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TALO Talos Energy

Filed: 3 Aug 21, 8:00pm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

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

For the quarterly period ended June 30, 2021

OR

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

For the transition period from             to            

Commission File Number: 001-38497

img122349021_0.jpg

Talos Energy Inc.

(Exact Name of Registrant as Specified in its Charter)

 

Delaware

82-3532642

( State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

333 Clay Street, Suite 3300

Houston, TX

77002

(Address of principal executive offices)

(Zip Code)

 

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

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

 

Title of Each Class

 

Trading Symbol(s)

 

Name of Each Exchange on Which Registered

Common Stock

 

TALO

 

NYSE

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

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

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

 

Large accelerated filer

 

 

Accelerated filer

Non-accelerated filer

 

 

Smaller reporting company

Emerging growth company

 

 

 

 

 

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

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

As of July 27, 2021, the registrant had 81,872,498 shares of common stock, $0.01 par value per share, outstanding.

 

 

 

 


 

TABLE OF CONTENTS

 

 

 

Page

GLOSSARY

1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

3

 

PART I — FINANCIAL INFORMATION

 

Item 1.

Condensed Consolidated Financial Statements

5

 

Condensed Consolidated Balance Sheets

5

 

Condensed Consolidated Statements of Operations

6

 

Condensed Consolidated Statements of Changes in Stockholders' Equity

7

 

Condensed Consolidated Statements of Cash Flows

8

 

Notes to Condensed Consolidated Financial Statements

9

 

Note 1 — Nature of Business and Basis of Presentation

9

 

Note 2 — Acquisitions

9

 

Note 3 — Property, Plant and Equipment

11

 

Note 4 — Leases

11

 

Note 5 — Financial Instruments

12

 

Note 6 — Debt

14

 

Note 7 — Employee Benefits Plans and Share-Based Compensation

16

 

Note 8 — Income Taxes

17

 

Note 9 — Income (Loss) Per Share

18

 

Note 10 — Related Party Transactions

18

 

Note 11 — Commitments and Contingencies

19

 

Note 12 — Subsequent Events

19

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

20

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

32

Item 4.

Controls and Procedures

32

 

PART II — OTHER INFORMATION

 

Item 1.

Legal Proceedings

33

Item 1A.

Risk Factors

33

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

33

Item 3.

Defaults Upon Senior Securities

33

Item 4.

Mine Safety Disclosures

33

Item 5.

Other Information

33

Item 6.

Exhibits

34

 

Signatures

36

 

 

 


Table of Contents

GLOSSARY

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

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

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

BOEM — Bureau of Ocean Energy Management.

BSEE — Bureau of Safety and Environmental Enforcement.

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 — Water depths of more than 600 feet.

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

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

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

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

MBoe — One thousand barrels of oil equivalent.

MBoepd — One thousand barrels of oil equivalent per day.

Mcf — One thousand cubic feet of natural gas.

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

MMBoe — One million barrels of oil equivalent.

MMBtu — One million British thermal units.

MMcf — One million cubic feet of natural gas.

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

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

NYMEX — The New York Mercantile Exchange.

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

OPEC — Organization of Petroleum Exporting Countries.

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

1


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

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

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

Shelf — Water depths of up to 600 feet.

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

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

2


Table of Contents

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q (this "Quarterly Report") includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about:

business strategy;
reserves;
exploration and development drilling prospects, inventories, projects and programs;
our ability to replace the reserves that we produce through drilling and property acquisitions;
financial strategy, liquidity and capital required for our development program and other capital expenditures;
realized oil and natural gas prices;
timing and amount of future production of oil, natural gas and NGLs;
our hedging strategy and results;
future drilling plans;
availability of pipeline connections on economic terms;
competition, government regulations and political developments;
our ability to obtain permits and governmental approvals;
pending legal, governmental or environmental matters;
our marketing of oil, natural gas and NGLs;
leasehold or business acquisitions on desired terms;
costs of developing properties;
general economic conditions;
credit markets;
impact of new accounting pronouncements on earnings in future periods;
estimates of future income taxes;
our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;
the success of the Company's exclusive collaborative agreement with Storegga Geotechnologies Limited;
the Company's ongoing strategy with respect to its Zama assets;
uncertainty regarding our future operating results and our future revenues and expenses; and
plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

3


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We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility due to the continued impact of the coronavirus disease 2019 (“COVID-19”), including any new strains or variants, and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business; the ability or willingness of OPEC and non-OPEC countries, such as Saudi Arabia and Russia, to set and maintain oil production levels; the impact of any such actions; lack of transportation and storage capacity as a result of oversupply, government and regulations; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, and winter storms; inflation; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our business combination are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations, and the other risks discussed in Part I, Item 1A. “Risk Factors” of Talos Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on March 11, 2021 (the “2020 Annual Report”).

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

Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

 

4


Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

 

 

June 30, 2021

 

 

December 31, 2020

 

 

 

(Unaudited)

 

 

 

 

ASSETS

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

65,354

 

 

$

34,233

 

Accounts receivable:

 

 

 

 

 

 

Trade, net

 

 

144,763

 

 

 

106,220

 

Joint interest, net

 

 

33,057

 

 

 

50,471

 

Other

 

 

10,448

 

 

 

18,448

 

Assets from price risk management activities

 

 

39

 

 

 

6,876

 

Prepaid assets

 

 

48,813

 

 

 

29,285

 

Other current assets

 

 

1,742

 

 

 

1,859

 

Total current assets

 

 

304,216

 

 

 

247,392

 

Property and equipment:

 

 

 

 

 

 

Proved properties

 

 

5,112,597

 

 

 

4,945,550

 

Unproved properties, not subject to amortization

 

 

253,988

 

 

 

254,994

 

Other property and equipment

 

 

28,481

 

 

 

32,853

 

Total property and equipment

 

 

5,395,066

 

 

 

5,233,397

 

Accumulated depreciation, depletion and amortization

 

 

(2,897,546

)

 

 

(2,697,228

)

Total property and equipment, net

 

 

2,497,520

 

 

 

2,536,169

 

Other long-term assets:

 

 

 

 

 

 

Assets from price risk management activities

 

 

42

 

 

 

945

 

Other well equipment inventory

 

 

20,282

 

 

 

18,927

 

Operating lease assets

 

 

7,601

 

 

 

6,855

 

Other assets

 

 

22,504

 

 

 

24,258

 

Total assets

 

$

2,852,165

 

 

$

2,834,546

 

LIABILITIES AND STOCKHOLDERSʼ EQUITY

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable

 

$

111,128

 

 

$

104,864

 

Accrued liabilities

 

 

160,602

 

 

 

163,379

 

Accrued royalties

 

 

48,768

 

 

 

27,903

 

Current portion of long-term debt

 

 

6,060

 

 

 

 

Current portion of asset retirement obligations

 

 

47,027

 

 

 

49,921

 

Liabilities from price risk management activities

 

 

230,258

 

 

 

66,010

 

Accrued interest payable

 

 

39,447

 

 

 

9,509

 

Current portion of operating lease liabilities

 

 

2,176

 

 

 

1,793

 

Other current liabilities

 

 

29,278

 

 

 

24,155

 

Total current liabilities

 

 

674,744

 

 

 

447,534

 

Long-term liabilities:

 

 

 

 

 

 

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

 

 

976,573

 

 

 

985,512

 

Asset retirement obligations

 

 

409,357

 

 

 

392,348

 

Liabilities from price risk management activities

 

 

44,144

 

 

 

9,625

 

Operating lease liabilities

 

 

18,380

 

 

 

18,554

 

Other long-term liabilities

 

 

42,546

 

 

 

54,372

 

Total liabilities

 

 

2,165,744

 

 

 

1,907,945

 

Commitments and Contingencies (Note 11)

 

 

 

 

 

 

Stockholdersʼ equity:

 

 

 

 

 

 

Preferred stock, $0.01 par value; 30,000,000 shares authorized and
  
0 shares issued or outstanding as of June 30, 2021 and December 31, 2020

 

 

 

 

 

 

Common stock $0.01 par value; 270,000,000 shares authorized;
  
81,872,498 and 81,279,989 shares issued and outstanding as of
  June 30, 2021 and December 31, 2020, respectively

 

 

819

 

 

 

813

 

Additional paid-in capital

 

 

1,666,887

 

 

 

1,659,800

 

Accumulated deficit

 

 

(981,285

)

 

 

(734,012

)

Total stockholdersʼ equity

 

 

686,421

 

 

 

926,601

 

Total liabilities and stockholdersʼ equity

 

$

2,852,165

 

 

$

2,834,546

 

 

See accompanying notes.

5


Table of Contents

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share amounts)

(Unaudited)

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

Revenues and other:

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

$

267,990

 

 

$

74,471

 

 

$

497,551

 

 

$

241,095

 

Natural gas

 

 

26,131

 

 

 

11,140

 

 

 

54,365

 

 

 

23,038

 

NGL

 

 

9,647

 

 

 

1,964

 

 

 

18,760

 

 

 

6,265

 

Other

 

 

0

 

 

 

1,299

 

 

 

1,000

 

 

 

6,240

 

Total revenues and other

 

 

303,768

 

 

 

88,874

 

 

 

571,676

 

 

 

276,638

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

 

72,013

 

 

 

63,882

 

 

 

138,641

 

 

 

122,123

 

Production taxes

 

 

953

 

 

 

166

 

 

 

1,775

 

 

 

415

 

Depreciation, depletion and amortization

 

 

99,841

 

 

 

88,443

 

 

 

201,498

 

 

 

181,986

 

Write-down of oil and natural gas properties

 

 

0

 

 

 

0

 

 

 

0

 

 

 

57

 

Accretion expense

 

 

15,457

 

 

 

13,794

 

 

 

30,442

 

 

 

26,211

 

General and administrative expense

 

 

19,377

 

 

 

17,192

 

 

 

38,566

 

 

 

44,661

 

Other operating expense

 

 

2,783

 

 

 

0

 

 

 

2,783

 

 

 

0

 

Total operating expenses

 

 

210,424

 

 

 

183,477

 

 

 

413,705

 

 

 

375,453

 

Operating income (expense)

 

 

93,344

 

 

 

(94,603

)

 

 

157,971

 

 

 

(98,815

)

Interest expense

 

 

(33,570

)

 

 

(26,190

)

 

 

(67,646

)

 

 

(52,040

)

Price risk management activities income (expense)

 

 

(186,617

)

 

 

(68,682

)

 

 

(324,125

)

 

 

174,535

 

Other income (expense)

 

 

1,559

 

 

 

(528

)

 

 

(12,391

)

 

 

(674

)

Net income (loss) before income taxes

 

 

(125,284

)

 

 

(190,003

)

 

 

(246,191

)

 

 

23,006

 

Income tax benefit (expense)

 

 

(498

)

 

 

49,392

 

 

 

(1,082

)

 

 

(5,868

)

Net income (loss)

 

$

(125,782

)

 

$

(140,611

)

 

$

(247,273

)

 

$

17,138

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(1.54

)

 

$

(2.14

)

 

$

(3.03

)

 

$

0.28

 

Diluted

 

$

(1.54

)

 

$

(2.14

)

 

$

(3.03

)

 

$

0.28

 

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

81,823

 

 

 

65,807

 

 

 

81,630

 

 

 

62,023

 

Diluted

 

 

81,823

 

 

 

65,807

 

 

 

81,630

 

 

 

62,318

 

 

See accompanying notes.

6


Table of Contents

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

 

Shares

 

 

Par Value

 

 

Additional

 

 

 

 

 

Total

 

 

Common Stock

 

Preferred Stock

 

 

Common Stock

 

 

Preferred Stock

 

 

Paid-In Capital

 

 

Accumulated Deficit

 

 

Stockholders' Equity

 

Balance at March 31, 2020

 

65,342,273

 

 

 

 

$

652

 

 

$

 

 

$

1,504,903

 

 

$

(110,658

)

 

$

1,394,897

 

Equity-based compensation

 

22,509

 

 

 

 

 

1

 

 

 

 

 

 

4,306

 

 

 

 

 

 

4,307

 

Issuance of common stock
  (Note 6)

 

3,050,000

 

 

 

 

 

31

 

 

 

 

 

 

35,929

 

 

 

 

 

 

35,960

 

Net loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(140,611

)

 

 

(140,611

)

Balance at June 30, 2020

 

68,414,782

 

 

 

 

$

684

 

 

$

 

 

$

1,545,138

 

 

$

(251,269

)

 

$

1,294,553

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at March 31, 2021

 

81,707,214

 

 

 

 

$

817

 

 

$

 

 

$

1,661,840

 

 

$

(855,503

)

 

 

807,154

 

Equity-based compensation

 

165,284

 

 

 

 

 

2

 

 

 

 

 

 

5,047

 

 

 

 

 

 

5,049

 

Net loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(125,782

)

 

 

(125,782

)

Balance at June 30, 2021

 

81,872,498

 

 

 

 

$

819

 

 

$

 

 

$

1,666,887

 

 

$

(981,285

)

 

$

686,421

 

 

 

 

Shares

 

 

Par Value

 

 

Additional

 

 

 

 

 

Total

 

 

Common Stock

 

Preferred Stock

 

 

Common Stock

 

 

Preferred Stock

 

 

Paid-In Capital

 

 

Accumulated Deficit

 

 

Stockholders' Equity

 

Balance at December 31, 2019

 

54,197,004

 

 

 

 

$

542

 

 

$

 

 

$

1,346,142

 

 

$

(268,407

)

 

$

1,078,277

 

Equity-based compensation

 

167,778

 

 

 

 

 

1

 

 

 

 

 

 

6,977

 

 

 

 

 

 

6,978

 

Issuance of preferred stock
  (Note 2)

 

 

 

110,000

 

 

 

 

 

 

1

 

 

 

156,199

 

 

 

 

 

 

156,200

 

Conversion of preferred
  stock into common
  stock (Note 2)

 

11,000,000

 

 

(110,000

)

 

 

110

 

 

 

(1

)

 

 

(109

)

 

 

 

 

 

 

Issuance of common stock
  (Note 6)

 

3,050,000

 

 

 

 

 

31

 

 

 

 

 

 

35,929

 

 

 

 

 

 

35,960

 

Net income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

17,138

 

 

 

17,138

 

Balance at June 30, 2020

 

68,414,782

 

 

 

 

$

684

 

 

$

 

 

$

1,545,138

 

 

$

(251,269

)

 

$

1,294,553

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2020

 

81,279,989

 

 

 

 

$

813

 

 

$

 

 

$

1,659,800

 

 

$

(734,012

)

 

$

926,601

 

Equity-based compensation

 

592,509

 

 

 

 

 

6

 

 

 

 

 

 

7,087

 

 

 

 

 

 

7,093

 

Net loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(247,273

)

 

 

(247,273

)

Balance at June 30, 2021

 

81,872,498

 

 

 

 

$

819

 

 

$

 

 

$

1,666,887

 

 

$

(981,285

)

 

$

686,421

 

 

See accompanying notes.

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Table of Contents

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

Cash flows from operating activities:

 

 

 

 

 

 

Net income (loss)

 

$

(247,273

)

 

$

17,138

 

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

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion expense

 

 

231,940

 

 

 

208,197

 

Write-down of oil and natural gas properties and other well inventory

 

 

 

 

 

190

 

Amortization of deferred financing costs and original issue discount

 

 

6,934

 

 

 

3,985

 

Equity-based compensation, net of amounts capitalized

 

 

5,681

 

 

 

3,974

 

Price risk management activities expense (income)

 

 

324,125

 

 

 

(174,535

)

Net cash received (paid) on settled derivative instruments

 

 

(117,618

)

 

 

122,499

 

Loss (gain) on extinguishment of debt

 

 

13,225

 

 

 

(1,470

)

Settlement of asset retirement obligations

 

 

(36,329

)

 

 

(18,496

)

Gain on sale of assets

 

 

(853

)

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

Accounts receivable

 

 

(12,633

)

 

 

(5,164

)

Other current assets

 

 

(19,409

)

 

 

15,128

 

Accounts payable

 

 

3,776

 

 

 

12,645

 

Other current liabilities

 

 

48,597

 

 

 

16,039

 

Other non-current assets and liabilities, net

 

 

(1,069

)

 

 

(8,518

)

Net cash provided by operating activities

 

 

199,094

 

 

 

191,612

 

Cash flows from investing activities:

 

 

 

 

 

 

Exploration, development and other capital expenditures

 

 

(125,846

)

 

 

(154,628

)

Cash paid for acquisitions, net of cash acquired

 

 

(5,399

)

 

 

(296,966

)

Proceeds from sale of property and equipment, net

 

 

4,612

 

 

 

 

Net cash used in investing activities

 

 

(126,633

)

 

 

(451,594

)

Cash flows from financing activities:

 

 

 

 

 

 

Issuance of senior notes

 

 

600,500

 

 

 

 

Redemption of senior notes and other long-term debt

 

 

(356,803

)

 

 

(1,209

)

Proceeds from Bank Credit Facility

 

 

 

 

 

300,000

 

Repayment of Bank Credit Facility

 

 

(240,000

)

 

 

 

Deferred financing costs

 

 

(25,981

)

 

 

(1,287

)

Other deferred payments

 

 

(5,575

)

 

 

(7,575

)

Payments of finance lease

 

 

(10,361

)

 

 

(8,323

)

Employee stock awards tax withholdings

 

 

(3,120

)

 

 

(791

)

Net cash (used in) provided by financing activities

 

 

(41,340

)

 

 

280,815

 

 

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

 

31,121

 

 

 

20,833

 

Cash and cash equivalents:

 

 

 

 

 

 

Balance, beginning of period

 

 

34,233

 

 

 

87,022

 

Balance, end of period

 

$

65,354

 

 

$

107,855

 

 

 

 

 

 

 

 

Supplemental non-cash transactions:

 

 

 

 

 

 

Capital expenditures included in accounts payable and accrued liabilities

 

$

95,724

 

 

$

113,461

 

Debt exchanged for common stock

 

$

0

 

 

$

35,960

 

Supplemental cash flow information:

 

 

 

 

 

 

Interest paid, net of amounts capitalized

 

$

19,006

 

 

$

34,163

 

 

 

See accompanying notes.

8


Table of Contents

TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

Note 1 — Nature of Business and Basis of Presentation

Nature of Business

Talos Energy Inc. (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage opportunities. The Company leverages decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, we are also utilizing our expertise to explore opportunities to reduce industrial emissions through our carbon capture and storage collaborative arrangement along the U.S. Gulf Coast and Gulf of Mexico.

Basis of Presentation and Consolidation

The Condensed Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Accordingly, certain information and disclosures normally included in complete financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, these financial statements include all adjustments, which unless otherwise disclosed, are of a normal recurring nature, necessary for a fair presentation of the financial position, results of operations, cash flows and changes in equity for the periods presented. The results for interim periods are not necessarily indicative of results for the entire year. The unaudited financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s audited Consolidated Financial Statements and accompanying notes included in the 2020 Annual Report.

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

The Company has 1 reportable segment, which is the exploration and production of oil, natural gas and NGLs. Substantially all of the Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States. 

Note 2 — Acquisitions

Business Combination

The following acquisition was accounted for as a business combination whereby the Company recorded the assets acquired and liabilities assumed at their respective fair values as of the acquisition date.

ILX and Castex Acquisition — On February 28, 2020, the Company acquired the outstanding limited liability interests in certain wholly owned subsidiaries of 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 (as defined below) (the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers”) with an effective date of July 1, 2019 (collectively, the “ILX and Castex Acquisition”). The ILX and Castex Acquisition was consummated pursuant to separate Purchase and Sale Agreements, dated December 10, 2019 (as amended from time to time, the “Purchase Agreements”) for aggregate consideration consisting of (i) $385.0 million in cash subject to customary closing adjustments and (ii) an aggregate 110,000 shares (the “Preferred Shares”) of a series of the Company’s preferred stock designated as “Series A Convertible Preferred Stock” which subsequently converted to 11.0 million shares of the Company’s common stock on March 30, 2020 (such common stock, the “Conversion Stock”). The cash payment and escrow deposit were funded with borrowings under the Bank Credit Facility (as defined in Note 5 — Financial Instruments).

9


Table of Contents

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

Talos Conversion Stock

 

 

11,000,000

 

Talos common stock price per share(1)

 

$

14.20

 

Conversion Stock value

 

$

156,200

 

 

 

 

 

Cash consideration

 

$

385,000

 

Customary closing and post-closing adjustments

 

 

(81,878

)

Net cash consideration

 

$

303,122

 

 

 

 

 

Total purchase price

 

$

459,322

 

 

(1)
Represents the closing price of the Company’s common stock on February 28, 2020, the date of the closing of the ILX and Castex Acquisition. The purchase price was based on the value of the Conversion Stock as the value approximates the value of the Preferred Shares as a result of the automatic conversion and dividend rights described in that certain Certificate of Designation, Preferences, Rights and Limitations.

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on February 28, 2020 (in thousands):

Current assets(1)

 

$

11,060

 

Property and equipment

 

 

496,835

 

Other long-term assets

 

 

148

 

Current liabilities

 

 

(16,520

)

Other long-term liabilities

 

 

(32,201

)

Allocated purchase price

 

$

459,322

 

 

(1)
Includes trade and other receivables of $8.2 million.

The Company incurred a total of $12.1 million of transaction related costs, of which NaN and $0.8 million were incurred during the three months ended June 30, 2021 and 2020, respectively, and NaN and $8.3 million were incurred during the six months ended June 30, 2021 and 2020, respectively. These costs are reflected in “General and administrative expense” in the Condensed Consolidated Statements of Operations.

The following table presents revenue and net income attributable to the assets acquired in the ILX and Castex Acquisition:

 

 

Three Months Ended June 30, 2020

 

 

Six Months Ended June 30, 2020

 

Revenue

 

$

26,299

 

 

$

40,191

 

Net loss

 

$

(15,161

)

 

$

(11,952

)

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 six months ended June 30, 2020 as if the ILX and Castex Acquisition had occurred on January 1, 2020. The unaudited pro forma information was derived from historical statements of operations of the Company and the Sellers adjusted to (i) include depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) include interest expense to reflect borrowings under the Bank Credit Facility, (iii) eliminate the write-down of oil and natural gas properties on the assets acquired to reflect the pro-forma ceiling test calculation and (iv) include weighted average basic and diluted shares of common stock outstanding, which was calculated assuming the 11.0 million shares of Conversion Stock were issued to the Sellers. This information does not purport to be indicative of results of operations that would have occurred had the ILX and Castex Acquisition occurred on January 1, 2020, nor is such information indicative of any expected future results of operations.

 

 

Six Months Ended June 30, 2020

 

Revenue

 

$

324,073

 

Net income

 

$

29,996

 

Basic net income per common share

 

$

0.46

 

Diluted net income per common share

 

$

0.46

 

 

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Table of Contents

Note 3 — Property, Plant and Equipment

Proved Properties

During the three and six months ended June 30, 2021 and 2020, the Company’s ceiling test computations did 0t result in a write-down of its U.S. oil and natural gas properties. At June 30, 2021, the Company’s ceiling test computation was based on SEC pricing of $50.23 per Bbl of oil, $2.48 per Mcf of natural gas and $14.92 per Bbl of NGLs.

Asset Retirement Obligations

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

 

 

Asset Retirement Obligations

 

Asset retirement obligations at December 31, 2020

 

$

442,269

 

Obligations acquired

 

 

398

 

Obligations settled

 

 

(36,329

)

Obligations divested

 

 

(340

)

Accretion expense

 

 

30,442

 

Changes in estimate

 

 

19,944

 

Asset retirement obligations at June 30, 2021

 

$

456,384

 

Less: Current portion at June 30, 2021

 

 

(47,027

)

Long-term portion at June 30, 2021

 

$

409,357

 

 

Note 4 — Leases

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

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

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

Finance lease cost - interest on lease liabilities

 

$

3,012

 

 

$

4,040

 

 

$

6,268

 

 

$

8,305

 

Operating lease cost, excluding short-term leases(1)

 

 

720

 

 

 

866

 

 

 

1,436

 

 

 

1,732

 

Short-term lease cost(2)

 

 

12,092

 

 

 

15,748

 

 

 

17,852

 

 

 

19,283

 

Variable lease cost(3)

 

 

322

 

 

 

3

 

 

 

644

 

 

 

6

 

Total lease cost

 

$

16,146

 

 

$

20,657

 

 

$

26,200

 

 

$

29,326

 

 

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

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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, 2021

 

 

December 31, 2020

 

Operating leases:

 

 

 

 

 

 

Operating lease assets

 

$

7,601

 

 

$

6,855

 

 

 

 

 

 

 

 

Current portion of operating lease liabilities

 

$

2,176

 

 

$

1,793

 

Operating lease liabilities

 

 

18,380

 

 

 

18,554

 

Total operating lease liabilities

 

$

20,556

 

 

$

20,347

 

 

 

 

 

 

 

 

Finance leases:

 

 

 

 

 

 

Proved property

 

$

124,299

 

 

$

124,299

 

 

 

 

 

 

 

 

Other current liabilities

 

$

24,279

 

 

$

21,804

 

Other long-term liabilities

 

 

27,386

 

 

 

40,222

 

Total finance lease liabilities

 

$

51,665

 

 

$

62,026

 

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

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

Operating cash outflow from finance leases

 

$

6,268

 

 

$

8,306

 

Operating cash outflow from operating leases

 

$

1,974

 

 

$

911

 

 

 

 

 

 

 

 

Right-of-use assets obtained in exchange for new operating lease
  liabilities

 

$

1,020

 

 

$

0

 

 

Note 5 — Financial Instruments

Debt Instruments

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

 

 

June 30, 2021

 

 

December 31, 2020

 

 

 

Carrying
Amount

 

 

Fair
Value

 

 

Carrying
Amount

 

 

Fair
Value

 

12.00% Second-Priority Senior Secured Notes –
  due
January 2026

 

$

583,777

 

 

$

684,093

 

 

$

 

 

$

 

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

 

$

 

 

$

 

 

$

343,579

 

 

$

355,935

 

7.50% Senior Notes – due May 2022

 

$

6,060

 

 

$

5,069

 

 

$

6,060

 

 

$

5,238

 

Bank Credit Facility – matures November 2024

 

$

392,796

 

 

$

400,000

 

 

$

635,873

 

 

$

640,000

 

As of June 30, 2021 and December 31, 2020, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values because of the short-term nature of these instruments.

The carrying value of the senior notes are presented net of the original issue discount and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

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

12


Table of Contents

Oil and Natural Gas Derivatives

The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Collar contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.

The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the Condensed Consolidated Balance Sheets 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.

The following table presents the impact that derivatives, not qualifying as hedging instruments, had on its Condensed Consolidated Statements of Operations (in thousands): 

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

Net cash received (paid) on settled derivative
  instruments

 

$

(69,237

)

 

$

86,039

 

 

$

(117,618

)

 

$

122,499

 

Unrealized gain (loss)

 

 

(117,380

)

 

 

(154,721

)

 

 

(206,507

)

 

 

52,036

 

Price risk management activities income (expense)

 

$

(186,617

)

 

$

(68,682

)

 

$

(324,125

)

 

$

174,535

 

The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of June 30, 2021:

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 2021 – December 2021

 

Swaps

 

 

22,505

 

 

$

45.45

 

 

$

0

 

 

$

0

 

July 2021 – December 2021

 

Collars

 

 

1,000

 

 

$

0

 

 

$

30.00

 

 

$

40.00

 

January 2022 – December 2022

 

Swaps

 

 

19,101

 

 

$

48.62

 

 

$

0

 

 

$

0

 

January 2023 – June 2023

 

Swaps

 

 

3,000

 

 

$

54.07

 

 

$

0

 

 

$

0

 

Crude Oil – LLS:

 

 

 

(Bbls)

 

 

(per Bbl)

 

 

(per Bbl)

 

 

(per Bbl)

 

July 2021 – December 2021

 

Swaps

 

 

3,500

 

 

$

42.00

 

 

$

0

 

 

$

0

 

Natural Gas – NYMEX Henry Hub:

 

 

 

(MMBtu)

 

 

(per MMBtu)

 

 

(per MMBtu)

 

 

(per MMBtu)

 

July 2021 – December 2021

 

Swaps

 

 

50,815

 

 

$

2.50

 

 

$

0

 

 

$

0

 

July 2021 – December 2021

 

Collars

 

 

5,000

 

 

$

0

 

 

$

2.50

 

 

$

3.10

 

January 2022 – December 2022

 

Swaps

 

 

40,162

 

 

$

2.69

 

 

$

0

 

 

$

0

 

January 2023 – June 2023

 

Swaps

 

 

5,000

 

 

$

2.61

 

 

$

0

 

 

$

0

 

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

 

 

June 30, 2021

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas swaps and costless collars

 

$

0

 

 

$

81

 

 

$

0

 

 

$

81

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas swaps and costless collars

 

 

0

 

 

 

(274,402

)

 

 

0

 

 

 

(274,402

)

Total net liability

 

$

0

 

 

$

(274,321

)

 

$

0

 

 

$

(274,321

)

 

13


Table of Contents

 

 

 

December 31, 2020

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas swaps and costless collars

 

$

0

 

 

$

7,821

 

 

$

0

 

 

$

7,821

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas swaps and costless collars

 

 

0

 

 

 

(75,635

)

 

 

0

 

 

 

(75,635

)

Total net liability

 

$

0

 

 

$

(67,814

)

 

$

0

 

 

$

(67,814

)

Financial Statement Presentation

Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its Condensed Consolidated Balance Sheets. On derivative contracts recorded as assets in the table below, the Company is exposed to the risk the counterparties may not perform. The following table presents the fair value of derivative financial instruments (in thousands): 

 

 

June 30, 2021

 

 

December 31, 2020

 

 

 

Assets

 

 

Liabilities

 

 

Assets

 

 

Liabilities

 

Oil and natural gas derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

39

 

 

$

230,258

 

 

$

6,876

 

 

$

66,010

 

Non-current

 

 

42

 

 

 

44,144

 

 

 

945

 

 

 

9,625

 

Total

 

$

81

 

 

$

274,402

 

 

$

7,821

 

 

$

75,635

 

Credit Risk

The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company has entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at June 30, 2021 represent derivative instruments from 8 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 7 of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities.

Note 6 — Debt

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

 

 

June 30, 2021

 

 

December 31, 2020

 

12.00% Second-Priority Senior Secured Notes – due January 2026

 

$

650,000

 

 

$

 

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

 

 

 

 

 

347,254

 

7.50% Senior Notes – due May 2022

 

 

6,060

 

 

 

6,060

 

Bank Credit Facility – matures November 2024

 

 

400,000

 

 

 

640,000

 

Total debt, before discount and deferred financing cost

 

 

1,056,060

 

 

 

993,314

 

Discount and deferred financing cost

 

 

(73,427

)

 

 

(7,802

)

Total debt, net of discount and deferred financing costs

 

 

982,633

 

 

 

985,512

 

Less: current portion of long-term debt

 

 

(6,060

)

 

 

 

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

 

$

976,573

 

 

$

985,512

 

 

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12.00% Second-Priority Senior Notes

The 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the "Parent Guarantor"), Talos Production Inc. (the "Issuer"), and certain of the Issuer's subsidiaries (the "Subsidiary Guarantors" and, together with the Parent Guarantor, the "Guarantors") 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 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 Subsidiary Guarantors and will be unconditionally guaranteed on the same basis by certain of the Issuer’s future subsidiaries. The 12.00% Notes are secured on a second-priority 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 January 15, 2026 and have interest payable semi-annually each January 15 and July 15, commencing on July 15, 2021. At any time prior to January 15, 2023, the Company may redeem up to 40% of the principal amount of the 12.00% Notes at a redemption rate of 112.00% of the principal amount plus accrued and unpaid interest. Thereafter, the Company may redeem all or a portion of the 12.00% Notes at redemption prices decreasing annually on January 15 from 106.00% to 100.00% plus accrued and unpaid interest.

The indenture governing the 12.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from Talos Production Inc.’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of Talos Production Inc.’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. The 12.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at June 30, 2021.

11.00% Second-Priority Senior Secured Notes

On January 13, 2021, the Company redeemed $347.3 million aggregate principal amount of the 11.00% Second-Priority Senior Secured Notes due 2022 (the “11.00% Notes”) at 102.75% plus accrued and unpaid interest using the proceeds from the issuance of the 12.00% Notes. The debt redemption resulted in a loss on extinguishment of debt of NaN and $13.2 million for the three and six months ended June 30, 2021, respectively, which is presented as “Other income (expense)” on the Condensed Consolidated Statements of Operations.

On June 15, 2020, the Company entered into an exchange agreement pursuant to which the Company agreed to exchange $37.2 million aggregate principal amount of the 11.00% Notes from certain holders in exchange for 3.1 million shares of the Company’s common stock plus cash in an amount equal to accrued interest up to the June 18, 2020 settlement date. Additionally, during the three months ended June 30, 2020, the Company repurchased $2.0 million of the 11.00% Notes in two separate open market repurchases. The exchange agreement and debt repurchases resulted in a gain on extinguishment of $1.5 million for the three and six months ended June 30, 2020, respectively, and is presented as “Other income (expense)” on the Condensed Consolidated Statements of Operations.

Bank Credit Facility

The Company maintains a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. On June 22, 2021, the Company entered into a Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement (the “Sixth Amendment”). The Sixth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from May 10, 2022 to November 12, 2024, (ii) decreased the borrowing base from $960.0 million to $950.0 million and (iii) decreased the commitments to $655.0 million. The next scheduled redetermination meeting is expected to occur in November 2021.

The Bank Credit Facility sets the interest rate at either (at the Company’s option) an alternative base rate plus a specified percentage, or London Interbank Offered Rate (“LIBOR”) plus a specified percentage. The specified percentage is referred to as the applicable margin, which varies based on the borrowing base utilization percentage.

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As of June 30, 2021, the Company's borrowing base was $950.0 million with total commitments of $655.0 million. Additionally, no more than $200.0 million of the Company’s borrowing base can be used as letters of credit with current commitments at $150.0 million. The amount the Company is 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. The Company was in compliance with all debt covenants at June 30, 2021. As of June 30, 2021, the Company had $400.0 million in outstanding borrowings at a weighted average interest rate of 3.55% and $13.6 million in letters of credit issued under the Bank Credit Facility.

Subsequent Event — During July 2021, the Company announced the addition of a new lender to its Bank Credit Facility adding an additional $75.0 million of commitments. The addition increases total commitments from $655.0 million to $730.0 million.

Note 7 — Employee Benefits Plans and Share-Based Compensation

Long Term Incentive Plans

On May 11, 2021, the Company’s stockholders approved the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”), which had previously been approved by the board of directors of the Company. No further awards will be granted under the Talos Energy Inc. Long Term Incentive Plan (the “2018 LTIP”).

The 2021 LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs (together with ISOs, “Options”), (iii) stock appreciation rights, (iv) restricted stock awards, (v) restricted stock units (the “RSUs”), (vi) awards of vested stock, (vii) dividend equivalents, (viii) other stock-based or cash awards and (ix) substitute awards (collectively, the “Awards”). Employees, non-employee directors and consultants of the Company and its affiliates are eligible to receive awards under the 2021 LTIP. The 2021 LTIP authorizes the Company to grant awards of up to 8,639,415 shares of the Company’s common stock, subject to the share counting and share recycling provisions of the 2021 LTIP.

Restricted Stock Units — The following table summarizes RSU activity for the six months ended June 30, 2021:

 

 

RSUs

 

 

Weighted Average
Grant Date Fair
Value

 

Unvested RSUs at December 31, 2020

 

 

1,652,988

 

 

$

13.73

 

Granted

 

 

1,067,141

 

 

$

13.11

 

Vested

 

 

(657,590

)

 

$

14.92

 

Forfeited

 

 

(61,055

)

 

$

12.63

 

Unvested RSUs at June 30, 2021(1)

 

 

2,001,484

 

 

$

13.04

 

 

(1)
As of June 30, 2021, 44,372 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Condensed Consolidated Balance Sheet.

The Company considers its intent and ability to settle awards in cash or shares in determining whether to classify the awards as equity or as a liability. Certain awards granted during the six months ended June 30, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The aggregate amount of compensation cost related to these awards is determined by the fair value of the award on the modification date.

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

 

 

PSUs

 

 

Weighted Average
Grant Date Fair
Value

 

Unvested PSUs at December 31, 2020

 

 

834,172

 

 

$

25.46

 

Granted

 

 

586,984

 

 

$

18.96

 

Vested

 

 

(197,585

)

 

$

44.61

 

Forfeited

 

 

(14,400

)

 

$

18.47

 

Unvested PSUs at June 30, 2021

 

 

1,209,171

 

 

$

19.26

 

 

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Certain awards granted during the six months ended June 30, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the PSUs granted and modified at the date indicated:

 

 

Modification Date

 

 

Grant Date

 

 

 

May 11, 2021

 

 

March 8, 2021

 

Expected term (in years)

 

 

2.6

 

 

 

2.8

 

Expected volatility

 

 

80.9

%

 

 

78.3

%

Risk-free interest rate

 

 

0.3

%

 

 

0.3

%

Dividend yield

 

 

0

%

 

 

0

%

Fair Value (in thousands)

 

$

9,715

 

 

$

11,129

 

Share-based Compensation Expense, net

Share-based compensation expense associated with RSUs, PSUs and other awards are reflected as “General and administrative expense,” in the Condensed Consolidated Statements of Operations, net amounts capitalized to “Proved Properties,” in 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” in the Condensed Consolidated Statements of Cash Flows.

The Company recognized the following share-based compensation expense, net (in thousands):

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

Share-based compensation costs

 

$

5,626

 

 

$

4,455

 

 

$

10,541

 

 

$

7,667

 

Less: amounts capitalized to oil and gas properties

 

 

(2,609

)

 

 

(2,108

)

 

 

(4,860

)

 

 

(3,693

)

Total share-based compensation expense, net

 

$

3,017

 

 

$

2,347

 

 

$

5,681

 

 

$

3,974

 

 

Note 8 — Income Taxes

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

For the three months ended June 30, 2021, the Company recognized an income tax expense of $0.5 million for an effective tax rate of negative 0.4%. The Company’s effective tax rate of negative 0.4% is lower than the U.S. federal statutory income tax rate of 21% primarily due to recording a valuation allowance for its deferred tax assets. For the three months ended June 30, 2020, the Company recognized income tax benefit of $49.4 million for an effective tax rate of 26.0%. The Company’s effective tax rate of 26.0% is higher than the U.S. federal statutory income tax rate of 21% primarily due to the state income taxes and other permanent differences.

For the six months ended June 30, 2021, the Company recognized income tax expense of $1.1 million for an effective tax rate of negative 0.4%. The Company’s effective tax rate of negative 0.4% is lower than the U.S. federal statutory income tax rate of 21% primarily due to recording a valuation allowance for its deferred tax assets. For the six months ended June 30, 2020, the Company recognized an income tax expense of $5.9 million for an effective tax rate of 25.5%. The difference between the Company’s effective tax rate of 25.5% and federal statutory income tax rate of 21% primarily due to the state income taxes, and other permanent differences, primarily related to non-deductible executive compensation and the impact of equity-based compensation shortfalls.

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

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Deferred income tax assets and liabilities are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce deductions and income in the future. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowance, the Company considers cumulative losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax optimization planning and future taxable income for each of its taxable jurisdictions. The Company assesses the realizability of its deferred tax assets quarterly; changes to the Company’s assessment of its valuation allowance in future periods could materially impact its results of operations. As of June 30, 2021, the Company maintains a full valuation allowance for U.S. federal, state and foreign net deferred tax assets.

Note 9 — Income (Loss) Per Share

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

The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts):

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

Net income (loss)

 

$

(125,782

)

 

$

(140,611

)

 

$

(247,273

)

 

$

17,138

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares
  outstanding — basic

 

 

81,823

 

 

 

65,807

 

 

 

81,630

 

 

 

62,023

 

Dilutive effect of securities

 

 

0

 

 

 

0

 

 

 

0

 

 

 

295

 

Weighted average common shares
  outstanding — diluted

 

 

81,823

 

 

 

65,807

 

 

 

81,630

 

 

 

62,318

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(1.54

)

 

$

(2.14

)

 

$

(3.03

)

 

$

0.28

 

Diluted

 

$

(1.54

)

 

$

(2.14

)

 

$

(3.03

)

 

$

0.28

 

Anti-dilutive potentially issuable securities
  excluded from diluted common shares

 

 

869

 

 

 

5,106

 

 

 

2,252

 

 

 

4,732

 

 

Note 10 — Related Party Transactions

On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds” and, together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment. The Sponsors hold greater than 10% of the Company’s voting power.

ILX and Castex Acquisition

On February 28, 2020 the Company acquired assets and liabilities at fair value from sellers that include, the Riverstone Sellers, affiliates of the Riverstone Funds. See additional details in Note 2 — Acquisitions.

Whistler Acquisition

On August 31, 2018, the Company acquired certain properties from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds. Included in current assets at June 30, 2021 is $1.1 million in receivables from an affiliate of the Apollo Funds to reimburse the Company for certain payments made post-closing.

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Table of Contents

Equity Registration Rights Agreement

The Sponsors and Riverstone Sellers 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 Notes to the Consolidated Financial Statements in the 2020 Annual Report.

The Company will bear all of the expenses incurred in connection with the 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, 2021, fees incurred by the Company were $0.3 million and $0.4 million, respectively. For the three and six months ended June 30, 2020, the Company incurred NaN and $0.2 million, respectively.

Stockholders’ Agreement Amendment

On May 10, 2018, the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020, the Company and the other parties thereto amended the Stockholders’ Agreement (the “Stockholders’ Agreement Amendment”). A discussion of the Stockholders’ Agreement Amendment is included in the Notes to Consolidated Financial Statements in the 2020 Annual Report.

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. 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 Vinson & Elkins L.L.P. For the three and six months ended June 30, 2021, the Company incurred fees of approximately $0.8 million and $1.7 million, respectively, of which $0.9 million were payable for legal services performed by Vinson & Elkins L.L.P. as of June 30, 2021. For the three and six months ended June 30, 2020, the Company incurred fees of approximately $1.8 million and $3.4 million, respectively, of which $3.2 million were payable for legal services performed by Vinson & Elkins L.L.P. as of June 30, 2020.

Note 11 — Commitments and Contingencies

Performance Obligations

Regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities and to guarantee the execution of the minimum work program under the Mexico production sharing contracts. As of June 30, 2021, the Company had secured performance bonds totaling approximately $673.9 million. The cost of securing these bonds are reflected as “Interest expense" in the Condensed Consolidated Statements of Operations. As of June 30, 2021, the Company had $13.6 million in letters of credit issued under its Bank Credit Facility.

Legal Proceedings and Other Contingencies

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.

Decommissioning Obligations

The Company has divested various leases, wells and facilities located in the U.S. Gulf of Mexico where the purchasers typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Under certain circumstances, regulations or federal laws could require the Company to assume such obligations.

Note 12 — Subsequent Events

Debt

For additional information, see Note 6 — Debt.

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

The following management’s discussion and analysis should be read in conjunction with our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Condensed Consolidated Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2020 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 2020 Annual Report.

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

Our Business

We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage 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 are also utilizing our expertise to explore opportunities to reduce industrial emissions through our carbon capture and storage collaborative arrangement along the U.S. Gulf Coast and 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 joint venture opportunities, among others.

In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organically from our existing acreage, an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible.

Outlook

COVID-19 and Global Economic Environment — The ongoing COVID-19 pandemic that emerged at the beginning of 2020 has resulted in the reimplementation of travel and social distancing restrictions as well as border and office closures in the various countries in which we operate, and continues to impact some of our business operations. Beginning June 1, 2021, based on the high vaccination rate of our employees, our entire corporate workforce returned to the office and our offshore employees returned to normal offshore rotations; however, we continue to actively monitor the ongoing situation with respect to any future containment measures which may result from the emergence of new strains or variants of COVID-19 and promote the safety and wellbeing of our employees. Working remotely did not significantly impact our ability to maintain operations, or caused us to incur significant additional expenses; however, we continue to evaluate the effect of COVID-19 on our business by, amongst other things, developing a flexible capital spending budget for fiscal year 2021.

As part of the government response to the COVID-19 outbreak, President Biden signed into law the American Rescue Plan Act of 2021 on March 11, 2021, a $1.9 trillion stimulus package and there is continued uncertainty as to how COVID-19 will impact the global economy.

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FERC Regulatory Matters — The Federal Energy Regulatory Commission (“FERC”) issued its Five-Year Review of the Oil Pipeline Index establishing an index level of 0.78% (PPI-FG+0.78%) on December 17, 2020 for the five-year period commencing July 1, 2021. A number of parties requested rehearing of FERC’s order and these requests remain pending as a result of FERC’s February 18, 2021 order granting rehearing for further consideration. FERC issued a notice on May 14, 2021, providing the final change in the PPI-FG that determines the oil pricing index factor to be applied for the index year starting July 1, 2021. The oil pricing index factor, calculated as the percent change in the annual average PPG-FG plus an index level of 0.78%, resulted in a negative percent change for the index year July 1, 2021 through June 30, 2022. A negative percent changes means that the ceiling level for certain oil pipelines’ rates may decrease and, if the actual transportation rate would be above such ceiling level, the rate also must decrease to be equal to or less than the applicable ceiling. Accordingly, on June 15, 2021, SP 49 Pipeline filed to reduce certain of its rates, effective July 1, 2021. FERC’s final application of its indexing rate methodology for the next five-year term of index rates may impact our revenues associated with any transportation services we may provide pursuant to rates adjusted by the FERC oil pipeline index.

Outer Continental Shelf Regulation With regard to President Biden’s issuance of an executive order in January 2021 mandating the suspension of new leasing activities for oil and gas exploration and production on federal lands and offshore waters pending review and reconsideration of federal oil and gas permitting and leasing practices, in June 2021, a federal judge issued a nationwide temporary injunction in a lawsuit filed in federal district court in Louisiana that effectively halts the Biden Administration’s suspension on new leasing. While the temporary injunction effectively allows for new leasing of oil and gas interests on federal lands and waters to resume, it remains to be seen if the federal judge's temporary injunction decision is appealed or when subsequent lease sales will occur.

Recent Developments

Zama Update — On July 2, 2021, we were notified by Mexico’s Ministry of Energy that it had designated Petróleos Mexicanos ("Pemex") as the operator of the Zama unit. The Block 7 partners and Pemex had recently engaged a third-party reservoir engineering firm to evaluate initial tract participation within the Zama reservoir, which concluded that the Block 7 consortium led by us holds 49.6% of the gross interest in Zama and Pemex holds 50.4%. Although we are currently evaluating the scope and extent of potential impacts of this designation, we caution that such designation may potentially result in material delays, underperformance, insufficient access to capital or adverse consequences as compared to our expectations for such project should we have been designated as operator. However, we remain committed to maximizing value for our shareholders and will explore legal and strategic options to do so.

Bank Credit Facility — On June 22, 2021, we entered into the Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement, which amended the Credit Agreement, dated as of May 10, 2018 (as amended from time to time, the “Credit Agreement”), among Talos Energy, as holdings, Talos Production Inc., as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender, the lenders party thereto, and the other persons from time to time party thereto, which such Credit Agreement governs our Bank Credit Facility (as defined below). See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt for more information.

Formation of Storegga Venture — On June 8, 2021, we announced that we have formed an exclusive collaborative arrangement with Storegga Geotechnologies Limited (“Storegga” and, together with Talos, the “Partners”) to source, evaluate and develop carbon capture and storage (“CCS”) project opportunities on the U.S. Gulf Coast and Gulf of Mexico, including state and federal waters offshore Texas, Louisiana, Mississippi and Alabama. Under the collaborative arrangement framework, the Partners will originate and mature CCS ventures with emitters, infrastructure providers, service companies and financing partners, among others. The Partners are actively exploring opportunities with counterparties along the CCS value chain. Pursuant to the terms of the agreement, as individual CCS projects are matured in the future, each will be ring-fenced with separate operating agreements, financing structures and the possibility of additional working interest partners. The agreement requires zero up front capital commitments. We are designated as the operating partner of the arrangement.

Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”) — On May 11, 2021, our stockholders approved the 2021 LTIP, which had previously been approved by the board of directors of the Company. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 7 — Employee Benefits Plans and Share-Based Compensation for more information.

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Table of Contents

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

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

LLOG Properties Acquisition — On November 16, 2020, we completed the acquisition of select interests in oil and natural gas assets from LLOG Exploration & Production Company, LLC (the “LLOG Acquisition”). A discussion of the LLOG Acquisition is included the Notes to Consolidated Financial Statements in the 2020 Annual Report.

Castex Energy 2005 Acquisition — On August 5, 2020, we completed the acquisition of select oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC (the “Castex 2005 Acquisition”). A discussion of the Castex 2005 Acquisition is included the Notes to Consolidated Financial Statements in the 2020 Annual Report.

ILX and Castex Acquisition — On February 28, 2020 we acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate with the entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers” and collectively, the “ILX and Castex Acquisition”). See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions for more information.

Known Trends and Uncertainties

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2020 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 2020 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.

In 2020, OPEC and certain non-OPEC producers (“OPEC Plus”) agreed to production cuts intended to stabilize and support commodity prices, which resulted in cutting production by a record 9.7 million barrels per day starting on May 1, 2020 but was subsequently scaled back to 7.7 million barrels per day from August 1, 2020 through December 2020. On December 3, 2020, OPEC Plus agreed to increase production by 500,000 barrels per day beginning in January 2021 bringing the total production cuts to 7.2 million barrels per day. In January 2021, Saudi Arabia pledged 1.0 million barrels per day of voluntary cuts during February and March 2021. On March 4, 2021, OPEC Plus agreed to increase production by 150,000 barrels per day beginning in April 2021 and Saudi Arabia extended its one million barrels per day voluntary production cut into April 2021. At the April 1, 2021 meeting, OPEC Plus agreed to ease production cuts by 1.2 million barrels per day over a three month period starting May 1, 2021 through July 31, 2021, reducing the total production cuts to 5.8 million barrels per day. Moreover, Saudi Arabia decided to roll back its 1.0 million barrels per day of voluntary cuts over this same period. On July 18, 2021, OPEC Plus reached an agreement that will allow its members to collectively increase production by 400,000 barrels per day each month beginning August 2021 until phasing out the 5.8 million barrels per day and will reassess market developments in December 2021.

Oil prices have benefited from the continuation of coordinated production cuts by the OPEC Plus and capital discipline by oil and gas producers. Despite the recent upswing in oil prices, we believe that commodity prices will remain cyclical and volatile. We developed a flexible fiscal year 2021 capital spending budget that is within projected operating cash flows and does not require any long-term commitments. During January 1, 2021 through June 30, 2021, the daily spot prices for NYMEX WTI crude oil ranged from a high of $74.21 per Bbl to a low of $47.47 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu. The spread between the high and low natural gas prices was caused by a severe winter storm that precipitated both an immediate constraint in the supply of and a significant increase in the demand for natural gas. 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. From time to time, we may hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Financial Instruments” for more additional information regarding our commodity derivative positions as of June 30, 2021.

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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 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. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three and six months ended June 30, 2021 and 2020, we did not recognize an impairment based on the ceiling test computations. At June 30, 2021 our ceiling test computation was based on SEC pricing of $50.23 per Bbl of oil, $2.48 per Mcf of natural gas and $14.92 per Bbl of NGLs.

There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 2020 Annual Report. Any decrease in pricing, negative change in price differentials or increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties.

Third Party Planned Downtime — Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the 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 United States Coast Guard, during which time we are unable to produce the Phoenix Field. The next dry-dock is scheduled for the first half of 2022 with an estimated shut-in lasting approximately 60 days.

BOEM Bonding Requirements — In 2016, the BOEM issued the 2016 Notice to Lessees and Operators (“NTL”), which bolstered supplemental bonding requirements. The NTL was not fully implemented as the BOEM under the Trump Administration first paused, and then in 2020 rescinded, this NTL. The BOEM and BSEE issued a jointly proposed rulemaking in October 2020 in which the BOEM proposed amendments to its financial assurance program. The proposed rule was significantly less stringent with respect to financial assurance than 2016 NTL. To date, however, a final rule has not issued.

The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us, whether as current or predecessor lessee or grant holder, as a result of the implementation of a new NTL analogous to the 2016 NTL, or the October 2020 proposed rule, to the extent finalized, as well as to the provisions of any other new, more stringent NTLs or final rules on supplemental bonding published by the BOEM under the Biden Administration, could materially and adversely affect our financial condition, cash flows and results of operations. Moreover, the BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements.

Deepwater Operations — We have interests in deepwater fields in the U.S. Gulf of Mexico. Operations in the deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

Oil Spill Response Plan — We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil spill response plans are generally approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.

Hurricanes — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production and 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 and possible acceleration of plugging and abandonment costs.

How We Evaluate Our Operations

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

production volumes;

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realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;
lease operating expenses;
capital expenditures; and
Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.

Results of Operations

Revenue

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

 

 

Three Months Ended June 30,

 

 

 

 

 

Six Months Ended June 30,

 

 

 

 

 

 

2021

 

 

2020

 

 

Change

 

 

2021

 

 

2020

 

 

Change

 

Revenues and Other:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

$

267,990

 

 

$

74,471

 

 

$

193,519

 

 

$

497,551

 

 

$

241,095

 

 

$

256,456

 

Natural gas

 

 

26,131

 

 

 

11,140

 

 

 

14,991

 

 

 

54,365

 

 

 

23,038

 

 

 

31,327

 

NGL

 

 

9,647

 

 

 

1,964

 

 

 

7,683

 

 

 

18,760

 

 

 

6,265

 

 

 

12,495

 

Other

 

 

 

 

 

1,299

 

 

 

(1,299

)

 

 

1,000

 

 

 

6,240

 

 

 

(5,240

)

Total revenues and other

 

$

303,768

 

 

$

88,874

 

 

$

214,894

 

 

$

571,676

 

 

$

276,638

 

 

$

295,038

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Production Volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

4,169

 

 

 

3,279

 

 

 

890

 

 

 

8,218

 

 

 

7,005

 

 

 

1,213

 

Natural gas (MMcf)

 

 

8,572

 

 

 

6,997

 

 

 

1,575

 

 

 

17,080

 

 

 

14,039

 

 

 

3,041

 

NGL (MBbls)

 

 

433

 

 

 

330

 

 

 

103

 

 

 

915

 

 

 

717

 

 

 

198

 

Total production volume (MBoe)

 

 

6,031

 

 

 

4,775

 

 

 

1,256

 

 

 

11,980

 

 

 

10,062

 

 

 

1,918

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Daily Production Volumes by
  Product:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBblpd)

 

 

45.8

 

 

 

36.0

 

 

 

9.8

 

 

 

45.4

 

 

 

38.5

 

 

 

6.9

 

Natural gas (MMcfpd)

 

 

94.2

 

 

 

76.9

 

 

 

17.3

 

 

 

94.4

 

 

 

77.1

 

 

 

17.3

 

NGL (MBblpd)

 

 

4.8

 

 

 

3.6

 

 

 

1.2

 

 

 

5.1

 

 

 

3.9

 

 

 

1.2

 

Total production volume (MBoepd)

 

 

66.3

 

 

 

52.4

 

 

 

13.9

 

 

 

66.2

 

 

 

55.2

 

 

 

11.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Sale Price Per Unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

64.28

 

 

$

22.71

 

 

$

41.57

 

 

$

60.54

 

 

$

34.42

 

 

$

26.12

 

Natural gas (per Mcf)

 

$

3.05

 

 

$

1.59

 

 

$

1.46

 

 

$

3.18

 

 

$

1.64

 

 

$

1.54

 

NGL (per Bbl)

 

$

22.28

 

 

$

5.95

 

 

$

16.33

 

 

$

20.50

 

 

$

8.74

 

 

$

11.76

 

Price per Boe

 

$

50.37

 

 

$

18.34

 

 

$

32.03

 

 

$

47.64

 

 

$

26.87

 

 

$

20.77

 

Price per Boe (including realized
  commodity derivatives)

 

$

38.89

 

 

$

36.36

 

 

$

2.53

 

 

$

37.82

 

 

$

39.05

 

 

$

(1.23

)

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

 

 

Three Months Ended
June 30, 2021 vs 2020

 

 

Six Months Ended
June 30, 2021 vs 2020

 

 

 

Price

 

 

Volume

 

 

Total

 

 

Price

 

 

Volume

 

 

Total

 

Oil

 

$

173,307

 

 

$

20,212

 

 

$

193,519

 

 

$

214,705

 

 

$

41,751

 

 

$

256,456

 

Natural gas

 

 

12,487

 

 

 

2,504

 

 

 

14,991

 

 

 

26,340

 

 

 

4,987

 

 

 

31,327

 

NGL

 

 

7,070

 

 

 

613

 

 

 

7,683

 

 

 

10,764

 

 

 

1,731

 

 

 

12,495

 

Total revenues and other

 

$

192,864

 

 

$

23,329

 

 

$

216,193

 

 

$

251,809

 

 

$

48,469

 

 

$

300,278

 

 

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Three Months Ended June 30, 2021 and 2020 Volumetric Analysis — Production volumes increased by 13.9 MBoepd to 66.3 MBoepd. The increase in production volumes was attributable to an increase of 6.3 MBoepd in production from the oil and natural gas assets acquired primarily in the Castex 2005 Acquisition. Additionally, production volumes increased 7.1 MBoepd from the Green Canyon 18 Field, primarily attributable to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 Field platform rig program.

Six Months Ended June 30, 2021 and 2020 Volumetric Analysis — Production volumes increased by 11.0 MBoepd to 66.2 MBoepd. The increase in production volumes was attributable to an increase of 9.3 MBoepd in production from the oil and natural gas assets acquired primarily in the ILX and Castex Acquisition and Castex 2005 Acquisition. Additionally, production volumes increased 5.5 MBoepd from the Green Canyon 18 Field, primarily attributable to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 Field platform rig program. The increase was partially offset by a 3.5 MBoepd reduction in production volumes from the Phoenix Field primarily as a result of well performance and natural declines.

Expenses

Lease Operating Expense

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

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

Lease operating expenses

 

$

72,013

 

 

$

63,882

 

 

$

138,641

 

 

$

122,123

 

Lease operating expenses per Boe

 

$

11.94

 

 

$

13.38

 

 

$

11.57

 

 

$

12.14

 

Three Months Ended June 30, 2021 and 2020 — Total lease operating expense for the three months ended June 30, 2021 increased by approximately $8.1 million, or 13%. This increase was primarily related to an increase in lease operating expenses of $5.9 million incurred in connection with assets acquired in the ILX and Castex Acquisition, Castex 2005 Acquisition and LLOG Acquisition when compared to the same period in 2020. Additionally, an increase in non-recurring and workover expenses of $5.5 million primarily related to South Marsh Island 130 Field and Ram Powell Field. On a per unit basis, lease operating expense decreased $1.44 per Boe to $11.94 per Boe primarily as a result of higher production.

Six Months Ended June 30, 2021 and 2020 — Total lease operating expense for the six months ended June 30, 2021 increased by approximately $16.5 million, or 14%. This increase was primarily related to an increase in lease operating expenses of $18.5 million incurred in connection with assets acquired in the ILX and Castex Acquisition, Castex 2005 Acquisition and LLOG Acquisition when compared to the same period in 2020. On a per unit basis, lease operating expense decreased $0.57 per Boe to $11.57 per Boe primarily as a result of higher production.

Depreciation, Depletion and Amortization

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

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

Depreciation, depletion and amortization

 

$

99,841

 

 

$

88,443

 

 

$

201,498

 

 

$

181,986

 

Depreciation, depletion and amortization per Boe

 

$

16.55

 

 

$

18.52

 

 

$

16.82

 

 

$

18.09

 

Three Months Ended June 30, 2021 and 2020 — Depreciation, depletion and amortization expense for the three months ended June 30, 2021 increased by approximately $11.4 million, or 13%. This increase was primarily due to increased production of 13.9 MBoepd offset by a decrease of $1.90 per Boe, or 10% in the depletion rate on our proved oil and natural gas properties as a result of the impairment on oil and gas properties in the fourth quarter of 2020.

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Six Months Ended June 30, 2021 and 2020 — Depreciation, depletion and amortization expense for the six months ended June 30, 2021 increased by approximately $19.5 million, or 11%. This increase was primarily due to increased production of 11.0 MBoepd offset by a decrease of $1.24 per Boe, or 7% in the depletion rate on our proved oil and natural gas properties as a result of the impairment on oil and gas properties in the fourth quarter of 2020.

General and Administrative Expense

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

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

General and administrative expense

 

$

19,377

 

 

$

17,192

 

 

$

38,566

 

 

$

44,661

 

General and administrative expense per Boe

 

$

3.21

 

 

$

3.60

 

 

$

3.22

 

 

$

4.44

 

Three Months Ended June 30, 2021 and 2020 — General and administrative expense for the three months ended June 30, 2021, increased by approximately $2.2 million, or 13%, which was primarily related to increased employee and contract labor costs. Transaction and non-recurring expenses were $1.3 million or $0.22 per Boe for the three months ended June 30, 2021, which is a decrease of $2.2 million primarily due to the ILX and Castex Acquisition that occurred in the first quarter of 2020.

Six Months Ended June 30, 2021 and 2020 — General and administrative expense for the six months ended June 30, 2021, decreased by approximately $6.1 million, or 14%. Transaction and non-recurring expenses were $3.1 million or $0.26 per Boe for the six months ended June 30, 2021, which is a decrease of $8.2 million primarily due to the ILX and Castex Acquisition that occurred in the first quarter of 2020. Non-cash equity-based compensation was $5.7 million, or $0.47 per Boe for the six months ended June 30, 2021, which is an increase of $1.7 million.

Other Income and Expense

The following table highlights other income and expense items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

Write-down of oil and natural gas properties

 

$

 

 

$

 

 

$

 

 

$

57

 

Accretion expense

 

$

15,457

 

 

$

13,794

 

 

$

30,442

 

 

$

26,211

 

Other operating expense

 

$

2,783

 

 

$

 

 

$

2,783

 

 

$

 

Price risk management activities (income)
  expense

 

$

186,617

 

 

$

68,682

 

 

$

324,125

 

 

$

(174,535

)

Other (income) expense

 

$

(1,559

)

 

$

528

 

 

$

12,391

 

 

$

674

 

Income tax (benefit) expense

 

$

498

 

 

$

(49,392

)

 

$

1,082

 

 

$

5,868

 

Three Months Ended June 30, 2021 and 2020 —

Other operating expense — During the three months ended June 30, 2021, we recorded $2.8 million of decommissioning obligations as a result of notification from the State of Louisiana to assume the plug and abandonment costs of certain wells due to the bankruptcy of a third party that was unable to perform its required abandonment obligations.

Price risk management activities — Price risk management activities for the three months ended June 30, 2021, decreased by approximately $117.9 million, or 172%. The expense of $186.6 million for the three months ended June 30, 2021 consists of $117.4 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $69.2 million in cash settlement losses. The expense of $68.7 million for the three months ended June 30, 2020 consists of $154.7 million in non-cash losses from the decrease in the fair value of our open derivative contracts partially offset by $86.0 million in cash settlement gains. 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 June 2023, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

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Income tax (benefit) expense — During the three months ended June 30, 2021, we recorded $0.5 million of income tax expense compared to $49.4 million of income tax benefit during the three months ended June 30, 2020. The change is primarily a result of recording a valuation allowance on our deferred tax assets. The realization of our deferred tax asset depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of all of the deferred tax assets will not be realized. See additional information on the valuation allowance as described in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 8 — Income Taxes.”

Six Months Ended June 30, 2021 and 2020 —

Other operating expense — During the six months ended June 30, 2021, we recorded $2.8 million of decommissioning obligations as a result of notification from the State of Louisiana to assume the plug and abandonment costs of certain wells due to the bankruptcy of a third party that was unable to perform its required abandonment obligations.

Price risk management activities — Price risk management activities for the six months ended June 30, 2021, decreased by approximately $498.7 million, or 286%. The expense of $324.1 million for the six months ended June 30, 2021 consists of $206.5 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $117.6 million in cash settlement losses. The income of $174.5 million for the six months ended June 30, 2020 consists of $122.5 million in cash settlement gains and $52.0 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 June 2023, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

Other (income) expense — During the six months ended June 30, 2021 we recorded a $13.2 million loss on extinguishment of debt as a result of the redemption of the 11.00% Notes further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt.”

Income tax (benefit) expense — During the six months ended June 30, 2021, we recorded $1.1 million of income tax expense compared to $5.9 million of income tax expense during the six months ended June 30, 2020. The change is primarily a result of recording a valuation allowance on our deferred tax assets as of December 31, 2020. The realization of our deferred tax asset depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of all of the deferred tax assets will not be realized. See additional information on the valuation allowance as described in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 8 — Income Taxes.”

Supplemental Non-GAAP Measure

EBITDA and Adjusted EBITDA

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

We define these as the following:

EBITDA Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense.

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Adjusted EBITDA — EBITDA plus non-cash write-down of oil and natural gas properties, transaction and non-recurring expenses, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense.

The following tables present a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

 

2021

 

 

2020

 

Reconciliation of net income (loss)
  to Adjusted EBITDA:

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(125,782

)

 

$

(140,611

)

 

$

(247,273

)

 

$

17,138

 

Interest expense

 

 

33,570

 

 

 

26,190

 

 

 

67,646

 

 

 

52,040

 

Income tax (benefit) expense

 

 

498

 

 

 

(49,392

)

 

 

1,082

 

 

 

5,868

 

Depreciation, depletion and amortization

 

 

99,841

 

 

 

88,443

 

 

 

201,498

 

 

 

181,986

 

Accretion expense

 

 

15,457

 

 

 

13,794

 

 

 

30,442

 

 

 

26,211

 

EBITDA

 

 

23,584

 

 

 

(61,576

)

 

 

53,395

 

 

 

283,243

 

Write-down of oil and natural gas properties

 

 

 

 

 

 

 

 

 

 

 

57

 

Transaction and non-recurring expenses(1)

 

 

4,083

 

 

 

3,498

 

 

 

5,861

 

 

 

11,256

 

Derivative fair value (gain) loss(2)

 

 

186,617

 

 

 

68,682

 

 

 

324,125

 

 

 

(174,535

)

Net cash received (paid) on settled
  derivative instruments
(2)

 

 

(69,237

)

 

 

86,039

 

 

 

(117,618

)

 

 

122,499

 

(Gain) loss on extinguishment of debt

 

 

 

 

 

(1,470

)

 

 

13,225

 

 

 

(1,470

)

Non-cash write-down of other well
  equipment inventory

 

 

 

 

 

 

 

 

 

 

 

133

 

Non-cash equity-based compensation
  expense

 

 

3,017

 

 

 

2,347

 

 

 

5,681

 

 

 

3,974

 

Adjusted EBITDA

 

$

148,064

 

 

$

97,520

 

 

$

284,669

 

 

$

245,157

 

 

(1)
Includes transaction related expenses, restructuring expenses, cost saving initiatives and other miscellaneous expenses.
(2)
The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. Our working capital deficit has increased since December 31, 2020 primarily due to a $164.2 million increase in liabilities from price risk management activities. As of June 30, 2021, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $306.8 million.

We fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

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Table of Contents

Capital ExpendituresThe following is a table of our capital expenditures, excluding acquisitions, for the six months ended June 30, 2021 (in thousands):

U.S. drilling & completions

 

$

96,611

 

Mexico appraisal & exploration

 

 

674

 

Asset management

 

 

29,551

 

Seismic and G&G, land, capitalized G&A and other

 

 

25,195

 

Total capital expenditures

 

 

152,031

 

Plugging & abandonment

 

 

36,329

 

Total capital expenditures and plugging & abandonment

 

$

188,360

 

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 2021 capital spending program of $340.0 million to $370.0 million and our working capital deficit. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, raising debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding debt.

Guarantor Financial Information — Talos owns no operating assets and has no operations independent of its subsidiaries. Talos Production Inc. (the “Issuer”) issued the 12.00% Notes (as defined below) on January 4, 2021 and January 14, 2021, which are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Talos and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material domestic subsidiaries (collectively, the “Subsidiary Guarantors” and, together with the Talos, the “Guarantors”) that guarantees the Issuer’s senior reserve-based revolving credit facility. Our non-domestic subsidiaries (the “Non-Guarantors”) are 100% owned by Talos but do not guarantee the 12.00% Notes issued on January 4, 2021 and January 14, 2021.

In lieu of providing separate financial statements for the Issuer and the Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and income statement information for the Issuer and the Guarantors on a combined basis after elimination of intercompany transactions and amounts related to investment in any subsidiary that is a Non-Guarantor.

The following table presents the balance sheet information for the respective periods (in thousands):

 

 

June 30, 2021

 

 

December 31, 2020

 

Current assets

 

$

296,235

 

 

$

231,669

 

Non-current assets

 

 

2,400,508

 

 

 

2,444,886

 

Total Assets

 

$

2,696,743

 

 

$

2,676,555

 

 

 

 

 

 

 

 

Current liabilities

 

$

671,655

 

 

$

438,340

 

Non-current liabilities

 

 

1,490,571

 

 

 

1,459,816

 

Talos Energy Inc. stockholdersʼ equity

 

 

534,517

 

 

 

778,399

 

Total liabilities and stockholdersʼ equity

 

$

2,696,743

 

 

$

2,676,555

 

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

 

 

Six Months Ended
June 30, 2021

 

Revenues and other

 

$

571,676

 

Costs and expenses

 

 

(817,044

)

Net loss

 

$

(245,368

)

 

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Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

 

 

Six Months Ended June 30,

 

 

 

2021

 

 

2020

 

Operating activities

 

$

199,094

 

 

$

191,612

 

Investing activities

 

$

(126,633

)

 

$

(451,594

)

Financing activities

 

$

(41,340

)

 

$

280,815

 

Operating ActivitiesNet cash provided by operating activities increased $7.5 million in the six months ended June 30, 2021 compared to the corresponding period in 2020 primarily attributable to an increase in revenues of $295.0 million. This was offset by an increase in cash payments on derivative instruments of $240.1 million and settlements of asset retirement obligations of $17.8 million.

Investing Activities — Net cash used in investing activities decreased $325.0 million in the six months ended June 30, 2021 compared to the corresponding period in 2020 primarily due to a decrease in payments for acquisitions of $291.6 million and a decrease in capital expenditures of $28.8 million.

Financing ActivitiesNet cash provided by financing activities decreased $322.2 million in the six months ended June 30, 2021 compared to the corresponding period in 2020 primarily attributable to decrease in net proceeds of $540.0 million received from the Bank Credit Facility used primarily to fund the ILX and Castex Acquisition in the first quarter of 2020. Additionally, $355.6 million was utilized for the redemption of the 11.00% Notes in the first quarter of 2021. This decrease was offset by proceeds of $600.5 million from the issuance of the 12.00% Notes in January 2021.

Overview of Debt Instruments

Bank Credit Facility — matures November 2024 — We maintain a Bank Credit Facility with a syndicate of financial institutions (the “Bank Credit Facility”). The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. On June 22, 2021, we entered into a Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement (the “Sixth Amendment”). The Sixth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from May 10, 2022 to November 12, 2024, (ii) decreased the borrowing base from $960.0 million to $950.0 million, and (iii) decreased the commitments to $655.0 million. The next scheduled redetermination meeting is expected to occur in November 2021.

The Bank Credit Facility sets the interest rate at either (at the Company’s option) an alternative base rate plus a specified percentage, or LIBOR plus a specified percentage. The specified percentage is referred to as the applicable margin, which varies based on the borrowing base utilization percentage.

As of June 30, 2021, our borrowing base was $950.0 million with total commitments of $655.0 million. Additionally, no more than $200.0 million of our borrowing base can be used as letters of credit with current commitments at $150.0 million. 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, 2021. As of June 30, 2021, we had $400.0 million in outstanding borrowings at a weighted average interest rate of 3.55% and $13.6 million in letters of credit issued under the Bank Credit Facility.

During July 2021, the Company announced the addition of a new lender in the Bank Credit Facility adding an additional $75.0 million of commitments. The addition increases total commitments from $655.0 million to $730.0 million.

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Table of Contents

12.00% Second-Priority Senior Secured Notes—due January 2026 The 12.00% Second-Priority Senior Secured Notes (the “12.00% Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the "Parent Guarantor"), Talos Production Inc. (“Issuer”), and the Subsidiary Guarantors 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 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, commencing on July 15, 2021. We made an interest payment of $41.4 million on July 15, 2021. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt for more information.

Redemption of the 11.00% Second-Priority Senior Secured Notes—due April 2022 On January 13, 2021, the Company redeemed the 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) using the proceeds from the issuance of 12.00% Notes.

The debt redemption resulted in a loss on extinguishment of debt of nil and $13.2 million for the three and six months ended June 30, 2021, respectively, which is presented as “Other income (expense)” on the Condensed Consolidated Statements of Operations.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations since those reported in our 2020 Annual Report except:

The aggregate principal of our debt increased from $993.3 million to $1,056.1 million due to the issuance of the 12.00% Notes, redemption of the 11.00% Notes and lower borrowings under the Bank Credit Facility;
Interest expense increased by approximately $369.1 million primarily due to the issuance of the 12.00% Notes, maturity extension of the Bank Credit Facility and lower borrowings under the Bank Credit Facility; and
Derivative net liabilities increased from $67.8 million to $274.3 million.

Performance Bonds — As of June 30, 2021, we had secured performance bonds primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico and to guarantee the completion of the minimum work program under the Mexico production sharing contracts totaling approximately $673.9 million.

See “Known Trends and Uncertainties — BOEM Bonding Requirements” under Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.

Off Balance Sheet Arrangements

We did not have any off balance sheet arrangements as of June 30, 2021.

Critical Accounting Policies and Estimates

We consider accounting policies related to oil and natural gas properties, proved reserve estimates, fair value measure of financial instruments, asset retirement obligations, revenue recognition, imbalances and production handling fees and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting policies, which are summarized in the Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our 2020 Annual Report.

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

None.

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Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2020 Annual Report. Except as disclosed in this Quarterly Report, there have been no material changes from the disclosures presented in our 2020 Annual Report regarding our exposures to certain market risks.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2021.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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Table of Contents

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

There have been no material developments with respect to the information previously reported under Part I, Item 3. “Legal Proceedings” of our 2020 Annual Report.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under Part I, Item 1A. “Risk Factors” included in our 2020 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2020 Annual Report or our other SEC filings.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Table of Contents

Item 6. Exhibits

 

Exhibit

Number

 

Description

 

 

 

    2.1#

 

Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings, LLC (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

 

 

 

    2.2

 

Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings LLC (incorporated by reference to Exhibit 2.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

 

 

 

    2.3#

 

Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings II, LLC (incorporated by reference to Exhibit 2.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

 

 

 

    2.4

 

Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings II LLC (incorporated by reference to Exhibit 2.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

 

 

 

    2.5#

 

Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings III LLC (incorporated by reference to Exhibit 2.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

 

 

 

    2.6

 

Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings III LLC (incorporated by reference to Exhibit 2.6 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

 

 

 

    2.7#

 

Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and Castex Energy 2014, LLC (incorporated by reference to Exhibit 2.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

 

 

 

    2.8

 

Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and Castex Energy 2014, LLC (incorporated by reference to Exhibit 2.8 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

 

 

 

    2.9#

 

Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and Castex Energy 2016, LP (incorporated by reference to Exhibit 2.5 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

 

 

 

    3.1

 

Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

 

 

 

    3.2

 

Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

 

 

 

    3.3

 

Certificate of Designation, dated as of February 27, 2020 (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020).

 

 

 

    4.1

 

 

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).

 

 

 

 

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Table of Contents

    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).

 

 

 

   10.1

 

Talos Energy Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).

 

 

 

   10.2

 

Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement, dated as of June 22, 2021, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender and the lenders party thereto. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on June 23, 2021).

 

 

 

   22.1*

 

List of Subsidiary Guarantors and Issuers of Guaranteed Securities.

 

 

 

   31.1*

 

Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

   31.2*

 

Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

   32.1**

 

Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.

 

 

 

101.INS*

 

Inline XBRL Instance.

 

 

 

101.SCH*

 

Inline XBRL Taxonomy Extension Schema.

 

 

 

101.CAL*

 

Inline XBRL Taxonomy Extension Calculation.

 

 

 

101.DEF*

 

Inline XBRL Taxonomy Extension Definition.

 

 

 

101.LAB*

 

Inline XBRL Taxonomy Extension Label.

 

 

 

101.PRE*

 

Inline XBRL Taxonomy Extension Presentation.

 

 

 

104*

 

Cover Page Interactive Date File (Embedded within the Inline XBRL document and included in Exhibit 101).

 

 

 

 

* Filed herewith.

** Furnished herewith.

# Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K, but will be furnished supplementally to the SEC upon request.

 

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Table of Contents

SIGNATURES

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

 

 

 

TALOS ENERGY INC.

 

 

 

 

Date:

August 3, 2021

By:

/s/ Shannon E. Young III

 

 

 

Shannon E. Young III

 

 

 

Executive Vice President and Chief Financial Officer

 

36