477	)
Net income	$	99,315

Exploration	$	13,462
Development		60,333
Geological and geophysical/seismic		2,928
Land and lease		2,388
Other		9,163
Total	$	88,274


	2023		2024		2025		2026		2027		Thereafter		Total(5)
Long-term financing obligations:
Debt principal	$	15,000	$	30,000	$	30,000	$	806,041	$	200,000	$	—	$	1,081,041
Debt interest		60,564		118,626		115,307		63,405		4,986		—		362,888
Vessel commitments(1)		7,538		—		—		—		—		—		7,538
Derivative liabilities		4,552		5,112		—		—		—		—		9,664
Operating lease obligations		2,937		5,796		5,783		5,891		5,817		12,653		38,877
Finance lease(2)		23,204		19,336		—		—		—		—		42,540
Purchase obligations(3)		28,412		—		—		—		—		—		28,412
Other commitments(4)		327		2,468		2,468		2,141		—		—		7,404
Total contractual obligations(5)	$	142,534	$	181,338	$	153,558	$	877,478	$	210,803	$	12,653	$	1,578,364

	2018		2019		2020		2021		Thereafter		Total
Long-term financing obligations:
Debt principal	$	217	$	217	$	—	$	—	$	647,272	$	647,706
Debt interest		33,759		67,517		67,517		67,517		23,560		259,870
Vessel commitments ⁽¹⁾		22,030		11,765		—		—		—		33,795
Derivative liabilities		92,293		94,195		—		—		—		186,488
Committed purchase orders⁽²⁾		1,460		13,704		—		—		—		15,164
Capital lease ⁽³⁾		22,500		45,000		45,000		45,000		63,750		221,250
Minimum lease payments		2,242		3,944		3,791		3,811		30,492		44,280
Mexico minimum work program		—		34,942		—		—		—		34,942
Total contractual obligations⁽⁴⁾	$	174,501	$	271,284	$	116,308	$	116,328	$	765,074	$	1,443,495


			Oil and Natural Gas Derivatives
			Ten Percent Increase						Ten Percent Decrease
	Fair Value		Fair Value			Change			Fair Value		Change
Price impact(1)	$	44,513	$	(16,779	)	$	(61,292	)	$	108,227	$	63,714

				Oil and Natural Gas Derivatives
				10 Percent Increase						10 Percent Decrease
	Fair Value			Fair Value			Change			Fair Value			Change
Price impact⁽¹⁾	$	(185,755	)	$	(281,258	)	$	(95,503	)	$	(90,224	)	$	95,531


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)
April 1, 2023- April 30, 2023		—	$	—		—	$	73,382
May 1, 2023- May 31, 2023		—	$	—		—	$	73,382
June 1, 2023- June 30, 2023		1,500,000	$	13.89		1,500,000	$	52,547
Total		1,500,000	$	13.89		1,500,000


Exhibit Number	Description

~~2.1~~2.1#		~~Transaction~~ Agreement and Plan of Merger, dated as of ~~November~~September 21, ~~2017,~~2022, by and among ~~Stone~~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 ~~Sailfish Energy Holdings Corporation, Sailfish Merger Sub Corporation,~~(incorporated by reference to Exhibit 2.1 to Talos Energy ~~LLC and Talos Production LLC (Included in the Company’s Current Report on~~Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~September 22, 2022).

3.1		Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. ~~(Included in the Company’s Current Report on~~(incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~February 14, 2023).

3.2		Second Amended &and Restated Bylaws of Talos Energy Inc. ~~(Included in the Company’s Current Report on~~(incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~February 14, 2023).

4.1		~~Stockholders’~~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 ~~May 10, 2018,~~January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

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

4.6	Registration Rights Agreement, dated September 21, 2022, by and among Talos Energy Inc. and ~~each of~~ the ~~other parties set forth~~Persons listed on ~~the signature pages~~Schedule A thereto ~~(Included in the Company’s Current Report on~~(incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~September 22, 2022).

~~4.2~~4.7		~~Registration Rights Agreement,~~Second Supplemental Indenture, dated as of ~~May 10, 2018, by and~~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. ~~and each of the other parties set forth on the signature pages thereto (Included in the Company’s Current Report on~~’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~October 28, 2022).

~~4.3~~4.8		~~Warrant Agreement,~~Indenture, dated as of ~~February 28, 2017,~~April 15, 2021, by and among ~~Stone~~ Energy Ventures GoM LLC, EnVen Finance Corporation, ~~Computershare~~Talos Production Inc. (as successor in interest to EnVen Energy Corporation), the other guarantors party thereto and ~~Computershare~~Wilmington Trust, ~~Company, N.A. (Included in the Company’s Current Report on~~National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~February 14, 2023).

~~4.4~~4.9		Amendment No. 1 to Warrant Agreement, dated as of May 10, 2018, by and among Talos Energy Inc., Stone Energy Corporation, Computershare Inc. and Computershare Trust Company, N.A. (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).

~~4.5~~		Second Supplemental Indenture, dated as of ~~May 10, 2018, by and~~February 13, 2023, among Talos Production ~~LLC, Talos Production Finance,~~ Inc., each of the ~~subsidiary~~other guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent ~~(Included in the Company’s Current Report on~~(incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~February 14, 2023).

~~4.6~~4.10		~~Registration Rights Agreement,~~Third Supplemental Indenture, dated as of ~~May 10, 2018, by and~~February 13, 2023, among Talos Production ~~LLC, Talos Production Finance,~~ Inc., ~~the subsidiary guarantors and~~Energy Ventures GoM LLC, EnVen Finance Corporation, each of the ~~holders set forth on the signature pages~~other guarantors party thereto ~~(Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.1~~		Exchange Agreement, dated as of November 21, 2017, by and among Talos Production LLC, Talos Production Finance Inc., Stone Energy Corporation, Sailfish Energy Holdings Corporation and the lenders and noteholders listed on the schedules thereto (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).

~~10.2~~		Credit Agreement, dated as of May 10, 2018, by and among Talos Production LLC, as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders named therein (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on July 18, 2018, and incorporated herein by reference).

~~10.3~~			~~Intercreditor Agreement, dated as of May 10, 2018, between JPMorgan Chase Bank, N.A., as First Lien Agent,~~ and Wilmington Trust, National Association, as ~~Second Lien Agent (Included in the Company’s Current Report on~~trustee and collateral agent (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~February 14, 2023).

~~10.4~~10.1†			Indemnification Agreement (Sergio L. Maiworm, Jr.) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc. ~~Long Term Incentive Plan (Included in the Company’s Current Report on~~’s Form ~~8-K12B~~8-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~June 15, 2023).

~~10.5~~22.1			~~Indemnification Agreement (Timothy S. Duncan) (Included in the Company’s Current Report on~~List of Subsidiary Guarantors and Issuers of Guaranteed Securities (incorporated by reference to Exhibit 22.1 to Talos Energy Inc.'s Form ~~8-K12B~~10-K (File No. 001-38497) filed with the SEC on ~~May 16, 2018, and incorporated herein by reference)~~March 1, 2023).


~~10.6~~31.1*			~~Indemnification Agreement (Stephen E. Heitzman) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.7~~			~~Indemnification Agreement (John A. Parker) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.8~~			~~Indemnification Agreement (Michael L. Harding II) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.9~~			~~Indemnification Agreement (William S. Moss III) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.10~~			~~Indemnification Agreement (Gregory A. Beard) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.11~~			~~Indemnification Agreement (Christine Hommes) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.12~~			~~Indemnification Agreement (Robert M. Tichio) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.13~~			~~Indemnification Agreement (Olivia C. Wassenaar) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.14~~			~~Indemnification Agreement (Neal P. Goldman) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.15~~			~~Indemnification Agreement (John “Brad” Juneau) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.16~~			~~Indemnification Agreement (James M. Trimble) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.17~~			~~Indemnification Agreement (Charles M. Sledge) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.18~~			~~Indemnification Agreement (Donald R. Kendall, Jr.) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

~~10.19~~			~~Indemnification Agreement (Rajen Mahagaokar) (Included in the Company’s Current Report on Form 8-K12B filed with the SEC on May 16, 2018, and incorporated herein by reference).~~

10.20*			~~Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors).~~

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*

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.INS101.INS			Inline XBRL ~~Instance Document~~Instance.

101.SCH101.SCH			Inline XBRL Taxonomy Extension ~~Schema Document~~Schema.

101.CAL101.CAL			Inline XBRL Taxonomy Extension ~~Calculation Linkbase Document~~Calculation.

101.DEF101.DEF			Inline XBRL Taxonomy Extension ~~Definition Linkbase Document~~Definition.

101.LAB101.LAB			Inline XBRL Taxonomy Extension ~~Label Linkbase Document~~Label.

101.PRE101.PRE			Inline XBRL Taxonomy Extension ~~Presentation Linkbase Document~~