Talos Energy

2021  

TALOS ENERGY 
ANNUAL REPORT

Innovation 
& Leadership

Talos Energy
AT A GLANCE

Talos Energy is leveraging its unique capabilities and rich heritage 
to position itself as a leading energy business of tomorrow.

As one of the largest independent 
energy companies in the U.S. 
Gulf of Mexico, Talos maintains a 
strong technical skill set focused on 
conventional geology, geophysics 
and reservoir engineering as well as 
decades of operational experience 
spanning from the U.S. Gulf Coast to 
ultra-deepwater in the Gulf of Mexico. 
These capabilities allow Talos to unlock 
new resources, providing secure, 
reliable and responsible energy supply 
to the global marketplace. 

Talos is also applying its core skill sets 
to develop numerous major carbon 
capture and sequestration projects 
along the U.S. Gulf Coast. These 
complementary businesses uniquely 
position Talos to contribute to global 
prosperity through energy security 
today while also playing a leading role 
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NYSE: TALO

APRIL 2022

TALOS ENERGY

Asset Overview

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TALOS ENERGY

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GC-18

Letter to Shareholders
APRIL 2022

2021 was a historic year for Talos Energy. Not only did our company 
manage through the unprecedented challenge created by the COVID-19 
pandemic, but in 2021 we rebounded with record breaking production, 
our best year of safety and environmental performance and rapid 
progress on our emissions reduction targets. 

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our Carbon Capture and Sequestration (“CCS”) business to

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ANNUAL REPORT

(Continued on Page 3)

1

“We have evolved from one of the top 
independent energy producers in the Gulf of 
Mexico to a total energy solutions company 
focused on both energy production and 
industrial carbon capture and sequestration and 
we are excited about the role we will play going 
forward in the future of our industry.”

Timothy Duncan, President and 
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2

TALOS ENERGY

Letter to Shareholders
(CONTINUED)

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TIMOTHY 
DUNCAN 
TALOS ENERGY CEO

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(cid:135)(cid:143)(cid:135)(cid:148)(cid:137)(cid:135)(cid:3)(cid:136)(cid:148)(cid:145)(cid:143)(cid:3)(cid:131)(cid:3)(cid:149)(cid:143)(cid:131)(cid:142)(cid:142)(cid:3)(cid:149)(cid:150)(cid:131)(cid:148)(cid:150)(cid:486)(cid:151)(cid:146)(cid:3)(cid:150)(cid:145)(cid:3)(cid:131)(cid:3)(cid:142)(cid:135)(cid:131)(cid:134)(cid:139)(cid:144)(cid:137)(cid:3)(cid:145)(cid:136)(cid:136)(cid:149)(cid:138)(cid:145)(cid:148)(cid:135)(cid:3)(cid:139)(cid:144)(cid:134)(cid:135)(cid:146)(cid:135)(cid:144)(cid:134)(cid:135)(cid:144)(cid:150)(cid:3)

(cid:138)(cid:135)(cid:142)(cid:146)(cid:3)(cid:135)(cid:152)(cid:135)(cid:148)(cid:155)(cid:145)(cid:144)(cid:135)(cid:3)(cid:148)(cid:135)(cid:131)(cid:133)(cid:138)(cid:3)(cid:150)(cid:138)(cid:135)(cid:139)(cid:148)(cid:3)(cid:136)(cid:151)(cid:142)(cid:142)(cid:3)(cid:146)(cid:145)(cid:150)(cid:135)(cid:144)(cid:150)(cid:139)(cid:131)(cid:142)(cid:484)(cid:3)

(cid:146)(cid:148)(cid:145)(cid:134)(cid:151)(cid:133)(cid:135)(cid:148)(cid:3)(cid:139)(cid:144)(cid:3)(cid:140)(cid:151)(cid:149)(cid:150)(cid:3)(cid:150)(cid:135)(cid:144)(cid:3)(cid:155)(cid:135)(cid:131)(cid:148)(cid:149)(cid:481)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:12)(cid:3)(cid:132)(cid:135)(cid:142)(cid:139)(cid:135)(cid:152)(cid:135)(cid:3)(cid:145)(cid:151)(cid:148)(cid:3)(cid:145)(cid:146)(cid:146)(cid:145)(cid:148)(cid:150)(cid:151)(cid:144)(cid:139)(cid:150)(cid:155)(cid:3)(cid:149)(cid:135)(cid:150)(cid:3)(cid:133)(cid:131)(cid:144)(cid:3)

(cid:131)(cid:133)(cid:133)(cid:135)(cid:142)(cid:135)(cid:148)(cid:131)(cid:150)(cid:135)(cid:3)(cid:145)(cid:151)(cid:148)(cid:3)(cid:137)(cid:148)(cid:145)(cid:153)(cid:150)(cid:138)(cid:3)(cid:139)(cid:144)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:144)(cid:135)(cid:154)(cid:150)(cid:3)(cid:150)(cid:135)(cid:144)(cid:3)(cid:155)(cid:135)(cid:131)(cid:148)(cid:149)(cid:484)

(cid:6)(cid:131)(cid:144)(cid:3)(cid:131)(cid:144)(cid:3)(cid:135)(cid:144)(cid:135)(cid:148)(cid:137)(cid:155)(cid:3)(cid:133)(cid:145)(cid:143)(cid:146)(cid:131)(cid:144)(cid:155)(cid:3)(cid:137)(cid:148)(cid:145)(cid:153)(cid:3)(cid:139)(cid:150)(cid:149)(cid:3)(cid:145)(cid:139)(cid:142)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:137)(cid:131)(cid:149)(cid:3)(cid:132)(cid:151)(cid:149)(cid:139)(cid:144)(cid:135)(cid:149)(cid:149)(cid:3)(cid:150)(cid:145)(cid:3)(cid:143)(cid:135)(cid:135)(cid:150)(cid:3)

(cid:150)(cid:138)(cid:135)(cid:3)(cid:135)(cid:144)(cid:135)(cid:148)(cid:137)(cid:155)(cid:3)(cid:134)(cid:135)(cid:143)(cid:131)(cid:144)(cid:134)(cid:149)(cid:3)(cid:145)(cid:136)(cid:3)(cid:150)(cid:145)(cid:134)(cid:131)(cid:155)(cid:3)(cid:153)(cid:138)(cid:139)(cid:142)(cid:135)(cid:3)(cid:131)(cid:142)(cid:149)(cid:145)(cid:3)(cid:132)(cid:135)(cid:139)(cid:144)(cid:137)(cid:3)(cid:131)(cid:3)(cid:142)(cid:135)(cid:131)(cid:134)(cid:135)(cid:148)(cid:3)(cid:139)(cid:144)

(cid:22)(cid:139)(cid:144)(cid:133)(cid:135)(cid:148)(cid:135)(cid:142)(cid:155)(cid:3)(cid:28)(cid:145)(cid:151)(cid:148)(cid:149)(cid:481)

(cid:135)(cid:144)(cid:152)(cid:139)(cid:148)(cid:145)(cid:144)(cid:143)(cid:135)(cid:144)(cid:150)(cid:131)(cid:142)(cid:3)(cid:149)(cid:150)(cid:135)(cid:153)(cid:131)(cid:148)(cid:134)(cid:149)(cid:138)(cid:139)(cid:146)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:148)(cid:135)(cid:134)(cid:151)(cid:133)(cid:139)(cid:144)(cid:137)(cid:3)(cid:139)(cid:150)(cid:149)(cid:3)(cid:10)(cid:11)(cid:10)(cid:3)(cid:139)(cid:144)(cid:150)(cid:135)(cid:144)(cid:149)(cid:139)(cid:150)(cid:155)(cid:491)(cid:3)

(cid:4)(cid:144)(cid:134)(cid:3)(cid:133)(cid:131)(cid:144)(cid:3)(cid:131)(cid:144)(cid:3)(cid:135)(cid:144)(cid:135)(cid:148)(cid:137)(cid:155)(cid:3)(cid:133)(cid:145)(cid:143)(cid:146)(cid:131)(cid:144)(cid:155)(cid:3)(cid:151)(cid:149)(cid:135)(cid:3)(cid:139)(cid:150)(cid:149)(cid:3)(cid:149)(cid:141)(cid:139)(cid:142)(cid:142)(cid:3)(cid:149)(cid:135)(cid:150)(cid:149)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:146)(cid:135)(cid:145)(cid:146)(cid:142)(cid:135)(cid:3)(cid:150)(cid:145)(cid:3)

(cid:134)(cid:139)(cid:148)(cid:135)(cid:133)(cid:150)(cid:142)(cid:155)(cid:3)(cid:148)(cid:135)(cid:134)(cid:151)(cid:133)(cid:135)(cid:3)(cid:139)(cid:144)(cid:134)(cid:151)(cid:149)(cid:150)(cid:148)(cid:139)(cid:131)(cid:142)(cid:3)(cid:135)(cid:143)(cid:139)(cid:149)(cid:149)(cid:139)(cid:145)(cid:144)(cid:149)(cid:3)(cid:139)(cid:144)(cid:3)(cid:142)(cid:145)(cid:133)(cid:131)(cid:142)(cid:3)(cid:133)(cid:145)(cid:143)(cid:143)(cid:151)(cid:144)(cid:139)(cid:150)(cid:139)(cid:135)(cid:149)(cid:491)(cid:3)

(cid:26)(cid:135)(cid:3)(cid:132)(cid:135)(cid:142)(cid:139)(cid:135)(cid:152)(cid:135)(cid:3)(cid:150)(cid:138)(cid:131)(cid:150)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:139)(cid:149)(cid:3)(cid:149)(cid:151)(cid:133)(cid:138)(cid:3)(cid:131)(cid:144)(cid:3)(cid:135)(cid:144)(cid:135)(cid:148)(cid:137)(cid:155)(cid:3)(cid:133)(cid:145)(cid:143)(cid:146)(cid:131)(cid:144)(cid:155)(cid:484)(cid:3)

Timothy S. Duncan
(cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:2814)(cid:70)(cid:72)(cid:85)

ANNUAL REPORT

3

“Over what has been a turbulent decade in the 
energy industry, Talos has steadily built a solid 
(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:73)(cid:82)(cid:70)(cid:88)(cid:86)(cid:72)(cid:71)(cid:3)(cid:68)(cid:85)(cid:82)(cid:88)(cid:81)(cid:71)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:71)(cid:76)(cid:2698)(cid:72)(cid:85)(cid:72)(cid:81)(cid:87)(cid:76)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)
skill sets, unique investment thesis and strong 
(cid:192)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:83)(cid:85)(cid:76)(cid:81)(cid:70)(cid:76)(cid:83)(cid:79)(cid:72)(cid:86)(cid:17)(cid:3)(cid:58)(cid:72)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:72)(cid:71)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)
long-term success with this platform.”

Shane Young, Executive Vice President 
(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:50)(cid:3528)(cid:70)(cid:72)(cid:85)

4

TALOS ENERGY

2021 Financial Highlights
2018-2021 FISCAL YEARS

Year Ended (Millions)

Revenue

Net Income (Loss)

Capital Expenditures(1)

Total Long-term Debt(2)

Reserves(3) (MMBoe)

Proved Developed Producing (PDP)

Proved Developed Non-Producing (PDNP)

Proved Developed

Proved Undeveloped (PUD)

Total Proved

Production

Sales Volume (MMBoe)

Average Daily Production (MBoe/d)

2021

$1,244.5

2020

$575.9

($183.0)

($465.6)

$338.8

$405.5

$1,071.3

$1,055.3

95.6

40.6

136.3

25.3

161.6

23.5

64.4

89.7

37.4

127.1

35.9

163.0

20.0

54.7

2019

$908.1

$58.7

$545.7

$826.5

68.3

29.6

97.9

43.8

141.7

19.0

52.0

2018

$891.3 

$221.5 

$390.6 

$766.2

78.1 

37.5 

115.5

36.2 

151.7

16.7 

45.9 

AVERAGE DAILY PRODUCTION 
(MBoe/d)

PDP RESERVES 
(MMBoe)

52.0

54.7

45.9

78.1

68.3

64.4

89.7

95.6

2018

2019

2020

2021

2018

2019

2020

2021

(1) Includes plugging and abandonment.
(cid:11)(cid:21)(cid:12)(cid:3)(cid:44)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:86)(cid:3)(cid:192)(cid:81)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:79)(cid:72)(cid:68)(cid:86)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:72)(cid:91)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:86)(cid:3)(cid:82)(cid:85)(cid:76)(cid:74)(cid:76)(cid:81)(cid:68)(cid:79)(cid:3)(cid:76)(cid:86)(cid:86)(cid:88)(cid:72)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:71)(cid:72)(cid:73)(cid:72)(cid:85)(cid:85)(cid:72)(cid:71)(cid:3)(cid:192)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:81)(cid:74)(cid:3)(cid:70)(cid:82)(cid:86)(cid:87)(cid:86)(cid:17)
(cid:11)(cid:22)(cid:12)(cid:3)(cid:36)(cid:79)(cid:79)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:192)(cid:74)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:68)(cid:87)(cid:3)(cid:92)(cid:72)(cid:68)(cid:85)(cid:16)(cid:72)(cid:81)(cid:71)(cid:3)(cid:54)(cid:40)(cid:38)(cid:3)(cid:83)(cid:85)(cid:76)(cid:70)(cid:72)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:7)(cid:25)(cid:26)(cid:17)(cid:20)(cid:23)(cid:18)(cid:69)(cid:69)(cid:79)(cid:3)(cid:58)(cid:55)(cid:44)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:7)(cid:22)(cid:17)(cid:26)(cid:20)(cid:18)(cid:80)(cid:70)(cid:73)(cid:3)(cid:43)(cid:43)(cid:15)(cid:3)(cid:7)(cid:22)(cid:28)(cid:17)(cid:23)(cid:26)(cid:18)(cid:7)(cid:20)(cid:17)(cid:28)(cid:26)(cid:15)(cid:3)(cid:7)(cid:25)(cid:20)(cid:17)(cid:19)(cid:20)(cid:18)(cid:7)(cid:21)(cid:17)(cid:24)(cid:28)(cid:15)(cid:3)
(cid:7)(cid:25)(cid:28)(cid:17)(cid:23)(cid:21)(cid:18)(cid:7)(cid:22)(cid:17)(cid:19)(cid:27)(cid:15)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:21)(cid:19)(cid:21)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:28)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:15)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:79)(cid:92)(cid:17)(cid:3)

ANNUAL REPORT

5

Corporate Responsibility
COMMITMENT TO SAFE, RESPONSIBLE ENERGY PRODUCTION

Safety and environmental responsibility are top priorities for Talos and are 
at the core of our daily operations.

T (cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:139)(cid:149)(cid:3)(cid:138)(cid:139)(cid:137)(cid:138)(cid:142)(cid:155)(cid:3)(cid:136)(cid:145)(cid:133)(cid:151)(cid:149)(cid:135)(cid:134)(cid:3)(cid:145)(cid:144)(cid:3)(cid:148)(cid:135)(cid:134)(cid:151)(cid:133)(cid:139)(cid:144)(cid:137)(cid:3)(cid:139)(cid:150)(cid:149)(cid:3)(cid:137)(cid:148)(cid:135)(cid:135)(cid:144)(cid:138)(cid:145)(cid:151)(cid:149)(cid:135)(cid:3)(cid:137)(cid:131)(cid:149)

(cid:523)(cid:498)(cid:10)(cid:11)(cid:10)(cid:499)(cid:524)(cid:3)(cid:135)(cid:143)(cid:139)(cid:149)(cid:149)(cid:139)(cid:145)(cid:144)(cid:149)(cid:3)(cid:139)(cid:144)(cid:150)(cid:135)(cid:144)(cid:149)(cid:139)(cid:150)(cid:155)(cid:3)(cid:145)(cid:152)(cid:135)(cid:148)(cid:3)(cid:150)(cid:139)(cid:143)(cid:135)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:138)(cid:131)(cid:149)(cid:3)(cid:149)(cid:150)(cid:135)(cid:131)(cid:134)(cid:139)(cid:142)(cid:155)(cid:3)

(cid:148)(cid:135)(cid:134)(cid:151)(cid:133)(cid:135)(cid:134)(cid:3)(cid:22)(cid:133)(cid:145)(cid:146)(cid:135)(cid:3)(cid:883)(cid:3)(cid:135)(cid:143)(cid:139)(cid:149)(cid:149)(cid:139)(cid:145)(cid:144)(cid:149)(cid:3)(cid:139)(cid:144)(cid:150)(cid:135)(cid:144)(cid:149)(cid:139)(cid:150)(cid:155)(cid:3)(cid:136)(cid:148)(cid:145)(cid:143)(cid:3)(cid:139)(cid:150)(cid:149)(cid:3)(cid:145)(cid:146)(cid:135)(cid:148)(cid:131)(cid:150)(cid:139)(cid:145)(cid:144)(cid:149)

(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:150)(cid:131)(cid:141)(cid:135)(cid:149)(cid:3)(cid:137)(cid:148)(cid:135)(cid:131)(cid:150)(cid:3)(cid:146)(cid:148)(cid:139)(cid:134)(cid:135)(cid:3)(cid:139)(cid:144)(cid:3)(cid:149)(cid:131)(cid:136)(cid:135)(cid:150)(cid:155)(cid:486)(cid:976)(cid:139)(cid:148)(cid:149)(cid:150)(cid:3)(cid:145)(cid:146)(cid:135)(cid:148)(cid:131)(cid:150)(cid:139)(cid:145)(cid:144)(cid:149)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:139)(cid:149)(cid:3)(cid:131)(cid:3)(cid:142)(cid:135)(cid:131)(cid:134)(cid:135)(cid:148)

(cid:131)(cid:143)(cid:145)(cid:144)(cid:137)(cid:3)(cid:146)(cid:135)(cid:135)(cid:148)(cid:149)(cid:481)(cid:3)(cid:153)(cid:139)(cid:150)(cid:138)(cid:3)(cid:141)(cid:135)(cid:155)(cid:3)(cid:149)(cid:131)(cid:136)(cid:135)(cid:150)(cid:155)(cid:3)(cid:146)(cid:135)(cid:148)(cid:136)(cid:145)(cid:148)(cid:143)(cid:131)(cid:144)(cid:133)(cid:135)(cid:3)(cid:139)(cid:144)(cid:134)(cid:139)(cid:133)(cid:131)(cid:150)(cid:145)(cid:148)(cid:149)(cid:3)(cid:132)(cid:135)(cid:142)(cid:145)(cid:153)

(cid:139)(cid:144)(cid:134)(cid:151)(cid:149)(cid:150)(cid:148)(cid:155)(cid:3)(cid:131)(cid:152)(cid:135)(cid:148)(cid:131)(cid:137)(cid:135)(cid:149)(cid:484)(cid:3)(cid:12)(cid:144)(cid:3)(cid:884)(cid:882)(cid:884)(cid:883)(cid:481)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:6)(cid:145)(cid:143)(cid:146)(cid:131)(cid:144)(cid:155)(cid:3)(cid:148)(cid:135)(cid:133)(cid:145)(cid:148)(cid:134)(cid:135)(cid:134)(cid:3)(cid:131)(cid:3)(cid:148)(cid:135)(cid:133)(cid:145)(cid:148)(cid:134)

(cid:135)(cid:152)(cid:135)(cid:148)(cid:155)(cid:3)(cid:155)(cid:135)(cid:131)(cid:148)(cid:3)(cid:149)(cid:139)(cid:144)(cid:133)(cid:135)(cid:3)(cid:884)(cid:882)(cid:883)(cid:890)(cid:484)(cid:3)(cid:12)(cid:144)(cid:3)(cid:884)(cid:882)(cid:884)(cid:883)(cid:481)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:135)(cid:149)(cid:150)(cid:131)(cid:132)(cid:142)(cid:139)(cid:149)(cid:138)(cid:135)(cid:134)(cid:3)(cid:142)(cid:145)(cid:144)(cid:137)(cid:486)(cid:150)(cid:135)(cid:148)(cid:143)
(cid:22)(cid:133)(cid:145)(cid:146)(cid:135)(cid:3)(cid:883)(cid:3)(cid:135)(cid:143)(cid:139)(cid:149)(cid:149)(cid:139)(cid:145)(cid:144)(cid:149)(cid:3)(cid:139)(cid:144)(cid:150)(cid:135)(cid:144)(cid:149)(cid:139)(cid:150)(cid:155)(cid:3)(cid:148)(cid:135)(cid:134)(cid:151)(cid:133)(cid:150)(cid:139)(cid:145)(cid:144)(cid:3)(cid:150)(cid:131)(cid:148)(cid:137)(cid:135)(cid:150)(cid:149)(cid:3)(cid:150)(cid:138)(cid:148)(cid:145)(cid:151)(cid:137)(cid:138)(cid:3)(cid:884)(cid:882)(cid:884)(cid:887)(cid:481)(cid:3)

(cid:142)(cid:145)(cid:153)(cid:3)(cid:882)(cid:484)(cid:882)(cid:882)(cid:3)(cid:142)(cid:145)(cid:149)(cid:150)(cid:3)(cid:150)(cid:139)(cid:143)(cid:135)(cid:3)(cid:139)(cid:144)(cid:133)(cid:139)(cid:134)(cid:135)(cid:144)(cid:150)(cid:3)(cid:148)(cid:131)(cid:150)(cid:135)(cid:3)(cid:523)(cid:498)(cid:15)(cid:23)(cid:12)(cid:21)(cid:499)(cid:524)(cid:484)(cid:3)(cid:12)(cid:144)(cid:3)(cid:884)(cid:882)(cid:884)(cid:883)(cid:481)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:131)(cid:142)(cid:149)(cid:145)
(cid:148)(cid:135)(cid:133)(cid:145)(cid:148)(cid:134)(cid:135)(cid:134)(cid:3)(cid:156)(cid:135)(cid:148)(cid:145)(cid:3)(cid:138)(cid:155)(cid:134)(cid:148)(cid:145)(cid:133)(cid:131)(cid:148)(cid:132)(cid:145)(cid:144)(cid:3)(cid:148)(cid:135)(cid:142)(cid:135)(cid:131)(cid:149)(cid:135)(cid:149)(cid:3)(cid:145)(cid:136)(cid:136)(cid:149)(cid:138)(cid:145)(cid:148)(cid:135)(cid:3)(cid:137)(cid:148)(cid:135)(cid:131)(cid:150)(cid:135)(cid:148)(cid:3)(cid:150)(cid:138)(cid:131)(cid:144)(cid:3)(cid:145)(cid:144)(cid:135)

(cid:131)(cid:144)(cid:134)(cid:3)(cid:139)(cid:149)(cid:3)(cid:145)(cid:144)(cid:3)(cid:150)(cid:148)(cid:131)(cid:133)(cid:141)(cid:3)(cid:150)(cid:145)(cid:3)(cid:131)(cid:133)(cid:138)(cid:139)(cid:135)(cid:152)(cid:135)(cid:3)(cid:150)(cid:138)(cid:145)(cid:149)(cid:135)(cid:3)(cid:150)(cid:131)(cid:148)(cid:137)(cid:135)(cid:150)(cid:149)(cid:3)(cid:139)(cid:144)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:133)(cid:145)(cid:143)(cid:139)(cid:144)(cid:137)(cid:3)(cid:155)(cid:135)(cid:131)(cid:148)(cid:149)(cid:484)

(cid:132)(cid:131)(cid:148)(cid:148)(cid:135)(cid:142)(cid:3)(cid:153)(cid:138)(cid:139)(cid:142)(cid:135)(cid:3)(cid:145)(cid:146)(cid:135)(cid:148)(cid:131)(cid:150)(cid:139)(cid:144)(cid:137)(cid:3)(cid:145)(cid:152)(cid:135)(cid:148)(cid:3)(cid:884)(cid:885)(cid:3)(cid:143)(cid:139)(cid:142)(cid:142)(cid:139)(cid:145)(cid:144)(cid:3)(cid:132)(cid:131)(cid:148)(cid:148)(cid:135)(cid:142)(cid:149)(cid:3)(cid:145)(cid:136)(cid:3)(cid:145)(cid:139)(cid:142)(cid:3)(cid:135)(cid:147)(cid:151)(cid:139)(cid:152)(cid:131)(cid:142)(cid:135)(cid:144)(cid:150)(cid:484)

27%

Reduction in GHG Intensity(cid:11)(cid:20)(cid:12)

ZERO

(cid:50)(cid:2813)(cid:86)(cid:75)(cid:82)(cid:85)(cid:72)(cid:3)(cid:54)(cid:83)(cid:76)(cid:79)(cid:79)(cid:86)(cid:3)(cid:33)(cid:3)(cid:20)(cid:3)(cid:37)(cid:68)(cid:85)(cid:85)(cid:72)(cid:79)(cid:3)(cid:76)(cid:81)(cid:3)(cid:54)(cid:76)(cid:93)(cid:72)

ZERO

(cid:21)(cid:19)(cid:21)(cid:20)(cid:3)(cid:47)(cid:82)(cid:86)(cid:87)(cid:3)(cid:55)(cid:76)(cid:80)(cid:72)(cid:3)(cid:44)(cid:81)(cid:70)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:53)(cid:68)(cid:87)(cid:72)

GHG INTENSITY 
(cid:11)(cid:42)(cid:85)(cid:82)(cid:86)(cid:86)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:51)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(2)(cid:15)(cid:3)(cid:48)(cid:55)(cid:3)(cid:38)(cid:50)2(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:89)(cid:68)(cid:79)(cid:72)(cid:81)(cid:87)(cid:18)(cid:48)(cid:69)(cid:82)(cid:72)(cid:12)

21.8

18.2

17.4

15.9

Original 30% Reduction 
Target by 2025(1)

New 40% 
Reduction 
Stretch Target

2018
(1) From 2018 baseline. 
(cid:11)(cid:21)(cid:12)(cid:3)(cid:42)(cid:43)(cid:42)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:86)(cid:76)(cid:87)(cid:92)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:88)(cid:83)(cid:82)(cid:81)(cid:3)(cid:55)(cid:68)(cid:79)(cid:82)(cid:86)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:83)(cid:79)(cid:88)(cid:86)(cid:3)(cid:87)(cid:75)(cid:76)(cid:85)(cid:71)(cid:16)(cid:83)(cid:68)(cid:85)(cid:87)(cid:92)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:86)(cid:3)(cid:193)(cid:82)(cid:90)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:75)(cid:85)(cid:82)(cid:88)(cid:74)(cid:75)(cid:3)(cid:55)(cid:68)(cid:79)(cid:82)(cid:86)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:73)(cid:68)(cid:70)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:17)

2019

2021

2020

6

TALOS ENERGY

15.3

13.1

2025

“Talos has always prioritized safety, 
environmental responsibility and community 
engagement. We’re proud to not only provide 
secure, reliable and responsible energy, but to 
do it with the highest level of care and respect 
for people and the environment.”

Robin Fielder, EVP – Low Carbon Strategy 
(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:54)(cid:88)(cid:86)(cid:87)(cid:68)(cid:76)(cid:81)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:50)(cid:3528)(cid:70)(cid:72)(cid:85)

ANNUAL REPORT

7

Culture and Community
SUPPORTING OUR EMPLOYEES AND LOCAL COMMUNITIES

Talos aims to be a highly supportive partner of our employees, their 
careers, their families and the broader communities in which they work 
and live. We actively support numerous organizations and are consistently 
named one of the Top Workplaces in Houston by the Houston Chronicle. 

T(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:131)(cid:139)(cid:143)(cid:149)(cid:3)(cid:150)(cid:145)(cid:3)(cid:132)(cid:135)(cid:3)(cid:131)(cid:3)(cid:146)(cid:145)(cid:149)(cid:139)(cid:150)(cid:139)(cid:152)(cid:135)(cid:3)(cid:136)(cid:145)(cid:148)(cid:133)(cid:135)(cid:3)(cid:136)(cid:145)(cid:148)(cid:3)(cid:131)(cid:142)(cid:142)(cid:3)(cid:145)(cid:136)(cid:3)(cid:145)(cid:151)(cid:148)(cid:3)

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(cid:142)(cid:135)(cid:134)(cid:3)(cid:150)(cid:145)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:132)(cid:135)(cid:139)(cid:144)(cid:137)(cid:3)(cid:144)(cid:131)(cid:143)(cid:135)(cid:134)(cid:3)(cid:131)(cid:3)(cid:23)(cid:145)(cid:146)(cid:3)(cid:26)(cid:145)(cid:148)(cid:141)(cid:146)(cid:142)(cid:131)(cid:133)(cid:135)(cid:3)(cid:132)(cid:155)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:11)(cid:145)(cid:151)(cid:149)(cid:150)(cid:145)(cid:144)(cid:3)
(cid:6)(cid:138)(cid:148)(cid:145)(cid:144)(cid:139)(cid:133)(cid:142)(cid:135)(cid:3)(cid:136)(cid:145)(cid:148)(cid:3)(cid:144)(cid:139)(cid:144)(cid:135)(cid:3)(cid:149)(cid:150)(cid:148)(cid:131)(cid:139)(cid:137)(cid:138)(cid:150)(cid:3)(cid:155)(cid:135)(cid:131)(cid:148)(cid:149)(cid:484)(cid:3)(cid:5)(cid:135)(cid:155)(cid:145)(cid:144)(cid:134)(cid:3)(cid:145)(cid:151)(cid:148)(cid:3)(cid:135)(cid:143)(cid:146)(cid:142)(cid:145)(cid:155)(cid:135)(cid:135)(cid:149)(cid:481)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)

(cid:135)(cid:143)(cid:146)(cid:142)(cid:145)(cid:155)(cid:135)(cid:135)(cid:149)(cid:3)(cid:153)(cid:139)(cid:150)(cid:138)(cid:3)(cid:149)(cid:150)(cid:148)(cid:145)(cid:144)(cid:137)(cid:3)(cid:132)(cid:135)(cid:144)(cid:135)(cid:136)(cid:139)(cid:150)(cid:149)(cid:481)(cid:3)(cid:136)(cid:142)(cid:135)(cid:154)(cid:139)(cid:132)(cid:142)(cid:135)(cid:3)(cid:149)(cid:133)(cid:138)(cid:135)(cid:134)(cid:151)(cid:142)(cid:135)(cid:149)(cid:3)(cid:131)(cid:144)(cid:134)

(cid:131)(cid:133)(cid:150)(cid:139)(cid:152)(cid:135)(cid:142)(cid:155)(cid:3)(cid:131)(cid:149)(cid:149)(cid:139)(cid:149)(cid:150)(cid:149)(cid:3)(cid:131)(cid:3)(cid:153)(cid:139)(cid:134)(cid:135)(cid:3)(cid:131)(cid:148)(cid:148)(cid:131)(cid:155)(cid:3)(cid:145)(cid:136)(cid:3)(cid:142)(cid:145)(cid:133)(cid:131)(cid:142)(cid:3)(cid:145)(cid:148)(cid:137)(cid:131)(cid:144)(cid:139)(cid:156)(cid:131)(cid:150)(cid:139)(cid:145)(cid:144)(cid:149)(cid:3)(cid:153)(cid:139)(cid:150)(cid:138)(cid:3)(cid:134)(cid:139)(cid:148)(cid:135)(cid:133)(cid:150)(cid:3)

(cid:131)(cid:144)(cid:144)(cid:151)(cid:131)(cid:142)(cid:3)(cid:133)(cid:145)(cid:144)(cid:150)(cid:148)(cid:139)(cid:132)(cid:151)(cid:150)(cid:139)(cid:145)(cid:144)(cid:149)(cid:3)(cid:145)(cid:136)(cid:3)(cid:836)(cid:887)(cid:882)(cid:882)(cid:3)(cid:135)(cid:131)(cid:133)(cid:138)(cid:3)(cid:150)(cid:145)(cid:3)(cid:131)(cid:3)(cid:142)(cid:145)(cid:133)(cid:131)(cid:142)(cid:3)(cid:133)(cid:138)(cid:131)(cid:148)(cid:139)(cid:150)(cid:131)(cid:132)(cid:142)(cid:135)(cid:3)

(cid:133)(cid:145)(cid:144)(cid:150)(cid:148)(cid:139)(cid:132)(cid:151)(cid:150)(cid:139)(cid:145)(cid:144)(cid:149)(cid:481)(cid:3)(cid:133)(cid:145)(cid:143)(cid:143)(cid:139)(cid:150)(cid:143)(cid:135)(cid:144)(cid:150)(cid:149)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:152)(cid:145)(cid:142)(cid:151)(cid:144)(cid:150)(cid:135)(cid:135)(cid:148)(cid:3)(cid:146)(cid:148)(cid:145)(cid:140)(cid:135)(cid:133)(cid:150)(cid:149)(cid:484)(cid:3)(cid:26)(cid:135)(cid:3)(cid:146)(cid:148)(cid:145)(cid:151)(cid:134)(cid:142)(cid:155)(cid:3)

(cid:145)(cid:148)(cid:137)(cid:131)(cid:144)(cid:139)(cid:156)(cid:131)(cid:150)(cid:139)(cid:145)(cid:144)(cid:3)(cid:145)(cid:136)(cid:3)(cid:150)(cid:138)(cid:135)(cid:139)(cid:148)(cid:3)(cid:133)(cid:138)(cid:145)(cid:139)(cid:133)(cid:135)(cid:484)

(cid:149)(cid:151)(cid:146)(cid:146)(cid:145)(cid:148)(cid:150)(cid:3)(cid:145)(cid:151)(cid:148)(cid:3)(cid:133)(cid:145)(cid:143)(cid:143)(cid:151)(cid:144)(cid:139)(cid:150)(cid:139)(cid:135)(cid:149)(cid:3)(cid:153)(cid:139)(cid:150)(cid:138)(cid:3)(cid:139)(cid:143)(cid:146)(cid:148)(cid:145)(cid:152)(cid:135)(cid:143)(cid:135)(cid:144)(cid:150)(cid:3)(cid:146)(cid:148)(cid:145)(cid:140)(cid:135)(cid:133)(cid:150)(cid:149)(cid:481)(cid:3)(cid:145)(cid:144)(cid:137)(cid:145)(cid:139)(cid:144)(cid:137)(cid:3)

(cid:133)(cid:138)(cid:131)(cid:148)(cid:139)(cid:150)(cid:131)(cid:132)(cid:142)(cid:135)(cid:3)(cid:145)(cid:146)(cid:135)(cid:148)(cid:131)(cid:150)(cid:139)(cid:145)(cid:144)(cid:149)(cid:3)(cid:131)(cid:149)(cid:3)(cid:153)(cid:135)(cid:142)(cid:142)(cid:3)(cid:131)(cid:149)(cid:3)(cid:134)(cid:139)(cid:149)(cid:131)(cid:149)(cid:150)(cid:135)(cid:148)(cid:3)(cid:148)(cid:135)(cid:142)(cid:139)(cid:135)(cid:136)(cid:3)(cid:139)(cid:144)(cid:3)(cid:150)(cid:139)(cid:143)(cid:135)(cid:149)(cid:3)(cid:145)(cid:136)(cid:3)(cid:133)(cid:148)(cid:139)(cid:149)(cid:139)(cid:149)(cid:484)

$500

(cid:50)(cid:2813)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:68)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:72)(cid:89)(cid:72)(cid:85)(cid:92)(cid:3)
(cid:72)(cid:80)(cid:83)(cid:79)(cid:82)(cid:92)(cid:72)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:71)(cid:82)(cid:81)(cid:68)(cid:87)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:68)(cid:81)(cid:3)
(cid:82)(cid:85)(cid:74)(cid:68)(cid:81)(cid:76)(cid:93)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:76)(cid:85)(cid:3)(cid:70)(cid:75)(cid:82)(cid:76)(cid:70)(cid:72)

~$1.6MM

(cid:38)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:71)(cid:3)(cid:82)(cid:85)(cid:3)(cid:85)(cid:68)(cid:76)(cid:86)(cid:72)(cid:71)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:79)(cid:82)(cid:70)(cid:68)(cid:79)(cid:3)
(cid:70)(cid:82)(cid:80)(cid:80)(cid:88)(cid:81)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:75)(cid:68)(cid:85)(cid:76)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)
(cid:82)(cid:85)(cid:74)(cid:68)(cid:81)(cid:76)(cid:93)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:86)(cid:76)(cid:81)(cid:70)(cid:72)(cid:3)(cid:21)(cid:19)(cid:20)(cid:28)

9X

HURRICANE IDA RELIEF

KIDS’ MEALS CHARITY

HOUSTON FOOD BANK

8

TALOS ENERGY

TALOS RUN CLUB

HOPE LODGE

CHRISTMAS GIVING

ANNUAL REPORT

9

Upstream Exploration
PROPROOJECOJECOOOO

CT LOCATIONS
CT LOCATIONS

Development

on
Exploration
Exp

EE
Exploitation

2022
Focus Area

Gulf of Mexico
Shelf

Kn l
Viosca Knoll

DeSoto
Canyon

iss
Miisssissippi
C
CCCanyon

Ewi
Ewing BankkBB
Ewing g
k

B

Garden Banks

Green Canyonon
on

Atwater Valley

(cid:50)(cid:2698)(cid:86)(cid:75)(cid:82)(cid:85)(cid:72)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:72)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:85)(cid:72)(cid:80)(cid:68)(cid:76)(cid:81)(cid:86)(cid:3)
one of the great frontiers of the energy 
industry, demanding the highest levels 
of technical expertise, operational 
experience and careful management.

As(cid:145)(cid:144)(cid:135)(cid:3)(cid:145)(cid:136)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:142)(cid:131)(cid:148)(cid:137)(cid:135)(cid:149)(cid:150)(cid:3)(cid:145)(cid:136)(cid:136)(cid:149)(cid:138)(cid:145)(cid:148)(cid:135)(cid:481)(cid:3)(cid:133)(cid:145)(cid:144)(cid:152)(cid:135)(cid:144)(cid:150)(cid:139)(cid:145)(cid:144)(cid:131)(cid:142)(cid:486)(cid:136)(cid:145)(cid:133)(cid:151)(cid:149)(cid:135)(cid:134)(cid:3)

(cid:139)(cid:144)(cid:134)(cid:135)(cid:146)(cid:135)(cid:144)(cid:134)(cid:135)(cid:144)(cid:150)(cid:3)(cid:135)(cid:144)(cid:135)(cid:148)(cid:137)(cid:155)(cid:3)(cid:133)(cid:145)(cid:143)(cid:146)(cid:131)(cid:144)(cid:139)(cid:135)(cid:149)(cid:3)(cid:139)(cid:144)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:24)(cid:144)(cid:139)(cid:150)(cid:135)(cid:134)(cid:3)(cid:22)(cid:150)(cid:131)(cid:150)(cid:135)(cid:149)(cid:481)

(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:139)(cid:149)(cid:3)(cid:151)(cid:144)(cid:139)(cid:147)(cid:151)(cid:135)(cid:142)(cid:155)(cid:3)(cid:146)(cid:145)(cid:149)(cid:139)(cid:150)(cid:139)(cid:145)(cid:144)(cid:135)(cid:134)(cid:3)(cid:150)(cid:145)(cid:3)(cid:135)(cid:154)(cid:146)(cid:142)(cid:145)(cid:148)(cid:135)(cid:3)(cid:136)(cid:145)(cid:148)(cid:481)(cid:3)(cid:976)(cid:139)(cid:144)(cid:134)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:134)(cid:135)(cid:152)(cid:135)(cid:142)(cid:145)(cid:146)

Holstein

Tahiti

Puma West
y)
(Discovery)

Argos

Mad Dog

Heidelberg

(cid:54)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:29)(cid:3)(cid:58)(cid:82)(cid:82)(cid:71)(cid:3)(cid:48)(cid:68)(cid:70)(cid:78)(cid:72)(cid:81)(cid:93)(cid:76)(cid:72)

(cid:150)(cid:138)(cid:135)(cid:3)(cid:133)(cid:148)(cid:139)(cid:150)(cid:139)(cid:133)(cid:131)(cid:142)(cid:3)(cid:138)(cid:155)(cid:134)(cid:148)(cid:145)(cid:133)(cid:131)(cid:148)(cid:132)(cid:145)(cid:144)(cid:3)(cid:148)(cid:135)(cid:149)(cid:145)(cid:151)(cid:148)(cid:133)(cid:135)(cid:149)(cid:3)(cid:150)(cid:138)(cid:131)(cid:150)(cid:3)(cid:146)(cid:145)(cid:153)(cid:135)(cid:148)(cid:3)(cid:143)(cid:145)(cid:134)(cid:135)(cid:148)(cid:144)(cid:3)(cid:142)(cid:139)(cid:136)(cid:135)(cid:484)

(cid:23)(cid:138)(cid:135)(cid:3)(cid:10)(cid:151)(cid:142)(cid:136)(cid:3)(cid:145)(cid:136)(cid:3)(cid:16)(cid:135)(cid:154)(cid:139)(cid:133)(cid:145)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:145)(cid:150)(cid:138)(cid:135)(cid:148) (cid:146)(cid:148)(cid:145)(cid:142)(cid:139)(cid:976)(cid:139)(cid:133)(cid:3)(cid:145)(cid:136)(cid:136)(cid:149)(cid:138)(cid:145)(cid:148)(cid:135)(cid:3)(cid:132)(cid:131)(cid:149)(cid:139)(cid:144)(cid:149)(cid:3)(cid:131)(cid:148)(cid:145)(cid:151)(cid:144)(cid:134)

(cid:23)(cid:138)(cid:135)(cid:3)(cid:6)(cid:145)(cid:143)(cid:146)(cid:131)(cid:144)(cid:155)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:139)(cid:139)(cid:150)(cid:149)(cid:3)(cid:146)(cid:148)(cid:145)(cid:140)(cid:135)(cid:133)(cid:150)(cid:3)(cid:133)(cid:145)(cid:486)(cid:145)(cid:153)(cid:144)(cid:135)(cid:148)(cid:149)(cid:3)(cid:146)(cid:142)(cid:131)(cid:144)(cid:3)(cid:150)(cid:145)(cid:3)(cid:131)(cid:146)(cid:146)(cid:148)(cid:131)(cid:139)(cid:149)(cid:135)(cid:3)(cid:150)(cid:138)(cid:135)

(cid:150)(cid:138)(cid:135)(cid:3)(cid:153)(cid:145)(cid:148)(cid:142)(cid:134)(cid:3)(cid:145)(cid:136)(cid:136)(cid:135)(cid:148)(cid:3)(cid:151)(cid:144)(cid:143)(cid:131)(cid:150)(cid:133)(cid:138)(cid:135)(cid:134)(cid:3)(cid:137)(cid:135)(cid:145)(cid:142)(cid:145)(cid:137)(cid:139)(cid:133)(cid:131)(cid:142)(cid:3)(cid:133)(cid:138)(cid:131)(cid:148)(cid:131)(cid:133)(cid:150)(cid:135)(cid:148)(cid:139)(cid:149)(cid:150)(cid:139)(cid:133)(cid:149)(cid:3)(cid:131)(cid:144)(cid:134)

(cid:134)(cid:139)(cid:149)(cid:133)(cid:145)(cid:152)(cid:135)(cid:148)(cid:155)(cid:3)(cid:153)(cid:139)(cid:150)(cid:138)(cid:3)(cid:131) (cid:149)(cid:135)(cid:135)(cid:133)(cid:145)(cid:144)(cid:134)(cid:3)(cid:153)(cid:135)(cid:142)(cid:142)(cid:3)(cid:139)(cid:144)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:149)(cid:135)(cid:133)(cid:145)(cid:144)(cid:134)(cid:3)(cid:138)(cid:131)(cid:142)(cid:136)(cid:3)(cid:145)(cid:136)(cid:3)(cid:884)(cid:882)(cid:884)(cid:884)(cid:484)

(cid:142)(cid:131)(cid:148)(cid:137)(cid:135)(cid:3)(cid:149)(cid:133)(cid:131)(cid:142)(cid:135)(cid:3)(cid:148)(cid:135)(cid:149)(cid:145)(cid:151)(cid:148)(cid:133)(cid:135)(cid:3)(cid:145)(cid:146)(cid:146)(cid:145)(cid:148)(cid:150)(cid:151)(cid:144)(cid:139)(cid:150)(cid:139)(cid:135)(cid:149)(cid:484)

(cid:12)(cid:144)(cid:3)(cid:884)(cid:882)(cid:884)(cid:883)(cid:481)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:131)(cid:144)(cid:144)(cid:145)(cid:151)(cid:144)(cid:133)(cid:135)(cid:134)(cid:3)(cid:149)(cid:151)(cid:133)(cid:133)(cid:135)(cid:149)(cid:149)(cid:3)(cid:136)(cid:148)(cid:145)(cid:143)(cid:3)(cid:139)(cid:150)(cid:149)(cid:3)(cid:19)(cid:151)(cid:143)(cid:131)(cid:3)(cid:26)(cid:135)(cid:149)(cid:150)(cid:3)

(cid:145)(cid:146)(cid:146)(cid:145)(cid:148)(cid:150)(cid:151)(cid:144)(cid:139)(cid:150)(cid:139)(cid:135)(cid:149)(cid:3)(cid:144)(cid:135)(cid:131)(cid:131)(cid:148)(cid:132)(cid:132)(cid:155)(cid:3)(cid:6)(cid:145)(cid:143)(cid:146)(cid:131)(cid:144)(cid:155)(cid:486)(cid:145)(cid:153)(cid:144)(cid:135)(cid:134)(cid:3)(cid:139)(cid:144)(cid:136)(cid:148)(cid:131)(cid:149)(cid:150)(cid:148)(cid:151)(cid:133)(cid:150)(cid:151)(cid:148)(cid:135)(cid:3)(cid:139)(cid:144)(cid:3)(cid:150)(cid:138)(cid:135)

(cid:135)(cid:154)(cid:146)(cid:142)(cid:145)(cid:148)(cid:131)(cid:150)(cid:139)(cid:145)(cid:144)(cid:3)(cid:153)(cid:135)(cid:142)(cid:142)(cid:3)(cid:139)(cid:144)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:133)(cid:135)(cid:144)(cid:150)(cid:148)(cid:131)(cid:142)(cid:3)(cid:10)(cid:151)(cid:142)(cid:136)(cid:3)(cid:145)(cid:136)(cid:3)(cid:16)(cid:135)(cid:154)(cid:139)(cid:133)(cid:145)(cid:481)(cid:3)(cid:135)(cid:144)(cid:133)(cid:145)(cid:151)(cid:144)(cid:150)(cid:135)(cid:148)(cid:139)(cid:144)(cid:137)

(cid:16)(cid:139)(cid:149)(cid:149)(cid:139)(cid:149)(cid:149)(cid:139)(cid:146)(cid:146)(cid:139)(cid:3)(cid:6)(cid:131)(cid:144)(cid:155)(cid:145)(cid:145)(cid:144)(cid:144)(cid:3)(cid:148)(cid:135)(cid:137)(cid:139)(cid:145)(cid:144)(cid:3)(cid:145)(cid:136)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:10)(cid:151)(cid:142)(cid:136)(cid:3)(cid:145)(cid:136)(cid:3)(cid:16)(cid:135)(cid:154)(cid:139)(cid:133)(cid:145)(cid:484)(cid:3)(cid:23)(cid:138)(cid:148)(cid:145)(cid:151)(cid:137)(cid:138)(cid:145)(cid:151)(cid:150)(cid:3)

(cid:135)(cid:144)(cid:133)(cid:145)(cid:151)(cid:148)(cid:131)(cid:137)(cid:139)(cid:144)(cid:137)(cid:3)(cid:148)(cid:135)(cid:149)(cid:151)(cid:142)(cid:150)(cid:149)(cid:3)(cid:136)(cid:148)(cid:145)(cid:143)(cid:3)(cid:149)(cid:151)(cid:132)(cid:486)(cid:149)(cid:131)(cid:142)(cid:150)(cid:3)(cid:150)(cid:131)(cid:148)(cid:137)(cid:135)(cid:150)(cid:3)(cid:134)(cid:148)(cid:139)(cid:142)(cid:142)(cid:139)(cid:144)(cid:137)(cid:3)(cid:145)(cid:132)(cid:140)(cid:135)(cid:133)(cid:150)(cid:139)(cid:152)(cid:135)(cid:149)(cid:3)(cid:131)(cid:150)(cid:3)

(cid:150)(cid:138)(cid:135)(cid:3)(cid:155)(cid:135)(cid:131)(cid:148)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:146)(cid:142)(cid:131)(cid:131)(cid:144)(cid:149)(cid:3)(cid:150)(cid:145)(cid:3)(cid:135)(cid:154)(cid:146)(cid:142)(cid:145)(cid:148)(cid:135)(cid:3)(cid:136)(cid:145)(cid:148)(cid:3)(cid:131)(cid:150)(cid:150)(cid:148)(cid:131)(cid:133)(cid:150)(cid:139)(cid:152)(cid:135)(cid:3)(cid:145)(cid:146)(cid:146)(cid:145)(cid:148)(cid:150)(cid:151)(cid:144)(cid:139)(cid:150)(cid:139)(cid:135)(cid:149)

(cid:134)(cid:135)(cid:146)(cid:150)(cid:138)(cid:149)(cid:3)(cid:132)(cid:135)(cid:155)(cid:145)(cid:144)(cid:134)(cid:3)(cid:884)(cid:887)(cid:481)(cid:882)(cid:882)(cid:882)(cid:3)(cid:136)(cid:135)(cid:135)(cid:150)(cid:484)

(cid:153)(cid:139)(cid:150)(cid:138)(cid:3)(cid:143)(cid:131)(cid:150)(cid:135)(cid:148)(cid:139)(cid:131)(cid:142)(cid:3)(cid:148)(cid:135)(cid:149)(cid:149)(cid:145)(cid:151)(cid:151)(cid:148)(cid:133)(cid:135)(cid:3)(cid:146)(cid:145)(cid:150)(cid:135)(cid:144)(cid:150)(cid:139)(cid:131)(cid:142)(cid:484)

(cid:12)(cid:144)(cid:3)(cid:884)(cid:882)(cid:884)(cid:884)(cid:481)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:146)(cid:142)(cid:131)(cid:131)(cid:144)(cid:149)(cid:3)(cid:150)(cid:145)(cid:3)(cid:139)(cid:144)(cid:133)(cid:148)(cid:135)(cid:131)(cid:149)(cid:135)(cid:3)(cid:139)(cid:150)(cid:149)(cid:3)(cid:136)(cid:145)(cid:133)(cid:151)(cid:149)(cid:3)(cid:145)(cid:144)(cid:3)(cid:138)(cid:139)(cid:137)(cid:138)(cid:486)(cid:139)(cid:143)(cid:146)(cid:131)(cid:133)(cid:150)(cid:3)

10

TALOS ENERGY

“We are proud to say that we are explorers. 
Every day we push the boundaries of the 
unknown and the impossible. That challenge 
drives our people and underpins our tremendous 
culture that has made us successful. Negative 
bias is just that and nothing more; one can 
(cid:68)(cid:79)(cid:90)(cid:68)(cid:92)(cid:86)(cid:3)(cid:192)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:68)(cid:86)(cid:82)(cid:81)(cid:86)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:71)(cid:85)(cid:76)(cid:79)(cid:79)(cid:3)(cid:68)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:17)(cid:3)(cid:54)(cid:88)(cid:70)(cid:70)(cid:72)(cid:86)(cid:86)(cid:73)(cid:88)(cid:79)(cid:3)
(cid:82)(cid:76)(cid:79)(cid:3)(cid:192)(cid:81)(cid:71)(cid:72)(cid:85)(cid:86)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)(cid:3)(cid:68)(cid:3)(cid:89)(cid:76)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:82)(cid:89)(cid:72)(cid:85)(cid:92)(cid:3)(cid:76)(cid:81)(cid:3)(cid:80)(cid:76)(cid:81)(cid:71)(cid:3)
and focus on compelling reasons to get the well 
(cid:71)(cid:85)(cid:76)(cid:79)(cid:79)(cid:72)(cid:71)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:192)(cid:81)(cid:71)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:81)(cid:72)(cid:91)(cid:87)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:82)(cid:89)(cid:72)(cid:85)(cid:92)(cid:17)(cid:181)

John Parker, Executive Vice 
President – Exploration

Mississippi Canyon(1)(cid:3)(cid:11)(cid:22)(cid:27)(cid:8)(cid:12)

~1.3MM 
GROSS ACRES

Green Canyon(2)(cid:3)(cid:11)(cid:21)(cid:22)(cid:8)(cid:12)

(cid:48)(cid:72)(cid:91)(cid:76)(cid:70)(cid:82)(cid:3)(cid:11)(cid:25)(cid:8)(cid:12)

(cid:54)(cid:75)(cid:72)(cid:79)(cid:73)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:42)(cid:88)(cid:79)(cid:73)(cid:3)(cid:38)(cid:82)(cid:68)(cid:86)(cid:87)(cid:3)(cid:11)(cid:22)(cid:22)(cid:8)(cid:12)

Acreage 
by Area

(1) Acreage includes Atwater Valley, DeSoto Canyon, Mississippi Canyon and Viosca Knoll 
(cid:11)(cid:21)(cid:12)(cid:3)(cid:36)(cid:70)(cid:85)(cid:72)(cid:68)(cid:74)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:86)(cid:3)(cid:40)(cid:90)(cid:76)(cid:81)(cid:74)(cid:3)(cid:37)(cid:68)(cid:81)(cid:78)(cid:15)(cid:3)(cid:42)(cid:68)(cid:85)(cid:71)(cid:72)(cid:81)(cid:3)(cid:37)(cid:68)(cid:81)(cid:78)(cid:86)(cid:15)(cid:3)(cid:42)(cid:85)(cid:72)(cid:72)(cid:81)(cid:3)(cid:38)(cid:68)(cid:81)(cid:92)(cid:82)(cid:81)(cid:15)(cid:3)(cid:46)(cid:72)(cid:68)(cid:87)(cid:75)(cid:79)(cid:72)(cid:92)(cid:3)(cid:38)(cid:68)(cid:81)(cid:92)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:58)(cid:68)(cid:79)(cid:78)(cid:72)(cid:85)(cid:3)(cid:53)(cid:76)(cid:71)(cid:74)(cid:72)

ANNUAL REPORT

11

Carbon Capture and Sequestration
DECARBONIZATION LEADERSHIP

Talos has rapidly established itself as a leader in carbon capture and 
(cid:86)(cid:72)(cid:84)(cid:88)(cid:72)(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:11)(cid:180)(cid:38)(cid:38)(cid:54)(cid:181)(cid:12)(cid:3)(cid:82)(cid:83)(cid:83)(cid:82)(cid:85)(cid:87)(cid:88)(cid:81)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:71)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:192)(cid:70)(cid:68)(cid:81)(cid:87)(cid:79)(cid:92)(cid:3)(cid:85)(cid:72)(cid:71)(cid:88)(cid:70)(cid:72)(cid:3)
emissions from key industrial regions along the U.S. Gulf Coast.

T(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:139)(cid:149)(cid:3)(cid:151)(cid:150)(cid:139)(cid:142)(cid:139)(cid:156)(cid:139)(cid:144)(cid:137)(cid:3)(cid:139)(cid:150)(cid:149)(cid:3)(cid:134)(cid:135)(cid:133)(cid:131)(cid:134)(cid:135)(cid:149)(cid:3)(cid:145)(cid:136)(cid:3)(cid:151)(cid:146)(cid:149)(cid:150)(cid:148)(cid:135)(cid:131)(cid:143)(cid:3)(cid:135)(cid:144)(cid:135)(cid:148)(cid:137)(cid:155)(cid:3)

(cid:135)(cid:154)(cid:146)(cid:135)(cid:148)(cid:139)(cid:135)(cid:144)(cid:133)(cid:135)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:131)(cid:146)(cid:146)(cid:142)(cid:155)(cid:139)(cid:144)(cid:137)(cid:3)(cid:150)(cid:138)(cid:145)(cid:149)(cid:135)(cid:3)(cid:149)(cid:141)(cid:139)(cid:142)(cid:142)(cid:3)(cid:149)(cid:135)(cid:150)(cid:149)(cid:3)(cid:150)(cid:145)(cid:3)(cid:135)(cid:143)(cid:135)(cid:148)(cid:137)(cid:139)(cid:144)(cid:137)(cid:3)(cid:6)(cid:6)(cid:22)(cid:3)

(cid:145)(cid:146)(cid:146)(cid:145)(cid:148)(cid:150)(cid:151)(cid:144)(cid:139)(cid:150)(cid:139)(cid:135)(cid:149)(cid:484)(cid:3)(cid:12)(cid:144)(cid:3)(cid:143)(cid:139)(cid:134)(cid:486)(cid:884)(cid:882)(cid:884)(cid:883)(cid:481)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:153)(cid:131)(cid:149)(cid:3)(cid:131)(cid:153)(cid:131)(cid:148)(cid:134)(cid:135)(cid:134)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:976)(cid:139)(cid:148)(cid:149)(cid:150)(cid:3)(cid:135)(cid:152)(cid:135)(cid:148)(cid:3)

(cid:143)(cid:131)(cid:140)(cid:145)(cid:148)(cid:3)(cid:145)(cid:136)(cid:136)(cid:149)(cid:138)(cid:145)(cid:148)(cid:135)(cid:3)(cid:6)(cid:6)(cid:22)(cid:3)(cid:149)(cid:139)(cid:150)(cid:135)(cid:3)(cid:139)(cid:144)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:24)(cid:484)(cid:22)(cid:484)(cid:481)(cid:3)(cid:141)(cid:144)(cid:145)(cid:153)(cid:144)(cid:3)(cid:131)(cid:149)(cid:3)(cid:5)(cid:131)(cid:155)(cid:145)(cid:151)(cid:3)(cid:5)(cid:135)(cid:144)(cid:134)(cid:3)(cid:6)(cid:6)(cid:22)(cid:481)(cid:3)

(cid:142)(cid:145)(cid:133)(cid:131)(cid:150)(cid:135)(cid:134)(cid:3)(cid:144)(cid:135)(cid:131)(cid:148)(cid:132)(cid:155)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:5)(cid:135)(cid:131)(cid:151)(cid:143)(cid:145)(cid:144)(cid:150)(cid:3)(cid:512)(cid:3)(cid:19)(cid:145)(cid:148)(cid:150)(cid:3)(cid:4)(cid:148)(cid:150)(cid:138)(cid:151)(cid:148)(cid:481)(cid:3)(cid:23)(cid:135)(cid:154)(cid:131)(cid:149)(cid:3)(cid:139)(cid:144)(cid:134)(cid:151)(cid:149)(cid:150)(cid:148)(cid:139)(cid:131)(cid:142)(cid:3)

(cid:133)(cid:145)(cid:148)(cid:148)(cid:139)(cid:134)(cid:145)(cid:148)(cid:484)(cid:3)(cid:22)(cid:139)(cid:144)(cid:133)(cid:135)(cid:3)(cid:150)(cid:138)(cid:131)(cid:150)(cid:3)(cid:131)(cid:144)(cid:144)(cid:145)(cid:151)(cid:144)(cid:133)(cid:135)(cid:143)(cid:135)(cid:144)(cid:150)(cid:481)(cid:3)(cid:23)(cid:131)(cid:142)(cid:145)(cid:149)(cid:3)(cid:138)(cid:131)(cid:149)(cid:3)(cid:147)(cid:151)(cid:139)(cid:133)(cid:141)(cid:142)(cid:155)(cid:3)(cid:132)(cid:151)(cid:139)(cid:142)(cid:150)(cid:3)

(cid:131)(cid:3)(cid:134)(cid:139)(cid:152)(cid:135)(cid:148)(cid:149)(cid:135)(cid:3)(cid:146)(cid:145)(cid:148)(cid:150)(cid:136)(cid:145)(cid:142)(cid:139)(cid:145)(cid:3)(cid:145)(cid:136)(cid:3)(cid:6)(cid:6)(cid:22)(cid:3)(cid:145)(cid:146)(cid:146)(cid:145)(cid:148)(cid:150)(cid:151)(cid:144)(cid:139)(cid:150)(cid:139)(cid:135)(cid:149)(cid:3)(cid:149)(cid:146)(cid:131)(cid:144)(cid:144)(cid:139)(cid:144)(cid:137)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:10)(cid:151)(cid:142)(cid:136)(cid:3)

(cid:6)(cid:145)(cid:131)(cid:149)(cid:150)(cid:481)(cid:3)(cid:136)(cid:148)(cid:145)(cid:143)(cid:3)(cid:6)(cid:145)(cid:148)(cid:146)(cid:151)(cid:149)(cid:3)(cid:6)(cid:138)(cid:148)(cid:139)(cid:149)(cid:150)(cid:139)(cid:481)(cid:3)(cid:23)(cid:135)(cid:154)(cid:131)(cid:149)(cid:3)(cid:150)(cid:145)(cid:3)(cid:9)(cid:148)(cid:135)(cid:135)(cid:146)(cid:145)(cid:148)(cid:150)(cid:481)(cid:3)(cid:23)(cid:135)(cid:154)(cid:131)(cid:149)(cid:3)(cid:150)(cid:145)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)

(cid:16)(cid:139)(cid:149)(cid:149)(cid:139)(cid:149)(cid:149)(cid:139)(cid:146)(cid:146)(cid:139)(cid:3)(cid:21)(cid:139)(cid:152)(cid:135)(cid:148)(cid:3)(cid:139)(cid:144)(cid:134)(cid:151)(cid:149)(cid:150)(cid:148)(cid:139)(cid:131)(cid:142)(cid:3)(cid:133)(cid:145)(cid:148)(cid:148)(cid:139)(cid:134)(cid:145)(cid:148)(cid:3)(cid:132)(cid:135)(cid:150)(cid:153)(cid:135)(cid:135)(cid:144)(cid:3)(cid:5)(cid:131)(cid:150)(cid:145)(cid:144)(cid:3)(cid:21)(cid:145)(cid:151)(cid:137)(cid:135)(cid:3)

(cid:131)(cid:144)(cid:134)(cid:3)(cid:17)(cid:135)(cid:153)(cid:3)(cid:18)(cid:148)(cid:142)(cid:135)(cid:131)(cid:144)(cid:149)(cid:481)(cid:3)(cid:15)(cid:145)(cid:151)(cid:139)(cid:149)(cid:139)(cid:131)(cid:144)(cid:131)(cid:484)(cid:3)

(cid:23)(cid:138)(cid:135)(cid:3)(cid:6)(cid:145)(cid:143)(cid:146)(cid:131)(cid:144)(cid:155)(cid:3)(cid:146)(cid:142)(cid:131)(cid:144)(cid:149)(cid:3)(cid:150)(cid:145)(cid:3)(cid:131)(cid:134)(cid:152)(cid:131)(cid:144)(cid:133)(cid:135)(cid:3)(cid:146)(cid:148)(cid:135)(cid:142)(cid:139)(cid:143)(cid:139)(cid:144)(cid:131)(cid:148)(cid:155)(cid:3)(cid:135)(cid:144)(cid:137)(cid:139)(cid:144)(cid:135)(cid:135)(cid:148)(cid:139)(cid:144)(cid:137)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)

(cid:146)(cid:135)(cid:148)(cid:143)(cid:139)(cid:150)(cid:150)(cid:139)(cid:144)(cid:137)(cid:3)(cid:146)(cid:148)(cid:145)(cid:133)(cid:135)(cid:149)(cid:149)(cid:135)(cid:149)(cid:3)(cid:139)(cid:144)(cid:3)(cid:884)(cid:882)(cid:884)(cid:884)(cid:3)(cid:131)(cid:144)(cid:134)(cid:3)(cid:151)(cid:142)(cid:150)(cid:139)(cid:143)(cid:131)(cid:150)(cid:135)(cid:142)(cid:155)(cid:3)(cid:138)(cid:145)(cid:146)(cid:135)(cid:149)(cid:3)(cid:150)(cid:145)(cid:3)(cid:132)(cid:151)(cid:139)(cid:142)(cid:134)(cid:3)

(cid:131)(cid:144)(cid:3)(cid:139)(cid:144)(cid:134)(cid:151)(cid:149)(cid:150)(cid:148)(cid:155)(cid:486)(cid:142)(cid:135)(cid:131)(cid:134)(cid:139)(cid:144)(cid:137)(cid:3)(cid:6)(cid:6)(cid:22)(cid:3)(cid:132)(cid:151)(cid:149)(cid:139)(cid:144)(cid:135)(cid:149)(cid:149)(cid:3)(cid:133)(cid:131)(cid:146)(cid:131)(cid:132)(cid:142)(cid:135)(cid:3)(cid:145)(cid:136)(cid:3)(cid:149)(cid:139)(cid:137)(cid:144)(cid:139)(cid:976)(cid:139)(cid:133)(cid:131)(cid:144)(cid:150)(cid:142)(cid:155)(cid:3)
(cid:148)(cid:135)(cid:134)(cid:151)(cid:133)(cid:139)(cid:144)(cid:137)(cid:3)(cid:139)(cid:144)(cid:134)(cid:151)(cid:149)(cid:150)(cid:148)(cid:139)(cid:131)(cid:142)(cid:3)(cid:6)(cid:18)(cid:884)(cid:3)(cid:135)(cid:143)(cid:139)(cid:149)(cid:149)(cid:139)(cid:145)(cid:144)(cid:149)(cid:3)(cid:131)(cid:133)(cid:148)(cid:145)(cid:149)(cid:149)(cid:3)(cid:150)(cid:138)(cid:135)(cid:3)(cid:10)(cid:151)(cid:142)(cid:136)(cid:3)(cid:6)(cid:145)(cid:131)(cid:149)(cid:150)(cid:484)(cid:3)

FOUR 

ANNOUNCED PROJECTS

~80,000

ACRES ACROSS THE U.S. GULF COAST

~850MM

METRIC TONS OF EST. SEQUESTRATION CAPACITY

BAYOU BEND CCS

FREEPORT LNG CCS

Freeport LNG Photo

RIVER BEND CCS

COASTAL BEND CCS

12

TALOS ENERGY

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 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

Talos Energy Inc.
(Exact name of Registrant as specified in its Charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
333 Clay Street, Suite 3300
Houston, TX
(Address of principal executive offices)

82-3532642
(I.R.S. Employer
Identification No.)

77002
(Zip Code)

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

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

Title of Each Class

Common Stock

Trading Symbol(s)

Name of Each Exchange on Which Registered

TALO

NYSE

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☑

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, 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
Non-accelerated filer
Emerging growth company

☑
☐
☐

Accelerated filer
Smaller reporting 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over
financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit
report. ☑

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

The aggregate market value of the voting and non-voting common equity held by non-affiff liates of the registrant, based on the closing price of the shares of common
stock on the New York Stock Exchange on June 30, 2021, was $703,193,887.

The number of shares of registrant’s Common Stock outstanding as of February 17, 2022 was 81,881,477.

Portions of the registrant’s definitive proxy statement relating to the 2022 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

GLOSSARY ........................................................................................................................................................
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS........................
SUMMARY RISK FACTORS ..........................................................................................................................

PART I

Item 5.

Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 9C.

Items 1 and 2. Business and Properties ...............................................................................................................
Risk Factors .................................................................................................................................
Item 1A.
Unresolved Staff Comments........................................................................................................
Item 1B.
Legal Proceedings........................................................................................................................
Item 3.
Mine Safety Disclosures..............................................................................................................
Item 4.
PART II
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
Of Equity Securities.....................................................................................................................
[Reserved]....................................................................................................................................
Management’s Discussion and Analysis of Financial Condition and Results of Operations .....
Quantitative and Qualitative Disclosures About Market Risk ....................................................
Financial Statements and Supplementary Data ...........................................................................
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .....
Controls and Procedures..............................................................................................................
Other Information ........................................................................................................................
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections ........................................
PART III
Directors, Executive Officers and Corporate Governance ..........................................................
Executive Compensation .............................................................................................................
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters .........................................................................................................................................
Certain Relationships and Related Transactions, and Director Independence ............................
Principal Accounting Fees and Services .....................................................................................
PART IV
Exhibits and Financial Statement Schedules ...............................................................................
Form 10-K Summary...................................................................................................................

Item 10.
Item 11.
Item 12.

Item 13.
Item 14.

Item 15.
Item 16.

Page
3
5
7

9
37
63
63
64

65
66
67
84
85
85
86
86
86

87
87

87
87
87

88
93

2

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.

Boepd — Barrels of oil equivalent per day.

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

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

Deepwater — Water depths of more than 600 feet.

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

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.

Gross acres or gross wells — The total acres or wells in which the Company owns a working interest.

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.

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

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.

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

3

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

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

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

PV-10 — The present value of estimated future revenues, discounted at 10% annually, to be generated from the
production of proved reserves determined in accordance with SEC guidelines, net of estimated production and
future development costs, using prices and costs as of the date of estimation without future escalation, without
giving effect to (i) non-property related expenses such as general and administrative expenses, derivatives, debt
service and future income tax expense or (ii) depreciation depletion and amortization expense.

SEC — The Securities and Exchange Commission.

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

Shelf — Water depths up to 600 feet.

Standardized Measure — The present value of estimated future net revenue to be generated from the production
of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC
and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of
estimation), less future development, production and income tax expenses, and discounted at 10% per annum
to reflect the timing of future net revenue.

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

Working interest — 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 (“API”) gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

4

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Annual Report on Form 10-K (this “Annual 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 Annual 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 Annual 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:







































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









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,
expenditures;

liquidity and capital required for our development program and other capital

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 our carbon capture and storage opportunities;

our ongoing strategy with respect to our Zama asset;

uncertainty regarding our future operating results and our future revenues and expenses; and

plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

5

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of
which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to,
commodity price volatility due to the continued impact of the coronavirus disease 2019 (“COVID-19”), including any
new strains or variants and governmental measures related thereto on global demand for oil and natural gas and on the
operations of our business; the ability or willingness of OPEC and other state-controlled oil companies (“OPEC Plus”)
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; cybersecurity threats;
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 acquisitions are not realized when expected or at all, including as a result of the impact of, or problems
arising from, the integration of acquired assets and operations, and the other risks discussed in Part I, Item 1A. Risk
Factors which are included herein.

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 Annual 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 Annual
Report.

6

Risks Related to our Business and the Oil and Natural Gas Industry

SUMMARY RISK FACTORS





































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

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

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

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

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

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

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

If we are forced to shut-in production, we will likely incur greater costs to bring the associated production
back online, and will be unable to predict the production levels of such wells once brought back online.

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

Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-
19, may materially adversely affect our business.

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

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

Hedging transactions may limit our potential gains.

Our operations may incur substantial liabilities to comply with environmental laws and regulations as
well as legal requirements applicable to marine mammals and endangered and threatened species.

We may be unable to provide the financial assurances in the amounts and under the time periods required
by the BOEM if it submits future demands to cover our decommissioning obligations. If in the future the
BOEM issues orders to provide additional financial assurances and we fail to comply with such future
orders, the BOEM could elect to take actions that would materially adversely impact our operations and
our properties, including commencing proceedings to suspend our operations or cancel our federal
offshore leases.

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

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

We may experience significant shut-ins and losses of production due to the effects of tropical storms and
hurricanes in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico.

7

Risks Related to our Capital Structure and Ownership of our Common Stock



















Our debt level and the covenants in our current or future agreements governing our debt, including our
Bank Credit Facility and the indenture for our 12.00% Second-Priority Senior Secured Notes, could
negatively impact our financial condition, results of operations and business prospects. Our failure to
comply with these covenants could result in the acceleration of our outstanding indebtedness.

ff

A financial
to obtain funding under our Bank Credit Facility or in the capital markets.

crisis may impact our business and financial condition and may adversely impact our ability

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

We are a holding company that has no material assets other than our ownership of the equity interests of
Talos Production Inc. Accordingly, we are dependent upon distributions from Talos Production Inc. to
pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common
stock.

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

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

Our future acquisitions could expose us to potentially significant liabilities, including P&A liabilities.

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

The interests of the Riverstone Funds may differ from the interests of our other stockholders.

8

Items 1 and 2. Business and Properties

Overview

PART I

As used in this Annual Report and unless otherwise indicated or the context otherwise requires, references to
“we,” “us,” “our,” “Talos Energy Inc.,” “Talos” and the “Company” refer to Talos Energy Inc. and its consolidated
subsidiaries.

We were incorporated on November 14, 2017 under the laws of the state of Delaware for the purpose of effecting
the business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”), pursuant to which
each of Talos Energy LLC and Stone became our wholly-owned subsidiary. We refer to this business combination as
the “Stone Combination,” and its date of consummation, May 10, 2018, as the “Stone Closing Date.”

We are 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. We leverage decades of technical and offshore
operational expertise in the acquisition, exploration and development of assets in key geological trends that are present
on environmental stewardship, we also utilize our expertise
in many offshore basins around the world. With a focus
to explore opportunities to reduce industrial emissions through our carbon capture and storage collaborative
arrangements along the coast of the U.S. Gulf of Mexico.

ff

We combine our technical experience in geology, geophysics and engineering with innovative resource
evaluation techniques and seismic imaging expertise to discover new resources. We rely on our operational experience
to safely and responsibly optimize production and recovery from our assets. Finally, we leverage our commercial and
corporate management experience to most effectively allocate our capital to balance risk and reward, grow our
business and maximize long-term stockholder value.

Business Strategy

We intend to increase stockholder value by growing our hydrocarbon reserves, production, cash flow and future
growth opportunities in a capital efficient manner, while exploring potential carbon capture and sequestration (“CCS”)
opportunities with aspirations to become a contributor to U.S. emissions reduction goals. Our deep technical expertise
and extensive physical operating experience allow us to successfully manage our hydrocarbon business asset base and
consistently make attractive acquisitions, thereby increasing stockholder value over time. Additionally, we believe
these same core competencies can be utilized to develop and commercialize future CCS opportunities.

Hydrocarbon Strategy

We maintain a large and diverse in-house technical staff focused on geology, geophysics, engineering and other
technical disciplines, providing many decades of exploration and production experience in the key resource trends in
which we focus. Our significant library of seismic data resources, which focuses on the U.S. Gulf of Mexico and
offshore Mexico, allows our technical team to apply proprietary seismic reprocessing techniques to evaluate or re-
evaluate potential resources across our asset portfolio. Finally, we have deep in-house experience across our offshore
operations, production operations, safety, facilities and business development.

Our strategic business development activities allow us to consistently identify and evaluate new opportunities
through a wide range of potential avenues, including government lease sales, joint ventures and acquisitions, among
others. Our proven track record of success through organic drilling opportunities frequently attracts potential drilling
partners in projects that we operate, while in non-operated projects we leverage our core competencies to
independently identify the best investment opportunities, review partner-proposed projects and be a value-added
contributor. Our asset acquisition strategy is focused on assets with a geological setting that can benefit from our
ability to use our seismic database and technical expertise to re-evaluate and improve the acquired properties.
Specifically, our acquisition focus areas target a variety of potential situations and sellers that are currently available
in offshore basins, including single asset acquisitions, consolidation of private companies and broader asset package
transactions. We seek to actively participate in government lease sales to identify and acquire attractive leasehold
acreage, which in many cases has not been evaluated with the latest reprocessed seismic data, resulting in an
opportunity for us to identify previously unknown drilling prospects.

9

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
asset acquisition market.

Utilizing our core competencies in conjunction with a robust and active business development effort allows us

to use the following strategies to increase stockholder value:









Continuously Optimizing our Existing Asset Base — We benefit from our proven ability to enhance and
extend the life of existing projects within our portfolio. Investments in optimization projects across our
asset base aim to stabilize and improve the profile of producing assets by increasing recovery, production
and cash flow with typically relatively low investment capital and risk. These projects allow for
reinvestment opportunities in exploitation and exploration projects.

Conducting Development and Near-Field Projects In and Around Our Existing Asset Footprint — We
undertake asset development and exploitation drilling projects in close proximity to our existing assets as
well as facilities that we either own or have access to. These projects leverage ongoing operations and
existing technical knowledge of the area, often coupled with recent proprietary seismic reprocessing
evaluations to provide attractive incremental investment opportunities to grow reserves, production and
cash flow in well-understood areas.

Our asset footprint, which includes operational control of several key shallow and Deepwater facilities,
allows us to invest in a diverse set of opportunities ranging from in-field development to high impact
exploration projects while optimizing our facilities to lower incremental operating costs structures. We
for
also believe our operated infrastructure can be attractive to other operators looking for a host facility
their subsea tie-back projects, which allows us either to be involved in new investment opportunities or
to offset the operating cost of these facilities.

ff

Engaging in Exploration Activities to Grow our Asset Base and Potentially Unlock Significant New
Resources — We conduct exploration drilling activities across our acreage set with risk-weighted
investments that could establish significant new reserves and production. These projects are intended to
optimize risk and reward across our portfolio of prospective drilling opportunities by finding and
developing previously undiscovered resources along existing or emerging geological trends with the most
efficient deployment of capital. When successful, exploration drilling activities can organically generate
material new assets for the Company.

Utilize Acquisitions and Other Business Development Activities to Expand our Asset Base, Opportunity
Set and Value Creation Potential — We rely on our commercial and business development activities to
expand our asset base through the acquisition or optimization of additional or existing properties,
respectively. Commercial and business development provides a key avenue to create additional value
from the acquisition of undervalued properties where we can apply our technical and operational
competencies to generate upside. Additionally, we utilize business development
to acquire new
leaseholds, enter new projects and increase or decrease working interests in various existing projects to
optimize capital planning and our
targeted risk/return profile for varying business conditions.
Consolidation opportunities in our basin and, more broadly, in the offshore exploration and production
segment in other basins around the world, are numerous and span a wide range of lifecycle stages, sizes
and geographic variables. We expect to continue utilizing acquisitions and business development to grow
our business in a manner that preserves a strong and healthy credit profile as well as a diverse and high-
quality asset base.

10



Maintain Safety, Environmental Responsibility and Sustainability as Key Principles for Operations
Across All Areas of our Business — We are focused on maintaining high standards of safety,
environmental responsibility and corporate citizenship across all elements of our business. We closely
monitor safety performance and consistently take steps to improve our performance. For the year ended
2021, we maintained a high level of safety performance with a lower recordable incident rate when
compared to the average for offshore operators in the U.S. Gulf of Mexico as well as across numerous
other industrial sectors of the broader economy. We strive to execute our business plan while
simultaneously minimizing our environmental footprint, including emissions, potential spills and other
impacts. Due to the nature of subsea wells and ample offshore pipelines, we believe the offshore operating
environment is a region where greenhouse gas (“GHG”) emissions can continue to be lowered over time.
Finally, we aim to be a good corporate citizen in the regions and communities where we operate. We
recently published our second annual Environmental, Social, and Governance (“ESG”) report highlighting
our performance and initiatives across all of these categories and other topics, which is not incorporated
into, and does not form a part of, this Annual Report.

Carbon Capture and Sequestration Strategy

Our CCS business intends to leverage our experience and technical expertise in the U.S. Gulf of Mexico,
including sub-surface engineering expertise, seismic data sets and interpretation capabilities, operational experience
offshore and along the coast and a solid track record of safety and environmentally responsible operations. The U.S.
Gulf of Mexico coast (“Gulf Coast”) is a critical industrial region with a large emissions footprint, while the underlying
conventional geology in the area is believed by us to be ideal for carbon sequestration. We intend to provide carbon
dioxide removal solutions to assist industrial partners with carbon emissions capture, transportation and injection into
sequestration sites that we intend to operate in the region.

Future CCS project opportunities and the associated sequestration sites can generally be categorized into two

project classifications where we intend to identify, lease and operate in order to increase stockholder value:





Regional Hub Projects — These will be large, contiguous sequestration sites located nearby large
industrial emissions centers in which we could consolidate carbon emissions from multiple contributing
sources and develop large-scale CCS projects. Hub projects can be characterized by their large size,
population of diverse contributing emitters and central proximity to major emitting regions.

Point Source Projects — These will be customized sequestration projects for individual industrial
partners to capture and eliminate carbon emissions from singular sources, such as liquefied natural gas
(“LNG”) facilities, manufacturing plants or power generation facilities, among others. Point source
projects can be characterized by their smaller scale, individual emissions source (i.e. one plant) and
location nearby or on-site to that emissions source. Point source projects may carry a wider range of
commercial structures than hub projects due to their customized and directly negotiated nature, and we
believe the total number of point source opportunities along the U.S. Gulf Coast to be significant.

Hydrocarbon Properties

United States Gulf of Mexico

Our area of focus in the United States is the Gulf of Mexico Deepwater. Our strategy is focused in areas
characterized by clearly defined infrastructure, well-known production history and geological well control, which
reduces operational and investment risk. We believe the potential for large discoveries and increasing success rates in
the sub-salt and mini-basin lower Pliocene and Miocene plays has resulted in increased industry focus on this area
over the last decade.

We believe our Deepwater operations in the U.S. Gulf of Mexico provide significant potential growth
opportunities through our planned drilling program. Through our technical approach of starting with known
hydrocarbon systems and applying modern seismic reprocessing techniques, we have generated a substantial inventory
of Deepwater prospects that we believe are capable of delivering predictable production growth. We primarily focus
our exploitation and exploration efforts around our existing infrastructure. This subsea tie-back strategy allows for
better project economics and shorter periods between a discovery and production.

11

As of December 31, 2021, our core areas in the United States are illustrated below:

Texas

Gulf of Mexico
Shelf

Louisiana

Pompano

Viosca Knoll

Ram Powell

Amberjack

Mississippi
Canyon

GC18

Ewing Bank

DeSoto
Canyon

Delta
House

East Breaks

Phoenix HP1

Garden Banks

Green Canyon

Atwater Valley

Talos Acreage

Talos Seismic

Keathley Canyon

Walker Ridge

Gulf of
Mexico

The following table sets forth a summary of certain key 2021 information regarding our core areas in the United

States:

Green Canyon
Mississippi Canyon
Shelf & Gulf Coast

Total United States

Estimated Proved Reserves

% Oil

% Natural
Gas

% NGLs

% Proved
Developed

Net
Production
(MBoe)

%
Operated

79%
75%
38%
67%

14%
16%
51%
24%

7%
9%
11%
9%

81%
90%
79%
84%

7,765
9,643
6,092
23,500

98%
52%
53%
68%

MBoe
52,777
67,349
41,465
161,591

Green Canyon — Green Canyon is a Deepwater region in the Central U.S. Gulf of Mexico and is a key focus
area both industry-wide and for our exploration activities. We operate two production facilities in the region, including
a floating
production unit, the Helix Producer I (“HP-I”), that is leased from Helix Energy Solutions Group, Inc.
(“Helix”).

ff

Mississippi Canyon — Mississippi Canyon is a Deepwater region in the eastern portion of the Central U.S Gulf
of Mexico with a track record of prolific production and ongoing exploration success that continues to unlock new
resources. We operate three production facilities in the region and are active as both an operator and non-operating
partner in numerous development projects and producing fields.

Shelf and Gulf Coast — The U.S. Gulf of Mexico Shelf (the “Shelf”) and Gulf Coast area spans an enormous
geographical area across the basin and provides diverse production from numerous operated production facilities. The
Shelf area is a producing region of the basin with attractive redevelopment and recovery enhancement opportunities.

12

Mexico

Our area of focus in Mexico is Block 7 located within the Sureste Basin, a prolific proven hydrocarbon province,
in the shallow waters off the coast of Mexico’s Tabasco state. As of December 31, 2021, our core area in Mexico is
illustrated below:

Block 7

Gulf of
Mexico

Talos Acreage

Talos Seismic

Veracruz

Tabasco

Block 7 — On July 15, 2015, a Talos-led consortium was awarded Block 7 (“Block 7 Consortium”) with a term
of thirty years, starting in September 2015, and extendable for two additional five-year periods. The Company’s
participation interest (“PI”) in Block 7 is 35% and we are the operator. The Block 7 Consortium made a significant
discovery in Block 7 after drilling the Zama-1 in 2017, less than two years after signing a production sharing contract
(“PSC”) for the block with Mexico's upstream oil and gas regulator, the National Hydrocarbon Commission (“CNH”).
Subsequent to the Zama-1 discovery, we drilled three additional wells to further appraise the discovery.

Upon conclusion of the three well appraisal program, we determined that the Zama Field likely extended into a
nearby offshore block owned by Petróleos Mexicanos (“PEMEX”). On July 7, 2020, we received a notice from
Mexico’s Secretaría de Energía (“Ministry of Energy” or “SENER”) instructing the Block 7 Consortium and PEMEX
to unitize the Zama Field. The Block 7 Consortium and PEMEX engaged a third-party reservoir engineering firm to
evaluate initial tract participation within the Zama reservoir, which concluded that the Block 7 Consortium holds
49.6% of the gross interest in the Zama Field and PEMEX holds 50.4%. On July 2, 2021, we were notified by SENER
that it had designated PEMEX as the operator of the Zama unit. During the third quarter of 2021, we submitted Notices
of Dispute (“Notices of Dispute”) to the Government of Mexico over decisions taken by SENER, including the
designation of PEMEX as the operator of a yet-to-be unitized asset.

The PSC forms the basis for the Company’s exploration, development and production operations on Block 7.
The Block 7 PSC includes a cost recovery feature pursuant to which eligible costs in relation to the minimum work
program activities are recoverable in-kind at a rate of 125% of costs from future production volumes. Production
volumes are allocated in-kind between the Block 7 Consortium and the United Mexican States on a monthly basis
based on the contractual value of the hydrocarbons as defined in the PSC. Up to 60% of the monthly contractual value
of the hydrocarbons will be allocated to the Block 7 Consortium to recover eligible costs incurred in petroleum
activities. Eligible costs exceeding 60% of the current month contractual value of the hydrocarbons will be recoverable
in future periods. The amount of royalties will be determined for each type of hydrocarbons (oil, associated natural
gas, non-associated natural gas and condensate) using an initial rate, adjusted thereafter for inflation. The remaining
value of the hydrocarbons after the allocation for cost recovery and royalties is considered operating profit under the
PSC. The allocation of operating profit to the Block 7 Consortium after the allocation for cost recovery and royalties
is 31%. The profit for oil and gas is determined on a monthly basis using an adjustment mechanism based on the
projects rate of return (“ROR”). If the cumulative project’s ROR in any one month exceeds 25%, the barrels of oil
allocated to the Block 7 Consortium after cost recovery are reduced on a sliding scale. Once the cumulative project’s
internal ROR meets or exceeds 40%, the reduction locks in at a maximum rate. The Hydrocarbons Revenue Law
provides that exploration and extraction activities are zero rated for value-added tax (“VAT”) purposes; all other
activities are taxed at 16% VAT. The 0% rates only apply to agreements between the United Mexican States and state-
owned enterprises or entities, and do not apply to any other agreement executed with third parties, even in the case of
exploration and extraction contracts. The Mexico income tax rate is 30%.

13

Block 31 — We own a 25% PI in Block 31, which is operated by Hokchi Energy, S.A. de C.V. (“Hokchi”), a
subsidiary of Pan American Energy LLC. To date, we have participated in a two-well drilling campaign that was
conducted during 2019. In considering the appraisal program proposed by Hokchi for Block 31, we made an election
to non-consent the program in order to allow us to allocate capital to other projects. We recorded an impairment of
$18.1 million for our unproved property investment in Block 31 during the year ended December 31, 2021, as the
costs were not recoverable. This non-cash impairment is presented in “Write-down of oil and natural gas properties”
on our Consolidated Statements of Operations in Part IV, Item 15. Exhibits and Financial Statement Schedules.

Carbon Capture & Sequestration

We are leveraging decades of experience with conventional geology and offshore energy operations to pursue
our goal of developing future carbon capture and storage opportunities. We are actively evaluating potential project
opportunities through our collaborative arrangements along the U.S. Gulf Coast. Our areas of development are
illustrated below:

Jefferson County GLO

Gulf of Mexico
Shelf

Texas

Freeport LNG

East Breaks

River Bend CCS

Louisiana

Viosca Knoll

DeSoto
Canyon

Mississippi
Canyon

Ewing Bank

Garden Banks

Green Canyon

Atwater Valley

Talos Acreage

Talos Seismic

Keathley Canyon

Walker Ridge

Gulf of
Mexico

Jefferson County GLO Hub Project — In August 2021, we, along with partner Carbonvert, Inc., were selected as
the winning bidder for the Texas General Land Office's (“GLO”) Jefferson County carbon storage site. The successful
bid makes us the operator of what we expect to be the first large-scale offshore carbon storage location in the United
States near the Beaumont and Port Arthur, Texas industrial corridor. As of December 31, 2021, the lease with the
Texas GLO remained subject to negotiation of final terms, which we expect to conclude and finalize in mid-2022.

Freeport LNG Point Source Project — In November 2021, we announced that, along with partner Storegga
Geotechnologies Limited (“Storegga”), we had executed a letter of intent with an affiliate of Freeport LNG
Development, L.P. (“Freeport LNG”) to develop a CCS project immediately adjacent to its existing LNG pre-
treatment facilities in Freeport, Texas. The project intends to utilize a Freeport LNG-owned geological sequestration
site located less than half a mile from point of capture with up to a 30-year injection term, and thus the project benefits
from a dedicated source of carbon dioxide (“CO2”) and a secured injection site in close physical proximity. The
companies anticipate first
injection could occur by the end of 2024. As of December 31, 2021, definitive
documentation with Freeport LNG remained subject to negotiation of final terms, which we expect to conclude and
finalize in early 2022.

14

River Bend Hub Project — In February 2022, we announced our entry into (i) a lease agreement for a major carbon
capture and sequestration project along the Mississippi River industrial corridor and (ii) a memorandum of
understanding with EnLink Midstream, LLC (“EnLink”) to jointly develop a carbon capture, transportation and
sequestration joint service offering focused on the Mississippi River industrial corridor. The joint service offering is
being marketed to potential customers by both us and EnLink. The lease agreement will allow for three sequestration
sites near EnLink’s existing pipelines. We will be the project manager and operator of the injection, storage, and
monitoring and will be joined by our partner, Storegga.

Summary of Reserves

The following table summarizes our estimated proved reserves which are all located in the United States:

December 31, 2021
Proved developed producing
Proved developed non-Producing

Total proved developed

Proved undeveloped

Total proved
December 31, 2020
Proved developed producing
Proved developed non-producing

Total proved developed

Proved undeveloped

Total proved
December 31, 2019
Proved developed producing
Proved developed non-producing

Total proved developed

Proved undeveloped

Total proved

Oil
(MBbls)

Natural Gas
(MMcf)

NGL
(MBbls)

MBoe

Standardized
Measure
(in thousands)

PV -10
(in thousands)

70,183
23,237
93,420
14,344
107,764

64,763
20,244
85,007
24,300
109,307

53,777
18,239
72,016
34,738
106,754

108,238
78,204
186,442
49,911
236,353

119,824
84,230
204,054
53,154
257,208

64,192
51,189
115,381
40,617
155,998

7,426
4,366
11,792
2,643
14,435

4,958
3,146
8,104
2,754
10,858

3,855
2,878
6,733
2,248
8,981

$

95,649
40,637
136,286
25,305
161,591 $ 3,440,611 $

$

89,692
37,428
127,120
35,913
163,033 $ 1,904,934 $

$

68,331
29,648
97,979
43,756
141,735 $ 2,537,595 $

3,073,168
599,010
3,672,178
253,819
3,925,997

1,556,221
197,924
1,754,145
244,340
1,998,485

1,837,964
378,244
2,216,208
776,814
2,993,022

Reconciliation of Standardized Measure to PV-10

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net
cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the
standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized
measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted
at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted
future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate
income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas
properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our
reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure
when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not
a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized
measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of the standardized measure of discounted future net cash flows

to PV-10 of our proved reserves (in thousands):

Standardized measure
Present value of future income taxes discounted at 10%
PV-10 (Non-GAAP)

$

$

Year Ended December 31,

2021
3,440,611 $
485,386
3,925,997 $

2020
1,904,934 $
93,551
1,998,485 $

2019
2,537,595
455,427
2,993,022

15

Changes in Proved Developed Reserves

The following table discloses our estimated changes in proved developed reserves:

Proved developed reserves at December 31, 2020
Changes during the year:

Production
Revisions of previous estimates
Additions
Conversion to proved developed producing reserves

Total proved developed reserves changes
Proved developed reserves at December 31, 2021

Oil, Natural Gas
and NGLs
(MBoe)

127,120

(23,500)
15,076
1,806
15,784
9,166
136,286

Our proved developed reserves at December 31, 2021 increased by 9.2 MMBoe, or 7% primarily due to:

Revisions of Previous Estimates — Upward revisions of 15.1 MMBoe are primarily attributable to a 13.2
MMBoe increase in commodity prices as well as net increase of 1.9 MMBoe in performance revisions across our core
areas.

Additions — Additions of 1.8 MMBoe are primarily attributable to the successful drilling in the Crown and

Anchor Field located in the Mississippi Canyon core area.

Development of Proved Undeveloped Reserves

The following table discloses our estimated proved undeveloped (“PUD”) reserve activities:

Proved undeveloped reserves at December 31, 2020
Changes during the year:

Revisions of previous estimates
Conversion to proved developed producing reserves

Total proved undeveloped reserves changes
Proved undeveloped reserves at December 31, 2021

Oil, Natural Gas
and NGLs
(MBoe)

Future
Development
Costs

(in thousands)

35,913 $

5,176
(15,784)
(10,608)
25,305 $

315,453

64,423
(71,844)
(7,421)
308,032

Our PUD reserves at December 31, 2021 decreased by 10.6 MMBoe, or 30% primarily due to:

Revisions of Previous Estimates — Upward revisions of 5.2 MMBoe are primarily attributable to an increase

in commodity prices across our core areas.

Conversion to Proved Developed Producing — Conversions of 15.8 MMBoe are primarily attributable to our
Deepwater drilling campaign which included successful development wells in our Phoenix Field and Grand Canyon
18 Field located in the Green Canyon core area.

We annually review all PUD reserves to ensure an appropriate plan for development exists. Our PUD reserves
are required to be converted to proved developed reserves within five years of the date they are first booked as PUD
reserves, unless the reserves are associated with an existing producing zone. Future development costs associated with
our PUD reserves at December 31, 2021 totaled approximately $308.0 million, of which $123.0 million, $93.7 million
and $91.3 million is attributable to our Green Canyon, Shelf and Gulf Coast and Mississippi Canyon core areas,
respectively. When considering capital expenditures associated with other exploration projects and abandonment
obligations, we expect to fund the development of PUD reserves using cash flows from operations and, if needed,
availability under the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”), in each
future annual period prior to the five year expiration. Our 2022 drilling program includes development of PUD
reserves, and the conversion rate may not be uniform due to obligatory wells, newly acquired PUD reserves and
production performance targets.

16

Internal Controls over Reserve Estimates and Reserve Estimation Procedures

At December 31, 2021, 2020 and 2019, proved oil, natural gas and NGL reserves attributable to our net interests
in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and
audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists, as
described in further detail below.

Our policies regarding internal controls over the determination of reserves estimates require reserves quantities,
reserves categorization, future producing rates, future net revenue and the present value of such future net revenue
prepared using the definitions set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and
guidance. These internal controls, which are intended to ensure reliability of our reserves estimations, include, but are
not limited to, the following:















reserve information, as well as models used to estimate such reserves, is stored on secure database
applications to which only authorized personnel are given access rights consistent with their assigned job
function;

a comparison of historical expenses is made to the lease operating costs in the reserve database;

internal reserves estimates are reviewed by well and by area by our reservoir engineers. A variance
analysis by well to the previous year-end reserve report is performed;

reserve estimates are reviewed and approved by certain members of senior management, including our
President and Chief Executive Officer;

our management requires that the independent petroleum engineers and geologists and our reserve
quantities and calculation of the net present value of the reserves, collectively, vary by no more than 10%
in the aggregate, in accordance with Society of Petroleum Evaluation Engineers (“SPEE”) auditing
standards;

data is transferred to NSAI through a secure file transfer protocol site; and

material reserve variances are discussed among NSAI, as applicable, our internal reservoir engineers and
our Director of Reserves to ensure the best estimate of remaining reserves.

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual
results, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are ultimately
recovered.

During the reserves audit, NSAI did not independently verify the accuracy and completeness of information and
data furnished by us with respect to ownership interests, oil, natural gas and NGL production, well test data, historical
costs of operation and development, product prices or any agreements relating to current and future operations of the
fields and sales of production. However, if in the course of the examination something came to the attention of NSAI
that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such
information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such
information or data. When compared on a well by well basis, some of our estimates are greater and some are less than
the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves,
differences between internal and external estimates are to be expected. NSAI determined that its estimates of reserves
have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable
certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic
and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. NSAI issued
unqualified audit opinions on our reserves as of December 31, 2021, 2020 and 2019 based upon its evaluations. NSAI
concluded that our estimates of reserves were, in the aggregate, reasonable and have been prepared in accordance with
Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPEE.
The 2021 NSAI report is filed as Exhibit 99.1 to this Annual Report.

17

Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from
projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes
reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil,
natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our
internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and
repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not
limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information
and property ownership interests. The accuracy of the estimates of our reserves is a function

of:

ff









the quality and quantity of available data and the engineering and geological interpretation of that data;

estimates regarding the amount and timing of future operating costs, development costs and workovers,
all of which may vary considerably from actual results;

future prices of oil, natural gas and NGLs, which may vary considerably from those mandated by the
SEC; and

the judgment of the persons preparing the estimates.

Qualifications of Primary Internal Engineer

Our Director of Reserves is the technical person primarily responsible for overseeing the preparation of our
internal reserve estimates and for coordinating reserve audits conducted by NSAI. He has over 47 years of industry
experience with positions of increasing responsibility, including 39 years as a reserves evaluator or manager. His
further professional qualifications include a State of Texas Professional Engineering License, extensive internal and
external reserve training and asset evaluation. In addition, he is an active participant in industry reserve seminars and
professional industry groups, and has been a member of the Society of Petroleum Engineers for over 47 years. He
reports directly to our Vice President of Corporate Development.

Drilling Activity

The following table sets forth our drilling activity:

Exploratory and Appraisal Wells
Dry(2)
y

y

Development Wells
Dry(2)
y

Productive(1)
Productive(1)
Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net

Total

Total

Total

December 31, 2021
United States
Mexico
Total

December 31, 2020
United States(3)
Mexico
Total

December 31, 2019
United States
Mexico
Total

3.9
— — 2.0
— — — — — — — — — — — — — —
3.9
— — 2.0

2.4 — — 5.0

2.4 — — 5.0

1.5

5.0

7.0

2.4

5.0

2.0

7.0

2.0

1.5

2.4

1.5

1.5

0.7 — — 2.0

2.0
2.6
— — — — — — — — — — — — — —
2.6
2.0

1.9 — — 3.0

1.9 — — 3.0

0.7 — — 2.0

0.7

5.0

1.9

5.0

1.9

3.0

3.0

0.7

3.0
1.0
2.3
— — 2.0
3.0
2.3
3.0

0.8
0.5
1.3

4.0
2.0
6.0

3.0

3.1
7.0
2.7 — — 3.0
0.5 — — — — — — 2.0
9.0
2.7 — — 3.0
3.6

2.7

2.7

3.0

5.8
0.5
6.3

(1)

(2)

(3)

A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to
justify completion as an oil or natural gas producing well. Productive wells are included in the table in the year they were determined to be
productive, as opposed to the year the well was drilled.
A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were
determined not to be productive, as opposed to the year the well was drilled.
One gross and net development well had a duald

completion in an exploratory zone.

18

As of December 31, 2021, we had wells actively drilling or completing and wells suspended or awaiting

completion, as follows:

United States
Mexico(1)
Total

Actively Drilling or Completing

Wells Suspended or Waiting on Completion

y
Exploratory
Net

Gross

Development

Gross

Net

y
Exploratory
Net

Gross

Development

Gross

Net

—
—
—

—
—
—

1.0
—
1.0

1.0
—
1.0

1.0
4.0
5.0

0.3
1.5
1.8

—
—
—

—
—
—

(1)

Excludes 2.0 gross and 0.5 net exploratory wells suspended or waiting on completion previously disclosed related to our Mexico Block 31
lease that as of December 31, 2021 have been fully impaired due to our non-consent of the appraisal program. See Part I, Items 1 and 2.
Business and Properties — Hydrocarbon Properties — Mexico — Block 31 for additional information.

Productive Wells

The number of our productive wells is as follows for the year ended December 31, 2021:

Crude oil
Natural gas
Total(1)

(1)

Includes 8.0 gross and 6.7 net wells with dual completions.

Acreage

Gross

Net

198.0
70.0
268.0

148.7
38.8
187.5

Gross and net developed and undeveloped acreage is as follows for the year ended December 31, 2021:

United States:
Deepwater(1)
Shelf

Total United States
Mexico(2)
Total

Developed Acres

Undeveloped Acres

Total Acres

Gross

Net

Gross

Net

Gross

Net

280,913
287,894
568,807
—
568,807

137,171
176,295
313,466
—
313,466

490,705
127,287
617,992
69,530
687,522

206,735
99,988
306,723
17,843
324,566

771,618
415,181
1,186,799
69,530
1,256,329

343,906
276,283
620,189
17,843
638,032

(1)

(2)

Does not include 57.6 gross and 36.7 net undeveloped acres from the November 2021 Federal Lease Sale in which we were the apparent
high bidder. As of December 31, 2021, the BOEM has not awarded these leases. See Part II, Item 7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations — Significant Developments — Federal Lease Sale for additional information.
Includes 64.9 gross and 16.2 net undeveloped acres from our Mexico Block 31 lease that as of December 31, 2021 have been fully impaired
due to our non-consent of the appraisal program. See Part I, Items 1 and 2. Business and Properties — Hydrocarbon Properties — Mexico
— Block 31 for additional information.

Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed
to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or
not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres (held by
production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the
productive well holding such lease. The terms of our leases on undeveloped acreage as of December 31, 2021 are
scheduled to expire as shown in the table below (the terms of which may be extended by drilling and production
operations):

2022
2023
2024
2025
2026
2027 and beyond

Total

Gross

Net

133,630
174,813
107,480
46,166
23,040
202,393
687,522

46,066
120,090
37,710
25,778
10,656
84,266
324,566

19

Crude Oil, Natural Gas and NGL Production, Prices and Production Costs

Our production volumes, average sales prices and average production costs are as follows:

Production Volumes:
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)

Total (MBoe)

Year Ended December 31,

2021

2020

2019

16,159
32,795
1,875
23,500

13,665
28,652
1,559
19,999

13,847
23,306
1,228
18,959

Percent of MBoe from crude oil

69%

68%

73%

Average Sales Price (including commodity derivatives):

Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Average (per Boe)

Average Sales Price (excluding commodity derivatives):

Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Average (per Boe)

Average Lease Operating Expense (per Boe)

$
$
$
$

$
$
$
$
$

49.67 $
3.11 $
26.54 $
40.61 $

65.86 $
3.98 $
26.54 $
52.96 $
12.07 $

47.36 $
2.00 $
9.90 $
35.99 $

37.09 $
1.87 $
9.90 $
28.80 $
12.33 $

59.23
2.55
16.02
47.43

60.17
2.37
16.02
47.90
12.84

Crude Oil, Natural Gas and NGL Production, Prices and Production Costs—Significant Fields

Green Canyon Core Area — Phoenix Field

The following table sets forth certain information regarding our production volumes, average sales prices and
average production costs for the Phoenix Field, which consisted of 15% or more of our total estimated proved reserves:

Production Volumes:
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)

Total (MBoe)

Year Ended December 31,

2021

2020

2019

4,201
3,871
411
5,257

4,000
3,552
345
4,937

4,812
4,803
368
5,980

Percent of MBoe from crude oil

80%

81%

80%

Average Sales Price (excluding commodity derivatives):

Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Average (per Boe)

Average Lease Operating Expense (per Boe)

$
$
$
$
$

66.27 $
4.55 $
30.05 $
58.66 $
4.86 $

37.53 $
2.22 $
12.70 $
32.89 $
6.12 $

59.72
2.74
15.68
51.23
5.90

20

Mississippi Canyon Core Area — Pompano Field

The following table sets forth certain information regarding our production volumes, average sales prices and
average production costs for the Pompano Field, which consisted of 15% or more of our total estimated proved
reserves:

Production Volumes:
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)

Total (MBoe)

Year Ended December 31,

2021

2020

2019

2,716
2,626
254
3,408

2,852
2,179
216
3,431

3,324
2,320
236
3,947

Percent of MBoe from crude oil

80%

83%

84%

Average Sales Price (excluding commodity derivatives):

Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Average (per Boe)

Average Lease Operating Expense (per Boe)

Expenditures and Costs Incurred

$
$
$
$
$

67.33 $
4.68 $
25.54 $
59.17 $
3.57 $

38.51 $
2.28 $
6.51 $
33.86 $
2.90 $

61.83
2.61
14.49
54.49
2.17

For information on property development, exploration and acquisition costs, see Part IV, Item 15. Exhibits and

Financial Statement Schedules — Note 13 — Supplemental Oil and Gas Disclosures (Unaudited).

Title to Properties

We believe that we have satisfactory title to our oil and natural gas properties in accordance with generally
accepted industry standards. Individual properties may be subject to burdens such as royalties, overriding royalties,
and carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may
be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course
liens incidental to operating agreements and for current taxes and development obligations under oil and natural gas
leases. As is customary in the industry in the case of undeveloped properties, ofteff n limited investigation of record title
is made at the time of acquisition. Title search investigations are made prior to the consummation of an acquisition of
producing properties and before commencement of drilling operations on undeveloped properties. To the extent title
opinions or other investigations reflect defects affecting such undeveloped properties, we are typically responsible for
curing any such title defects at our expense.

Commodity Price Risks and Price Risk Management Activities

Production from our properties is marketed using methods that are consistent with industry practices. Sales
prices for oil and natural gas production are negotiated based on factors normally considered in the industry, such as
an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing
supply and demand conditions. We enter into derivative contracts on our oil and natural gas production primarily to
stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity
sales. For additional information regarding our commodity price risk and commodity derivative instruments, see Part
II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

21

Significant Customers

Oil and natural gas companies spend capital on exploration, drilling and production operations expenditures,
the amount of which is generally dependent on the prevailing view of future oil and natural gas prices which are
subject to many external factors which may contribute to significant volatility in future prices. We market substantially
all of our oil, natural gas and NGL production from the properties we operate and those we do not operate. Our
customers consist primarily of major oil and gas companies, well-established oil and pipeline companies and
independent oil and natural gas producers and suppliers. We perform ongoing credit evaluations of our customers and
provide allowances for probable credit losses when necessary. For the year ended December 31, 2021, 45% and 29%
of our oil, natural gas and NGL revenues were attributable to Shell Trading (US) Company and Chevron Products
Company, respectively, which are the customers that individually represented 10% or more of our oil, natural gas and
NGL revenues.

Competitive Conditions

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the
acquisition of oil and natural gas leases, equipment and personnel required to find and produce reserves and in the
gathering and marketing of oil, natural gas and NGLs. We compete with large integrated oil and natural gas companies
as well as independent exploration and production companies. Certain of our competitors may have significantly more
financial or other resources available to them. In addition, certain of the larger integrated companies may be better
able to respond to industry changes, including price fluctuation, oil and natural gas demand and governmental
regulations.

However, we believe our high quality oil-weighted production base, proven expertise in utilizing seismic
technology to identify, evaluate and develop exploitation and exploration opportunities, balanced mix of assets in the
U.S. Gulf of Mexico deep and shallow waters and significant operating control give us a strong competitive position
relative to many of our competitors.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Due to these seasonal fluctuations,
our results of operations for individual quarterly periods may not be indicative of the results that may be realized on
an annual basis. Generally, but not always, the demand for gas decreases during the summer months and increases
during the winter months. Seasonal anomalies such as mild winters or hot summers may impact general seasonal
changes in demand.

Insurance Matters

Our oil and natural gas operations are subject to risks incident to the operation of oil and gas wells, including,
but not limited to, uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering,
mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could result
in substantial losses to us. In addition, our oil and natural gas properties are located in the U.S. Gulf of Mexico, which
makes us more vulnerable to tropical storms and hurricanes. These hazards can cause personal injury or loss of life,
severe damage to and destruction of property and equipment, pollution or environmental damage and the suspension
of operations. Damages arising from such occurrences may result in lawsuits asserting large claims. Insurance may
not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful
claim for which we are not fully insured could have a material adverse effect on our financial condition, results of
operations and cash flow. Although we obtain insurance against some of these risks, we cannot insure against all
possible losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our
financial condition, results of operations and cash flow.

We have insurance policies to cover some of our risk of loss associated with our operations, and we maintain
the amount of insurance we believe is prudent. However, not all of our business activities can be insured at the levels
we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying
cost).

22

Our general property damage insurance provides varying ranges of coverage based upon several factors,
including well counts and the cost of replacement facilities. Our general liability insurance program provides a limit
of $500 million for each occurrence and in the aggregate, and includes varying deductibles. Our Offshore Pollution
Act insurance is subject to a maximum of up to $150 million for each occurrence and in the aggregate, including a
$100,000 retention. Coverage is provided for damage to our assets resulting from a named U.S. Gulf of Mexico
windstorm; however, such coverage is subject to a maximum of $175 million per named windstorm and in the
aggregate, and is also subject to a maximum of $15 million per occurrence retention dependent on location. We
separately maintain an operators extra expense policy with additional coverage for an amount up to $500 million for
U.S. Gulf of Mexico Deepwater drilling wells, $150 million for U.S. Gulf of Mexico Shelf drilling wells, $75 million
for U.S. Gulf of Mexico producing and shut-in wells, $75 million for drilling and workover in inland waters and
$25 million for drilling and workover in onshore fields that would cover costs involved in making a well safe after a
blow-out or getting the well under control; re-drilling a well to the depth reached prior to the well being out of control
or blown out; costs for plugging and abandoning the well; and costs for clean-up and containment and for damages
caused by contamination and pollution. For our Mexico insurance policies, we maintain $250 million in operators
extra expense coverage for operations and $500 million per occurrence and aggregate limit for general liability.

We may increase or decrease insurance coverage around our key strategic assets, including potentially
purchasing catastrophic bond instruments. Our highest value assets, which are located in the Phoenix Field, produce
through the HP-I floating production system, which has the capability to disconnect and move away in the event of a
storm, mitigating the risk of property damage.

We customarily have reciprocal agreements with our customers and vendors in which each contracting party is
responsible for its respective personnel for liability related to work performed for us. Under these agreements, we
generally are indemnified against third party claims related to the injury or death of our customers’ or vendors’
personnel, subject to the application of various states’ laws.

Government Regulation

Exploration and development and the production and sale of oil, natural gas and NGLs are subject to extensive
federal, state, local and foreign laws and regulations. An overview of these legal requirements is set forth below.
Historically, our compliance with existing requirements has not had a material adverse effect on our financial position,
results of operations or cash flows. However, current regulatory requirements may change, currently unforeseen
environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.
Because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or
impact of complying with such laws. Although the regulatory burden on the oil and natural gas industry increases our
cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any
differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and
locations of production.

General Overview — Our oil and natural gas operations are subject to various federal, state, local and foreign laws

and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to:



















location of wells;

size of drilling and spacing units or proration units;

number of wells that may be drilled in a unit;

unitization or pooling of oil and natural gas properties;

drilling and casing of wells;

issuance of permits in connection with exploration, drilling and production;

well production;

spill prevention plans;

protection of private and public surface and ground water supplies;

23

















emissions permitting or limitations;

protection of endangered species;

use, transportation, storage and disposal of fluids and materials incidental to oil and natural gas operations;

surface usage and the restoration of properties upon which wells have been drilled;

calculation and disbursement of royalty payments and production taxes;

requirements for the posting of supplemental bonds or providing other forms of financial assurance for
the plugging and abandonment of wells located in the U.S. Gulf of Mexico and offshore Mexico and,
following cessation of operations, the removal or appropriate abandonment of all production facilities,
structures and pipelines in those areas (“P&A” or “decommissioning” obligations);

performance of P&A obligations; and

transportation of production.

Outer Continental Shelf (“OCS”) Regulation — Our operations on federal oil and natural gas leases in the U.S.
Gulf of Mexico are subject to regulation by the BSEE, the BOEM and the Office of Natural Resources Revenue
(“ONRR”), which are all agencies of the U.S. Department of the Interior (“DOI”). These leases are awarded by the
BOEM based on competitive bidding and contain relatively standardized terms and require compliance with detailed
BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the federal Outer
Continental Shelf Lands Acts (“OCSLA”). For offshore operations, lessees must obtain BOEM approval for
exploration, development and production plans prior to the commencement of their operations. In addition to permits
required from other agencies such as the U.S. Environmental Protection Agency (“EPA”), lessees must obtain a permit
from BSEE prior to the commencement of drilling and comply with regulations governing, among other things,
engineering and construction specifications for production facilities, safety procedures, P&A of wells on the OCS,
calculation of royalty payments and the valuation of production for this purpose, and decommissioning of facilities,
structures and pipelines.

ff

President Biden issued an executive order in January 2021 suspending federal offshore and onshore oil and gas
leasing pending review and reconsideration of federal oil and gas leasing and permitting practices. The suspension of
these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in
issuance of a nationwide preliminary injunction by a federal
district judge in Louisiana in June 2021, effectively
halting implementation of the leasing suspension. The federal government and a coalition of environmental groups
are appealing the district court decision but, in the interim, BOEM scheduled a lease sale for certain blocks in the U.S.
Gulf of Mexico consistent with the preliminary injunction, which sale occurred in November 2021. However, on
January 27, 2022, a D.C. District Court judge vacated the lease sale on the basis that BOEM failed to consider the
impact on foreign greenhouse gas emissions if the November 2021 lease sale was not held and the court determined
that this failure was a violation of the National Environmental Policy Act and directing the DOI to consider certain
climate effects of awarding the leases before deciding if DOI could proceed with a new lease sale. Pursuant to the
court’s ruling, the DOI will have to conduct a new environmental analysis that takes into consideration such climate
effects before holding a new lease sale. If this court ruling continues to stand, all of the winning bids identified for
award pursuant to this lease sale will be invalidated, including our winning bids. Separately, the DOI released its
report on federal oil and gas leasing and permitting practices in November 2021, following a review of the onshore
and offshore federal oil and gas program. The report states an intent to modernize the federal oil and gas leasing
program and, in respect of the offshore sector, recommends adjusting royalty rates to ensure that the full value of the
tracts being leased are captured, strengthening financial assurance coverage amounts that are more protective of the
Federal Government and taxpayers and establishing a “fitness to operate” criteria that companies would need to meet
in respect of safety, environmental and financial responsibilities in order to operate on the OCS. Several of the report
recommendations require action by the Congress and cannot be implemented unilaterally by the new administration
and, thus, the extent to which the Biden Administration will act upon the report’s recommendations cannot be
predicted at this time.

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ff

Laws and regulations are subject to change, and the trend in the United States over the past decade has been for
these governmental agencies to continue to evaluate and as necessary develop and implement new, more restrictive
safety, permitting and performance requirements, although under the Trump Administration there were actions
seeking to mitigate certain of those more rigorous standards. For example, in 2016, the BSEE under the Obama
Administration published a final
rule on well control that, among other things, imposed rigorous standards relating to
the design, operation and maintenance of blow-out preventers, real-time monitoring of Deepwater, high temperature,
high pressure drilling activities, and enhanced reporting requirements. However, BSEE under the Trump
Administration subsequently reconsidered the 2016 final rule and published final revisions to this rule that became
effective in 2019 and, among other things, eliminated the requirement for a BSEE-approved verification organization
for third parties providing certifications of certain critical well control functions. In another example, BSEE under the
Obama Administration published a final
rule in 2016 updating certain safety and pollution prevention equipment (e.g.,
subsea safety equipment, including blowout preventers) requirements for production safety equipment, including an
obligation for independent third-party review and certification that safety and pollution prevention equipment is
operational and functioning as designed in the most extreme conditions, but in 2018, BSEE amended this rule, rolling
back a number of safety requirements including the third-party review and certification obligation.

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BSEE and/or BOEM under the Biden Administration may reconsider regulatory actions taken by the Trump
Administration, with those agencies potentially seeking to adopt additional, more stringent safety, permitting and
performance requirements. For example, in the federal government’s most recent list of potential regulatory actions
for 2022, the DOI lists proposed rulemaking initiatives for which notice is anticipated to be issued in the first half of
2022 in respect to such matters as increased safety, environmental and equipment reliability protections under the
pipeline and pipeline rights-of-way requirements for operating on the OCS; establishing a comprehensive program for
identifying, prioritizing and managing risks associated with OCS lease and grant obligations; and revising certain
blowout preventor systems and well control requirements for operating on the OCS. Compliance with Biden
Administration legislative, executive and regulatory actions or any other legal initiatives that impact oil and natural
gas exploration, development and production activities on the OCS could result in significant costs, including
increased capital expenditures and operating costs, and could adversely impact our business. Our failure to comply
with legal requirements under the OCSLA, our lease or applicable regulations may ultimately result in BOEM
cancelling one or more of our leases, which such cancellation could adversely affect our financial condition and
operations.

Furthermore, tropical storms and hurricanes in the U.S. Gulf of Mexico can have a significant impact on oil and
natural gas operations. The effects from past hurricanes have included structural damage to fixed production facilities,
semi-submersibles and jack-up drilling rigs. The BOEM and BSEE continue to be concerned about the loss of these
facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from
future storms. In an effort to reduce the potential for future damage, the BOEM and the BSEE have periodically issued
guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in
the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be
issued by the BOEM and the BSEE for future hurricane seasons. New requirements, if any, could increase our
operating costs and/or capital expenditures.

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In addition, in order to cover the various decommissioning obligations of lessees on the OCS, the BOEM
generally requires that lessees post some form of acceptable financial assurances that such obligations will be met,
such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no
assurance that we can continue to obtain bonds or other surety in all cases. The BOEM requires that lessees
demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances
to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In 2016, the BOEM
under the Obama Administration issued Notice to Lessees and Operators (“NTL”) #2016-N01 (“2016 NTL”) to clarify
the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial
assurances may be required for OCS leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”).
However, the 2016 NTL was not fully implemented as the BOEM under the Trump Administration rescinded the NTL
in 2020 and, in October 2020, pursued a proposed rule published jointly with the BSEE that sought to clarify and
provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas
lessees (record title owners), sublessees (operating rights owners) and RUE and ROW grant holders conducting
operations on the federal OCS. Consistent with recommendations made in the November 2021 DOI leasing report in
response to President Biden’s January 2021 executive order, it is anticipated that the Biden Administration could
pursue more stringent financial assurance requirements that could increase our operating costs. For example, in the
federal government’s most recent list of potential regulatory actions for 2022, the BSEE lists its plans to pursue a
BSEE-only rule in early 2022 that would finalize the policies and procedures concerning compliance with OCS oil
and gas decommissioning obligations pursuant to the BOEM and BSEE jointly-proposed October 2020 rulemaking
issued under the Trump Administration. The BOEM will not be involved in final issuance of the October 2020
rulemaking, instead indicating under the federal government’s list that it will pursue a new proposed rule in respect
of financial assurance, as described earlier in this section, that is anticipated to be issued in mid-2022.

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 in respect of any 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.

Regulation in Shallow Waters Off the Coast of Mexico — Our operations on oil and natural gas blocks in shallow
waters off the coast of Mexico’s Veracruz and Tabasco states are subject to regulation by SENER, the CNH and other
Mexican regulatory bodies. The CNH is responsible for, among other things, overseeing the tender procedures for
awarding contracts for the exploration and production of oil and natural gas in Mexican waters, managing and
supervising contracts that have been awarded, and approving exploration and production plans. The PSCs that we and
our consortium partners have entered into for the development of these acreages contain terms that impose on us the
duty to comply with various laws and regulations. These laws and regulations govern, among other things, the
exploration and exploitation of hydrocarbons (including certain national content requirements), the treatment,
conveyance, marketing, transport and storage of petroleum, and requirements for industrial safety, operational
security, and facility decommissioning. Failure to comply can result in the imposition of monetary penalties,
revocation of permits, rescission of the relevant PSC, suspension of operations, and ordered decommissioning of
offshore facilities and systems. The laws and regulations governing activities in the Mexican energy sector were
significantly reformed in 2013, and the legal regulatory framework continues to evolve as SENER, the CNH and other
Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is
possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that
could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.

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Hydrocarbon Export Regulation in Mexico — Our operations on oil and natural gas blocks in shallow waters off
the coast of Mexico’s Veracruz and Tabasco states are subject to regulation by SENER. Such regulations are subject
to change, and it is possible that the Mexican National Agency of Industrial Safety and Environmental Protection of
the Hydrocarbons Sector (“ASEA”) or other Mexican regulatory bodies may impose new or revised requirements that
could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. For example,
in December 2020, SENER published regulations affecting the granting of permits for the import and export of
hydrocarbons. These regulations imposed additional constraints on permit applicants, and granted SENER more
discretion in issuing, modifying, and revoking those permits. Previously, such permits would have had a term of 20
years – the December 2020 regulations limit terms to 5 years, restrict extensions and add new requirements.
Subsequently, in May 2021, the Mexican government amended its federal Hydrocarbons Law in a manner that is
anticipated to be beneficial to PEMEX, but have an adverse impact on privately-held oil and gas energy companies
including by way of example, (i) authorizing SENER and the Mexican Energy Regulatory Commission (the “CRE”)
to suspend or revoke hydrocarbon permits if there is imminent danger to national security, energy security or the
national economy; (ii) allowing the government to temporarily occupy the facilities of hydrocarbon permit-holders to
safeguard the national interest and hand over the operation of such facilities to State-owned entities, such as PEMEX;
and (iii) allowing for denial by default of applications for new permits of private companies if the authorities do not
respond within 90 days. Also in May 2021, the Mexican government made a second amendment to its Hydrocarbons
Law, which such amendment halts the CRE’s power to enforce asymmetric regulation in the hydrocarbon, petroleum
products and petrochemical markets, which regulation obligates PEMEX to comply with certain obligations that
effectively limits its market position relative to its competitors. Amparo actions are being pursued in local courts in
response to these legal changes and, as interim measures, court actions suspended the December 2020 regulations in
March 2021, partially suspended portions of the first amendment to the Hydrocarbons Law (such suspension including
the authorization to temporarily occupy facilities of permit-holders) in May 2021 and suspended the second
amendment to the Hydrocarbons Law in May 2021. While these Amparo-driven suspensions apply to the entire oil
and gas sector, these suspensions remain temporary in nature while the courts determine the legal validity of the
regulations and amendments, and there remains the possibility that one or more of these suspensions may lifted or
otherwise revised.

Environmental and Occupational Safety and Health Regulations

We are subject to various federal, state, local and foreign regulations concerning occupational safety and health
as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations
relate to, among other things:

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assessing the environmental impact of seismic acquisition, drilling or construction activities;

the generation, storage, transportation and disposal of waste materials;

the emission of certain gases into the atmosphere;

the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of
former operations;

various environmental permitting requirements, such as permits for wastewater discharges;

the development of emergency response and spill contingency plans;

specific operating criteria addressing worker protection; and

protection of private and public surface and ground water supplies.

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Based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses
related to the protection of the environment and safety and health compliance have increased over the years and it is
possible such expenses will continue to increase in the future. We cannot predict with any reasonable degree of
certainty our future exposure concerning such matters, and the cost of compliance could be significant. Failure to
comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties,
the imposition of remedial obligations, natural resource damages or the issuance of injunctive relief (including orders
to cease operations). Both onshore and offshore drilling in certain areas has been opposed by environmental groups
and, in certain areas, has been restricted. Additionally, President Biden has made the combat of climate change arising
from GHG emissions a priority under his administration. Some environmental laws and regulations may impose strict
liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions
caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that
prohibits or restricts onshore or offshore drilling or imposes environmental protection requirements that result in
increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.

We expect to continue making expenditures on a regular basis relating to environmental compliance. We
maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully
insured against all such risks. Our insurance coverage provides for the reimbursement to us of certain costs incurred
for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our
operations, but such insurance does not fully insure against pollution and similar environmental risks. We do not
anticipate that we will be required under current environmental laws and regulations to expend amounts that will have
a material adverse effect on our consolidated financial position or our results of operations. However, since
environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar
businesses and since regulatory requirements frequently change and may become more stringent under the Biden
Administration including in respect of GHG emissions, there can be no assurance that material costs and liabilities
will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased
production.

Water Discharges — Our discharges into waters of the United States are limited by the federal Clean Water Act,
as amended (“CWA”), and analogous state laws. The CWA prohibits any discharge of pollutants, including spills and
leaks of oil and other substances, into waters of the United States, except in compliance with permits issued by federal
and state governmental agencies. These discharge permits also include monitoring and reporting obligations. Failure
to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in
administrative, civil or criminal enforcement actions. Violations of the CWA can result in suspension, debarment or
the imposition of statutory disability, each of which prevents companies and individuals from participating in
government contracts and receiving some non-procurement government benefits. The CWA also requires the
preparation of oil spill response plans and spill prevention, control and countermeasure plans.

Oil Pollution Act — The Oil Pollution Act of 1990, as amended (“OPA”), holds owners and operators of offshore
oil production or handling facilities, including the lessee or permittee of the area where an offshore facility is located,
strictly liable for the costs of removing oil discharged into waters of the United States and for certain damages from
such spills. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all containment
and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding
to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil
spill. Although defenses exist to the liability imposed by OPA, they are limited. OPA’s damages liability cap is
currently $137.7 million; however, a party cannot take advantage of liability limits if a spill was caused by gross
safety, construction or operating regulation, or
negligence or willful misconduct, resulted from violation of a federal
if the party failed to report a spill or cooperate fully in the clean-up. OPA also requires responsible parties to maintain
evidence of financial responsibility in prescribed amounts. OPA currently requires a minimum financial responsibility
demonstration of between $35 million to $150 million, based on a worst case oil spill discharge volume, for companies
operating on the OCS, although the BOEM may increase this amount in certain situations, but in no event greater than
$150 million. From time to time, the United States Congress has proposed, but not adopted, amendments to OPA
raising the financial responsibility requirements. If OPA is amended to increase the minimum level of financial
responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this
requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial
responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or
substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could
be material to our results of operations and financial position.

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National Environmental Policy Act — The National Environmental Policy Act, as amended (“NEPA”), requires
federal agencies, including the DOI, to consider the impacts their actions have on the human environment, and to
prepare detailed statements for major federal actions having the potential to significantly impact the environment.
These requirements can lead to additional costs and delays in permitting for operators as the DOI or its bureaus may
need to prepare Environmental Assessments (“EA”) and more detailed Environmental Impact Statements (“EIS”) in
support of its leasing and other activities that have the potential to significantly affect the quality of the environment.
of no significant impact
If the EA indicates that no significant impact is likely, then the agency can release a finding
EIS. In July 2020, the
and carry on with the proposed action. Otherwise, the agency must then conduct a full-scale
Council on Environmental Quality (“CEQ”) under former President Trump’s Administration published a final
rule
modifying the NEPA including, among other things, establishing a time limit of two years for preparation of EIS
statements and one year for the preparation of EAs, and also eliminating the responsibility to consider cumulative
effects of a project. While the July 2020 rule modifying NEPA remains subject to ongoing litigation in several federal
district courts, the CEQ, now under the Biden Administration, announced in October 2021, that it will propose a ruler
making three significant changes to the 2020 final rule, including authorizing agencies to consider direct, indirect and
cumulative effects of major federal actions including upstream and downstream GHG emissions impacts of fossil fuel
projects, allowing agencies to determine the purpose and need of a project, which allows consideration of less-harmful
alternatives, and affording agencies greater flexibility in crafting their own NEPA procedures, consistent with CEQ
regulations, so as to meet the agencies’ and public’s needs. The NEPA process involves public input through comment.
These comments, as well as the agency’s analysis of the proposed project, can result in changes to the nature of a
proposed project, such as by limiting the scope of the project or requiring resource-specific mitigation. The adequacy
of the agency’s NEPA process can be challenged in federal court by process participants. This process may result in
delaying the permitting and development of projects, and result in increased costs.

ff
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Endangered Species Act — The Endangered Species Act, as amended (“ESA”), restricts activities that may affect
federally identified endangered and threatened species or their habitats. Additionally, the Migratory Bird Treaty Act,
as amended (“MBTA”), implements various treaties and conventions between the United States and certain other
nations for the protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is
President Trump issued a final
unlawful without a permit. The U.S. Fish and Wildlife Service (“FWS”) under former
rule on January 7, 2021, which notably clarifies that criminal liability under the MBTA will apply only to actions
“directed at” migratory birds, its nests or its eggs; however, in October 2021, the FWS under the Biden Administration
revoked the Trump Administration’s rule on incidental take and published an advanced notice of proposed rulemaking
to codify a general prohibition on incidental take while establishing a process to regulate or permit exceptions to such
a prohibition. The Marine Mammal Protection Act, as amended (“MMPA”), similarly prohibits the taking of marine
mammals without authorization. Additionally, the FWS may make determinations on the listing of species as
threatened or endangered under the ESA and litigation with respect to the listing or non-listing of certain species may
result in more fulsome protections for non-protected or lesser-protected species. We conduct operations on oil and
natural gas leases in areas where certain species that are protected by the ESA, MBTA and MMPA are known to exist
and where other species that could potentially be protected under these statutes are known to exist. The FWS or the
National Marine Fisheries Service may designate critical habitat that it believes is necessary for survival of a
threatened or endangered species. A critical habitat designation could result in further material restrictions to federal
land use and may materially delay or prohibit access to protected areas for oil and natural gas development. These
statutes may result in operating restrictions or a temporary, seasonal or permanent ban in affected areas.

ff

Hazardous Substances and Waste Management — The Resource Conservation and Recovery Act, as amended
(“RCRA”), generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup
obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced
waters and other wastes associated with the exploration, development or production of crude oil, natural gas or
geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. However, it is possible
that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as
hazardous wastes in the future. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related
wastes could result in increased costs to manage and dispose of generated wastes. Also, ordinary industrial wastes,
such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

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Comprehensive Environmental Response, Compensation and Liability Act — The Comprehensive
Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), and comparable state laws
impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have
contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” may be subject
to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources. Further, it is not uncommon for coastal landowners
or other third parties to file claims for personal injury and property damage allegedly caused by the hazardous
substances released into the environment.

Air Emissions — The Clean Air Act, as amended (“CAA”), and comparable state statutes restrict the emission of
air pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to
obtain separate construction and operating permits before construction work can begin or operations may start, and
existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed,
and continues to develop, more stringent regulations governing emissions of toxic air pollutants and is considering the
regulation of additional air pollutants and air pollutant parameters. For example, in 2015, the EPA under the Obama
Administration issued a final
rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”)
for ground-level ozone more stringent. Since that time, the EPA has issued area designations with respect to ground-
level ozone and, more recently, in December 2020, the EPA, under the Trump Administration, published a final
action
that, upon conducting a periodic review of the ozone standard in accord with CAA requirements, elected to retain the
2015 ozone NAAQS without revision on a going-forward basis; however, several groups have filed litigation over
this December 2020 decision, and the Biden Administration has announced plans to reconsider the December 2020
final action in favor of a more stringent ground-level ozone NAAQS. State implementation of the revised NAAQS
could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in
increased expenditures for pollution control equipment, the costs of which could be significant.

ff

ff

Worker Health and Safety — The Occupational Safety and Health Act, as amended (“OSHA”), and comparable
state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard
requires maintenance of information about hazardous materials used or produced in operations and provision of such
information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure
to comply with OSHA requirements can lead to the imposition of penalties.

Climate Change — The threat of climate change continues to attract considerable public, governmental and
scientific attention in the United States and in foreign countries. As a result, numerous proposals have been made at
the international, national, regional and state levels of government to monitor and limit existing emissions of GHG as
well as to restrict or eliminate such future emissions. These efforts have included consideration of cap-and-trade
programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG
emissions from certain sources. In the United States, no comprehensive climate change legislation has been
implemented at the federal level. However, the EPA has adopted regulations under the existing CAA that, among
other things, impose pre-construction and operating permit requirements on certain large stationary sources, require
the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources and
implement New Source Performance Standards directing the reduction of methane from certain new, modified or
reconstructed facilities in the oil and natural gas sector. Compliance with these rules or others could result in increased
compliance costs on our operations. In November 2021, the EPA issued a proposed rule that would make methane
emissions from the crude oil and natural gas sources category more stringent, by establishing Quad Ob new source
and Quad Oc first-time existing source standards of performance for methane and volatile organic compound
emissions for new sources and existing sources in the crude oil and natural gas source category. The EPA plans to
issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain additional requirements
rule by the end of 2022.
not included in the November 2021 proposed rule and the agency anticipates issuing a final

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Additionally, state implementation of revised air emission standards could result in stricter permitting
requirements, delay, limit or prohibit our ability to obtain such permits and result in increased expenditures for
pollution control equipment, the costs of which could be significant. At the international level, there exists the United
Nations-sponsored “Paris Agreement,” which is a non-binding agreement among participating nations to limit their
GHG emissions through individually-determined emissions reduction goals every five years after 2020. President
Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50-52%
reduction from 2005 levels in economy-wide net GHG emissions by 2030. Moreover, the international community
gathered again in Glasgow in November 2021 at the 26th Conference of the Parties (“COP26”), during which multiple
announcements (not having the effect of law) were made, including a call for parties to eliminate certain fossil fuel
subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly
announced at COP26 the launch of a Global Methane Pledge, an initiative which over 100 countries joined, committing
to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all
feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or
regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other
international conventions cannot be predicted at this time.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has
resulted in increasing federal political risk regarding climate change. In the United States, President Biden has issued
several executive orders calling for more expansive action to address climate change and limit new oil and gas
operations on federal lands and waters. See Part I, Items 1 and 2. Business and Properties – Government Regulation
– Outer Continental Shelf (“OCS”) Regulation for more information. Other actions that could be pursued by the Biden
Administration include more restrictive requirements for the establishment of pipeline infrastructure or the permitting
of LNG export facilities, as well as more stringent emissions standards for oil and gas facilities. Litigation risks are
also increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and
natural gas companies in state or federal court, alleging, among other things, that such companies created public
nuisances by producing fuels that contributed to global warming effects, such as rising sea levels and therefore are
responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the
adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately
disclose those impacts. We are not currently a defendant in any of these lawsuits but could be named in actions making
similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have
an adverse impact on our financial condition.

Additionally, our access to capital may be impacted by climate change policies. Stockholders and bondholders
currently invested in fossil fuel energy companies such as ours, but concerned about the potential effects of climate
change, may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors.
Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to
sustainable lending practices that favor “clean” power sources, such as wind and solar, making those sources more
attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest
U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing
financed emissions across their portfolios and taking steps to quantify and reduce those emissions. At COP26, the
Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45
countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ
generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or
underwriting activities to net zero emissions by 2050. These and other developments in the financial sector could lead
to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil
and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Additionally,
there is the possibility that financial institutions will be required to adopt policies that limit funding to fossil fuel
energy companies.

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In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System
(“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector.
More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to
identify key issues and potential solutions for the climate-related challenges most relevant to central banks and
supervisory authorities. While we cannot predict what policies may result from these announcements, a material
reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for
exploration, development, production, transportation, and processing activities, which could impact our business and
operations. Separately, the SEC has announced in the federal government’s most recent list of potential regulatory
actions for 2022 that it is pursuing several proposed rulemaking initiatives for which notice is anticipated to be issued
in the first half of 2022 in respect to enhanced disclosures to be made by registrants for such topics as climate change,
human capital management, board members and nominees and cybersecurity. The SEC has also announced that it is
scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if
the SEC were to allege an issuer’s existing climate disclosures misleading or deficient.

Finally, some scientists have concluded that increasing concentrations of GHG emissions in the Earth’s
atmosphere may produce climate changes that have significant physical effects, such as increased frequency and
severity of storms, droughts, floods and other extreme climatic events, as well as chronic shifts in temperature and
precipitation patterns. Our offshore operations are particularly at risk from severe climatic events, which have the
potential to cause physical damage to our assets and thus could have an adverse effect on our exploration and
production operations. Additionally, changing meteorological conditions, particularly temperature, may result in
changes to the amount, timing, or location of demand for energy or the products we produce. While our consideration
of changing weather conditions and inclusion of safety factors in design is intended to reduce the uncertainties that
climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events
depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity
planning, which may not have considered or be prepared for every eventuality.

Environmental Regulation in Shallow Waters Off the Coast of Mexico — Our operations on oil and natural gas
blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states are subject to regulation by the ASEA.
We must obtain ASEA-issued permits and comply with ASEA regulations governing hydrocarbon activities, including
requirements for environmental impact and risk assessments, industrial safety, waste management, water and air
emissions, operational security and facility decommissioning. Failure to comply with applicable laws and regulations
can result in the imposition of monetary penalties, revocation of permits, suspension of operations and ordered
decommissioning of offshore facilities and systems. The laws and regulations governing the protection of health,
safety and the environment from activities in the Mexican energy sector are relatively new, having been significantly
reformed following the establishment of ASEA in 2014 as a result of federal constitutional amendments approved in
2013, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue
new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican
regulatory bodies may impose new or revised requirements that could increase our environmental compliance-related
operating costs and/or capital expenditures for operations in Mexican offshore waters.

For example, in May 2020, the ASEA published the Industrial Safety, Operational Safety and Environmental
Protection Guidelines for the Closing, Dismantling and Abandonment of Hydrocarbons Sector Facilities (the
“Dismantling Guidelines”). The Dismantling Guidelines are mandatory for all hydrocarbon sector facilities that
perform dismantling, abandonment and closing of hydrocarbon sector activities. The Dismantling Guidelines set out
several obligations in terms of safety, reporting and risk, including establishing a closing, dismantling and/or
abandonment activities program for each of the relevant phases. More recently, during the fourth quarter of 2021,
ASEA announced its implementation of a “Popular Denunciation System” that will utilize an internet-based platform
to allow persons, organizations and companies to anonymously report complaints against entities and companies
operating in Mexico, including in respect of safety and environmental incidents such as, for example, hydrocarbon
spills and pollution events. We anticipate that ASEA will conduct investigations to substantiate the incidents identified
in the new reporting system.

Under the PSCs, we are jointly and severally liable for the performance of all obligations under the PSCs,
including exploration, appraisal, extraction and abandonment activities and compliance with all environmental
regulations, and failure to perform such obligations could result in contractual rescission of the PSCs.

32

Federal Regulation of Sales and Transportation of Natural Gas — Our sales of natural gas are affected directly
or indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline
transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale
of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”) and the
Natural Gas Policy Act of 1978 (“NGPA”) and by regulations and orders promulgated under the NGA and/or NGPA
by the Federal Energy Regulatory Commission (“FERC”). In certain limited circumstances, intrastate transportation
and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the United States
Congress and by FERC regulations. However, certain offshore gathering and transportation services we rely upon are
subject to limited FERC regulation and are regulated by the states.

Pursuant to authority delegated to it by the Energy Policy Act of 2005 (“EPAct 2005”), FERC promulgated anti-
manipulation regulations establishing violation enforcement mechanisms that make it unlawful for any entity, directly
or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services
subject to the jurisdiction of FERC to (i) use or employ any device, scheme or artifice to defraud, (ii) make any untrue
statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the
light of the circumstances under which they were made, not misleading or (iii) engage in any act, practice or course
of business that operates or would operate as a fraud
or deceit upon any entity. The EPAct 2005 also amended the
NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes and regulations,
up to $1,388,496 per violation, per day for 2021 (this amount is adjusted annually for inflation). FERC may also order
disgorgement of profits and corrective action. The anti-market manipulation rule does not apply to activities that relate
only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and
storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the
activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC
jurisdiction, which includes annual reporting requirements for entities that purchase or sell a certain volume of natural
gas in a given calendar year. We believe, however, that neither the EPAct 2005 nor the regulations promulgated by
FERC as a result of the EPAct 2005 will affect us in a way that materially differs from the way they affect other
natural gas producers, gatherers and marketers with which we compete.

ff

Our sales of oil and natural gas are also subject to market manipulation and anti-disruptive requirements under
the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Wall Street Reform and Consumer Protection
Act (the “Dodd-Frank Act”), and regulations promulgated thereunder by the U.S. Commodity Futures Trading
Commission (the “CFTC”). The CFTC prohibits any person from manipulating or attempting to manipulate the price
of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering
or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or
conditions that affect or tend to affect the price of a commodity.

The current statutory and regulatory framework governing interstate natural gas transactions is subject to change
in the future, and the nature of such changes is impossible to predict. We cannot predict whether new legislation to
regulate natural gas might be proposed, what proposals, if any, might actually be enacted by the United States
Congress, the applicable federal agencies, or the various state legislatures, and what effect, if any, the proposals might
have on our operations. The natural gas industry historically has been very heavily regulated. In the past, the federal
government regulated the prices at which natural gas could be sold. Since 1978, various federal laws have been enacted
that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in
“first sales,” which include all of our sales of our own production. However, we are subject to reporting requirements
imposed by FERC. There is always some risk, however, that the United States Congress may reenact price controls in
the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability
of firm and/or interruptible transportation service on interstate pipelines or impose additional reporting or other
requirements upon our operations, and we cannot predict what future action FERC will take. Therefore, there is no
assurance that the current regulatory approach recently pursued by FERC and the United States Congress will
continue. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from
the way they will affect other natural gas producers, gatherers and marketers with which we compete.

33

Federal Regulation of Sales and Transportation of Crude Oil — FERC regulates the interstate pipeline of crude
oil, petroleum products and other liquids, such as NGLs. Our sales of crude oil and condensate are currently not
regulated and are made at negotiated prices. There is always some risk, however, that the United States Congress may
reenact crude oil, petroleum products and NGL price controls in the future. We cannot predict whether new legislation
to regulate crude oil, or the prices charged for crude oil might be proposed, what proposals, if any, might actually be
enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might
have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting
requirements.

Our ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of
service are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”), and intrastate oil pipeline
transportation rates are subject to regulation by state regulatory commissions. Certain regulations implemented by
FERC in recent years and certain pending rulemaking and other proceedings could result in an increase in the cost of
transportation service on certain petroleum products pipelines. The basis for intrastate oil pipeline regulation, and the
degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We do not
believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will
affect other crude oil and condensate producers with which we compete.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory
basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the
same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing
provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation
services generally will be available to us to the same extent as to other crude oil and condensate producers with which
we compete.

We have an undivided interest in a pipeline owned by CKB Petroleum, Inc. that is subject to FERC jurisdiction
under the ICA, but FERC has granted us a temporary waiver of the filing and reporting requirements. This pipeline is
still subject to FERC’s jurisdiction under the ICA and is still subject to the other requirements of the ICA. If the facts
upon which the waiver was granted change materially, we are required to inform FERC, which may result in
revocation of the waiver. If conditions change such that the pipeline no longer qualifies for a waiver, we may be
subject to regulation by FERC of the rates, terms and conditions of service on the CKB Petroleum, Inc. pipeline;
however, these burdens generally would not affect us any differently or to any greater or lesser extent than they affect
others in our industry with similar pipelines.

FERC also implements the OCSLA pertaining to transportation and pipeline issues, which requires that all
pipelines operating on or across the OCS provide nondiscriminatory transportation service. We own and operate
pipelines that are located in the OCS and are subject to the non-discrimination requirements in the OCSLA.

Human Capital

As of December 31, 2021, we employ approximately 443 people located primarily in Texas, Louisiana and
Mexico. In addition, we supplement our workforce with contractors and consultants. While headcount does not
significantly fluctuate throughout the year, in order to align our workforce with the pace of our business, headcount
might increase or decrease in response to various factors, including acquisition activity, unscheduled shut-ins or a
change in our capital program.

ff

Our human capital measures and objectives focus on several areas, including, but not limited to human rights,
diversity and inclusion measures, assuring the safety of our employees, employee recruitment and development and
offering a fulsome
array of employee health and welfare benefits. We consider our employees a key factor in our
success and are focused on developing a diverse team of qualified employees and creating an inclusive workplace
culture. While we may reference certain policies and other documents in these disclosures, these are primarily to
identify the existence of such policies. They are not, and should not be deemed to be, incorporated into this Annual
Report or any of our other SEC filings.

Human Rights — We remain committed to upholding human rights across every segment of our business. Our
Code of Business Conduct and Ethics, which applies to all of our directors, officers and other employees of the
Company, and our Vendor Code of Conduct work in tandem to establish our commitment to human rights as a
fundamental part of our responsibilities as a company. Our human rights principles include pay and benefits, freedom
of association, nondiscrimination and prevention of human trafficking, forced labor and child labor. In 2021, we
published our Talos Human Rights Policy to further strengthen our commitment to safeguard human rights.

34

Diversity and Inclusion — We believe that creating a work environment where employees feel welcome, supported
and valued results in increased employee engagement and reduced turnover. In order to achieve these goals we
carefully observe all applicable laws and have adopted and actively enforce policies in our employee handbook and
Code of Business Conduct and Ethics that ensure equal employment opportunities for all and prohibit harassment and
discrimination of any kind. Our Code of Business Conduct and Ethics requires adherence to the highest standards of
personal integrity and assures the protection of human rights. We have a compliance hotline so that employees can
report any violation of these policies, anonymously if they wish. We know that a diverse workforce brings expanded
creativity and problem-solving and leads to better decision-making and enhanced performance. In 2021, we engaged
a Diversity and Inclusion professional to partner with Human Resources and our employee diversity committee to
create a diversity and inclusion strategy. Our Code of Business Conduct and Ethics requires that our directors, officers
and employees treat each of our employees with the same high level of respect regardless of such employee’s age,
color, disability, ethnicity, family or marital status, gender identity or expression, language, national origin, physical
and mental ability, political affiliation, race, religion, sexual orientation, socio-economic status, veteran status or other
characteristics that make such employee unique. As reflected in our Code of Business Conduct and Ethics, we are
committed to working in partnership with vendors and other business partners directly linked to our operations that
share our commitment to these same principles.

Safety — At Talos, safety is defined as freedom from unacceptable risk of harm and an empowered workforce
promoting a safety-first culture across our operations. Safety in every aspect of our business is our number one priority
and is core to our Health, Safety, Environment, and Sustainability operational culture. We drive this culture by being
fully transparent in our reporting of safety and ESG matters to our Board of Directors and stakeholders on a regular
basis, including our continual collaboration with the BSEE and the United States Coast Guard. In 2021, we reaffirmed
our commitment to corporate responsibility and renamed the Board’s Safety Committee the Safety, Sustainability &
Corporate Responsibility (“SSCR”) Committee and explicitly expanded its scope and oversight to include ESG and
corporate responsibility matters. We rigorously train our employees to conduct operations in accordance with our
strict safety standards and encourage employees to immediately report any breach of safety protocol to their supervisor
or our compliance hotline. Our employees are empowered and obligated by our Chief Executive Officer to exercise
the Stop Work Authority (“SWA”). With SWA, our employees can call an immediate stop to any work for any safety
concern without fear of retaliation or intimidation.

Conducting regular safety training allows us to proactively address the dynamic nature of offshore operational
risk and promote a robust culture of offshore safety. Our employees and permanently assigned contractors complete
custom designed in-house trainings through our eLearning platform and role appropriate hands-on training upon hiring
and as part of a continuous development program. Employees are engaged in biweekly field safety meetings directly
with senior management to discuss safety culture and ESG initiatives. Employees and contractors conduct emergency
response training drills on each facility at least once per hitch allowing our employees to always be ready in case of
an emergency situation. After any serious incident we conduct thorough incident investigations and communicate a
lessons learned report and any changes to our safety policies to all offshore employees.

Safety performance is an element of each employee’s performance review and 10% of the value of the 2021
short-term incentive award pool was based upon our achievement of safety goals. Additionally, our offshore
employees are eligible to receive a quarterly safety bonus, the value of which is contingent upon the number of safety
or environmental incidents of non-compliance recorded at the employee’s facility location during the quarter.

Finally, many of our offshore employees participate in our ESG sub-committees so they can have a voice in
corporate-level decisions about ESG matters. Our ESG efforts strive to continually improve our safety and
environmental performance and our employees help determine the responsible path forward.

35

ff

Recruitment, Development and Training — We foster

an entrepreneurial culture where open communication is
encouraged, the views of our employees are heard, and the results of their efforts are recognized. This is one of the
reasons why every year since our inception, we have earned a ranking as a Top Workplace on the Houston Chronicle
Top Workplaces list. We implement an inclusive and dynamic recruiting process that utilizes online recruiting
platforms, referrals, internships and professional recruiters. We foster the growth and professional development of our
employees through the use of a robust performance review process, which includes the creation of performance
development goals and plans to achieve those goals in order to help our employees reach their full potential. We also
offer in-house training, eLearning through our Learning Management System, reimbursement of the costs of outside
training, and tuition reimbursement to support our employees’ pursuit of higher education at accredited institutions in
further support of developing our employees. We believe this emphasis on development and training has contributed
to our 4.9% turnover rate for 2021.

Health and Welfare Benefits — We work to retain employees by offering competitive wages and generous benefits
that are designed to meet the varied and evolving needs of a diverse workforce. We provide employees with the ability
to participate in health and welfare plans, including medical, dental, life, accidental death and dismemberment and
short-term and long-term disability insurance plans. In response to the COVID–19 pandemic, we transitioned office-
based employees to a work from home schedule and increased safety measures and protocols for those employees
choosing to report to the office, such as mandatory temperature checks, limiting third party visitors, and encouraging
the use of masks and social distancing. Beginning in June 2021, our office-based employees returned to the office and
protocols are in place to limit the spread of COVID-19. For our employees offshore, we increased pre-departure
screenings, which included symptom reporting questionnaires, contact tracing, temperature screenings, and in some
cases, negative COVID-19 tests. For our offshore facilities, we provided N95 masks and cleaning supplies, performed
daily temperature checks and increased response procedures in the event an employee displayed symptoms.

SS

Community & Social

Engagement — We are committed to supporting and giving back to the communities in
which we operate and live. We recognize the link between local communities, the success of our employees, and
ultimately the success of our business. To take a more proactive role in community support, our Community
Committee, comprised of our employees, engages directly in outreach, fundraising, education and awareness. We
regularly host volunteer and fundraising events supporting non-profit organizations in our communities, annually
provide a $500 allowance to every employee that can be applied in support of a non-profit of their choice, match funds
raised by the Community Committee's fundraising efforts for charitable organizations, and provide employees with a
paid volunteer day off to support an organization where they want to donate their time.

Available Information

We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K,
all amendments to those reports, and all other information filed with or furnished to the SEC available, free of charge,
through our website, https://www.talosenergy.com, as soon as reasonably practicable after those reports and other
information are electronically filed with or furnished to the SEC. The filings are also available by accessing the SEC’s
website at https://www.sec.gov.

36

Item 1A. Risk Factors

Certain factors may have a material adverse effect on our business, financial condition, and results of operations.
You should consider carefully the risks and uncertainties described below, in addition to other information contained
in this Annual Report, including our Consolidated Financial Statements and related notes. The risks and uncertainties
described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we
currently believe are not material, may also become important factors that adversely affect our business. If any of the
following risks actually occur, our business, financial condition, results of operations and future prospects could be
materially and adversely affected. In that event, the trading price of our common stock could decline, and you could
lose part or all of your investment.

Risks Related to our Business and the Oil and Natural Gas Industry

Oil and natural gas prices are volatile. Sustained periods of low, or declines in, commodity prices may

adversely affect our financial condition and results of operations, cash flows, access to the capital markets and
ability to grow.

Our revenues, cash flows, profitability and future rate of growth substantially depend upon the market prices of
oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to access funds under
our Bank Credit Facility and through the capital markets. The amount available for borrowing under our Bank Credit
Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved
reserves and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such
time. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling
test each quarter, which is impacted by declining prices. Significant price declines could cause us to take ceiling test
write-downs, which would be reflected as non-cash charges against current earnings. See the Risk Factor entitled
“Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other
impairments of our asset carrying values” for further discussion.

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

The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future.
For example, during the period January 1, 2019 through December 31, 2021, the daily NYMEX WTI crude oil price
per Bbl ranged from a low of $(36.98) to a high of $85.64, and the daily NYMEX Henry Hub natural gas price per
MMBtu ranged from a low of $1.33 to a high of $23.86. Subsequent to December 31, 2021, NYMEX WTI crude oil
and NYMEX Henry Hub natural gas prices recorded daily lows of $75.99 per Bbl and $3.73 per MMBtu, respectively.

The prices we receive for our oil and natural gas depend upon many factors beyond our control, including,

among others:



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

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







changes in the supply of and demand for oil and natural gas;

market uncertainty;

level of consumer product demands;

hurricanes and other adverse climatic conditions;

the impact of applicable market differentials, including those relating to quality, transportation, fees,
energy content and regional pricing;

domestic and foreign governmental actions, regulations and taxes;

price and availability of alternative fuels;

political and economic conditions in oil-producing countries, particularly those in the Middle East, Russia,
South America and Africa;

the occurrence or threat of epidemic or pandemic diseases, such as the outbreak of COVID-19, or any
government response to such occurrence or threat;

37























actions by OPEC Plus relating to oil and natural gas price and production controls;

U.S. and foreign supply of oil and natural gas;

price and quantity of oil and natural gas imports and exports;

the level of global oil and natural gas exploration and production;

the level of global oil and natural gas inventories;

localized supply and demand fundamentals and transportation availability;

capacity of processing, gathering, storage and transportation facilities;

speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

price and availability of competitors’ supplies of oil and natural gas;

technological advances affecting energy consumption; and

overall domestic and foreign economic conditions.

These factors make it very difficult to predict future commodity price movements with any certainty.
Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot
market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily
fluctuate in direct relation to each other. Because oil, natural gas and NGLs accounted for approximately 67%, 24%,
and 9%, respectively, of our estimated proved reserves as of December 31, 2021, and approximately 69%, 23%, and
8%, respectively, of our 2021 production on an MBoe basis, our financial results are sensitive to movements in oil,
natural gas and NGL prices.

Our production, revenue and cash flow from operating activities are derived from assets that are concentrated

in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

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



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





severe weather, such as hurricanes and other adverse climatic conditions;

delays or decreases in production or the availability of equipment, facilities or services;

delays or decreases in the availability or capacity to transport, gather or process production;

changes in the status of pipelines that we depend on for transportation of our production to the
marketplace;

extensive governmental regulation (including regulations that may, in certain circumstances, impose strict
liability for pollution damage or require posting substantial bonds to address decommissioning and P&A
costs) and interruption or termination of operations by governmental authorities based on environmental,
safety or other considerations;

changes in the regulatory environment such as the guidelines issued by the BOEM related to financial
assurance requirements to cover decommissioning obligations for operations on the OCS; and/or

changes imposed as a result of litigation or by a new Presidential Administration or by Congress in the
United States that may result in added restrictions and delays or prohibitions in offshore oil and natural
gas exploration and production activities, including with respect to leasing, permitting, site development
or operation in federal waters or hydraulic fracturing.

38

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

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

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

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

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

t

Estimates of our proved oil and natural

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

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

You should not assume that any present value of future net cash flows from our proved reserves represents the
market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows
from our proved reserves at December 31, 2021 on historical 12-month average prices and costs as of the date of the
estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues are
affected by factors such as:



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





the amount and timing of capital expenditures and decommissioning costs;

the rate and timing of production;

changes in governmental legislation, regulations or taxation;

volume, pricing and duration of our oil and natural gas hedging contracts;

supply of and demand for oil and natural gas;

actual prices we receive for oil and natural gas; and

our actual operating costs in producing oil and natural gas.

39

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

At December 31, 2021, approximately 16% of our estimated proved reserves (by volume) were undeveloped
and approximately 25% were non-producing. Any or all of our PUD or proved developed non-producing reserves may
not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developed non-producing
reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result
in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally requires significant
capital expenditures and successful drilling or waterflood operations. Our reserve estimates include the assumptions
that we incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated
with these properties may not be as estimated. Any material inaccuracies in these reserve estimates or underlying
assumptions materially affects the quantities and present value of our reserves, which could adversely affect our
business, results of operations and financial condition.

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

Unless production is established as required by the leases covering the undeveloped acres, the leases for such

acreage may expire.

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

The marketability of our production depends mostly upon the availability, proximity and capacity of oil and

natural gas gathering systems, pipelines and processing facilities.

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

ff

Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other

impairments of our asset carrying values.

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs
to acquire, explore for and develop oil and natural gas properties. Under the full cost method of accounting, our
capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves,
computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural
gas properties not being amortized less the related tax effects. A write-down of oil and natural gas properties does not
impact cash flows from operating activities, but does reduce net income. The risk that we are required to write-down
the carrying value of oil and natural gas properties increases when oil and natural gas prices are low or volatile. In
addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves
or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices,
poor conditions in the global economic markets and other factors could cause us to record additional write-downs of
our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings.
Any required write-downs or impairments could materially affect the quantities and present value of our reserves,
which could adversely affect our business, results of operations and financial condition.

40

With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties,
not subject to amortization. The finalization of the unitization and unit operating agreement, which sets out the terms
on which the reservoir will be jointly developed, and the outcome of the dispute with the Government of Mexico over
decisions taken by SENER with respect to the Zama discovery, could adversely affect the value of the oil and natural
gas assets and result in an impairment of our unevaluated oil and gas properties prior to reaching a final
investment
decision or of our evaluated properties upon reaching a final

investment decision.

ff

ff

If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back

online, and will be unable to predict the production levels of such wells once brought back online.

If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back
online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells
would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve
estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online,
there is no assurance that such wells will be as productive following recommencement as they were prior to being
shut-in. Any shut-in or curtailment of the oil, natural gas and NGLs produced from our fields could adversely affect
our financial condition and results of operations.

Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks

and other disruptions.

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

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

Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19,

may materially adversely affect our business.

We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and
could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak
of an illness or other communicable disease, or any other public health crisis, such as COVID-19, may cause
disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of
contractors or subcontractors,
(iv)
recommendations of, or restrictions imposed by government and health authorities, including quarantines, to address
an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including
facility shutdowns, to ensure the safety of employees.

interruption of supplies from third parties upon which we rely,

(iii)

41

In addition, the effects of COVID-19 and concerns regarding its global spread could negatively impact the
domestic and international demand for crude oil and natural gas, which could contribute to price volatility, impact the
price we receive for oil and natural gas and materially and adversely affect the demand for and marketability of our
production. The potential impact from COVID-19, both now and in the future, is difficult to predict, and the extent to
which it may negatively affect our operating results or the duration of any potential business disruption is uncertain.
Any potential impact will depend on future developments and new information that may emerge regarding the
COVID-19 infection rate or the efficacy and distribution of COVID-19 vaccines, and the actions taken by authorities
to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could
adversely affect our operating results.

New technologies may cause our current exploration and drilling methods to become obsolete, and we may not

be able to keep pace with technological developments in our industry.

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

We may not be in a position to control the timing of development efforts, the associated costs or the rate of

production of the reserves from our non-operated properties.

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

















the timing and amount of capital expenditures;

the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and
transportation infrastructure and qualified operating personnel;

the operator’s expertise and financial resources;

approval of other participants in drilling wells;

risk of other non-operator’s failure to pay its share of costs, which may require us to pay our proportionate
share of the defaulting party’s share of costs;

selection of technology;

the rate of production of the reserves; and

the timing and cost of P&A operations.

42

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









refuse to initiate exploration or development projects;

initiate exploration or development projects on a slower or faster schedule than we would prefer;

delay the pace of exploratory drilling or development; and/or

drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through
financing, which may limit our participation in those projects or limit the percentage of our revenues from
those projects.

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration

and development activities.

Hedging transactions may limit our potential gains.

In order to manage our exposure to price risks in the marketing of our oil, natural gas and NGLs, we periodically
enter into oil, natural gas and NGLs price hedging arrangements with respect to a portion of our expected production.
These arrangements may include futures contracts on the NYMEX. While intended to reduce the effects of volatile
oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains
if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such
transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:











our production is less than expected or is shut-in for extended periods due to hurricanes or other factors;

there is a widening of price differentials between delivery points for our production and the delivery point
to be assumed in the hedge arrangement;

the counterparties to our futures contracts fails to perform the contracts;

a sudden, unexpected event materially impacts oil or natural gas prices; or

we are unable to market our production in a manner contemplated when entering into the hedge contract.

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

Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as

legal requirements applicable to marine mammals and endangered and threatened species.

Our oil and natural gas operations in the United States and Mexico are subject to stringent federal, state and/or
local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to
environmental protection. These laws and regulations require the acquisition of a permit or other approval before
drilling or other regulated activity commences; restrict the types, quantities and concentration of substances that can
be released into the environment in connection with drilling and production activities; limit or prohibit exploration or
drilling activities on certain lands lying within protected areas or that may affect certain wildlife, including marine
species and endangered and threatened species and impose substantial liabilities for pollution resulting from our
operations. Additionally, the threat of climate change continues to attract considerable attention in the United States
and in foreign countries and the combat of climate change has been made a focal
point of the Biden Administration's
agenda. See Part I, Items 1 and 2. Business and Properties — Government Regulation — Environmental and
Occupational Safety and Health Regulations for more discussion on environmental and worker safety matters. One or
more of these developments that impact our oil and natural gas exploration and production activities on the OCS could
have a material adverse effect on our business, results of operations and financial condition.

ff

43

Additional drilling laws, regulations, executive orders and other regulatory initiatives that restrict, delay or
prohibit oil and natural gas exploration, development and production activities or access to locations where such
activities may occur could have a material adverse effect on our business, financial condition or results of
operations.

The Biden Administration has taken a number of actions that may result in stricter environmental, health and
safety standards applicable to our operations and those of the oil and gas industry more generally. The Biden
Administration issued the “Executive Order on Tackling the Climate Crisis at Home and Abroad” on January 27, 2021
(the “Climate Change Executive Order”). This executive order directed the Secretary of the Interior to halt indefinitely
new oil and natural gas leases on federal lands and offshore waters pending completion of a review by the Secretary
of the Interior of federal oil and gas permitting and leasing practices in light of the Biden Administration’s concerns
regarding the impact of these activities on the environment and climate. The Secretary of the Interior completed its
review of permitting and leasing practices in November 2021 and issued a report recommending, among other things,
an increase in royalty rates and financial assurance requirements. However, litigation concerning the Climate Change
Executive Order’s pause on new oil and gas leases is ongoing. In June 2021, the U.S. District Court for the Western
District of Louisiana issued a nationwide preliminary injunction barring the Biden Administration from implementing
the pause in new federal oil and gas leases. In November 2021, the Biden Administration conducted an offshore lease
sale and various industry participants submitted bids for leases in the Gulf of Mexico; however, on January 27, 2022,
in litigation brought by Friends of the Earth and other plaintiffs, the U.S. District Court for the District of Columbia
vacated the November 2021 lease sale and the related agency decision making process, finding that the BOEM failed
to consider the impact on foreign greenhouse gas emissions if the November 2021 lease sale was not held and the
court determined that this failure was a violation of the National Environmental Policy Act. Following this decision
by the District Court for the District of Columbia vacating the November 2021 lease sale, there is significant
uncertainty surrounding whether the sale can be revived and whether the leases for which we were the apparent high
bidder will be awarded. While the decision by the District Court for the District of Columbia has been appealed and a
motion for expedited hearing has been filed, a decision from the appellate court may not be released until 2023 or
beyond. In addition, there is increasing uncertainty regarding the near-term future of Gulf of Mexico lease sales. These
lease sales are conducted pursuant to Five-Year Leasing Programs under the Outer Continental Shelf Lands Act. The
current Five-Year Leasing Program is set to expire on June 30, 2022. No new Gulf of Mexico lease sales can be held
after June 30, 2022, until a new Five-Year Leasing Program is approved, a process which, once begun, can take two
to three years to complete. Consequently, it is uncertain whether a new Five-Year Leasing Program and subsequent
lease sales will be conducted during the current Biden Administration. Additionally, any new Five-Year Leasing
Program would likely be subject to heightened environmental review.

Over the past decade, BSEE and BOEM, primarily under the Obama Administration, have imposed new and
more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled
in federal waters. While actions by BSEE or BOEM under the Trump Administration sought to mitigate or delay
certain of those more rigorous standards, the Biden Administration could reconsider rules and regulatory initiatives
implemented under the previous administration and replace them with more stringent requirements and also provide
more rigorous enforcement of existing regulatory requirements. Compliance with any added or more stringent
regulatory requirements or enforcement initiatives and existing environmental and spill regulations, together with
uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and
approval of drilling permits and exploration, development, oil spill response and decommissioning plans could result
in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.
Moreover, governmental agencies under the Biden Administration may continue evaluating aspects of safety and
operational performance in the U. S. Gulf of Mexico that may result in new, more restrictive requirements.

These regulatory actions, or any new laws, executive orders, regulations or other legal or enforcement initiatives,
that impose increased costs or more stringent operational standards could delay or disrupt our operations, result in
increased supplemental bonding and associated costs, and limit activities in certain areas, or cause us to incur penalties,
fines, or shut-in production at one or more of our facilities or result in suspension or cancellation of leases. Also, if
material spill incidents were to occur in the future, the United States or other countries where such an event may occur
could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue
further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and
development, any of which could have a material adverse effect on our business. We cannot predict with any certainty
the full impact of any new laws or regulations on our drilling and production operations or on the cost or availability
of insurance to cover some or all of the risks associated with such operations.

44

See Part I, Items 1 and 2. Business and Properties — Government Regulation — OCS Regulation for more

discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS.

We may be unable to provide the financial assurances in the amounts and under the time periods required by
the BOEM if it submits future demands to cover our decommissioning obligations. If in the future the BOEM
issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM
could elect to take actions that would materially adversely impact our operations and our properties, including
commencing proceedings to suspend our operations or cancel our federal offshore leases.

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or
provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning
activities on the OCS. In 2016, the BOEM under the Obama Administration had sought to implement more stringent
and costly standards under the existing federal financial assurance requirements through issuance and implementation
of the 2016 NTL, but former President Trump’s Administration first suspended, and then in 2020 rescinded, the
implementation of this NTL. Consistent with recommendations made in a November 2021 DOI report on the federal
oil and gas leasing program, the Biden Administration could pursue more stringent and financial assurance
requirements that could increase our operating costs.

Following the effectiveness of the 2016 NTL, we received orders from the BOEM in late 2016 directing us to
provide additional financial assurance in material amounts relating to our OCS properties. We entered into discussions
with the BOEM regarding the requested additional financial security and submitted a proposed tailored plan for the
posting of additional financial security to the agency for review. However, as the Trump Administration rescinded the
2016 NTL, the BOEM has taken no action with respect to our previously submitted proposed tailored plan.

The BOEM, now under the Biden Administration, could in the future make new demands for additional financial
assurances in material amounts relating to the decommissioning of our OCS properties. The BOEM may reject our
proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities.

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

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

45

Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local

governmental regulations that materially affect our operations.

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

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

Even with the final regulations in place, there are still some uncertainties regarding the unitization process,
specifically relating to Block 7 offshore Mexico. In July 2021, SENER designated PEMEX as operator of the Zama
unit, just three days after SENER received a letter directly from PEMEX arguing for operatorship. Under Mexico’s
own unitization guidelines, SENER was required to “consider the principles of economy, competitiveness, efficiency,
legality, transparency, best practices of industry and the best use of hydrocarbons.” In September 2021, we submitted
Notices of Dispute to the Government of Mexico relating to the decision taken by SENER. Our aim is to resolve the
dispute amicably through consultations and negotiations to achieve a fair
and mutually beneficial agreement; however,
the outcome of these Notices of Dispute could be adverse to us and affect the value that we are able to recognize from
the reservoir discovery.

ff

In September 2015, we, together with our consortium partners executed a PSC with the CNH for each of Blocks
2 and 7 of Round 1. The PSCs require that the consortium execute a minimum work program expressed in work units
exploration period. Effective January 23, 2018, the activities already performed on Block 7 have
ff
during a four-year
satisfied the minimum work program on Block 7. Effective September 4, 2019, the activities already performed on
Block 2 have satisfied the minimum work program on Block 2. Effective December 2, 2020, the activities already
performed on Block 31 have satisfied the minimum work program on Block 31.

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

operate.

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

46

We may experience significant shut-ins and losses of production due to the effects of tropical storms and

hurricanes in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico.

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

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

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to
which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We
have insurance policies that include coverage for general liability, physical damage to our oil and gas properties,
operational control of well, named U.S. Gulf of Mexico windstorm, oil pollution, construction all risk, workers’
compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that have to
be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions
and limitations, and there is no assurance that such coverage will adequately protect us against liability from all
potential consequences, damages or losses. See Part I, Items 1 and 2. Business and Properties – Insurance Matters for
more information on our insurance coverage.

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

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

SEC rules could limit our ability to book additional PUD reserves in the future.

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

Our actual production could differ materially from our forecasts.

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

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

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



unexpected drilling conditions;

47











pressure or irregularities in formations;

equipment failures or accidents;

hurricanes and other adverse weather conditions;

shortages in experienced labor; and

shortages or delays in the delivery of equipment.

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

Our industry experiences numerous operating risks.

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

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

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

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

48

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

Competition within our industry may adversely affect our operations.

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

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

a

The loss of our larger customers could materially reduce our revenue and materially adversely affect our

business, financial condition and results of operations.

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

The loss of key personnel could adversely affect our ability to operate.

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

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

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We have operations in multiple jurisdictions, including jurisdictions in which the tax laws, their interpretation
or their
administration may change. As a result, our tax obligations and related filings are complex and subject to
tt
change, and our after-tax profitability could be lower than anticipated. Additionally, future tax legislative or
regulatory changes in the United States, Mexico or any othett
r jurisdiction in which we operate or have subsidiaries
could result in changes to the taxation of our income and operations, which could also adversely impact our after-
tax profitability.

We are subject to income, withholding and other taxes in the United States on a worldwide basis and in
numerous state, local and foreign jurisdictions with respect to our income, operations and subsidiaries in those
jurisdictions. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits,
exemptions, refunds (including refunds of value added taxes) and other benefits to reduce our tax liabilities, changes
in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate or have
subsidiaries, the potential expansion of our business into or otherwise becoming subject to tax in additional
jurisdictions, changes to our existing business structure and operations, the extent of our intercompany transactions
and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions.

Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations,
administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive
effect. In past years, federal and state level legislation in the United States has been proposed that would, if enacted
into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions
currently available to oil and natural gas exploration and development companies. For example, President Biden has
set forth several tax proposals that would, if enacted into law, make significant changes to U.S. tax laws. Such
proposals include, but are not limited to, an increase in the U.S. federal income tax rate applicable to corporations
(such as us) from 21%, and the elimination of tax subsidies for fossil fuels. The U.S. Congress could consider some
or all of these proposals in connection with tax reform to be undertaken by the Biden Administration. Additionally,
the U.S. House of Representatives passed legislation in 2021, which includes provisions that would, if ultimately
enacted, impact the U.S. federal income taxation of corporations. Among other items, this legislation includes
provisions that would impose a minimum tax on book income of certain corporations and an excise tax on certain
corporate stock repurchases that would be borne by the corporation repurchasing such stock. U.S. states in which we
operate or own assets may also impose new or increased taxes or fees on oil and natural gas extraction. It is unclear
whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect.
Additionally, the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and
Profit Shifting (the “Multilateral Instrument”) has entered into force among the jurisdictions that have ratified it,
although the United States has not yet become a signatory to the Multilateral Instrument. Such proposed legislative
changes and ratification of the Multilateral Instrument in the jurisdictions in which we operate could result in further
changes to our global taxation. Additionally, Mexico has enacted tax reform legislation, and a majority of the
provisions became effective on January 1, 2020. These tax reforms provided for new and complex provisions that
significantly change how Mexico tax entities and operations and are subject to further legislative change and
administrative guidance and interpretation, which may differ from our interpretation. Future tax legislative or
regulatory changes in the United States, Mexico or in any other jurisdictions in which we operate now or in the future
could also adversely impact our after-tax profitability.

A significant portion of our production, revenue and cash flow is concentrated in our Phoenix Field and our
impacts of adverse weather or

Pompano Field. Because of this concentration, any production problems,
inaccuracies in reserve estimates could have a material adverse impact on our business.

For the year ended December 31, 2021, approximately 22% and 15% of our production and 25% and 16% of
our total revenue was attributable to our Phoenix Field and our Pompano Field, respectively, both of which are located
in the federal waters offshore in the U.S. Gulf of Mexico. This concentration in these fields means that any impact on
our production from these fields, whether because of mechanical problems, adverse weather, well containment
activities, changes in the regulatory environment or otherwise, could have a material effect on our business. We
produce the Phoenix Field through the HP-I, a dynamically positioned floating production facility that is operated by
Helix. The HP-I interconnects the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot
maintain its position on station, such as in the event of a mechanical problem with the dynamic positioning system or
the approach of a hurricane. Because the HP-I may have to be disconnected from the Phoenix Field if circumstances
require, our production from the Phoenix Field may be subject to more frequent interruptions than if the Phoenix Field
was produced by a more conventional platform.

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We are also required to disconnect and dry-dock the HP-I every two to three years for inspection as required by
the United States Coast Guard, during which time we are unable to produce the Phoenix Field. During the year ended
December 31, 2019, Helix dry-docked the HP-I. After conducting sea trials, production resumed in late March 2019,
resulting in a total shut-in period of 57 days. The next dry-dock is scheduled for mid-2022 with an estimated shut-in
lasting approximately 45 to 60 days.

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

In addition, all of our production from the Phoenix Field flows through the Green Canyon 19 connection facility
operated by Shell GOM Pipeline Company LLC. To the extent Shell GOM Pipeline Company LLC temporarily shuts
in its Green Canyon 19 connection facility, whether for maintenance or otherwise, we would not be able to produce
the Phoenix Field during this period of time, which may have a material adverse effect on our business, financial
condition, results of operations and cash flows. If the actual reserves associated with the Phoenix Field are less than
our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial
condition, results of operations and cash flows.

In addition, all of our production from the Pompano Field flows through the Pompano Pipeline System operated
by Crimson Gulf LLC. To the extent Crimson Gulf LLC temporarily shuts in the Pompano Pipeline System, whether
for maintenance or otherwise, we would not be able to produce the Pompano Field during this period of time, which
may have a material adverse effect on our business, financial condition, results of operations and cash flows. If the
actual reserves associated with the Pompano Field are less than our estimated reserves, such a reduction of reserves
could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our Mexican operations are subject to certain offshore regulatory and environmental laws and regulations

promulgated by Mexico.

Our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco
states and in other Mexican offshore areas where we are assessing other exploration opportunities, are subject to
regulation by the SENER, the CNH and other Mexican regulatory bodies. The laws and regulations governing
activities in the Mexican energy sector have undergone significant reformation over the past decade, and the legal
regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new
regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other
Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or
capital expenditures for operations in Mexican offshore waters. See Part I, Items 1 and 2. Business and Properties –
Government Regulation – Regulation in Shallow Waters Off the Coast of Mexico and Part I, Items 1 and 2. Business
and Properties – Government Regulation – Hydrocarbon Export Regulation in Mexico for additional disclosure
relating to the legal requirements imposed by SENER, CNH or other Mexican regulatory bodies to which we may be
subject in the pursuit of our operations.

In addition, our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz
and Tabasco states and in other Mexican offshore areas where we are assessing other exploration opportunities, are
subject to regulation by the ASEA. The laws and regulations governing the protection of health, safety and the
environment from activities in the Mexican energy sector are also relatively new, having been significantly reformed
in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory
bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or
other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs
and/or capital expenditures for operations in Mexican offshore waters. See Part I, Items 1 and 2. Business and
Properties – Environmental and Occupational Safety and Health Regulations – Environmental Regulation in Shallow
Waters Off the Coast of Mexico for additional disclosure relating to the legal requirements imposed by ASEA or other
Mexican regulatory bodies to which we may be subject in the pursuit of our operations. The permit holders must
comply with requirements relating to insurance, facility construction and design, law compliance, and risk analysis
scenarios.

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Under the PSCs, we are also jointly and severally liable for the performance of all obligations under the PSCs,
including exploration, appraisal, extraction and abandonment activities and compliance with all environmental
regulations, and failure to perform such obligations could result in contractual rescission of the PSCs.

Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present,

produce in economic quantities.

We rely on 3D seismic studies to assist us with assessing prospective drilling opportunities

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

t

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

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

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

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

facilities.

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

52

Our operations are subject to various risks arising out of the threat of climate change that could result in
increased operating costs, limit the areas in which oil and natural gas production may occur and reduce demand
for the crude oil and natural gas that we produce.

Climate change continues to attract considerable public, political and scientific attention. In the United States,
no comprehensive climate change legislation has been adopted at the federal level, but President Biden has indicated
that action to address climate change is an important part of his administration’s agenda. As a result, numerous
executive actions and legislative and regulatory initiatives have been made or are likely to be considered by his
administration and analogous legal actions are likely to be made or considered at the state, regional or international
levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future
emissions. These regulatory efforts have included consideration of cap-and-trade programs, carbon taxes, GHG
emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.
Additionally, the threat of climate change has resulted in increasing political, litigation and financial risks associated
with the production of fossil fuels and emissions of GHG. Moreover, climate change activism calling for reduced
access to capital, fuel conservation measures, governmental initiatives for renewable energy resources, increasing
consumer demand for alternative forms of energy, technological advances in fuel economy and energy generation
devices may create new competitive conditions that result in reduced demand for the oil and natural gas we produce.
Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have
significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and
other climatic events. See Part I, Items 1 and 2. Business and Properties – Environmental and Occupational Safety
and Health Regulations – Climate Change for additional disclosure relating to risks arising out of the threat of climate
change.

The adoption of legislation or regulatory programs to reduce or eliminate future emissions of GHG could require
us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire
emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory
programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we
produce. Consequently, legislation and regulatory programs to reduce or eliminate future emissions of GHG could
have an adverse effect on our business, financial condition and results of operations. Also, political, financial and
litigation risks may result in our restricting or canceling production activities, incurring liability for infrastructure
damages as a result of climatic changes or impairing the ability to continue to operate in an economic manner. Further,
if any such effects of climate changes were to occur, they could have an adverse effect on our financial condition and
results of operations.

Increasing attention to ESG matters may impact our business.

Increasing attention to climate change, societal expectations on companies to address climate change, and
potential consumer use of substitutes to oil and gas commodities may result in increased costs, reduced demand for
our products and our services and the products and services of our customers, reduced profits, increased investigations
and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate
change, for example, may result in demand shifts for the hydrocarbon products we produce as well as additional
governmental investigations and private litigation against us. To the extent that societal pressures or political or other
factors are involved, it is possible that such liability could be imposed without regard to our causation of or
contribution to the asserted damage, or to other mitigating factors.

Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many
of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or
may not be representative of current or actual risks or events or forecasts of expected risks or events, including the
costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or
subject to misinterpretation given the long timelines involved and the lack of an established single approach to
identifying, measuring and reporting on many ESG matters.

53

We enhanced and re-named the Board of Directors’ Safety Committee to become the Safety, Sustainability and
Corporate Responsibility Committee, which is the primary committee of our Board of Directors responsible for
overseeing and managing our ESG initiatives. Committee members are expected to meet quarterly to review the
implementation and effectiveness of our ESG programs and policies. Additionally, we have set the following
aspirational goals to help strengthen our ESG performance: (i) a 30% reduction in GHG emissions intensity by 2025
with a stretch goal of 40%, as compared to our 2018 GHG emissions intensity baseline; and (ii) increased to 20% the
ESG metrics component of our management’s annual incentive plan, which includes key initiatives aimed at GHG
emissions reduction and health and safety performance. We note, however, that despite our governance changes we
may not be able to adequately identify or manage ESG-related risks and opportunities, which may include failing to
achieve our GHG emission intensity reduction or other ESG-related aspirational goals, including but not limited to as
a result of unforeseen costs or technical difficulties associated with achieving such goals. Additionally, to the extent
we meet such targets, they may be achieved through various contractual arrangements, including the purchase of
various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG
performance.

In addition, organizations that provide information to investors on corporate governance and related matters
have developed ratings processes for evaluating companies on their approach to ESG matters. We and other companies
in our industry publish sustainability reports that are made available to investors. Such ratings and reports are used by
some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased
negative investor sentiment toward us and to the diversion of investment to other industries which could have a
negative impact on our stock price and/or our access to and costs of capital. Additionally, certain institutional lenders
may decide not to provide funding to us based on ESG concerns, which could adversely affect our financial condition
and access to capital for potential growth projects. To the extent ESG matters negatively impact our reputation, we
may also be unable to compete as effectively to recruit or retain employees, which may adversely affect our operations.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments

to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, expanded federal oversight and regulation of the over-the-
counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the CFTC and the
SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC and the SEC have
finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict
when this is accomplished.

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

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

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

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

Negative publicity may adversely impact us.

Media coverage and public statements that insinuate improper actions by us, regardless of their factual accuracy
or truthfulness, may result in negative publicity, litigation or governmental investigations by regulators. For example,
in September 2021, we experienced negative publicity relating to an oil release in the U.S. Gulf of Mexico, off the
coast of Port Fourchon, Louisiana. Although we were a prior lessee of the block in question, had ceased production in
the area in 2017 and had removed all pipeline infrastructure by 2019, the resulting publicity may have had a negative
impact on us.

Similar or further such negative publicity in the future relating to U.S. Gulf of Mexico operations generally, or
our operations specifically, may expose us to adverse consequences. Addressing negative publicity and any resulting
litigation or investigations may distract management, increase costs and divert resources. Negative publicity may have
an adverse impact on our reputation and the morale of our employees, which could materially adversely affect our
business, financial position, results of operations, cash flows, growth prospects and stock price.

A change in the jurisdictional characterization of our FERC-jurisdictional pipelines, tribal or local regulatory
agencies or a change in policy by those agencies may result in increased regulation of such asset, which may cause
our revenues to decline and operating expenses to increase or delay or increase the cost of expansion projects.

With respect to CKB Petroleum, Inc., which has been granted a waiver of certain portions of the ICA and related
regulations by the FERC, should the pipeline’s circumstances change, the FERC could, either at the request of other
entities or on its own initiative, assert that such pipeline no longer qualifies for a waiver. In the event that the FERC
were to determine that CKB Petroleum, Inc. no longer qualified for a waiver, we would likely be required to file a
tariff with the FERC, provide a cost justification for the transportation charge and provide service to all potential
shippers without undue discrimination. Such a change in the jurisdictional status of transportation on the CKB
Petroleum, Inc. pipeline could adversely affect our results of operations.

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We may be unable to pursue our CCS business, either wholly or in significant measure, which could have a

material adverse effect on our business, results of operations and financial condition.

Our CCS business strategy envisions the construction and operation of one or more CCS projects within the
next two to three years, utilizing anthropogenic CO2 generated by industrial emitters along the Texas and Louisiana
Gulf Coast. CCS projects currently being actively evaluated include a Texas GLO carbon storage project located in
Jefferson County, Texas, for which we were selected together with our partner Carbonvert Inc. by the agency in
October 2021 as a winning bidder to pursue this project, and a commercial carbon storage venture entered into in
November 2021 with Freeport LNG to be located along the Texas Gulf Coast adjacent to our co-venturer’s LNG
natural gas pre-treatment facilities near Freeport, Texas. In February 2022, we entered into a lease agreement along
the Mississippi River Corridor in eastern Louisiana to develop a carbon capture, transportation and sequestration joint
service along with EnLink Midstream, LLC. Our goal is that CCS projects, such as these three, will eventually enable
us to offset some or all of our annual net CO2 emissions while delivering an economic return. However, the successful
development of such projects is dependent on various economic, regulatory and operational factors, the failure of
which to satisfy wholly or in significant measure any one or more of such factors could have a material adverse impact
on our business, results of operations and financial condition.

The successful development of our CCS projects is dependent upon our ability to benefit from certain financial
incentives available with respect to CCS projects. The U.S. Congress has incentivized the development of CCS
projects through the establishment of the Section 45Q tax credit, which provides a tax credit for qualified CO2 that is
captured using carbon capture equipment and that is disposed of in secure geological storage. Unless legislation is
passed that allows for the direct cash payment of Section 45Q tax credits, our ability to benefit from Section 45Q tax
credits is dependent upon us having a tax liability against which to utilize such credits or our ability to indirectly
benefit from such credits through contractual arrangements with parties that are able to utilize such credits.
Additionally, we will benefit from Section 45Q tax credits only if we own carbon capture equipment that captures
qualified CO2 that we physically or contractually capture and securely store or if another party that owns carbon
capture equipment elects to pass through Section 45Q tax credits to us and we dispose of the qualified CO2. While we
intend to utilize Section 45Q tax credits in an economically beneficial manner, the market with respect to Section 45Q
credits is developing and there can be no assurance that we will be able to effectively benefit from such tax credits.
Section 45Q tax credits are also subject to recapture with respect to any CO2 that ceases to be disposed of in secure
storage, which recapture is treated as an increase in tax liability for the year in which the recapture occurs. The
recapture period for Section 45Q tax credits is limited to a 3-year lookback period preceding the date that sequestered
CO2 escapes from its secure storage.

Additionally, the Section 45Q tax credits may be reduced, modified or eliminated as a matter of legislative or
regulatory policy. There can be no assurance that the tax credits under Section 45Q will not be reduced, modified, or
eliminated in the future. Any such reduction, modification or elimination of Section 45Q tax credits, or our inability
to enter into arrangements to utilize Section 45Q tax credits, could materially reduce our ability to develop CCS
projects and, as a result, may adversely impact our business, results of operations and financial condition. Even if we
are able to benefit from Section 45Q tax credits, we may determine that additional financial incentives are required
for our CCS projects to be economical. If such additional incentives do not emerge, we may not be able to achieve an
economic return from our CCS business or, alternatively, the construction or operation of our CCS projects may be
substantially delayed, unprofitable or otherwise infeasible. Another emerging financial incentive for CCS projects
may be the approximately $1.2 trillion infrastructure bill signed by President Biden in November 2021, which includes
a provision for approximately $2.5 billion to expand the U.S. Department of Energy’s Carbon Storage Validation and
Testing program to include large-scale commercialization of new or expanded carbon sequestration projects and CO2
transport infrastructure. However, the applicability of the financial incentives in the infrastructure bill to our projects
is uncertain at this time and there is no assurance that we would qualify for such incentives in the pursuit of our CCS
projects or that such credits would be adequate for our CCS project needs.

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Additionally, successful development of CCS projects in the United States requires that we comply with what
we anticipate will be a stringent regulatory scheme requiring that we obtain certain permits applicable to subsurface
injection of CO2 for geologic sequestration. Moreover, as operator of our CCS projects, we must demonstrate and
maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post
injection site care and site closure, and emergency and remedial response. As CCS and carbon management represent
an emerging sector, regulations may evolve rapidly, which could impact the feasibility of one or more of our
anticipated projects. There is no assurance that we will be successful in obtaining permits or adequate levels of
financial assurance for one or more of our CCS projects or that permits can be obtained on a timely basis, whether due
to difficulty with the technical demonstrations required to obtain such permits, public opposition or otherwise.
Separately, permitting CCS projects also requires obtaining a number of other permits and approvals unrelated to
subsurface injection from various U.S. federal and state agencies, such as for air emissions or impacts to
environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility.
To the extent regulatory requirements are imposed, are amended or more stringently enforced, we may incur additional
costs in the pursuit of one or more of our CCS projects, which costs may be material or may render any one or more
of our CCS projects uneconomical.

Development of successful CCS projects will also require satisfying certain operational factors, such as locating
a suitable source of anthropogenic CO2 and reaching suitable agreements to capture that CO2. Such agreements are
complex and may involve allocation of not only fees but also various credits, incentives and environmental attributes
associated with the storage of CO2. Not all emission sources produce sufficiently large quantities of pure or relatively
pure streams of CO2, or have installed equipment to capture such CO2, so as to be usable in one or more of our CCS
projects. As a result, we cannot assure whether we will be able to procure sufficient quantities of CO2 on terms that
are acceptable to us, and the failure to do so may have a material impact on our ability to execute our CCS strategy.
Additionally, development of successful CCS projects will require infrastructure to transport CO2 between the source
and our CCS sites. In project areas with existing CO2 transportation pipelines, this may require reaching an agreement
on CO2 transportation with operators of CO2 pipelines within the regions in which we operate. Inability to reach a
suitable agreement may render a project uneconomical or impracticable. Separately, if no CO2 pipelines exist in
proposed project areas, or if existing pipelines do not extend to one or more of our project sites, we may be required
to convert existing pipelines, or build new CO2 pipelines or lateral connections, which may be subject to various
environmental and other permitting requirements as well as third party easements, which may render one or more
projects uneconomical. We will also need to build the required equipment on a timely basis and at a cost that is
economically viable. Additionally, complex recordkeeping and GHG emissions/sequestration accounting may be
required in connection with one or more of our projects, which may increase the costs of such operations. Different
methodologies may be
regarding GHG
emissions/sequestration at one or more of our projects, including but not limited to, compliance with the EPA’s
mandatory Greenhouse Gas Reporting Program. Furthermore, as CCS may be viewed as a pathway to the continued
use of fossil fuels, notwithstanding that CO2 emissions are intended to be captured, there may be organized opposition
to CCS, including as it relates to our projects.

regulatory and non-regulatory accounts

required for various

In consideration of the above matters, we anticipate, but can provide no assurance, that we will be able to execute
upon our CCS business strategy in the future. Any failure by us to achieve such expectations in whole or any significant
measure could have a material adverse effect on our business, results of operations and financial condition.

Risks Related to our Capital Structure and Ownership of our Common Stock

Our debt level and the covenants in our current or future agreements governing our debt, including our Bank
Credit Facility and the indenture for our 12.00% Second-Priority Senior Secured Notes, could negatively impact
our financial condition, results of operations and business prospects. Our failure to comply with these covenants
could result in the acceleration of our outstanding indebtedness.

The terms of the agreements governing our debt impose significant restrictions on our ability to take a number

of actions that we may otherwise desire to take, including:









incurring additional debt;

paying dividends on stock, redeeming stock or redeeming subordinated debt;

making investments;

creating liens on our assets;

57













selling assets;

guaranteeing other indebtedness;

entering into agreements that restrict dividends from our subsidiaries to us;

merging, consolidating or transferring all or substantially all of our assets;

hedging future production; and

entering into transactions with affiliates.

Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the
Bank Credit Facility and the indenture for our 12.00% Second-Priority Senior Secured Notes due January 2026 (the
“12.00% Notes”) of Talos Production Inc. (the “Issuer”), have important consequences on our operations, including:













requiring that we dedicate a substantial portion of our cash flow from operating activities to required
payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures,
and other general business activities;

limiting our ability to obtain additional financing in the future for working capital, capital expenditures,
acquisitions and other general business activities;

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which
we operate;

detracting from our ability to successfully withstand a downturn in our business or the economy generally;

placing us at a competitive disadvantage against other less leveraged competitors; and

making us vulnerable to increases in interest rates because debt under our Bank Credit Facility is at
variable rates.

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

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

58

We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand,
we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell
assets, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to
generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity
financings or proceeds from the sale of assets are available to pay or refinance such debt. Any refinancing of
indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could
further restrict business operations. The terms of our debt, including our Bank Credit Facility and the indenture for
our 12.00% Notes, may also prohibit us from taking such actions. Factors that affect our ability to raise cash through
offerings of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our
market value and operating performance at the time of such offerings, refinancing or sale of assets. We cannot assure
you that any such offerings, restructuring, refinancing or sale of assets would be successfully completed.

A financial crisis may impact our business and financial condition and may adversely impact our ability to

obtain funding under our Bank Credit Facility or in the capital markets.

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

ff

In addition, from time to time, we could be required to, or we or our affiliates may seek to, retire or purchase
our outstanding debt through cash purchases and/or exchanges for equity or debt, open-market purchases, privately
negotiated transactions or other transactions. Such debt repurchase or exchange transactions, if any, will be upon such
terms and at such prices as we may determine and will depend on prevailing market conditions, our liquidity
requirements, contractual restrictions and other factors. The amounts involved may be material. Such transactions may
give rise to taxable cancellation of indebtedness income (to the extent the fair market value of the property exchanged,
or the amount of cash paid to acquire the outstanding debt, is less than the adjusted issue price of the outstanding debt)
and adversely impact our ability to deduct interest expenses in respect of our debt against our taxable income in the
future. This could result in a current or future tax liability, which could adversely affect our financial condition and
cash flows.

We require substantial capital expenditures to conduct our operations and replace our production, and we may

be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

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

reduction in commodity prices may result in a further

ff

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











our proved reserves;

the level of hydrocarbons we are able to produce from our wells;

the prices at which our production is sold;

our ability to acquire, locate and produce new reserves; and

our ability to borrow under our Bank Credit Facility.

59

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

We are a holding company that has no material assets other than our ownership of the equity interests of Talos
Production Inc. Accordingly, we are dependent upon distributions from Talos Production Inc. to pay taxes, cover
our corporate and other overhead expenses and pay dividends, if any, on our common stock.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos
Production Inc. We have no independent means of generating revenue. To the extent Talos Production Inc. has
available cash, we will cause Talos Production Inc. to make distributions of cash to us, directly and indirectly through
our wholly owned subsidiaries, to pay taxes, cover our corporate and other overhead expenses and pay dividends, if
any, on our common stock. As we have never declared or paid any cash dividends on our common stock, we anticipate
that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead
expenses, will be retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we
do not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect
to pay dividends on our common stock, if our board of directors decides to do so in the future, our ability to do so may
be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the
significant restrictions the agreements governing Talos Production Inc.’s debt impose on the ability of Talos
Production Inc. to make distributions and other payments to us. To the extent that we need funds and Talos Production
Inc. is restricted from making such distributions under applicable law or regulation or under the terms of our financing
agreements, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial
condition.

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

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

60

We have divested, as assignor, various leases, wells and facilities located in the U.S. Gulf of Mexico where the
purchasers, as assignees, 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 such as the OCSLA could impose joint and several strict liability and require
predecessor assignors, such as us, to assume such obligations. As of December 31, 2021, we have accrued $3.8 million
and $20.6 million in obligations reflected as “Other current liabilities” and “Other long-term liabilities”, respectively,
on the Consolidated Balance Sheets. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 —
Summary of Significant Accounting Policies and Part IV, Item 15. Exhibits and Financial Statement Schedules —
Note 12 — Commitments and Contingencies for more information.

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

successfully integrate future acquisitions.

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

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















operating a larger organization;

coordinating geographically disparate organizations, systems and facilities;

integrating corporate, technological and administrative functions;

diverting management’s attention from regular business concerns;

diverting financial resources away from existing operations;

increasing our indebtedness; and

incurring potential environmental or regulatory liabilities and title problems.

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

Our future acquisitions could expose us to potentially significant liabilities, including P&A liabilities.

We expect that future acquisitions will contribute to our growth. In connection with potential future acquisitions,

we may only be able to perform limited due diligence.

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

61

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

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

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

The interests of the Riverstone Funds may differ from the interests of our other stockholders.

As of December 31, 2021, entities controlled by or affiliated with Riverstone Energy Partners V, L.P.
(“Riverstone Funds”) beneficially owned and possessed voting power over 24.7% of our common stock. Under the
Stockholders’ Agreement, the Riverstone Funds may acquire additional shares of our common stock without the
approval of our Independent Directors as defined in that certain Stockholders’ Agreement, dated as of May 10, 2018
(the “Stockholders’ Agreement”).

Through the provisions set forth in our Amended and Restated Certificate of Incorporation, our Amended and
Restated Bylaws and the Stockholders’ Agreement, the Riverstone Funds currently have the ability to designate certain
members of our Board of Directors.

The Riverstone Funds also have significant influence over all other matters submitted to stockholders for
approval, including changes in capital structure, transactions requiring stockholder approval under Delaware law, and
corporate governance, subject to the terms of the Stockholders’ Agreement. The Riverstone Funds may have different
interests than other holders of our common stock and may make decisions adverse to your interests.

Among other things, the Riverstone Funds’ concentration of voting power could delay or defer a sale of us that
many of our other stockholders support. This concentration of voting power could discourage a potential investor from
seeking to acquire our common stock and, as a result, might harm the market price of our common stock.

The corporate opportunity provisions in our Amended and Restated Certificate of Incorporation could enable

others to benefit from corporate opportunities that might not otherwise be available to us.

Subject to the limitations of applicable law, our Amended and Restated Certificate of Incorporation, among

other things:







permits us to enter into transactions with entities in which one or more of our officers or directors are
financially or otherwise interested;

permits the 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”), the Riverstone
Funds, and any of our officers or directors who is also an officer, director, employee, managing director,
or other affiliate of the Apollo Funds or the Riverstone Funds to conduct business that competes with us
and to make investments in any kind of property in which we may make investments; and

provides that if the Apollo Funds, the Riverstone Funds, or any of our officers or directors who is also an
officer, director, employee, managing director or other affiliate of the Apollo Funds or the Riverstone
Funds becomes aware of a potential business opportunity, transaction or other matter (other than one
expressly offered to that director or officer in writing solely in his or her capacity as an director or officer
of us), that director or officer will have no duty to communicate or offer that opportunity to us, and will
be permitted to communicate or offer that opportunity to any other entity or individual and that director
or officer will not be deemed to have acted in a manner inconsistent with his or her fiduciary duty to us
or our stockholders.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may

be used for the benefit of others.

62

Our Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of
Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings
that may be initiated by our stockholders, which could limit our stockholders’ abilityll
to obtain a favff orable judicial
forum for disputes with us or our directors, officers, employees or agents.

ff

Our Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the
selection of an alternative forum, the Court of Chancery will be the sole and exclusive forum for (i) any derivative
action or proceeding brought on behalf of us, (ii) any action asserting a claim of breach of a fiduciary
duty owed by
any of our current or former directors, officers, employees, agents or stockholders (including a beneficial owner of
stock) to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware
General Corporation Law, our Amended and Restated Certificate of Incorporation or Amended and Restated Bylaws,
or (iv) any action asserting a claim governed by the internal affairs doctrine, in each case subject to the Court of
Chancery having personal jurisdiction over the indispensable parties named as defendants in the case. Section 27 of
the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created
by the Exchange Act or the rules and regulations promulgated thereunder. As a result, the exclusive forum provision
will not apply to actions arising under the Exchange Act or the rules and regulations promulgated thereunder.
However, Section 22 of the Securities Act provides for concurrent federal and state court jurisdiction over actions
under the Securities Act and the rules and regulations promulgated thereunder, subject to a limited exception for
certain “covered class actions” as defined in Section 16 of the Securities Act and interpreted by the courts.
Accordingly, we believe that the exclusive forum provision would apply to actions arising under the Securities Act or
the rules and regulations promulgated thereunder, except to the extent a particular action fell within the exception for
covered class actions or the exception in the certificate of incorporation described above otherwise applied to such
action, which could occur if, for example, the action also involved claims under the Exchange Act. Stockholders will
not be deemed, by operation of Article 12 of our Amended and Restated Certificate of Incorporation alone, to have
waived claims arising under the federal securities laws and the rules and regulations promulgated thereunder.

Any person or entity purchasing or otherwise acquiring any interest in any share of our capital stock will be
deemed to have notice of and consent to these provisions of our Amended and Restated Certificate of Incorporation.
This exclusive forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds
favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits
against us and such persons. Alternatively, if a court were to find these provisions of our Amended and Restated
Certificate of Incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of
actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions,
which could adversely affect our business, financial condition or results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

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

On May 29, 2020, a lawsuit was filed in the Court of Chancery asserting derivative and class action claims
against us relating to the ILX and Castex Acquisition. Specifically, the lawsuit relates to the fairness of the
consideration paid for such acquisitions in light of the fact that certain of the sellers are our affiliates. The lawsuit was
dismissed during the third quarter of 2021, and the plaintiffs have appealed the dismissal to the Delaware Supreme
Court.

63

The following proceedings represent previous Stone litigation that was assumed as part of the Stone

Combination.

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

On November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of
Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial
District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain
of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified
damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and
declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March
and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively,
intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish
dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the
Louisiana Department of Natural Resources were not similarly dismissed. The Plaquemines Parish lawsuit has been
stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of
the CRMA, but not involving Stone. The Plaquemines Parish lawsuit has been removed to the United States District
Court for the Eastern District of Louisiana. The plaintiffs have moved to remand the lawsuit to the state courts.

Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal
issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of
some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters.
See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies for
more information.

Item 4. Mine Safety Disclosures

Not applicable.

64

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuers Purchases of Equity
Securities

PART II

Market for Common Stock

Our common stock is listed on the NYSE under the symbol “TALO”.

Holders of Record

Pursuant to the records of our transfer agent, as of February 17, 2022, there were approximately 152 holders of

record of our common stock.

Dividends

We have never declared or paid any cash dividends on our common stock, and we anticipate that any available
cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be
retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we do not anticipate
paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends
on our common stock, if our board of directors decides to do so in the future, our ability to do so may be limited to
the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions
that the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make
distributions and other payments to us.

Securities Authorized for Issuance Under Equity Compensation Plans

See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder

Matters” for information regarding securities authorized for issuance under equity compensation plans.

65

Stockholder Return Performance Presentation

The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This
historic stock price performance is not necessarily indicative of future stock performance. The graph compares the
change in the cumulative total return of our common stock, the Dow Jones U.S. Exploration and Production Index,
and the S&P 500 Index for May 10, 2018 through December 31, 2021. The graph assumes that $100 was invested in
our common stock and each index on May 10, 2018 and that dividends were reinvested.

Comparison of Cumulative Total Return

$200

$150

$100

$50

$0
5/10/18

12/31/18

12/31/19

12/31/20

12/31/21

Talos Energy Inc.

S&P 500 Index

Dow Jones U.S. Select Oil Explox

ration & Production Index

Talos Energy Inc.
S&P 500 Index
Dow Jones U.S. Exploration & Production
Index

May 10, 2018
$
$

100 $
100 $

$

100 $

2018

2019

2020

2021

45 $
93 $

71 $

83 $
123 $

23 $
145 $

78 $

53 $

27
187

93

The performance graph and the information contained in this section is not “soliciting material,” is being
“furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the
Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general
incorporation language contained in such filing.

Item 6. [Reserved]

66

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on, and should
be read in conjunction with our Consolidated Financial Statements and the Notes to Consolidated Financial Statements
set forth in Part IV, Item 15. Exhibits and Financial Statement Schedules; Part I, Items 1 and 2. Business and
Properties; Part I, Item 1A. Risk Factors; and Part II, Item 7A. Quantitative and Qualitative Disclosures About Market
Risk. This discussion and analysis contains forward-looking statements that involve risk and uncertainties. Actual
results may differ materially from those anticipated in these forward-looking statements.

This section of this Annual Report generally discusses 2021 and 2020 items and year-to-year comparisons
between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not
included in this Annual Report can be found in “Part II, Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended
December 31, 2020 filed on March 11, 2021.

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 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 also utilize our expertise to explore opportunities
to reduce industrial emissions through our carbon capture and storage collaborative arrangements along the coast of
the U.S. Gulf of Mexico.

ff

We have historically focused our operations in the U.S. Gulf of Mexico because of our deep experience and
technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple
reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive
and robust asset acquisition market. Additionally, we have access to state-of-the-art three-dimensional seismic data,
some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our
current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a large
and expanding inventory of high-quality prospects, which we believe greatly improves our development and
exploration success. The application of our extensive seismic database, coupled with our ability to effectively
reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range
of business development opportunities, including acquisitions and collaborative arrangement opportunities, among
others.

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

Outlook

During 2021, commodity prices experienced significant improvement, particularly crude oil prices, due to a
confluence of factors that have provided positive developments to the overall pricing environment when compared to
2020. With some exceptions, pandemic-related travel restrictions have gradually eased as governments continue to
have increasing access to vaccines that help reduce the spread of COVID-19. As restrictions continue to abate, there
is renewed emphasis on improving economic activity to pre-pandemic levels while managing the risk of a resurgence
in COVID-19. Meanwhile, commodity prices demonstrated resiliency during the year. Producers continued to show
restraint in increasing their capital expenditures even as prices increased, thereby causing a muted response in supply
as demand for commodities increased. Additionally, OPEC Plus remained committed to modest increases in
production during the year as the global economy recovered.

67

While the current outlook for commodity prices is favorable and our operations are no longer significantly
impacted by confinement restrictions, the risk of disruption to our operations continues as the emergence of a new
variant of COVID-19 could adversely impact our operations, or commodity prices could significantly decline from
current levels. The ongoing COVID-19 outbreak continues to evolve and, during the fourth quarter of 2021, a new
variant emerged, the Omicron variant. It is difficult to assess if it will cause meaningful disruptions in economic
activity across the world and if there will be any significant impacts in demand for energy. Additionally, while OPEC
Plus remained committed to steady and predictable production increases throughout 2021, it is difficult to determine
whether it will change its production output policy or whether its members will remain committed to the production
quotas set by the organization.

In January 2022, the Energy Information Administration published its short-term energy outlook. WTI spot
prices are expected to average $71.32 per Bbl for 2022. Global oil production is forecasted to outpace global oil
consumption during 2022 resulting in rising global oil inventories. Oil market balances are subject to significant
uncertainties which could keep oil prices volatile. Henry Hub spot prices are expected to average $3.82 per MMBtu
in the first quarter of 2022 and average $3.79 per MMBtu for all of 2022.

Looking at external events impacting the oil and gas industry, the focus on the transition and evolution to cleaner
forms of energy continues to accelerate as governments across the world discuss how to reduce GHG emissions.
Governments will continue to emphasize the importance of utilizing cleaner sources of energy and industry-wide
investments in renewables and carbon capture and storage in order to meet the emission reduction targets that will
limit the impact of GHG emissions. We believe that the pressure on our industry to manage its carbon footprint will
continue to grow as governments find ways to meet their carbon reduction targets. We see the transition to providing
cleaner forms of energy as an opportunity to position ourselves to support our industry's efforts to reduce our carbon
footprint through the use of commercially available technologies that allow us to capture and store significant volumes
of CO2.

Significant Developments

The following encompasses significant developments since our Annual Report on Form 10-K for the year ended

December 31, 2020:

Carbon Capture Initiatives — On February 15, 2022, we announced our entry into (i) a lease agreement for a
major carbon capture and sequestration project along the Mississippi River industrial corridor and (ii) a memorandum
of understanding with EnLink Midstream, LLC to jointly develop a carbon capture, transportation and sequestration
joint service offering focused on the Mississippi River industrial corridor. See Part I, Items 1 and 2. Business and
Properties — Carbon Capture & Sequestration
for additional information regarding this project and previously
announced projects.

SS

Eugene Island Pipeline System — We have experienced approximately 30 days of unplanned third-party
downtime to date in the first quarter of 2022 resulting from maintenance of the Eugene Island Pipeline System, which
carries our production from the HP-I and Green Canyon 18 facilities. As of the filing of this Annual Report, the shut-in
has resulted in a production impact of approximately 3.5 to 4.0 MBoepd for the first quarter of 2022 or 0.8 to 1.0
MBoepd for the full year 2022.

Zama Update — See Part I, Items 1 and 2. Business and Properties — Hydrocarbon Properties — Mexico — Block

7.

Federal Lease Sale — In November 2021, we announced that we were named as the high bidder on ten Deepwater
blocks comprising 57,600 acres, or 36,720 net acres, for a net total consideration of approximately $4.8 million. As
of December 31, 2021, the BOEM has not announced whether we have been awarded these leases. In January 2022,
a federal
judge invalidated the lease sale, finding that BOEM failed to consider the impact on foreign greenhouse gas
emissions if the November 2021 lease sale was not held and the court determined that this failure was a violation of
the National Environmental Policy Act.

ff

68

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 Asset 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”). See Part IV, Item
15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions for more information.

Castex Energy 2005 Asset Acquisition — On August 5, 2020, we completed the acquisition of select interest in
oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC (the “Castex 2005 Acquisition”). See
Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions for more information.

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 IV, Item 15. Exhibits and Financial
Statement Schedules — Note 3 — Acquisitions for more information.

Hurricanes and Tropical Storms — During 2021, production from the U.S. Gulf of Mexico was impacted due to
Hurricane Ida. While our assets did not sustain significant damage, the storm impacted key third-party downstream
infrastructure, which prevented us from restoring the majority of our production for several weeks. For the year ended
December 31, 2021, we estimate deferred production related to this storm was approximately 4.2 MBoepd.

During 2020, production from the U.S. Gulf of Mexico was impacted due to precautionary shut-ins of facilities
and evacuations associated with Hurricanes Hanna, Laura, Marco, Sally, Delta and Zeta and Tropical Storms Cristobal
and Beta. Although there was no major storm-related damage to our facilities, we incurred production downtime
associated with the shut-ins for the storms. For the year ended December 31, 2020, we estimate deferred production
related to these storms was approximately 4.1 MBoepd.

Ram Powell Shut-In — Production at our Ram Powell facility was shut-in in late June 2020 while waiting for the
repair of the platform’s oil export riser. We received final regulatory approvals and completed the repair of the export
riser. Production commenced on November 21, 2020. For the year ended December 31, 2020, the Ram Powell facility
shut-in resulted in deferred production of 2.1 MBoepd.

Known Trends and Uncertainties

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.

Oil prices have benefited from the continuation of coordinated production policies by 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. During January 1, 2021 through December 31, 2021, the daily spot prices for NYMEX
WTI crude oil ranged from a high of $85.64 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. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business.
See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more
additional information regarding our commodity derivative positions as of December 31, 2021.

69

Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test”
under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs,
less
accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic
limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an
impairment must be recorded. During 2021, 2020 and 2019 our ceiling test computations for our U.S. oil and gas
properties resulted in a write down of nil, $267.9 million and nil, respectively. At December 31, 2021, the Company’s
ceiling test computation was based on SEC pricing of $67.14 per Bbl of oil, $3.71 per Mcf of natural gas and $26.62
per Bbl of NGLs.

ff

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. The discounted present
value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change
in price differentials, or increase in capital or operating costs could negatively impact the estimated undiscounted cash
flows related to our proved oil and natural gas properties.

With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties,
not subject to amortization. The finalization of the unitization and unit operating agreement, which sets out the terms
on which the Block 7 reservoir will be jointly developed, and the outcome of the dispute with the Government of
Mexico over decisions taken by SENER with respect to the Zama discovery could adversely affect the value of the oil
and natural gas assets and result in an impairment of our unevaluated oil and gas properties prior to reaching a final
investment decision or of our evaluated properties upon reaching a final
investment decision. We recorded an
impairment of $18.1 million for our unproved property investment in Block 31 during the year ended December 31,
2021. See Part I, Items 1 and 2. Business and Properties — Hydrocarbon Properties — Mexico — Block 31 for
additional information.

ff

ff

Third Party Planned Downtime — Since our operations are offshore, we are vulnerable to third party downtime
events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through
the HP-I that is operated by Helix. 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 mid-2022 with an estimated shut-in lasting approximately 45 to 60 days.

BOEM Bonding Requirements — In 2016, the BOEM issued the 2016 NTL, which bolstered supplemental
bonding requirements. The NTL was not fully implemented as the BOEM under the Trump Administration first
paused, and then in 2020 rescinded, this NTL.

The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us,
whether as current or predecessor lessee or grant holder, as a result of the implementation of a new NTL analogous to
the 2016 NTL to the extent finalized, as well as to the provisions of any other new, more stringent NTLs or final rules
on supplemental bonding published by the BOEM under the Biden Administration, could materially and adversely
affect our financial condition, cash flows and results of operations. Moreover, the BOEM has the right to issue liability
orders in the future, including if it determines there is a substantial risk of nonperformance of the 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 and Tropical Storms — Since our operations are in the U.S. Gulf of Mexico, we are particularly
vulnerable to the effects of hurricanes and tropical storms on production and capital projects. Significant impacts could
include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating
expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

70

How We Evaluate Our Operations

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

operations, including:











production volumes;

realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative
contracts;

lease operating expenses;

capital expenditures; and

Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.

Basis of Presentation

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs, that
are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects
of derivatives, which are reported in “Price risk management activities income (expense)” on our Consolidated
Statements of Operations. The following table presents a breakout of each revenue component:

Oil
Natural gas
NGL

Year Ended December 31,

2021

2020

2019

86%
10%
4%

88%
9%
3%

92%
6%
2%

Our revenues may vary significantly from period to period as a result of changes in volumes of production sold

or changes in commodity prices.

Realized Prices on the Sale of Oil, Natural Gas and NGLs — The NYMEX WTI prompt month oil settlement
price is a widely used benchmark in the pricing of domestic oil in the United States. The actual prices we realize from
the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example,
the prices we realize on the oil we produce are affected by the Gulf of Mexico Basin’s proximity to U.S. Gulf Coast
refineries and the quality of the oil production sold in Eugene Island Crude, Louisiana Light Sweet Crude and Heavy
Louisiana Sweet Crude markets.

The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the
United States. The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub
price as a result of quality and location differentials. Currently, the sales points of our gas production are generally
within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our
production versus average Henry Hub prices.

71

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as
indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry
Hub monthly contract prices as well as our average realized oil, natural gas, and NGL sales prices for the periods
indicated.

Oil:

NYMEX WTI high per Bbl
NYMEX WTI low per Bbl
Average NYMEX WTI per Bbl
Average oil sales price per Bbl
(including commodity derivatives)
Average oil sales price per Bbl
(excluding commodity derivatives)

Natural Gas:

NYMEX Henry Hub high per MMBtu
NYMEX Henry Hub low per MMBtu
Average NYMEX Henry Hub per MMBtu
Average natural gas sales price per Mcf
(including commodity derivatives)
Average natural gas sales price per Mcf
(excluding commodity derivatives)

NGLs:

NGL realized price as a % of average NYMEX WTI

Year Ended December 31,

2021

2020

2019

81.48 $
52.01 $
67.99 $

57.52 $
16.55 $
39.16 $

49.67 $

47.36 $

65.86 $

37.09 $

5.51 $
2.62 $
3.91 $

3.11 $

3.98 $

39%

2.61 $
1.63 $
2.03 $

2.00 $

1.87 $

25%

63.86
51.38
56.98

59.23

60.17

3.11
2.22
2.56

2.55

2.37

28%

$
$
$

$

$

$
$
$

$

$

To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, we
enter into commodity derivative arrangements for a portion of our anticipated production. By removing a significant
portion of price volatility associated with our anticipated production, we believe it will mitigate, but not eliminate, the
potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods.
However, our price risk management activity may also reduce our ability to benefit from increases in prices. We will
sustain losses to the extent our commodity derivatives contract prices are lower than market prices and, conversely,
we will sustain gains to the extent our commodity derivatives contract prices are higher than market prices.

We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our
hedging strategy and future hedging transactions will be determined in accordance with both our Bank Credit Facility
and Hedging Policy and may be different from what we have done on a historical basis.

Expenses

Lease Operating Expense — Lease operating expense consists of the daily costs incurred to bring oil, natural
gas and NGLs out of the underground formation and to the market, together with the daily costs incurred to maintain
our producing properties. Expenses for direct labor, insurance, a portion of the HP-I lease, materials and supplies,
rental and third party costs comprise the most significant portion of our lease operating expense. It further consists of
costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s
production. Because the amount of workover and maintenance expense is closely correlated to the levels of workover
activity, which is not regularly scheduled, workover and maintenance expense is not necessarily comparable from
period-to-period. There is a reduction in our lease operating expenses for production handling fees related to certain
reimbursements for costs from certain third parties.

Production Taxes — Production taxes consist of severance taxes levied by the Louisiana Department of
Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of
Louisiana.

Depreciation, Depletion and Amortization expense — Depreciation, depletion and amortization expense is the
expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the
full cost method of accounting for oil and natural gas activities. See Part IV, Item 15. Exhibits and Financial Statement
Schedules — Note 2 — Summary of Significant Accounting Policies for further discussion.

72

Accretion Expense — We have obligations associated with the retirement of our oil and natural gas wells and
related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no
longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on
our estimate of the timing and amount to replace, remove or retire the associated assets. Accretion of the liability is
recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life
of the related assets as the discounted liabilities are accreted to their expected settlement values.

General and Administrative Expense — General and administrative expense generally consists of costs
incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters,
costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other
fees for professional services and legal compliance.

Interest Expense — We finance a portion of our working capital requirements, capital expenditures and
acquisitions with borrowings under our Bank Credit Facility and term-based debt. As a result, we incur interest
expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest
incurred under our debt agreements, the amortization of deferred financing costs (including origination and
amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual
agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory
projects that are not subject to current amortization.

Price Risk Management Activities — We utilize commodity derivative instruments to reduce our exposure to
fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity
derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change.
The commodity derivative contracts we have in place are not designated as hedges for accounting purposes.
Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and
losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the
actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

73

Results of Operations

Revenues

The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas

and NGL revenues, production volumes and sales prices (in thousands):

Revenues:

Oil
Natural gas
NGL

Total revenues

Total Production Volumes:

Oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)

Total production volume (MBoe)

Daily Production Volumes by Product:

Oil (MBblpd)
Natural gas (MMcfpd)
NGL (MBblpd)

Total production volume (MBoepd)

Year Ended December 31,

2021

2020

Change

$

$

1,064,161 $
130,616
49,763
1,244,540 $

506,788 $
53,714
15,434
575,936 $

557,373
76,902
34,329
668,604

16,159
32,795
1,875
23,500

44.3
89.8
5.1
64.4

65.86 $
3.98 $
26.54 $
52.96 $
40.61 $

13,665
28,652
1,559
19,999

37.3
78.3
4.3
54.7

37.09 $
1.87 $
9.90 $
28.80 $
35.99 $

2,494
4,143
316
3,501

7.0
11.5
0.8
9.7

28.77
2.11
16.64
24.16
4.62

Average Sale Price per Unit:

$
Oil (per Bbl)
$
Natural gas (per Mcf)
$
NGL (per Bbl)
Price per Boe
$
Price per Boe (including realized commodity derivatives) $

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):

Oil
Natural gas
NGL

Total revenues

Price

Volume

Total

464,871 $
69,155
31,201
565,227 $

92,502 $
7,747
3,128
103,377 $

557,373
76,902
34,329
668,604

$

$

Volumetric Analysis — Production volumes increased by 9.7 MBoepd to 64.4 MBoepd for the year ended
December 31, 2021. The increase in production volumes was due to an increase of 7.6 MBoepd from the Green
Canyon 18 Field, primarily due to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 Field
platform rig program. Additionally, production volumes increased 2.1 MBoepd from temporary shut-ins for repairs
and maintenance on the Ram Powell Field export riser that were completed in the fourth quarter of 2020.

74

Operating Expenses

Lease Operating Expense

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

Lease operating expenses
Lease operating expenses per Boe

Year Ended December 31,

2021

2020

$
$

283,601 $
12.07 $

246,564
12.33

Total lease operating expenses for the year ended December 31, 2021 increased by approximately $37.0 million,
or 15%. We had an overall increase in direct operating expenses and labor costs of $6.2 million due to the temporary
shuttering of the non-operated Garden Banks Field, Vermilion Field and High Island Field related to cost cutting
measures taken during the second half of 2020 because of the economic environment caused by the COVID-19
pandemic. There was an additional $19.4 million increase attributable to facility and workover expense across our
portfolio. Due to the Castex 2005 Acquisition and LLOG Acquisition in the second half of 2020, we had an increase
of $12.9 million in total lease operating expenses during the year ended December 31, 2021. On a per unit basis, lease
operating expense decreased $0.26 per Boe to $12.07 per Boe primarily due to higher production volumes.

Depreciation, Depletion and Amortization

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

Depreciation, depletion and amortization
Depreciation, depletion and amortization per Boe

Year Ended December 31,

2021

2020

$
$

395,994 $
16.85 $

364,346
18.22

Depreciation, depletion and amortization expense for the year ended December 31, 2021 increased by
approximately $31.6 million, or 9%. This increase was primarily due to increased production of 9.7 MBoepd offset
by a decrease of $1.32 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):

General and administrative expense
General and administrative expense per Boe

Year Ended December 31,

2021

2020

$
$

78,677 $
3.35 $

79,175
3.96

General and administrative expense for the year ended December 31, 2021, decreased by approximately $0.5
million, or 1%. Transaction and non-recurring costs were $5.4 million or $0.23 per Boe for 2021, which is a decrease
of $9.6 million primarily due to the ILX and Castex Acquisition and Castex 2005 Acquisition in 2020. The decrease
was offset with general and administrative expenses of $4.3 million incurred by our emerging carbon capture and
sequestration operating segment during the year ended December 31, 2021. Additionally, general and administrative
expense includes non-cash equity-based compensation of $11.0 million, or $0.47 per Boe, during the year ended
December 31, 2021, which is an increase of $2.1 million. On a per unit basis, general and administrative expense
decreased $0.61 per Boe.

75

Miscellaneous

The following table highlights miscellaneous items in total. The information below provides the financial results

and an analysis of significant variances in these results (in thousands):

Write-down of oil and natural gas properties
Accretion expense
Other operating (income) expense
Interest expense
Price risk management activities (income) expense
Other (income) expense
Income tax (benefit) expense

Year Ended December 31,

2021

2020

18,123 $
58,129 $
32,037 $
133,138 $
419,077 $
6,988 $
(1,635) $

267,916
49,741
(11,550)
99,415
(87,685)
(3,018)
35,583

$
$
$
$
$
$
$

Write-Down of Oil and Natural Gas Properties — Due to our non-consent to the Block 31 appraisal program,
we recorded an impairment of $18.1 million for our unproved property investment in Block 31 during the year ended
December 31, 2021 as the costs were not recoverable. During the year ended December 31, 2020, we recorded a
$267.9 million write-down of our oil and natural gas properties as a result of our ceiling test evaluation for our oil and
gas properties in the United States as described in Part IV, Item 15. Exhibits and Financial Statement Schedules —
Note 4 — Property, Plant and Equipment.

Other Operating (Income) Expense — During the year ended December 31, 2021, we recorded $21.1 million
of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of
divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or
insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and
Contingencies. Additionally, we recorded an impairment of $5.6 million related to the adjustment of other well
equipment inventory to net realizable value, which was expensed and reflected in “Other operating (income) expense”
on the Consolidated Statements of Operations. See further discussion in Part IV, Item 15. Exhibits and Financial
Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

During the year ended December 31, 2020, we recorded $8.9 million in income related to our multi-year federal
royalty refund claim from the ONRR. See further discussion in Part IV, Item 15. Exhibits and Financial Statement
Schedules — Note 2 — Summary of Significant Accounting Policies.

Interest Expense — During the year ended December 31, 2021, we recorded $133.1 million of interest expense
compared to $99.4 million during the year ended December 31, 2020. The change is primarily a result of the interest
associated with the 12.00% Notes issued in January 2021 with an aggregate principal amount of $650.0 million when
compared to the interest on the 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) that were
redeemed in January 2021. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules —
Note 7 — Debt.

Price Risk Management Activities — Price risk management activities for year ended December 31, 2021
resulted in a decrease of approximately $506.8 million, or 578%. The expense of $419.1 million for the year ended
December 31, 2021 consisted of $290.2 million in cash settlement losses and $128.9 million in non-cash losses from
the decrease in the fair value of our open derivative contracts. The income of $87.7 million for the year ended
December 31, 2020 consisted of $143.9 million in cash settlement gains that was offset by $56.2 million in non-cash
losses from the decrease in the fair value of our open derivative contracts.

These unrealized gains and 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 Consolidated
Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated
production volumes through December 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 year ended December 31, 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 IV, Item 15. Exhibits
and Financial Statement Schedules — Note 7 — Debt. This was partially offset by a $4.4 million gain as a result of
the settlement related to the Whistler Acquisition that is further discussed in Part IV, Item 15. Exhibits and Financial
Statement Schedules — Note 11 — Related Party Transactions.

76

Income Tax Benefit (Expense) — During the year ended December 31, 2021, we recorded $1.6 million of
income tax benefit compared to $35.6 million of income tax expense during the year ended December 31, 2020. The
change is primarily a result of the recognition of a valuation allowance for its excess federal and state deferred tax
assets in the year ended 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 9 — Income Taxes.

Commitments and Contingencies

ff
For a further

discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits and Financial
Statement Schedules — Note 12 — Commitments and Contingencies. Additionally, we are party to lawsuits arising
in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our
management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on
our financial condition. See Part I, Item 3. Legal Proceedings for additional information.

Due to the nature of our business, we are, from time-to-time, involved in other routine litigation or subject to
disputes or claims related to business activities, including workers’ compensation claims, employment related disputes
and civil penalties by regulators. In the opinion of our management, none of these other pending litigations, disputes
or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or
results of operations. See Part I, Item 3. Legal Proceedings for additional information.

Supplemental Non-GAAP Measure

EBITDA and Adjusted EBITDA

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

We define these as the following:





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

Adjusted EBITDA — EBITDA plus non-cash write-down of oil and natural gas properties, transaction
and 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.

77

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):

Year Ended December 31,

2021

2020

2019

Net income (loss)
Interest expense
Income tax expense (benefit)
Depreciation, depletion and amortization
Accretion expense

EBITDA

Write-down of oil and natural gas properties
Transaction and other expenses(1)
Derivative fair value (gain) loss(2)
Net cash received (paid) on settled derivative
instruments(2)
(Gain) loss on debt extinguishment
Non-cash write-down of other well equipment inventory
Non-cash equity-based compensation expense

Adjusted EBITDA

$

$

(182,952)$
133,138
(1,635)
395,994
58,129
402,674
18,123
26,941
419,077

(290,164)
13,225
5,606
10,992
606,474 $

(465,605)$
99,415
35,583
364,346
49,741
83,480
267,916
14,917
(87,685)

143,905
(1,662)
699
8,669
430,239 $

58,729
97,847
(36,141)
345,931
34,389
500,755
12,221
7,460
95,337

(8,820)
132
165
6,964
614,214

(1)
(2)

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

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 an increase of $120.5
million in liabilities from price risk management activities. As of December 31, 2021, our available liquidity (cash
plus available capacity under the Bank Credit Facility) was $472.6 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.

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year

ended December 31, 2021 (in thousands):

U.S. drilling & completions
Mexico appraisal & exploration
Asset management
Seismic and G&G, land, capitalized G&A and other

Total capital expenditures

a
Plugging & abandonment

Total capital expenditures and plugging & abandonment

a

$

$

129,441
921
90,000
50,472
270,834
67,988
338,822

78

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
2022 capital spending program of $450.0 million to $480.0 million, of which approximately $30.0 million is allocated
to CCS. 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
basis. To
required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic
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.

t

Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of

activity, for the following periods (in thousands):

Operating activities
Investing activities
Financing activities

Year Ended December 31,

2021

2020

$
$
$

411,388 $
(293,747) $
(82,022) $

301,923
(678,904)
324,192

Operating Activities — Cash provided by operating activities increased $109.5 million in 2021 compared to
2020 primarily attributable to an increase in revenues net of lease operating expense of $631.6 million. This was offset
by an increase in cash payments on derivatives of $434.1 million, interest expense of $33.7 million and settlements of
asset retirement obligations of $24.1 million.

Investing Activities — Cash used in investing activities decreased $385.2 million in 2021 compared to 2020
primarily due to a decrease in payments for acquisitions of $310.6 million and in capital expenditures of $69.6 million.

Financing Activities — Cash used in financing activities increased $406.2 million in 2021 compared to 2020.
During 2021, the issuance of the 12.00% Notes in January 2021 generated $579.0 million after original discount and
deferred financing costs. The net proceeds from the 12.00% Notes funded the $356.8 million redemption of the 11.00%
Notes and reduced the indebtedness under the Bank Credit Facility by $175.0 million in the first quarter of 2021.
Indebtedness under the Bank Credit Facility was then further reduced by $90.0 million during the remainder of 2021.

During 2020, net borrowings under the Bank Credit Facility was $290.0 million and proceeds from the issuance
of common stock was $71.1 million. These cash inflows were primarily offset by finance lease payments of $17.5
million and other deferred payments of $11.9 million.

Overview of Debt Instruments

Financing Arrangements — As of December 31, 2021, total debt, net of discount and deferred financing costs,
was approximately $962.7 million, comprised of our $650.0 million aggregate principal amount of the 12.00% Notes
and $6.1 million aggregate principal amount of our 7.50% Senior Notes due 2022 issued by Stone (“7.50% Notes”),
and $367.8 million outstanding under our Bank Credit Facility. We were in compliance with all debt covenants at
December 31, 2021. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement
Schedules — Note 7 — Debt.

Bank Credit Facility – matures November 2024 — We maintain a Bank Credit Facility with a syndicate of
financial institutions. 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. For additional details on our
Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt.

79

12.00% Second-Priority Senior Secured Notes—due January 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”); the Subsidiary Guarantors (defined below);
and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in
right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes
are secured on a second-priority senior secured basis by liens on substantially the same collateral as the Issuer’s
existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes mature on January 15, 2026 and
have interest payable semi-annually each January 15 and July 15, commencing on July 15, 2021. We made an interest
payment of $39.0 million on January 14, 2022. For additional details on the 12.00% Notes, see Part IV, Item 15.
Exhibits and Financial Statement Schedules — Note 7 — Debt.

Redemption of the 11.00% Second-Priority Senior Secured Notes—due April 2022 — On January 13, 2021,
we redeemed the 11.00% Notes using the proceeds from the issuance of the 12.00% Notes. For additional details on
this redemption, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt.

7.50% Senior Notes – due May 2022 — The 7.50% Notes mature May 31, 2022 and have interest payable semi-
annually each May 31 and November 30. For additional details on the 7.50% Notes, see Part IV, Item 15. Exhibits
and Financial Statement Schedules — Note 7 — Debt.

Guarantor Financial Information — We own no operating assets and have no operations independent of our
subsidiaries. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured
basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future
direct or indirect wholly owned material domestic subsidiaries (collectively, the “Subsidiary Guarantors” and, together
with the Parent Guarantor, the “Guarantors”) that guarantees the Issuer’s senior reserve-based revolving credit facility.
Our non-domestic subsidiaries (the “Non-Guarantors”) are 100% owned by us but do not guarantee the 12.00% Notes.

In lieu of providing separate financial statements for the Issuer and the Guarantors, we have presented the
accompanying supplemental summarized combined balance sheet and 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):

Current assets
Non-current assets
Total assets

Current liabilities
Non-current liabilities
Talos Energy Inc. stockholdersʼ equity

Total liabilities and stockholdersʼ equity

Year Ended December 31,

2021

2020

330,415 $

2,305,855
2,636,270 $

598,062 $

1,405,382
632,826
2,636,270 $

231,669
2,444,886
2,676,555

438,340
1,459,816
778,399
2,676,555

$

$

$

$

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

Revenues
Costs and expenses

Net loss

Year Ended December 31, 2021
1,244,540
$
(1,398,306)
(153,766)

$

Material Cash Requirements — We are party to various contractual obligations. Some of these obligations may
be reflected in our accompanying Consolidated Financial Statements, while other obligations, such as certain operating
leases and capital commitments, are not reflected on our accompanying Consolidated Financial Statements.

80

The following table and discussion summarizes our material cash requirements from known contractual

obligations as of December 31, 2021 (in thousands):

2022

2023

2024

2025

2026

Thereafter

Total(4)

Long-term financing obligations:

Debt principal
Debt interest

Vessel commitments(1)
Derivative liabilities
Operating lease obligations
Finance lease(2)
Purchase obligations(3)

$

6,060 $
93,785
29,710
186,526
3,712
45,000
3,153

— $ 375,000 $

— $ 650,000 $

93,596
—
13,938
3,652
18,750
—

91,733
—
——
3,454
——
—

78,000
—
—
3,519
—
—

3,250
—
—
3,584
—
—

Total contractual obligations(4) $ 367,946 $ 129,936 $ 470,187 $ 81,519 $ 656,834 $

— $1,031,060
— 360,364
—
29,710
— 200,464
27,179
63,750
3,153
9,258 $1,715,680

9,258
—
—

(1)

(2)
(3)
(4)

Includes commitments for drilling rigs we will utilize for certain Deepwater well intervention and decommissioning activities. These
commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for
their working interest share of such costs.
Lease agreement for the HP-I floating production facility in the Phoenix Field.
Includes committed purchase orders to execute planned future drilling activities.
This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas
properties of $434.0 million as of December 31, 2021. For additional information regarding these liabilities, please see Part IV, Item 15.
Exhibits and Financial Statement Schedules — Note 4 — Property, Plant and Equipment. Additionally, this table does not include liabilities
associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see please
see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitment and Contingencies.

Performance Obligations — As of December 31, 2021, we had secured performance bonds from third party
sureties and letters of credit issued under its Bank Credit Facility primarily related to P&A of wells and removal of
facilities in the U.S. Gulf of Mexico and certain obligations under the Mexico PSCs totaling approximately $724.4
million and $13.6 million, respectively.

For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and

Financial Statement Schedules — Note 12 — Commitments and Contingencies.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates
and assumptions that affect the reported amount of assets, liabilities, revenue and expense, and the disclosures of
contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require
complex or subjective judgment in the application of the accounting policy and that could significantly impact our
financial results based on changes in those judgments. Changes in facts and circumstances may result in revised
estimates and actual results may differ materially from those estimates. Our management has identified the following
critical accounting estimates. Our significant accounting policies are described in Part IV, Item 15. Exhibits and
Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

Oil and Natural Gas Properties — The Company follows the full cost method of accounting for oil and natural
gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection
with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized
amounts include the internal costs directly related to acquisition, development and exploration activities, asset
retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical
costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly
basis through a ceiling test calculation as discussed below.

81

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

The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from
proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved
oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling for
U.S. oil and gas properties are recognized as a non-cash “Write-down of oil and natural gas properties” on the
Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on
the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher
oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test
calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when
performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though
actual prices and costs of oil and natural gas are often volatile and may change from period to period.

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

When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and
natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds
on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does
not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the
relationship between capitalized costs and proved reserves.

Proved Reserve Estimates — We estimate our proved oil, natural gas and NGL reserves in accordance with the
guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas
and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be
economically producible in future periods from known reservoirs and under existing economic conditions, operating
methods and governmental regulations. Prices are determined using SEC pricing.

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

Fair Value Measure of Financial Instruments — Our financial instruments generally consisted of cash and cash
equivalents, accounts receivable, commodity derivatives, accounts payable and debt as of December 31, 2021. The
carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due
to the highly liquid nature of these instruments.

82

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







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

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

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

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

valuation techniques are as follows:







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

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

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

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The
estimated fair value amounts have been determined using available market information and valuation methodologies.
Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of
different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural
gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is
exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company
accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove
or retire the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several
assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated
timing of when the work will be performed and a projected inflation rate. Changes in estimate in the table below
represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically,
these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and
natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with
the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the
Company incurs an amount different from the amount accrued for asset retirement obligations, the Company
recognizes the difference as an adjustment to proved properties.

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

83

Revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable
is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an
underlying property. Our imbalances are presented gross on our Consolidated Balance Sheets. At December 31, 2021
and 2020, our imbalance receivable was approximately $1.7 million and $1.7 million, respectively, and imbalance
payable was approximately $2.5 million and $3.6 million, respectively.

Income Taxes — Our provision for income taxes includes U.S. state and federal and foreign taxes. We record our
federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of
deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book
carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which those temporary differences and
carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in
tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established
to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of
December 31, 2021, we believe it is more likely than not that some or all of the benefits from our federal and state
deferred tax assets will not be realized and reduced the net federal and state deferred tax assets by a valuation
allowance. We maintain a valuation allowance on most of our Mexico deferred tax assets.

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

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

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

There were no recently issued accounting standards material to us.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are currently exposed to market risk in two areas: commodity prices and, to a lesser extent, interest rate risk.
Our risk management activities involve the use of derivative financial instruments to mitigate the impact of market
price risk exposures primarily related to our oil and natural gas production. We are subject to a minimum hedging
requirement under our Bank Credit Facility for each calendar month on a six-full fiscal quarter rolling basis. For any
quarter occurring during the first four forward fiscal quarters, we are required to hedge a minimum of 60% of our
reasonably anticipated projected production from proved developed producing reserves from the semi-annual reserves
report delivered to the administrative agent of our Bank Credit Facility, adjusted to 45% in July and November and
30% in August, September and October. For the fifth and sixth forward fiscal quarters, we are required to hedge a
minimum of 30%, adjusted to 20% in August, September and October. Our Hedging Policy permits us to hedge more
than the minimum thresholds established by the Bank Credit Facility plus an additional two fiscal quarters with the
minimum set at 25% and reduced in the same proportions applicable under the Bank Credit Facility for hurricane
months (July to November). All derivatives are recorded on the 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 Consolidated Statements of Operations in each period.

84

Commodity Price Risks

Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and
cash flow. During year ended December 31, 2021, our average oil price realizations after the effect of derivatives
increased 5% to $49.67 per Bbl from $47.36 per Bbl in the comparable 2020 period. Our average natural gas price
realizations after the effect of derivatives increased 56% during the year ended December 31, 2021 to $3.11 per Mcf
from $2.00 per Mcf in the comparable 2020 period.

Price Risk Management Activities

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

We had commodity derivative instruments in place to reduce the price risk associated with future production of
11,310 MBbls of crude oil and 21,827 MMBtu of natural gas at December 31, 2021, with a net derivative liability
position of $196.7 million. For additional information regarding our commodity derivative instruments, see Part IV,
Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments, included elsewhere in this
Annual Report. The table below presents the hypothetical sensitivity of our commodity price risk management
activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at
December 31, 2021 (in thousands):

Price impact(1)

Oil and Natural Gas Derivatives

Ten Percent Increase

Ten Percent Decrease

Fair Value

Fair Value

Change

Fair Value

Change

$

(196,727) $

(283,824)$

(87,097)$

(109,630)$

87,097

(1)

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

Variable Interest Rate Risks

We had total debt outstanding of $1,031.1 million at December 31, 2021, before unamortized original issue
discount and deferred financing costs. Of this, $656.1 million aggregate principal was from our 12.00% Notes and
7.50% Notes, which bear interest at fixed rates. The remaining $375.0 million is from outstanding borrowings under
our Bank Credit Facility with variable interest rates. We are subject to the risk of changes in interest rates under our
Bank Credit Facility. In addition, the terms of our Bank Credit Facility require us to pay higher interest rates as we
utilize a larger percentage of our available borrowing base. We manage our interest rate exposure by maintaining a
combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates. We believe
our interest rate risk exposure is partially mitigated as a result of fixed interest rates on 64% of our debt. The all-in
interest rate on our variable rate debt at December 31, 2021 was 3.5%, which includes a spread of 3.25% based on the
utilization rate of our Bank Credit Facility, and a London Interbank Offered Rate (“LIBOR”) of 0.25%. A 10% change
in the LIBOR rate on this variable rate debt balance at December 31, 2021 would change interest expense for the year
ended December 31, 2021 by approximately $0.1 million. For additional information regarding the borrowing base
utilization percentage associated with our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement
Schedules — Note 7 — Debt, included elsewhere in this Annual Report.

Item 8. Financial Statements and Supplementary Data

See the Consolidated Financial Statements and Report of Independent Registered Public Accounting Firm as of
December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019, included in Part IV, Item
15. Exhibits and Financial Statements Schedules.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

85

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has 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 Annual Report on Form 10-K. Based on such evaluation,
our chief executive officer and chief financial officer have concluded that as of December 31, 2021, our disclosure
controls and procedures are designed at a reasonable assurance level and are effective to provide reasonable assurance
that 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 SEC, and that such
information is accumulated and communicated to our management, including our chief executive officer and chief
financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial
reporting as defined in Rule 13a-15(f) under the Exchange Act. Management conducted an assessment of the
effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control—
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013
framework). Based on the assessment, management has concluded that its internal control over financial reporting
was effective as of December 31, 2021 to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements in accordance with GAAP. Our independent registered public accounting
firm, Ernst & Young LLP, has issued an audit report with respect to our internal control over financial reporting,
which is included in this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting identified in management's evaluation
pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the fourth quarter of 2021 that materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection

Not applicable.

86

Item 10. Directors, Executive Officers and Corporate Governance

PART III

The information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual

Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors
and employees, which is available on our website (www.talosenergy.com) under “Corporate Responsibility.” We
intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a
provision of our Code of Business Conduct and Ethics by posting such information on the website address and location
specified above.

Item 11. Executive Compensation

The information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual

Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual

Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual

Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

Item 14. Principal Accounting Fees and Services

The information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual

Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

87

Item 15. Exhibits and Financial Statement Schedules

(a)

The following documents are filed as part of this Annual Report:

(1)

Financial Statements:

PART IV

Refer to the Index to Consolidated Financial Statements on page F-1 for a list of all financial statements
filed as part of this Annual Report on Form 10-K.

(2)

Financial Statement Schedules:

Financial statement schedules have been omitted because they are either not material, not required, not
applicable or the information required to be presented is included in our Consolidated Financial
Statements and related notes.

(3) Exhibits:

Exhibit
Number

2.1#

2.2#

2.3

2.4#

2.5

2.6#

2.7

2.8#

2.9

Description

Transaction Agreement, dated as of November 21, 2017, by and among Stone Energy Corporation,
Sailfish Energy Holdings Corporation, Sailfish Merger Sub Corporation, Talos Energy LLC and Talos
Production LLC (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K12B filed with
the SEC on May 16, 2018).

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).

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).

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).

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).

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).

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).

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).

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).

2.10#

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).

88

3.1

3.2

3.3

4.1

4.2

4.3

4.4

4.5

4.6

4.7

4.8

4.9

4.10

4.11

10.1

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).

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).

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).

Form of Stock Certificate for Common Stock of Talos Energy Inc. (incorporated by reference to Exhibit
4.2 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-
222341) filed with the SEC on February 9, 2018).

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).

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).

Form of 12.00% Second-Priority Senior Secured Note due 2026 (included as Exhibit A to Exhibit 4.6
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).

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

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

Stockholders’ Agreement, dated as of May 10, 2018, by and among Talos Energy Inc. and each of the
other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 4.1 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Stockholders’ Agreement Amendment, dated as of February 24, 2020, by and among Talos Energy Inc.
and each of the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit
4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

Registration Rights Agreement, dated as of May 10, 2018, by and among Talos Energy Inc. and each of
the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 4.2 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Registration Rights Agreement Amendment, dated as of February 28, 2020, by and among Talos Energy
Inc. and each of the other parties set forth on the signature pages thereto (incorporated by reference to
Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020).

Description of Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act
of 1934 (incorporated by reference to Exhibit 4.12 to Talos Energy Inc.’s Form 10-K (File No. 001-
38497) filed with the SEC on March 12, 2020).

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

89

10.2

10.3†

10.4†

10.5†

10.6†

10.7†

10.8†

10.9†

10.10

10.11

10.12

Intercreditor Agreement, dated as of May 10, 2018, between JPMorgan Chase Bank, N.A., as First Lien
Agent, and Wilmington Trust, National Association, as Second Lien Agent (incorporated by reference to
Exhibit 10.3 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Offer Letter between Talos Energy Inc. and Shannon Young, dated as of April 13, 2019 (incorporated by
reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on April 24, 2019).

Offer Letter between Talos Energy Inc. and Robert D. Abendschein, dated as of December 26, 2019
(incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed
with the SEC on January 23, 2020).

Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating
Company LLC and Timothy S. Duncan (incorporated by reference to Exhibit 10.10 to Talos Energy
Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the
SEC on March 30, 2018).

Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating
Company LLC and John A. Parker (incorporated by reference to Exhibit 10.12 to Talos Energy Inc.’s
Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC
on March 30, 2018).

Employment Agreement, dated as of August 30, 2013, by and between Talos Energy Operating Company
LLC and William S. Moss III (incorporated by reference to Exhibit 10.14 to Talos Energy Inc.’s
Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC
on March 30, 2018).

Talos Energy Inc. Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Talos Energy
Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

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).

Support Agreement, dated as of November 21, 2017, by and among Stone Energy Corporation, Sailfish
Energy Holdings Corporation, Apollo Management VII, L.P., Apollo Commodities Management, L.P.,
with respect to Series I, and Riverstone Energy Partners V, L.P. (incorporated by reference to Exhibit
10.3 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-
222341) filed with the SEC on February 9, 2018).

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

Contract for the Exploration and Extraction of Hydrocarbons under Production Sharing Modality
(Contract Area 7), dated as of September 4, 2015, by and among the National Hydrocarbons Commission,
Sierra O&G Exploración y Producción, S. de R.L. de C.V., Talos Energy Offshore México 7, S. de R.L.
de C.V. and Premier Oil Exploration and Production Mexico, S.A. de C.V. (incorporated by reference to
Exhibit 10.9 to Talos Energy Inc.’s Amendment No. 4 to the Registration Statement on Form S-4 (File
No. 333-222341) filed with the SEC on April 4, 2018).

10.13†

10.14†

10.15†

10.16†

Indemnification Agreement (Timothy S. Duncan) (incorporated by reference to Exhibit 10.5 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (Stephen E. Heitzman) (incorporated by reference to Exhibit 10.6 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (John A. Parker) (incorporated by reference to Exhibit 10.7 to Talos Energy
Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (Michael L. Harding II) (incorporated by reference to Exhibit 10.8 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

90

10.17†

10.18†

10.19†

10.20†

10.21†

10.22†

10.23†

10.24†

10.25†

10.26†

Indemnification Agreement (William S. Moss III) (incorporated by reference to Exhibit 10.9 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (Olivia C. Wassenaar) (incorporated by reference to Exhibit 10.1 to Talos
Energy Inc.’s Form 8-K filed with the SEC on November 23, 2018).

Indemnification Agreement (Christine Hommes) (incorporated by reference to Exhibit 10.11 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (Robert M. Tichio) (incorporated by reference to Exhibit 10.12 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (Neal P. Goldman) (incorporated by reference to Exhibit 10.14 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (John “Brad” Juneau) (incorporated by reference to Exhibit 10.15 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (James M. Trimble) (incorporated by reference to Exhibit 10.16 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (Charles M. Sledge) (incorporated by reference to Exhibit 10.17 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (Donald R. Kendall, Jr.) (incorporated by reference to Exhibit 10.18 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

Indemnification Agreement (Rajen Mahagaokar) (incorporated by reference to Exhibit 10.19 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.27†*

Indemnification Agreement (Paula R. Glover).

10.28†

10.29†

10.30†

10.31†

10.32†

10.33†

10.34†

10.35†

Indemnification Agreement (Shannon E. Young III), effective as of May 16, 2019 (incorporated by
reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K filed with the SEC on April 24, 2019).

Indemnification Agreement (Robert D. Abendschein) (incorporated by reference to Exhibit 10.3 to Talos
Energy Inc.’s Form 8-K filed with the SEC on January 23, 2020).

Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors) (incorporated
by reference to Exhibit 10.20 to Talos Energy Inc.’s Form 10-Q filed with the SEC on August 9, 2018).

Form of Talos Energy Inc. Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted
Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form
10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).

Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives)
(incorporated by reference to Exhibit 10.32 to Talos Energy Inc.’s Registration Statement on Form S-4
(File No. 333-227362) filed with the SEC on September 14, 2018)

Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives)
(incorporated by reference to Exhibit 10.33 to Talos Energy Inc.’s Registration Statement on Form S-4
(File No. 333-227362) filed with the SEC on September 14, 2018).

Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and
Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.3 to Talos Energy
Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).

Form of Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and
Performance Share Unit Agreement (Executives) (incorporated by reference to Exhibit 10.4 to Talos
Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).

91

10.36†

10.37†

10.38†

10.39†

10.40†

10.41

10.42

10.43

10.44

10.45*

21.1*

22.1

23.1*

23.2*

24.1*

Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and
Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy
Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 3, 2021).

Talos Energy Operating Company LLC Executive Severance Plan (incorporated by reference to Exhibit
10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on September 5, 2018).

Form of Participation Agreement pursuant to the Talos Energy Operating Company LLC Executive
Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K filed with the
SEC on September 5, 2018).

Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated
by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC
on March 2, 2020).

Form of Participation Agreement pursuant to Talos Energy Operating Company LLC Amended and
Restated Executive Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s
Form 8-K (File No. 001-38497) filed with the SEC on October 26, 2020).

Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement, dated as
of July 3, 2019, by and among Talos Energy Inc., as holdings, Talos Production LLC, as borrower, each
other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline
lender, and the lenders (including the new lenders) party thereto (incorporated by reference to Exhibit
10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on July 10, 2019).

Joinder, Commitment Increase Agreement, Second Amendment to Credit Agreement, Borrowing Base
Redetermination Agreement, and Amendment to Other Credit Documents, dated as of December 10,
2019, 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 (including the new 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 December 16, 2019).

Third Amendment to Credit Agreement and Borrowing Base Redetermination Agreement, dated as of
June 19, 2020, 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 swing
line 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 25, 2020).

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 thereto, 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).

Incremental Agreement, Borrowing Base Redetermination Agreement and Seventh Amendment to Credit
Agreement, dated as of December 21, 2021, by and among Talos Energy Inc., as holdings, Talos
Production Inc., as borrower, each other credit party thereto, JPMorgan Chase Bank, N.A., as
administrative agent, and the lenders party thereto.

List of Subsidiaries of Talos Energy Inc.

List of Subsidiary Guarantors and Issuers of Guaranteed Securities (incorporated by reference to Exhibit
22.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on August 4, 2021).

Consent of Ernst & Young LLP.

Consent of Netherland, Sewell & Associates, Inc.

Powers of Attorney (included on signature pages of this Part IV).

92

31.1*

31.2*

32.1**

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.

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.

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.

99.1*

Netherland, Sewell & Associates, Inc. reserve report for Talos Energy Inc. as of December 31, 2021.

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 Data File – The cover page interactive data file does not appear in the Interactive
Data File because its XBRL tags are embedded within the Inline XBRL document.

*

**

†

#

Filed herewith.

Furnished herewith.

Identifies management contracts and compensatory plans or arrangements.

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.

Item 16. Form 10-K Summary

None.

93

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.

SIGNATURES

Date:

February 24, 2022

By:

TALOS ENERGY INC.

/s/ Shannon E. Young III
Shannon E. Young III
Executive Vice President and Chief Financial Officer

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes
and appoints Timothy S. Duncan and Shannon E. Young III, and each of them, as his or her true and lawful attorneys-
in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and
stead, in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits
thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto
said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and
thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might
or could do in person, hereby ratifying and confirming that all said attorneys-in-fact and agents, or any of them or
their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the

following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Date

February 24, 2022

February 24, 2022

February 24, 2022

February 24, 2022

February 24, 2022

February 24, 2022

February 24, 2022

February 24, 2022

February 24, 2022

Signature

g

/s/ Timothy S. Duncan
Timothy S. Duncan
/s/ Shannon E. Young III
Shannon E. Young III
/s/ Gregory Babcock
Gregory Babcock
/s/ Paula R. Glover
Paula R. Glover

/s/ Neal P. Goldman
Neal P. Goldman

/s/ Charles M. Sledge
Charles M. Sledge

/s/ Robert M. Tichio
Robert M. Tichio

/s/ John “Brad” Juneau
John “Brad” Juneau

/s/ Donald R. Kendall, Jr.
Donald R. Kendall, Jr.

Title

Chief Executive Officer
(Principal Executive Officer, Director)
Chief Financial Officer
(Principal Financial Officer, Authorized Signatory)
Chief Accounting Officer
(Principal Accounting Officer, Authorized Signatory)

Director

Director

Director

Director

Director

Director

94

Index to Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firm (PCAOB ID 42) .................................................

Consolidated Balance Sheets as of December 31, 2021 and 2020 ....................................................................

Consolidated Statements of Operations for the years ended December 31, 2021, 2020 and 2019 ...................

Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the years ended December 31,
2021, 2020 and 2019 .........................................................................................................................................

Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019 ..................

Notes to Consolidated Financial Statements......................................................................................................

Note 1 — Organization, Nature of Business and Basis of Presentation .......................................................

Note 2 — Summary of Significant Accounting Policies ..............................................................................

F-2

F-5

F-6

F-7

F-8

F-9

F-9

F-9

Note 3 — Acquisitions..................................................................................................................................

F-15

Note 4 — Property, Plant and Equipment.....................................................................................................

F-18

Note 5 — Leases ...........................................................................................................................................

F-19

Note 6 — Financial Instruments ...................................................................................................................

F-20

Note 7 — Debt ..............................................................................................................................................

F-22

Note 8 — Employee Benefit Plans and Share-Based Compensation ...........................................................

F-25

Note 9 — Income Taxes ...............................................................................................................................

F-27

Note 10 — Income (Loss) Per Share ............................................................................................................

F-30

Note 11 — Related Party Transactions.........................................................................................................

F-30

Note 12 — Commitments and Contingencies...............................................................................................

F-32

Note 13 — Supplemental Oil and Gas Disclosures (Unaudited)..................................................................

F-33

F-1

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Talos Energy Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Talos Energy Inc. (the Company) as of December
31, 2021 and 2020, the related consolidated statements of operations, changes in stockholders' equity (deficit) and
cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively
referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present
fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results
of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity
with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2021, based on criteria
established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework) and our report dated February 24, 2022 expressed an unqualified opinion
thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an
opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with
the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material
procedures that respond to
misstatement of the financial statements, whether due to error or fraud, and performing
those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in
the financial statements. Our audits also included evaluating the accounting principles used and significant estimates
made by management, as well as evaluating the overall presentation of the financial statements. We believe that our
audits provide a reasonable basis for our opinion.

ff

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial
statements that was communicated or required to be communicated to the audit committee and that: (1) relates to
accounts or disclosures that are material to the financial statements and (2) involved our especially challenging,
subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our
opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical
audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which
it relates.

F-2

Description of the
Matter

Depreciation, depletion and amortization of oil and natural gas properties

At December 31, 2021, the carrying value of the Company’s property and equipment was
$2.4 billion, and depreciation, depletion and amortization (DD&A) expense was $396.0
million for the year then ended. As described in Note 2, the Company follows the full cost
method of accounting for its oil and gas properties. DD&A of the cost of proved oil and gas
properties is calculated using the unit-of-production method based on proved oil and gas
reserves, as estimated by the Company’s internal reservoir engineers.

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and
natural gas liquids, 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. Significant judgment is required by the Company’s internal reservoir
engineers in evaluating geological and engineering data when estimating oil and gas reserves.
Estimating reserves also requires the selection of inputs,
including oil and gas price
assumptions, future operating and capital costs assumptions, among others. Because of the
complexity involved in estimating oil and gas reserves, management engaged independent
petroleum engineers to audit the proved oil and gas reserve estimates prepared by the
Company’s internal reservoir engineers for all properties as of December 31, 2021.

Auditing the Company’s DD&A calculation is complex because of the use of the work of the
internal reservoir engineers and independent petroleum engineers and the evaluation of
management’s determination of the inputs described above used by the engineers in
estimating proved oil and gas reserves.

How We Addressed
the Matter in Our
Audit

We obtained an understanding, evaluated the design, and tested the operating effectiveness of
the Company’s controls over its process to calculate DD&A, including management’s
controls over the completeness and accuracy of the financial data provided to the engineers
for use in estimating oil and gas reserves.

Our audit procedures included, among others, evaluating the professional qualifications and
objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing
the preparation of the reserve estimates and the independent petroleum engineers used to audit
the proved oil and gas reserve estimates. In addition, in assessing whether we can use the
work of the engineers, we evaluated the completeness and accuracy of the financial data and
inputs described above used by the engineers in estimating oil and gas reserves by agreeing
them to source documentation, and we identified and evaluated corroborative and contrary
evidence. For proved undeveloped reserves, we evaluated management’s development plan
for compliance with the SEC rule that undrilled locations are scheduled to be drilled within
five years, unless specific circumstances justify a longer time, by assessing consistency of the
development projections with the Company’s development plan and the availability of capital
relative to the development plan. We also tested the mathematical accuracy of the DD&A
calculations, including comparing the oil and gas reserve amounts used in the calculations to
the Company’s reserve reports.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2010.

Houston, Texas
February 24, 2022

F-3

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Talos Energy Inc.

Opinion on Internal Control Over Financial Reporting

We have audited Talos Energy Inc.’s internal control over financial reporting as of December 31, 2021, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Talos Energy Inc. (the
Company) maintained, in all material respects, effective internal control over financial reporting as of December 31,
2021, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related
consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the three
years in the period ended December 31, 2021, and the related notes (collectively referred to as the “consolidated
financial statements”) and our report dated February 24, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and
for its assessment of the effectiveness of internal control over financial reporting included in the accompanying
Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on
the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance
with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could
have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.

/s/ Ernst & Young LLP

Houston, Texas
February 24, 2022

F-4

TALOS ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)

Year Ended December 31,

2021

2020

$

69,852 $

ASSETS

Current assets:

Cash and cash equivalents
Accounts receivable:

Trade, net
Joint interest, net
Other, net

Assets from price risk management activities
Prepaid assets
Other current assets

Total current assets
Property and equipment:
Proved properties
Unproved properties, not subject to amortization
Other property and equipment

Total property and equipment

Accumulated depreciation, depletion and amortization

Total property and equipment, net
Other

glong-term assets:

Assets from price risk management activities
Other well equipment inventory
Operating lease assets
Other assets

Total assets

LIABILITIES AND STOCKHOLDERSʼ EQUITY

Current liabilities:

ypayable
Accounts
Accrued liabilities
Accrued royalties
Current portion of long-term debt
Current portion of asset retirement obligations
Liabilities from price risk management activities
Accrued interest payable
Current portion of operating lease liabilities
Other current liabilities

Total current liabilities
gLong-term liabilities:

Long-term debt, net of discount and deferred financing costs
Asset retirement obligations
Liabilities from price risk management activities
Operating lease liabilities
Other long-term liabilities

Total liabilities
Commitments and contingencies (Note 12)
Stockholdersʼ equity:

Preferred stock, $0.01 par value; 30,000,000 shares authorized and
no shares issued or outstanding as of December 31, 2021 and 2020
Common stock $0.01 par value; 270,000,000 shares authorized;
81,881,477 and 81,279,989 shares issued and outstanding as of
December 31, 2021 and 2020, respectively
Additional paid-in capital
Accumulated deficit
Total stockholdersʼ equity
Total liabilities and stockholdersʼ equity

See accompanying notes.

F-5

$

$

$

173,241
28,165
18,062
967
48,042
1,674
340,003

5,232,479
219,055
29,091
5,480,625
(3,092,043)
2,388,582

2,770
17,449
5,714
12,297
2,766,815 $

85,815 $
130,459
59,037
6,060
60,311
186,526
37,542
1,715
33,061
600,526

956,667
373,695
13,938
16,330
45,006
2,006,162

34,233

106,220
50,471
18,448
6,876
29,285
1,859
247,392

4,945,550
254,994
32,853
5,233,397
(2,697,228)
2,536,169

945
18,927
6,855
24,258
2,834,546

104,864
163,379
27,903
—
49,921
66,010
9,509
1,793
24,155
447,534

985,512
392,348
9,625
18,554
54,372
1,907,945

—

—

819
1,676,798
(916,964)
760,653
2,766,815 $

813
1,659,800
(734,012)
926,601
2,834,546

TALOS ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share amounts)

2021

Year Ended December 31,
2020

2019

Revenues:
Oil
Natural gas
NGL

Total revenues
Operating expenses:

Lease operating expense
Production taxes
Depreciation, depletion and amortization
Write-down of oil and natural gas properties
Accretion expense
General and administrative expense
Other operating (income) expense

Total operating expenses
Operating income (expense)
Interest expense
Price risk management activities income (expense)
Other income (expense)
Net income (loss) before income taxes
Income tax benefit (expense)
Net income (loss)

Net income (loss) per common share:

Basic
Diluted

Weighted average common shares outstanding:

Basic
Diluted

$

$

$
$

1,064,161 $
130,616
49,763
1,244,540

283,601
3,363
395,994
18,123
58,129
78,677
32,037
869,924
374,616
(133,138)
(419,077)
(6,988)
(184,587)
1,635
(182,952)$

(2.24)$
(2.24)$

81,769
81,769

506,788 $
53,714
15,434
575,936

246,564
1,054
364,346
267,916
49,741
79,175
(11,550)
997,246
(421,310)
(99,415)
87,685
3,018
(430,022)
(35,583)
(465,605)$

(6.88)$
(6.88)$

67,664
67,664

833,118
55,278
19,668
908,064

243,427
1,349
345,931
12,221
34,389
77,209
(19,556)
694,970
213,094
(97,847)
(95,337)
2,678
22,588
36,141
58,729

1.08
1.08

54,185
54,413

See accompanying notes.

F-6

TALOS ENERGY INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)
(In thousands, except share amounts)

Shares

Par Value

Preferred
Stock

Common Stock Preferred Stock

— $
—

542 $
—

Balance at December 31, 2018
Equity-based compensation
Equity-based compensation
tax withholdings

Equity-based compensation
stock issuances
Net income

Balance at December 31, 2019
Equity-based compensation
Equity-based compensation
tax withholdings
Equity-based compensation
stock issuances
Issuance of preferred stock
(Note 3)
Conversion of preferred
stock
into common stock (Note
3)
Issuance of common stock
Issuance of common stock
for acquisitions (Note 3)
Issuance of common stock
for debt exchange (Note 7)
Net loss

y

Balance at December 31, 2020
Equity-based compensation
Equity-based compensation
tax withholdings
Equity-based compensation
stock issuances
Net loss

Balance at December 31, 2021

Common
Stock
54,155,768
—

—

41,236
—
54,197,004
—

—

180,525

—

—
—
—
—

—

—

—

110,000

11,000,000
8,250,000

4,602,460

3,050,000
—
81,279,989
—

—

601,488
—
81,881,477

(110,000)
—

—

—
—
—
—

—

—
—
— $

—

—
—
542
—

—

1

—

110
83

46

31
—
813
—

—

Additional
Paid- In
Capital
1,334,090 $
12,385

Accumulated
Deficit

(327,136)$

Total
Stockholders
Equity
(Deficit)
1,007,496
12,385

(333)

(333)

—

—

— $
—

—

—
—
—
—
— 1,346,142
16,462
—

—
58,729
(268,407)
—

—
58,729
1,078,277
16,462

—

—

1

(1)
—

—

(827)

(1)

156,199

(109)
70,658

35,347

—

—

—

—
—

—

(827)

—

156,200

—
70,741

35,393

35,929
—
—
—
— 1,659,800
20,165
—

—
(465,605)
(734,012)
—

35,960
(465,605)
926,601
20,165

—

(3,161)

—

(3,161)

6
—
819 $

—
—
— $

(6)
—

1,676,798 $

—
(182,952)
(916,964)$

—
(182,952)
760,653

See accompanying notes.

F-7

TALOS ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

Year Ended December 31,
2020

2019

2021

$

(182,952)$

(465,605)$

58,729

454,123
23,729
13,382
10,992
419,077
(290,164)
13,225
(67,988)
(687)

(35,396)
(18,901)
(6,261)
64,800
14,409
411,388

(293,331)
(5,399)
4,983
(293,747)

—
600,500
(356,803)
100,000
(365,000)
(27,833)
(7,921)
(21,804)
(3,161)
(82,022)

35,619

34,233
69,852 $

45,761 $
— $

68,891 $

414,087
268,615
6,804
8,669
(87,685)
143,905
(1,662)
(43,933)
—

(34,645)
35,934
27,096
4,200
26,143
301,923

(362,942)
(315,962)
—
(678,904)

71,100
—
(5,364)
350,000
(60,000)
(1,287)
(11,921)
(17,509)
(827)
324,192

(52,789)

87,022
34,233 $

74,957 $
35,960 $

67,443 $

380,320
12,386
5,207
6,964
95,337
(8,820)
—
(75,331)
—

5,788
(15,114)
7,523
(35,459)
(43,797)
393,733

(463,409)
(37,916)
5,369
(495,956)

—
—
(10,567)
110,000
(25,000)
(1,963)
(9,921)
(14,133)
(333)
48,083

(54,140)

141,162
87,022

90,956
—

62,571

Cash flows from operating activities:

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

Depreciation, depletion, amortization and accretion expense
Write-down of oil and natural gas properties and other well inventory
Amortization of deferred financing costs and original issue discount
Equity-based compensation expense
Price risk management activities expense (income)
Net cash received (paid) on settled derivative instruments
Loss (gain) on extinguishment of debt
Settlement of asset retirement obligations
Gain on sale of assets

Changes in operating assets and liabilities:

Accounts receivable
Other current assets
Accounts payable
Other current liabilities
Other non-current assets and liabilities, net

Net cash provided by operating activities
Cash flows from investing activities:

Exploration, development and other capital expenditures
Cash paid for acquisitions, net of cash acquired
Proceeds from sale of property and equipment, net

Net cash used in investing activities
Cash flows from financing activities:

Proceeds from issuance of common stock
Issuance of senior notes
Redemption of senior notes and other long-term debt
Proceeds from Bank Credit
Facility
y
Repayment of Bank Credit Facility
Deferred financing costs
Other deferred payments
Payments of finance lease
Employee stock awards tax withholdings

Net cash provided by (used in) financing activities

Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents:

Balance,
g
Balance, end of period

beginning of period
g

$

Supplemental non-cash transactions:

Capital expenditures included in accounts payable and accrued liabilities $
Debt exchanged for common stock
$
Supplemental cash flow information:

Interest paid, net of amounts capitalized

$

See accompanying notes.

F-8

TALOS ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2021

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

Organization and Nature of Business

Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14,
2017. On May 10, 2018, the Parent Company consummated a combination between Talos Energy LLC and Stone
Energy Corporation (“Stone”) (such combination, “Stone Combination”). Talos Energy LLC, which was the acquirer
of Stone for financial reporting and accounting purposes, was formed in 2011 and commenced commercial operations
on February 6, 2013. The Parent Company conducts all business operations through its operating subsidiaries, owns
no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent
Company’s common stock is traded on the New York Stock Exchange under the ticker symbol “TALO.”

The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven
independent exploration and production company focused on safely and efficiently maximizing long-term value
through its operations, currently in the United States (“U.S.”) 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 in the
acquisition, exploration and development of assets in key geological trends that are present in many offshore basins
around the world. With a focus
on environmental stewardship, the Company also utilizes its expertise to explore
opportunities to reduce industrial emissions through our carbon capture and storage collaborative arrangements along
the coast of the U.S. Gulf of Mexico.

ff

Basis of Presentation and Consolidation

The Consolidated Financial Statements have been prepared in accordance with GAAP and include each
subsidiary from the date of inception. All intercompany transactions have been eliminated. All adjustments are of a
normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows
for the periods reflected herein.

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.

Certain reclassifications have been made to the prior year presentation to conform to the current year
presentation. Amounts previously included as income in “Other” within “Revenues and Other” on the Consolidated
Statements of Operations are now reflected in “Other operating (income) expense” as a component of “Total
operating expenses” on the Consolidated Statements of Operations.

The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“E&P
Segment”) and (ii) carbon capture and sequestration (“CCS Segment”). The E&P Segment is the Company’s only
reportable segment. The CCS Segment did not meet any of the quantitative thresholds to be a separate reportable
segment. It did not generate any revenue and incurred $4.3 million of general and administrative expense during the
year ended December 31, 2021. The CCS Segment did not have any assets at December 31, 2021.

Note 2 — Summary of Significant Accounting Policies

Overview of Significant Accounting Policies

Cash and Cash Equivalents — The Company presents cash as “Cash and cash equivalents” on the Company’s
Consolidated Balance Sheets. The Company considers all cash, money market funds and highly liquid investments
with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried
at cost, which approximates fair value.

F-9

Accounts Receivable and Allowance for Expected Credit Losses — Accounts receivable are stated at the
historical carrying amount net of an allowance for expected credit losses. At each reporting period, the recoverability
of material receivables is assessed using historical data, current market conditions and reasonable and supported
forecasts of future economic conditions to determine their expected collectability. A loss-rate methodology is used
to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to
be collected. As of December 31, 2021 and 2020, the Company had allowances of $15.1 million and $9.2 million,
respectively, presented net in accounts receivable on the Consolidated Balance Sheets.

The Company presented $10.0 million and $19.1 million of long-term refund claims for value added taxes paid
in Mexico in “Other assets” on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively.
Current refund claims for value added taxes paid of $3.9 million and nil is presented net of an allowance in “Other”
accounts receivable on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively.

Prepaid Assets — Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue
(“ONRR”). The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days
of the production date. On a monthly basis the Company adjusts the deposit based on actual royalty payments remitted
to the ONRR.

Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold
to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of
production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to
the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably
assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The
Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the
product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are
wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not
required.

Gas Imbalances — Revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance
receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved
developed reserves in an underlying property. Our imbalances are presented gross on our Consolidated Balance
Sheets. At December 31, 2021 and 2020, our imbalance receivable was approximately $1.7 million and $1.7 million,
respectively, and imbalance payable was approximately $2.5 million and $3.6 million, respectively.

Production Handling Fees — The Company presents certain reimbursements for costs from certain third parties

as a reduction of “Lease operating expense” on the Consolidated Statements of Operations.

ONRR Federal Royalty Refund — Included within “Other operating (income) expense” on the Consolidated
Statements of Operations is income from the Company’s multi-year federal royalty refund claim from the ONRR.
The Company records income when a refund is filed and its collection is reasonably assured. The refunds for the
years ended December 31, 2021, 2020 and 2019 were nil, $8.9 million and $19.3 million, respectively.

Debt Issuance Costs — The Company presents debt issuance costs associated with revolving line-of-credit

arrangements as a reduction of the carrying value of long-term debt.

Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for
oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred
in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These
capitalized amounts include the internal costs directly related to acquisition, development and exploration activities,
asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and
geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment
on a quarterly basis through a ceiling test calculation as discussed below.

F-10

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

The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from
proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved
oil and natural gas properties not being amortized less the related tax effects. Generally, any costs in excess of the
ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements
of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s
Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas
and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each
quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the
ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices
and costs of oil and natural gas are often volatile and may change from period to period.

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

When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and
natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds
on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does
not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the
relationship between capitalized costs and proved reserves.

Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of
leasehold improvements, office furniture and fixtures and computer hardware. Acquisitions and betterments are
capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line
method over estimated useful lives of three to ten years.

Other Well Equipment Inventory — Other well equipment inventory primarily represents the cost of equipment
to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and
certain wellhead equipment. When well equipment is supplied to wells, the cost is capitalized in oil and gas
properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party
participants. The Company’s well equipment is stated at the lower of cost or net realizable value. The Company
recorded $5.6 million, $0.7 million, and $0.2 million of impairment to adjust inventory to net realizable value, which
was expensed and reflected in “Other operating (income) expense” on the Consolidated Statements of Operations,
during the years ended December 31, 2021, 2020 and 2019, respectively.

Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash
equivalents, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash
and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid
nature of these instruments.

F-11

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







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

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

Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require
the reporting entity to develop its own assumptions, and are significant to the fair value measurement.

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

valuation techniques are as follows:







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

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

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

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The
estimated fair value amounts have been determined using available market information and valuation methodologies.
Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of
different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural
gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is
exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company
accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove
or retire the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several
assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services,
estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent
changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these
changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural
gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the
increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the
Company incurs an amount different from the amount accrued for asset retirement obligations, the Company
recognizes the difference as an adjustment to proved properties.

F-12

Decommissioning Obligations — Certain counterparties in divestiture transactions or third parties in existing
leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform
required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning
of various facilities and related wells. The Company accrues losses associated with decommissioning obligations
when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount
accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the
others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information
becomes available. As of December 31, 2021, the Company incurred $3.8 million and $20.6 million in obligations
reflected as “Other current liabilities” and “Other long-term liabilities”, respectively, on the Consolidated Balance
Sheets. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate
for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 12 —
Commitments & Contingencies

for additional information.

CC

Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil
and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may
require payments to (or receipts from) counterparties based on the differential between a fixed
price and a variable
price for a fixed

ff
quantity of oil or natural gas without the exchange of underlying volumes.

ff

Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such
contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the
settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk
management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies
cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash
flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash
flows from operating activities. The Company does not enter into derivative agreements for trading or other
speculative purposes.

The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange
or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that
extend beyond the period for which quotations are available. Where quotes are not available, the Company then
utilizes other valuation techniques or models to estimate market values. These modeling techniques require the
Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s
actual results may differ from its estimates, and these differences can be favorable or unfavorable.

Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent
an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates
the pattern of expense recognition in the income statement. Operating leases are reflected as “Operating lease assets,”
“Current portion of operating lease liabilities” and “Operating lease liabilities” on the Consolidated Balance Sheets.
Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabilities”
on the Consolidated Balance Sheets.

A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease
liability representing our obligation to make lease payments arising from the lease are recognized on the Consolidated
Balance Sheets for all leases, regardless of classification. The ROU asset is initially measured as the present value of
the lease liability adjusted for any payments made prior to lease commencement, including any initial direct costs
incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease
payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit
rate, the Company generally uses an incremental borrowing rate based on the estimated rate of interest for
collateralized borrowing over a similar term of the lease payments at commencement date.

The Company has elected to account for lease and non-lease components in its contracts as a single lease
component for all asset classes. Our lease terms may include options to extend or terminate the lease when it is
reasonably certain that the Company will exercise that option. The Company has elected, as an accounting policy,
not to record leases with terms of twelve months or less (i.e. short-term) on the Consolidated Balance Sheets. See
Note 5 — Leases for additional information.

F-13

Income Taxes — The Company records current income taxes based on estimates of current taxable income and
provides for deferred income taxes to reflect estimated future income tax payments and receipts. The impact to
changes in tax laws are recorded in the period the change is enacted. Deferred taxes represent the tax impacts of
differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end.
The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-
term on the Consolidated Balance Sheets.

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

The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as
“Interest expense” and “General and administrative expense” on the Consolidated Statements of Operations,
respectively.

Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income
(loss) by the weighted average number of shares of common stock outstanding during the period. Except when the
effect would be antidilutive, diluted EPS includes the impact of restricted stock units (“RSUs”), performance share
units (“PSUs”) and outstanding warrants. See Note 10 — Income (Loss) Per Share for additional information.

Share-Based Compensation — Certain of the Company’s employees participate in its equity-based compensation
plan. The Company measures all employee equity based compensation awards at fair value on the date awards are
granted to its employees and recognizes compensation cost on a straight-line basis in the Company’s financial
statements over the requisite service period of each grant.

The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards
classified as equity unless the award is modified, but is remeasured at each reporting period for awards classified as
a liability. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in
“General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to
oil and gas properties. See Note 8 — Employee Benefits Plans and Share-Based Compensation for additional
information.

RSUs — Share-based compensation is based on the market price of the Company’s common stock on the grant

date and recognized over the requisite service period using the straight-line method.

PSUs — Share-based compensation is based on the grant date fair value determined using a Monte Carlo
valuation model and recognized over the requisite service period using the straight-line method. Estimates used in
the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of common
stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total
shareholder return (“TSR”) relative to the TSR achieved by a specified industry peer group. Share-based
compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition
is not achieved.

Concentration of Credit Risk

Consisting principally of cash and cash equivalents, accounts receivable and commodity derivatives, the

Company is subject to concentrated financial instruments credit risk.

Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed federally
insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on
these accounts.

Commodity derivatives are entered into with registered swap dealers, all of which participate in the Company’s
senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial
condition of these institutions and has not experienced losses due to counterparty default on these instruments.

F-14

The Company markets substantially all of its oil and natural gas production, and substantially all of its revenues
are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers
under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily
of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas
producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances
for probable credit losses when necessary. The percent of consolidated revenue of major customers, those whose
total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows:

Shell Trading (US) Company
Chevron Products Company
Phillips 66

** Less than 10%

Year Ended December 31,

2021

2020

2019

45%
29%
**

47%
12%
22%

58%
**
28%

The loss of a major customer could have material adverse effect on the Company in the short term. However,
the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.

Note 3 — Acquisitions

Asset Acquisitions

Acquisitions qualifying as an asset acquisition requires, among other items, that the cost of the assets acquired
and liabilities assumed to be recognized on the Consolidated Balance Sheets by allocating the asset cost on a relative
fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement
obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not
observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but
are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated
future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the
Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized
as a component of the assets acquired and any contingent consideration is recognized as the contingency is resolved.

Acquisition of LLOG Properties — On November 16, 2020, the Company completed the acquisition of select oil
and natural gas assets from LLOG Exploration & Production Company, L.L.C. with an effective date of August 1,
2020 (the “LLOG Acquisition”). The oil and natural gas assets consist of interests in the Mississippi Canyon core
area. The LLOG Acquisition was consummated pursuant to a Purchase and Sale Agreement executed on November
16, 2020 for $13.2 million in cash, inclusive of customary closing adjustments and $0.2 million of transaction related
expenses.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed,

based on their relative fair values, on November 16, 2020 (in thousands):

Property and equipment
Asset retirement obligations
Allocated purchase price

$

$

17,421
(4,234)
13,187

F-15

Acquisition of Castex Energy 2005 — On August 5, 2020, the Company completed the acquisition of select oil
and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC with an effective date of April 1, 2020 (the
“Castex Energy 2005 Acquisition”). The oil and natural gas assets consisted of 16 properties in the U.S. Gulf of
Mexico shelf and Gulf Coast core area. The Castex Energy 2005 Acquisition was consummated pursuant to a
Purchase and Sale Agreement dated June 19, 2020 for consideration consisting of (i) $6.5 million in cash, (ii) 4.6
million shares of the Company’s common stock and (iii) $1.4 million in transaction related expenses, inclusive of
customary closing adjustments.

The following table summarizes the purchase price, inclusive of customary closing adjustments (in thousands

except share and per share data):

Talos common stock
Talos common stock price per share(1)

Talos common stock value

Cash consideration
Transaction cost

Total purchase price

$
$

$
$

$

4,602,460
7.69
35,393

6,500
1,413

43,306

(1)

Represents the closing price of the Company’s common stock on August 5, 2020, the closing date of the Castex Energy 2005 Acquisition.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed,

based on their relative fair values, on August 5, 2020 (in thousands):

Property and equipment
Asset retirement obligations
Allocated purchase price

$

$

46,626
(3,320)
43,306

Acquisition of Gunflint Field — On January 11, 2019, the Company completed the acquisition of an approximate
9.6% non-operated working interest in the Gunflint Field located in the Mississippi Canyon area (the “Gunflint
Acquisition”) from Samson Offshore Mapleleaf, LLC for $29.6 million ($27.9 million after customary purchase price
adjustments).

Business Combination

Acquisitions qualifying as business combinations are accounted for under the acquisition method of
accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the
Consolidated Balance Sheets at their fair values as of the acquisition date. The fair value measurements of the oil and
natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach
and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements
in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development
costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required
significant judgments and estimates at the time of the valuation.

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 in Note 11
— Related Parties) (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 consideration was funded with borrowings under the Bank Credit Facility.

F-16

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

Talos Conversion Stock
Talos common stock price per share(1)

Conversion Stock value

Cash consideration
Customary closing and post-closing adjustments

Net cash consideration

Total purchase price

$
$

$

$

$

11,000,000
14.20
156,200

385,000
(81,878)
303,122

459,322

(1)

Represents the closing price of the Company’s common stock on February 28, 2020, the closing date 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)
Property and equipment
Other long-term assets
Current liabilities
Other long-term liabilities
Allocated purchase price

$

$

11,060
496,835
148
(16,520)
(32,201)
459,322

(1)

Includes trade and other receivables of $8.2 million.

The Company incurred $12.1 million of transaction related costs, of which $8.7 million and $3.4 million were
recognized in the years ended December 31, 2020 and 2019, respectively. These costs are reflected in “General and
administrative expense” on the Consolidated Statements of Operations.

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

Acquisition:

Revenue
Net loss

Year Ended December 31, 2020
126,857
$
(6,011)
$

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information
(in thousands, except per common share amounts), presents the consolidated results of operations for the years ended
December 31, 2020 and 2019 as if the ILX and Castex Acquisition had occurred on January 1, 2019. 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, 2019, nor is such information
indicative of any expected future results of operations.

Revenue
Net income (loss)
Basic net income (loss) per common share
Diluted net income (loss) per common share

Year Ended December 31,
2019
2020

634,921 $
(449,988)$
(6.48)$
(6.48)$

1,246,391
148,091
2.27
2.26

$
$
$
$

F-17

Note 4 — Property, Plant and Equipment

Proved Properties

The Company’s interests in oil and natural gas proved properties are located in the United States, primarily in
the Gulf of Mexico deep and shallow waters. During 2021, 2020 and 2019,
the Company’s ceiling test
computations resulted in a write-down of its U.S. oil and natural gas properties of nil, $267.9 million and nil,
respectively. At December 31, 2021, its ceiling test computation was based on SEC pricing of $67.14 per Bbl of oil,
$3.71 per Mcf of natural gas and $26.62 per Bbl of NGLs.

Unproved Properties

Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated
properties associated with acquisitions, leases awarded in the U.S. Gulf of Mexico federal lease sales, certain
geological and geophysical costs, expenditures associated with certain exploratory wells in progress and capitalized
associated with exploration and appraisal activities in Block
interest. Unproved properties also include expenditures
7 located in the shallow waters off the coast of Mexico’s Tabasco state.

t

The following table sets forth a summary of the Company’s oil and natural gas property costs not being

amortized at December 31, 2021, by the year in which such costs were incurred (in thousands):

Acquisition United States
Exploration United States
Exploration Mexico

Total unproved properties, not subject
to amortization

Total

2021

2020

2019

Year Ended December 31,

$

46,757 $
62,038
110,260

— $

16,242
2,736

37,704 $
11,195
13,853

3,216 $
31,111
48,508

2018 and Prior
5,837
3,490
45,163

$

219,055 $

18,978 $

62,752 $

82,835 $

54,490

The excluded costs will be included in the amortization base as properties are evaluated and proved reserves

are established or impairment is determined.

The Company’s evaluation of unproved property located offshore Mexico resulted in a non-cash impairment
of $18.1 million, $0.1 million and $12.2 million for the years ended December 31, 2021, 2020 and 2019, respectively,
presented as “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations. The non-
cash impairment is attributable to the Company’s operations offshore Mexico in Block 2 and Block 31. The
impairment of operations in Block 31 is attributable to the Company’s non-consent of the proposed appraisal plan
during the fourth quarter of 2021. The impairment of operations in Block 2 is attributable to the Company’s
assessment of future exploratory drilling opportunities and results from exploratory wells drilled during the second
quarter of 2019.

Asset Retirement Obligations

The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current

liabilities, and the changes in that liability were as follows (in thousands):

Balance, beginning of period
Obligations acquired(1)
Obligations incurred
Obligations settled
gObligations divested
Accretion expense
Changes in estimate
Balance, end of period

Less: Current portion

Long-term portion

Year Ended December 31,

2021

2020

$

$

$

442,269 $
433
52
(67,988)
(340)
58,129
1,451
434,006 $
60,311
373,695 $

369,478
44,311
4,511
(43,933)
(185)
49,741
18,346
442,269
49,921
392,348

(1)

Year ended December 31, 2020 includes $35.3 million, $3.3 million and $4.2 million of asset retirement obligations assumed in the ILX
and Castex Acquisition, Castex Energy 2005 Acquisition and LLOG Acquisition, respectively.

F-18

Note 5 — 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.

ff

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

Finance lease cost - interest on lease liabilities
Operating lease cost, excluding short-term leases(1)
Short-term lease cost(2)
Variable lease cost(3)
Total lease cost

Year Ended December 31,

2021

2020

2019

11,453 $
2,706
38,472
1,356
53,987 $

15,748 $
3,361
53,573
543
73,225 $

19,115
3,261
85,865
11
108,252

$

$

(1)

(2)

(3)

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

The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability,

adjusted for initial direct costs and incentives were as follows (in thousands):

Operating leases:

Operating lease assets

Current portion of operating lease liabilities
Operating lease liabilities
Total operating lease liabilities

Finance leases:

Proved property

Other current liabilities
Other long-term liabilities
Total finance lease liabilities

Year Ended December 31,

2021

2020

5,714 $

1,715 $
16,330
18,045 $

6,855

1,793
18,554
20,347

124,299 $

124,299

27,083 $
13,138
40,221 $

21,804
40,222
62,026

$

$

$

$

$

$

F-19

The table below presents the lease maturity by year as of December 31, 2021 (in thousands). Such
commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on
the Consolidated Balance Sheets.

2022
2023
2024
2025
2026
Thereafter

Total lease payments

Imputed interest

Total lease liabilities

g
Operating Leases

Finance Leases

$

$

$

3,712 $
3,652
3,454
3,519
3,584
9,258
27,179 $
(9,134)
18,045 $

33,257
13,857
—
—
—
—
47,114
(6,893)
40,221

The table below presents the weighted average remaining lease term and discount rate related to leases:

Weighted average remaining lease term:

Operating leases
Finance leases

Weighted average discount rate:

Operating leases
Finance leases

Year Ended December 31,

2021

2020

2019

7.4 years
1.4 years

7.8 years
2.4 years

8.4 years
3.4 years

11.9%
21.9%

12.0%
21.9%

10.2%
21.9%

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

Operating cash outflow from finance leases
Operating cash outflow from operating leases

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

Note 6 — Financial Instruments

$
$

$

Year Ended December 31,

2021

2020

2019

11,453 $
3,864 $

15,748 $
2,648 $

19,115
1,812

1,020 $

— $

2,225

As of December 31, 2021 and 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.

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):

December 31, 2021

Carrying
Amount

Fair
Value

December 31, 2020
Fair
Value

Carrying
Amount

12.00% Second-Priority Senior Secured Notes –
due January 2026
11.00% Second-Priority Senior Secured Notes –
due April 2022
7.50% Senior Notes – dued May 2022
Bank Credit Facility – matures November 2024

$

$
$
$

588,838 $

685,945 $

— $

—

— $
6,060 $
367,829 $

— $
6,145 $
375,000 $

343,579 $
6,060 $
635,873 $

355,935
5,238
640,000

The carrying value of the senior notes are presented net of the original issue discount and deferred financing
value measurement) using quoted secondary market trading

costs. Fair value is estimated (representing a Level 1 fair
prices.

ff

F-20

The carrying amount of the Company’s 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).

ff

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 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 Consolidated Statements of Operations in each period.

The following table presents the impact that derivatives, not designated as hedging instruments, had on its

Consolidated Statements of Operations (in thousands):

Net cash received (paid) on settled derivative instruments
Unrealized loss
Price risk management activities income (expense)

Year Ended December 31,

2021
(290,164) $
(128,913)
(419,077) $

$

$

2020

2019

143,905 $
(56,220)
87,685 $

(8,820)
(86,517)
(95,337)

The following table reflects the contracted volumes and weighted average prices under the terms of the

Company's derivative contracts as of December 31, 2021:

Production Period
Crude oil:

January 2022 – December 2022
January 2023 – December 2023

Natural gas:

January 2022 – December 2022
January 2023 – December 2023

Swap Contracts

Settlement Index

NYMEX WTI CMA
NYMEX WTI CMA

NYMEX Henry Hub
NYMEX Henry Hub

Average
Daily
Volumes
(Bbls)

Weighted
Average
Swap Price
(per Bbl)

23,523 $
7,463 $

52.42
63.13

(MMBtu)

(per MMBtu)

43,392 $
16,408 $

2.77
3.29

The following tables provide additional information related to financial instruments measured at fair value on

a recurring basis (in thousands):

Assets:

Oil and natural gas swaps

Liabilities:

Oil and natural gas swaps

Total net liability

December 31, 2021

Level 1

Level 2

Level 3

Total

$

$

— $

—
— $

3,737 $

(200,464)
(196,727)$

— $

—
— $

3,737

(200,464)
(196,727)

F-21

Assets:

Oil and natural gas swaps and costless collars

Liabilities:

Oil and natural gas swaps and costless collars

Total net liability

$

$

— $

—
— $

7,821 $

(75,635)
(67,814)$

— $

—
— $

7,821

(75,635)
(67,814)

December 31, 2020

Level 1

Level 2

Level 3

Total

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 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 as well as the potential effect
of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands):

Oil and natural gas derivatives:

Current
Non-current

Total gross amounts presented on balance sheet

Less: Gross amounts not offset on the balance sheet

Net amounts

Credit Risk

December 31, 2021

December 31, 2020

Assets

Liabilities

Assets

Liabilities

$

$

967 $

2,770
3,737
3,737

— $

186,526 $
13,938
200,464
3,737
196,727 $

6,876 $
945
7,821
4,877
2,944 $

66,010
9,625
75,635
4,877
70,758

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 creditworthiness; (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 December 31, 2021 represent derivative instruments from seven 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 all 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 7 — 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):

Year Ended December 31,

2021

2020

12.00% Second-Priority Senior Secured Notes – dued
11.00% Second-Priority Senior Secured Notes – dued April 2022
7.50% Senior Notes – dued May 2022
Bank Credit Facility – matures November 2024

January 2026

Total debt, before discount and deferred financing cost

Discount and deferred financing cost

Total debt, net of discount and deferred financing costs

Less: Current portion of long-term debt

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

$

$

650,000 $

—
6,060
375,000
1,031,060
(68,333)
962,727
6,060
956,667 $

—
347,254
6,060
640,000
993,314
(7,802)
985,512
—
985,512

F-22

12.00% Second-Priority Senior Secured 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 the Parent
Company (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. At any time
prior to January 15, 2023, the Company may also redeem some or all of the 12.00% Notes at a price equal to 100%
of the principal amount of the 12.00% Notes, plus a “make-whole premium,” together with accrued and unpaid
interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of
the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as
percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on
January 15 of the years set forth below:

Period

Redemption Price

2023
2024
2025

106.00%
103.00%
100.00%

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
transfers from Talos Production Inc.’s restricted
investments; (v) restrict distributions,
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 December 31, 2021.

loans or other asset

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 $13.2 million for the year ended December 31, 2021, which is included in “Other income (expense)” on
the 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 year ended December 31, 2020, the Company repurchased $6.4 million
of the 11.00% Notes. The exchange agreement and debt repurchases resulted in a gain on extinguishment of debt for
the year ended December 31, 2020 of $1.7 million, which is included in “Other income (expense)” on the
Consolidated Statements of Operations.

F-23

7.50% Senior Notes

The 7.50% Senior Notes due May 2022 (the “7.50% Notes”) represent the remaining $6.1 million of debt
assumed on May 10, 2018 in a business combination that was not exchanged for the 11.00% Notes pursuant to an
exchange offer and consent solicitation, and thus remain outstanding. As a result of the exchange offer and consent
solicitation, substantially all of the restrictive covenants relating to the 7.50% Notes have been removed and collateral
securing the 7.50% Notes has been released. The 7.50% Notes mature May 31, 2022 and have interest payable semi-
annually each May 31 and November 30. The Company may redeem all or a portion of the 7.50% Notes at redemption
prices (expressed as percentages of the principal amount) equal to: (i) 105.625% for the twelve-month period
beginning on May 31, 2021 and (ii) 100% beginning May 31, 2022, in each case, plus accrued and unpaid interest at
the redemption date.

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 the Company's proved undeveloped reserves. The borrowing base is redetermined by the lenders at least
semi-annually during the second quarter and fourth quarter each year. On June 22, 2021, the Company entered into
a Borrowing Base Redetermination Agreement and Sixth Amendment
(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. On August 2, 2021 an additional lender was added to the
syndicate, which increased commitments from $655.0 million to $730.0 million. On December 21, 2021, the
Company entered into an Incremental Agreement, Borrowing Base Redetermination Agreement and Seventh
Amendment to Credit Agreement (the “Seventh Amendment”). The Seventh Amendment, among other things, (i)
reaffirmed the borrowing base at $950.0 million, (ii) increased the commitments from $730.0 million to $791.3
million, (iii) added an additional lender to the syndicate and (iv) added a provision to facilitate investments of up to
$50.0 million in carbon capture and sequestration and other emerging energy transition opportunities in unrestricted
subsidiaries.

to Credit Agreement

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank
Offered Rate (“LIBOR”) plus applicable margins, or an alternate base rate (“ABR”) plus applicable margins. The
ABR is based on the greater of (a) the prime rate, (b) a federal
funds rate plus 0.5% or (c) the one-month Adjusted
LIBOR Rate plus 1.0%. In addition, the Company is obligated to pay a commitment fee on the unutilized portion of
the commitments. The pricing grid below shows the applicable margin for LIBOR loans and ABR loans as well as
the commitment fee rate based upon the applicable borrowing base utilization percentage:

ff

g
Borrowing Base Utilization Percentage

g

Level 1
Level 2
Level 3
Level 4
Level 5

Utilization
< 25%
≥ 25% < 50%
≥ 50% < 75%
≥ 75% < 90%
≥ 90%

LIBOR Loans
3.00%
3.25%
3.50%
3.75%
4.00%

ABR Loans
2.00%
2.25%
2.50%
2.75%
3.00%

Commitment
Fee Rate
0.50%
0.50%
0.50%
0.50%
0.50%

The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must
maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00
calculated each quarter utilizing the most recent twelve months to determine EBITDAX. The Company must also
maintain a current ratio no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, unutilized
commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by
substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally
guaranteed by the Company and certain of its wholly-owned subsidiaries.

F-24

As of December 31, 2021, the Company's borrowing base was $950.0 million with total commitments of
$791.3 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 December 31, 2021. As of December 31, 2021, the
Company had outstanding borrowings at a weighted average interest rate of 3.50%. See Note 12 — Commitments
and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2021.

Note 8 — 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”) (together with the
2021 LTIP, the “LTIP Plans”).

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) RSUs, (vi) awards of vested stock, (vii) dividend equivalents,
(viii) other share-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.

EE

Restricted Stock Units – Employees

— RSUs granted to employees under the LTIP Plans primarily vest ratably
over an approximate three year period subject to such employee’s continued service through each vesting date. Upon
vesting, each RSU represents a contingent right to receive one share of common stock. The total unrecognized share-
based compensation expense related to these RSUs at December 31, 2021 was approximately $14.2 million, which
is expected to be recognized over a weighted average period of 1.8 years.

NN

Restricted Stock Units – Non-employee

Directors — RSUs granted to non-employee directors under the LTIP
Plans vested approximately one year following the date of grant, subject to such non-employee director’s continued
service through the vesting date. Upon vesting, these RSUs represent a contingent right to receive one share of
common stock for each RSU for 60%, and cash for the remaining 40%. The total unrecognized share-based
compensation expense related to these RSUs at December 31, 2021 was approximately $0.1 million, which is
expected to be recognized over a weighted average period of 0.2 years. Of the unrecognized share-based
compensation expense, $0.1 million relates to liability awards and will be subsequently remeasured at each reporting
period.

F-25

The following table summarizes RSU activity:

Unvested RSUs at December 31, 2018

Granted
Vested
Forfeited

Unvested RSUs at December 31, 2019

Granted
Vested
Forfeited

Unvested RSUs at December 31, 2020

Granted
Vested
Forfeited

Unvested RSUs at December 31, 2021(1)

Restricted Stock
Units

Weighted Average
Grant Date Fair
Value

138,704 $
732,771 $
(69,235) $
(68,463) $
733,777 $
1,284,797 $
(273,787) $
(91,799) $
1,652,988 $
1,102,038 $
(669,832) $
(101,995) $
1,983,199 $

33.85
24.39
33.72
25.43
25.20
10.02
25.09
19.65
13.73
13.11
15.01
12.46
13.02

(1)

As of December 31, 2021, 25,592 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the 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 year ended December 31, 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.

EE

Performance Share Units – Employees

— PSUs granted to employees under the LTIP Plans represent the
contingent right to receive one share of common stock. However, the number of shares of common stock issuable
upon vesting ranges from zero to 200% of the target number of PSUs granted based on the TSR of the common stock
relative to the TSR achieved by a specific industry peer group over an approximate three-year performance period,
the last day of which is also the vesting date. The total unrecognized share-based compensation expense related to
these PSUs at December 31, 2021 was approximately $8.8 million, which is expected to be recognized over a
weighted average period of 1.8 years.

The following table summarizes PSU activity:

Unvested PSUs at December 31, 2018

Granted
Forfeited

Unvested PSUs at December 31, 2019

Granted
Forfeited

Unvested PSUs at December 31, 2020

Granted
Vested
Forfeited

Unvested PSUs at December 31, 2021

Performance
Share
Units

Weighted Average
Grant Date Fair
Value

231,542 $
218,060 $
(31,771) $
417,831 $
441,642 $
(25,301) $
834,172 $
586,995 $
(391,308) $
(14,400) $
1,015,459 $

44.47
33.96
40.27
39.31
13.05
37.67
25.46
18.96
39.43
18.48
16.41

F-26

Certain awards granted during the year ended December 31, 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:

Expected term (in years)
Expected volatility
Risk-free interest rate
Dividend yield
Fair value (in thousands)

2021

Modification

May 11

Grant

March 8

2020

Grant

March 5

2.6
80.9%
0.3%
—%
9,715 $

2.8
78.3%
0.3%
—%

2.8
48.8%
0.6%
—%

11,129

$

5,763

$

$

2019

Grant

March 5

May 16

2.8
46.9%
2.5%
—%
6,195 $

2.6
44.8%
2.1%
—%

1,210

Share-based Compensation Costs

Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and
administrative expense” on the Consolidated Statements of Operations, net amounts capitalized to “Proved
Properties” on the Consolidated Balance Sheets. Because of the non-cash nature of share-based compensation, the
expensed portion of share-based compensation is added back to net income in arriving at “Net cash provided by
operating activities” on the Consolidated Statements of Cash Flows.

The following table presents the amount of cost expensed and capitalized (in thousands):

Share-based compensation costs
Less: Amounts capitalized to oil and gas properties

Total share-based compensation expense

Note 9 — Income Taxes

Income Tax Expense (Benefit)

Year Ended December 31,

2021

2020

2019

$

$

20,560 $
9,568
10,992 $

16,462 $
7,793
8,669 $

12,924
5,960
6,964

The components of income tax expense (benefit) were as follows (in thousands):

Current income tax expense (benefit):

United States
Mexico

Total current income tax expense (benefit)

Deferred income tax expense (benefit):

United States
Mexico

Total deferred income tax expense (benefit)

Total income tax expense (benefit)

Year Ended December 31,

2021

2020

2019

(5) $

(993)
(998) $

(499) $
185
(314) $

437
1,183
1,620

(1,067) $
430
(637) $

35,923 $
(26)
35,897 $

(37,131)
(630)
(37,761)

(1,635) $

35,583 $

(36,141)

$

$

$

$

$

F-27

A reconciliation of income tax expense (benefit) computed at the U.S. federal statutory tax rate to the

Company’s income tax expense (benefit) is as follows (in thousands, except percentages):

Income tax expense (benefit) at the federal statutory tax rate

$

State income taxes
Impact of foreign operations
Effect of change in state rate
Prior year taxes
Other adjustments
Legal entity reorganization
Change in valuation allowance
Other permanent differences
Total income tax expense (benefit)

Effective tax rate

$

Year Ended December 31,

2021

2020

2019

(38,763) $
(674)
(11,920)
2,008
486
—
—
45,547
1,681
(1,635) $

0.89%

(90,304) $
(14,215)
(1,030)
—
(4,237)
—
(17,566)
162,213
722
35,583

$

)
%

(8.27

4,744
1,396
(4,948)
—
(1,950)
137
39,336
(75,196)
340
(36,141)

(159.99)%

The Company’s effective tax rate for the year ending December 31, 2021 differed from the federal statutory
valuation allowance against its federal, state and foreign deferred tax

rate of 21.0% primarily due to recording a full
assets.

ff

The Company’s effective tax rate for the year ending December 31, 2020 differed from the federal statutory
rate of 21.0% primarily due to a non-cash tax expense of $162.2 million related to the recognition of a valuation
allowance for its excess federal and state deferred tax assets. This expense was partially offset by a tax benefit of
$17.6 million from adopting the final Treasury Regulations under Section 163(j) of the Internal Revenue Code (the
“IRC”) for tax years ended December 31, 2018 and December 31, 2019. The adoption of the final Treasury
Regulations reduced the non-cash tax expense recognized in the year ending December 31, 2019 from the legal entity
conversion of a partnership to a corporation.

The Company’s effective tax rate for the year ending December 31, 2019 differed from the federal statutory
rate of 21.0% primarily due to a non-cash tax benefit of $75.2 million related to the full release of the valuation
allowance for its federal and a significant portion of its state deferred tax assets. The federal and state portion of the
release equals $80.2 million, partially offset by a $5.0 million increase in valuation allowance recorded against
foreign deferred tax assets. Additionally, the Company recorded a tax expense of $39.3 million related to the
reorganization of our subsidiaries, of which $38.9 million represents the non-cash impact from the legal entity
conversion of a partnership to a corporation.

F-28

Deferred Tax Assets and Liabilities

Net deferred tax assets (liabilities) reflect the net tax effects of temporary differences between the carrying
amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
Significant components of deferred tax assets and liabilities were as follows (in thousands):

Deferred tax assets:

Federal net operating loss
Foreign tax loss carryforward
State net operating loss
Asset retirement obligations
Tax credits
Derivatives
Other well equipment inventory
Accrued bonus
Operating lease liabilities
Other

Total deferred tax assets
Valuation allowance

Total deferred tax assets, net

Deferred tax liabilities:

Oil and gas properties
Deferred financing
Operating lease assets
Prepaid

Total deferred tax liabilities
Net deferred tax liability

Net Operating Loss

Year Ended December 31,

2021

2020

153,849 $
49,932
24,265
92,823
303
42,075
5,680
5,087
4,081
9,257
387,352
(224,266)
163,086 $

160,002 $

—
1,423
3,075
164,500

(1,414)$

133,804
45,980
25,740
106,604
522
16,346
9,470
3,069
4,904
7,727
354,166
(178,998)
175,168

170,596
1,765
1,652
3,216
177,229
(2,061)

$

$

$

$

The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2021

(in thousands):

Federal net operating losses
Federal net operating losses
Foreign tax loss carryforward
State net operating losses
State net operating losses

Amount

Expiration Year

534,964
197,651
166,440
125,958
268,221

2035 - 2037
Unlimited
2025 - 2031
2025 - 2037
Unlimited

$
$
$
$
$

As of December 31, 2021, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of
approximately $732.6 million, of which $546.5 million is subject to limitation under Section 382 of the IRC. IRC
Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes,
against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would
begin to expire in 2035.

Valuation Allowance

The Company recorded a valuation allowance of $224.3 million and $179.0 million as of December 31, 2021
and 2020, respectively. Deferred income tax assets and liabilities are recorded related to NOLs and temporary
differences between the book and tax basis of assets and liabilities expected to produce tax deductions and income
in the future. The realization of these assets depends on recognition of sufficient future taxable income in specific
tax jurisdictions in which those temporary differences or NOLs relate. In assessing the need for a valuation allowance,
the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not
be realized.

F-29

Uncertain Tax Positions

The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits.
None of the unrecognized benefits would impact the effective tax rate if recognized. While amounts could change
during the next 12 months, the Company does not anticipate having a material impact on its financial statements.

Balances in the uncertain tax positions are as follows (in thousands):

Total unrecognized tax benefits, beginning balance
Increases in unrecognized tax benefits as a result of:

Tax positions taken
Tax positions taken during the current period
Total unrecognized tax benefits, ending balance

during a prior period

g

Year Ended December 31,

2021

2020

648 $

21
27
696 $

791

(208)
65
648

$

$

The Company recognizes interest and penalties related to uncertain tax positions as “Interest Expense” and

“General and administrative expense” on the Consolidated Statements of Operations, respectively.

Years Open to Examination

The 2018 through 2020 tax years remain open to examination by the tax jurisdictions in which the Company
is subject to tax. The statute of limitations with respect to the U.S. federal income tax returns of the Company for
years ending on or before December 31, 2017 are closed, except to the extent of any NOL carryover balance.

Note 10 — 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 warrants expired unexercised on February 28, 2021.

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):

Net income (loss)

Weighted average common shares outstanding — basic
Dilutive effect of securities
Weighted average common shares outstanding — diluted

Net income (loss) per common share:

Basic
Diluted

Anti-dilutive potentially issuable securities excluded
from diluted common shares

Note 11 — Related Party Transactions

$

$
$

Year Ended December 31,
2020
(465,605) $

2021
(182,952) $

81,769
—
81,769

67,664
—
67,664

2019

58,729

54,185
228
54,413

(2.24) $
(2.24) $

(6.88) $
(6.88) $

1,709

5,019

1.08
1.08

4,220

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. Collectively, the Sponsors held 36.4% of the
Company's common stock as of December 31, 2021. On January 3, 2022, the Apollo Funds ceased being a beneficial
owner of more than five percent of the Company's common stock.

F-30

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 3 — Acquisitions.

Whistler Acquisition

On August 31, 2018, the Company acquired Whistler Energy II, LLC from Whistler Energy II Holdco, LLC,
an affiliate of the Apollo Funds. Included in “Other” accounts receivable on the Consolidated Balance Sheets is $1.1
million at December 31, 2020 due from an affiliate of the Apollo Funds to reimburse the Company for certain
payments made post-closing. The receivable was collected during October 2021. Additionally, a settlement
agreement was executed in September 2021 related to a dispute regarding a decommissioning obligation of a
Deepwater well. For the year ended December 31, 2021, the Company recognized a $4.4 million gain resulting from
the settlement which is reflected in “Other income (expense)” on the Company’s Consolidated Statements of
Operations.

Equity Registration Rights Agreement

On May 10, 2018, the Company entered into a Registration Rights Agreement (the “Original Equity
Registration Rights Agreement”) with certain of the Apollo Funds and the Riverstone Funds, certain funds controlled
by Franklin Advisers, Inc. (“Franklin”) and certain clients of MacKay Shields LLC (“MacKay Shields”), relating to
the registered resale of the Company’s common stock owned by such parties as of the closing of the Stone
Combination (the “Original Registrable Securities”).

The Company and the Riverstone Sellers (and their designated affiliates) agreed under the Purchase
Agreements to enter into an amendment to the Original Equity Registration Rights Agreement (such amendment, the
“Registration Rights Agreement Amendment,” and the Original Equity Registration Rights Agreement, as amended
by the Registration Rights Agreement Amendment, the “Registration Rights Agreement”). The Registration Rights
Agreement Amendment will add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties
to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the
Series A Convertible Preferred Stock (and Conversion Stock) (each as defined below) that the Riverstone Sellers
received at the closing of the ILX and Castex Acquisition (the “New Registrable Securities” and together with the
Original Registrable Securities, the “Registrable Securities”). Under the Registration Rights Agreement, the
Company is required to file a shelf registration statement within 30 days of the Company’s receipt of written request
by a holder of Registrable Securities (a “Holder”). Each Holder will be limited to two demand registrations in any
twelve-month period.

The Holders have the right to request that the Company initiate underwritten offerings of the Company’s
common stock; provided, that the Apollo Funds and the Riverstone Funds will have the right to demand three
underwritten offerings in any twelve-month period, and Franklin and MacKay Shields will only have the collective
right to demand one underwritten offering. The Holders have customary piggyback rights with respect to any
underwritten offering that the Company conducts for as long as the Holders and their respective affiliates own 5% of
the Registrable Securities. Each Holder will agree to a lock up with underwriters in the event of an underwritten
offering, provided that the lock up will not apply to any Holder who does not have a right to participate in such
underwritten offering. The Registration Rights Agreement have terminated with respect to Franklin and MacKay
Shields. Additionally, the Apollo Funds no longer have piggyback rights effective January 3, 2022. The Registration
Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding.

In connection with the closing of the ILX and Castex Acquisition, and pursuant to the Purchase Agreements,
as amended, the Company and ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Riverstone V
Castex 2014 Holdings, L.P., a Delaware limited partnership and designee of Castex Energy 2014, LLC, entered into
the Registration Rights Agreement Amendment to the Registration Rights Agreement to, among other things, add
each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights
Agreement and provide such parties with customary registration rights with respect to the Company’s Series A
Convertible Preferred Stock issued to the Riverstone Sellers at the closing of the ILX and Castex Acquisition

F-31

The Company will bear all of the expenses incurred in connection with the offer and sale, while the Apollo
Funds, the Riverstone Funds, Franklin and MacKay Shields will be responsible for paying underwriting fees,
discounts and selling commissions. The Company incurred fees of $0.7 million, $0.2 million and $0.7 million for the
fiscal years ended December 31, 2021, 2020 and 2019, respectively.

In June and November of 2021, the Company entered into separate secondary underwriting agreements with
certain stockholders affiliated with the Sponsors (the “Selling Stockholders”), pursuant to which the Selling
Stockholders sold shares of common stock of the Company. Each secondary offering was made pursuant to a
prospectus supplement filed with the SEC. The Selling Stockholders received all the proceeds from these offerings.

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”) to, among other things,
add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Stockholders’
Agreement and provide that for purposes of determining whether the Riverstone Sellers and their affiliates continue
to satisfy certain stock ownership requirements necessary to retain their rights to nominate directors to the board of
directors, the Series A Convertible Preferred Stock owned by the Riverstone Sellers was, prior to the conversion
thereof, counted towards such ownership requirements on an as converted basis at the closing of the ILX and Castex
Acquisition. On March 30, 2020, all 110,000 shares of Series A Convertible Preferred Stock were converted into an
aggregate 11.0 million shares of the Company’s common stock.

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An
immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel
and one of its executive officers, is a partner at V&E. For the years ended December 31, 2021, 2020 and 2019, the
Company incurred fees of approximately $3.1 million, $3.5 million and $4.2 million, respectively, of which $0.2
million, $0.7 million and $2.3 million were payable at each respective balance sheet date for legal services performed
by V&E.

Note 12 — Commitments and Contingencies

Legal Proceedings and Other Contingencies

From time to time, the Company is involved in litigation, regulatory examinations and administrative
proceedings primarily arising in the ordinary course of business in jurisdictions in which the Company does business.
Although the outcome of these matters cannot be predicted with certainty, the Company’s management believes none
of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial
position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a
specific interim period or year.

Performance Obligations

Regulations with respect

to the Company's operations govern, among other things, engineering and
construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal
of facilities in the U.S. Gulf of Mexico and certain obligations under the Mexico production sharing contracts. As of
December 31, 2021, the Company had secured performance bonds from third party sureties and letters of credit
issued under its Bank Credit Facility totaling approximately $724.4 million and $13.6 million, respectively.

F-32

The table below summarizes the Company’s total minimum commitments associated with vessel commitments

and purchase obligations as of December 31, 2021 (in thousands):

Vessel Commitments(1)
Committed purchase orders(2)

Total

2022
$ 29,710 $
3,153
$ 32,863 $

2023

2024

2025

Thereafter

Total

— $
—
— $

— $
—
— $

— $
—
— $

— $ 29,710
3,153
—
— $ 32,863

(1)

(2)

Includes vessel commitments the Company will utilize for certain Deepwater well intervention and decommissioning activities. These
commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will
be billed for their working interest share of such costs.
Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual
obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share
of such costs.

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. For the year ended December 31,
2021, the Company recorded $21.1 million related to estimated decommissioning obligations reflected in “Other
operating (income) expense” on the Consolidated Statements of Operations.

Although it is reasonably possible that the Company could receive state or federal decommissioning orders in
the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if,
how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from
such orders. However, the Company could incur judgments, enter into settlements or revise our opinion regarding
the outcome of certain notices or matters, and such developments could have a material adverse effect on our results
of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts
are paid.

Note 13 — Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount

of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands):

Proved properties
Unproved oil and gas properties, not subject to amortization(1)

Total oil and gas properties
Less: Accumulated depletion

Net capitalized costs

Depletion and amortization rate (Per MBoe)(2)

Year Ended December 31,

2021

2020

$

$
$

5,232,479 $
219,055
5,451,534
3,072,907
2,378,627 $
16.71 $

4,945,550
254,994
5,200,544
2,680,254
2,520,290
31.42

(1) Amount includes $110.3 million and $121.7 million of unproved properties, not subject to amortization, related to the Company’s operations

in offshore Mexico for the years ended December 31, 2021 and 2020, respectively.

(2) Year ended December 31, 2020 includes the impact of a write-down of its U.S. oil and natural gas properties as result of the Company's

ceiling test computations. See Note 4 — Property, Plant and Equipment for additional information.

Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate
share of asset retirement costs relating to these properties which are also reflected as “Asset retirement obligations”
on the accompanying Consolidated Balance Sheets. See Note 4 — Property, Plant and Equipment for additional
information.

F-33

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration
and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement
obligations established in the current year, as well as increases or decreases to the asset retirement obligations
resulting from changes to estimates during the year.

Property acquisition costs:

Proved properties
Unproved properties, not subject to amortization

Total property acquisition costs
Exploration costs(1)
Development costs
Total costs incurred

Year Ended December 31,

2021

2020

2019

$

$

210 $
—
210
23,844
245,058
269,112 $

422,833 $
95,242
518,075
59,422
362,011
939,508 $

27,660
16,062
43,722
209,161
292,547
545,430

(1)

Amount includes $6.6 million, $14.6 million and $74.2 million of exploration costs related to the Company’s operations in offshore Mexico
for the year ended December 31, 2021, 2020 and 2019, respectively.

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

The Company employs full-time experienced reserve engineers and geologists who are responsible for
determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in
estimating quantities of proved reserves and projecting future rates of production and timing of development
expenditures. The reserve data in the following tables only represent estimates and should not be construed as being
exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and
sub-surface information obtained from the drilling of existing wells. The Company’s Director of Reserves, internal
reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of
the Company’s proved oil, natural gas and NGL reserves are located in the U.S. Gulf of Mexico.

At, December 31, 2021, 2020 and 2019, 100% of proved oil, natural gas and NGL reserves attributable to all
of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the
Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent
petroleum engineers and geologists.

F-34

The following table presents the Company’s estimated proved reserves at its net ownership interest:

Total proved reserves at December 31, 2018

Revision of previous estimates
Production
Purchases of reserves
Extensions and discoveries

Total proved reserves at December 31, 2019

Revision of previous estimates
Production(1)
Purchases of reserves
Extensions and discoveries

Total proved reserves at December 31, 2020

Revision of previous estimates
Production
Extensions and discoveries

Total proved reserves at December 31, 2021
Total proved developed reserves as of:

December 31, 2019
December 31, 2020
December 31, 2021

Total proved undeveloped reserves as of:

December 31, 2019
December 31, 2020
December 31, 2021

Oil (MBbls)

Gas (MMcf)

112,539
(5,553)
(13,844)
2,094
11,518
106,754
(14,633)
(13,665)
26,903
3,948
109,307
13,619
(16,159)
997
107,764

72,016
85,007
93,420

34,738
24,300
14,344

171,024
(15,898)
(23,306)
2,626
21,552
155,998
(56,358)
(28,652)
181,872
4,348
257,208
8,979
(32,795)
2,961
236,353

115,381
204,054
186,442

40,617
53,154
49,911

NGL (MBbls)
10,696
(1,237)
(1,228)
130
620
8,981
(168)
(1,559)
3,528
76
10,858
5,137
(1,875)
315
14,435

6,733
8,104
11,792

2,248
2,754
2,643

Oil
Equivalent
(MBoe)

151,739
(9,440)
(18,956)
2,662
15,730
141,735
(24,195)
(19,999)
60,743
4,749
163,033
20,252
(23,500)
1,806
161,591

97,979
127,120
136,286

43,756
35,913
25,305

(1) Excludes approximately 3.0 MBoe of Mexico well test production.

During 2021, proved reserves decreased by 1.4 MMBoe primarily due to a decrease of 23.5 MMBoe of
production. The decrease was partially offset by revision to previous estimates of 20.3 MMBoe due to increase in
commodity prices as well as 1.8 MMBoe of estimated proved reserves from extensions and discoveries primarily
from an evaluation of Crown and Anchor Field located in the Mississippi Canyon core area.

During 2020, proved reserves decreased by 21.3 MMBoe primarily due to a decrease of 20.0 MMBoe of
production and revision to previous estimates of 24.2 MMBoe due to decrease in commodity prices. The decrease
was partially offset by the addition of 60.7 MMBoe added through purchases from the ILX and Castex Acquisition,
Castex Energy 2005 Acquisition and LLOG Acquisition as well as 4.7 MMBoe of estimated proved reserves from
extensions and discoveries primarily from an evaluation of Green Canyon 18 and Claiborne Fields.

During 2019, proved reserves decreased by 10.0 MMBoe primarily due to a decrease of 19.0 MMBoe of
production and revision to previous estimates of 9.7 MMBoe due to the Phoenix and Ram Powell Fields. The decrease
was partially offset by the addition of 15.7 MMBoe of estimated proved reserves from extensions and discoveries
primarily from an evaluation of Green Canyon 21, Pompano, and Ewing Bank 305 as well as 3.0 MMBoe added
through purchases from the Gunflint Acquisition.

F-35

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL
Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to the

Company’s interest in proved oil, natural gas and NGL reserves (in thousands):

Future cash inflows
Future costs:
Production
Development and abandonment

Future net cash flows before income taxes
Future income tax expense
Future net cash flows after income taxes
Discount at 10% annual rate
Standardized measure of discounted future net cash flows

Year Ended December 31,

2021
8,496,005 $

2020
4,927,497 $

2019
7,151,875

$

(1,868,818)
(1,422,507)
5,204,680
(676,778)
4,527,902
(1,087,291)
3,440,611 $

(1,105,211)
(1,236,874)
2,585,412
(141,515)
2,443,897
(538,963)
1,904,934 $

(1,633,432)
(1,464,270)
4,054,173
(662,317)
3,391,856
(854,261)
2,537,595

$

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The
discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for
base prices used in determining the standardized measure:

Oil price per Bbl
Natural gas price per Mcf
NGL price per Bbl

Year Ended December 31,

2021

2020

2019

$
$
$

67.14 $
3.71 $
26.62 $

39.47 $
1.97 $
9.89 $

61.01
2.59
26.17

Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary
considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs
and production rates were based on the best information available, the development and production of oil and gas
reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may
vary significantly from those used. Therefore, such estimated future net cash flow computations should not be
considered to represent the Company’s estimate of the expected revenues or the current value of existing proved
reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the

Company’s proved oil, natural gas and NGL reserves are as follows (in thousands):

Standardized measure, beginning of year

Sales and transfers of oil, net gas and NGLs produced during
the period
Net change in prices and production costs
Changes in estimated future development costs
Previously estimated development costs incurred
Accretion of discount
Net change in income taxes
Purchases of reserves
Extensions and discoveries
Net change due to revision in quantity estimates
Changes in production rates (timing) and other

Standardized measure, end of year

$

$

Year Ended December 31,
2020
2,537,595 $

2021
1,904,934 $

(957,576)
2,049,980
(57,876)
69,125
199,849
(391,834)
—
45,485
426,357
152,167
3,440,611 $

(339,557)
(1,468,304)
32,589
46,143
299,302
361,875
730,611
71,589
(309,338)
(57,571)
1,904,934 $

2019
3,340,246

(665,226)
(849,696)
(75,564)
117,049
392,526
129,590
75,009
306,515
(199,576)
(33,278)
2,537,595

F-36

MANAGEMENT TEAM

TIMOTHY S. DUNCAN
(cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:3516)(cid:70)(cid:72)(cid:85)

JOHN A. PARKER
Executive Vice President – Exploration

ROBERT D. ABENDSCHEIN
Executive Vice President and 
(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:50)(cid:3516)(cid:70)(cid:72)(cid:85)

SHANNON E. YOUNG, III
Executive Vice President
(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:50)(cid:3516)(cid:70)(cid:72)(cid:85)

WILLIAM S. MOSS III
Executive Vice President
and General Counsel

ROBIN FIELDER
Executive Vice President – Low Carbon 
(cid:54)(cid:87)(cid:85)(cid:68)(cid:87)(cid:72)(cid:74)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:54)(cid:88)(cid:86)(cid:87)(cid:68)(cid:76)(cid:81)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:50)(cid:3516)(cid:70)(cid:72)(cid:85)

BOARD OF DIRECTORS

JOHN B. SPATH
Senior Vice President – Drilling
and Production Operations

GREG BABCOCK
(cid:57)(cid:76)(cid:70)(cid:72)(cid:3)(cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:36)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:50)(cid:3516)(cid:70)(cid:72)(cid:85)

MEGAN DICK
Vice President - Human Resources

SERGIO L. MAIWORM JR.
Vice President – Finance, 
Investor Relations and Treasurer

DEBORAH HUSTON
Vice President and Deputy General Counsel

C. GORDON LINDSEY
Vice President - Corporate Development

NEAL P. GOLDMAN(1)
Managing Member, SAGE Capital 
Investments, LLC

CHARLES M. SLEDGE
(cid:53)(cid:72)(cid:87)(cid:76)(cid:85)(cid:72)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:50)(cid:3516)(cid:70)(cid:72)(cid:85)(cid:15)
Cameron International

TIMOTHY S. DUNCAN
(cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:3516)(cid:70)(cid:72)(cid:85)(cid:15)
Talos Energy Inc.

JOHN BRAD JUNEAU 
Sole Manager and General Partner,
Juneau Exploration, L.P

DONALD R. KENDALL, JR
(cid:39)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:3516)(cid:70)(cid:72)(cid:85)(cid:15)
Kenmont Capital Partners

ROBERT M. TICHIO 
Partner, Riverstone Holdings LLC

PAULA R. GLOVER
President, Alliance to Save Energy

(1) Chairman of the Board

ANNUAL REPORT

CORPORATE OFFICE
333 Clay St., Suite 3300
Houston, TX 77002
Phone: 713-328-3000

WEBSITE 
www.talosenergy.com

STOCK EXCHANGE LISTING 
New York Stock Exchange
Symbol: TALO

ANNUAL MEETING 
May 11, 2022
10:00 a.m. CT
Three Allen Center
333 Clay St., Suite 3300
Houston, TX 77002

FORM 10-K 
Copies of the corporation’s 10-K
are available on our website at
www.talosenergy.com

AUDITORS 
Ernst & Young
Houston, TX

SHAREHOLDER SERVICES 
Computershare
Mailing: P.O. Box 505000
Louisville, KY 40233
1-800-962-4284 (Toll-Free)
1-781-575-3120 (International)

OVERNIGHT MAIL 
462 South 4th Street
Suite 1600
Louisville, KY 40202

INVESTOR RELATIONS 
Additional corporate information
is available on our website at
www.talosenergy.com

CORPORATE OFFICE
333 Clay St., Suite 3300
Houston, TX 77002
Phone: 713-328-3000 
www.talosenergy.com