Talos Energy
Annual Report 2023

Plain-text annual report

2023 Annual Report Talos Energy(cid:3)(cid:76)(cid:86)(cid:3)(cid:68)(cid:3)(cid:79)(cid:72)(cid:68)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:76)(cid:81)(cid:71)(cid:72)(cid:83)(cid:72)(cid:81)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:3515)(cid:86)(cid:75)(cid:82)(cid:85)(cid:72)(cid:3) (cid:72)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:3)(cid:73)(cid:82)(cid:70)(cid:88)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(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:68)(cid:81)(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:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:56)(cid:81)(cid:76)(cid:87)(cid:72)(cid:71)(cid:3)(cid:54)(cid:87)(cid:68)(cid:87)(cid:72)(cid:86)(cid:3)(cid:42)(cid:88)(cid:79)(cid:73)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:72)(cid:91)(cid:76)(cid:70)(cid:82)(cid:3) (cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:3515)(cid:86)(cid:75)(cid:82)(cid:85)(cid:72)(cid:3)(cid:48)(cid:72)(cid:91)(cid:76)(cid:70)(cid:82)(cid:17)(cid:3)(cid:58)(cid:72)(cid:3)(cid:79)(cid:72)(cid:89)(cid:72)(cid:85)(cid:68)(cid:74)(cid:72)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:71)(cid:72)(cid:72)(cid:83)(cid:3)(cid:87)(cid:72)(cid:70)(cid:75)(cid:81)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3) (cid:72)(cid:91)(cid:83)(cid:72)(cid:85)(cid:87)(cid:76)(cid:86)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:72)(cid:91)(cid:87)(cid:72)(cid:81)(cid:86)(cid:76)(cid:89)(cid:72)(cid:3)(cid:83)(cid:75)(cid:92)(cid:86)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:85)(cid:76)(cid:72)(cid:81)(cid:70)(cid:72)(cid:3) (cid:87)(cid:82)(cid:3)(cid:86)(cid:88)(cid:70)(cid:70)(cid:72)(cid:86)(cid:86)(cid:73)(cid:88)(cid:79)(cid:79)(cid:92)(cid:3)(cid:80)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:56)(cid:83)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3) (cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:76)(cid:86)(cid:87)(cid:72)(cid:81)(cid:87)(cid:79)(cid:92)(cid:3)(cid:80)(cid:68)(cid:78)(cid:72)(cid:3)(cid:68)(cid:87)(cid:87)(cid:85)(cid:68)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:68)(cid:70)(cid:84)(cid:88)(cid:76)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3) (cid:68)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:86)(cid:68)(cid:73)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:72)(cid:3516)(cid:70)(cid:76)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:15)(cid:3) (cid:72)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:86)(cid:76)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:88)(cid:81)(cid:76)(cid:87)(cid:92)(cid:3)(cid:76)(cid:80)(cid:83)(cid:68)(cid:70)(cid:87)(cid:17) HIGHLIGHTS KEY METRICS 66.3 MBOE/D (cid:36)(cid:89)(cid:72)(cid:85)(cid:68)(cid:74)(cid:72)(cid:3)(cid:39)(cid:68)(cid:76)(cid:79)(cid:92) (cid:51)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(1) $951 MILLION (cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:40)(cid:37)(cid:44)(cid:55)(cid:39)(cid:36)(1)(2) $734 MILLION (cid:56)(cid:83)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3) (cid:40)(cid:91)(cid:83)(cid:72)(cid:81)(cid:71)(cid:76)(cid:87)(cid:88)(cid:85)(cid:72)(cid:86)(1)(3) RESPONSIBILITY A ESG RATING (cid:69)(cid:92)(cid:3)(cid:48)(cid:54)(cid:38)(cid:44)(cid:15)(cid:3)(cid:48)(cid:68)(cid:92)(cid:3)(cid:21)(cid:19)(cid:21)(cid:22) ~30% REDUCTION (cid:76)(cid:81)(cid:3)(cid:54)(cid:70)(cid:82)(cid:83)(cid:72)(cid:3)(cid:20) (cid:42)(cid:43)(cid:42)(cid:3)(cid:40)(cid:80)(cid:76)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:44)(cid:81)(cid:87)(cid:72)(cid:81)(cid:86)(cid:76)(cid:87)(cid:92)(4) ~64% REDUCTION (cid:76)(cid:81)(cid:3)(cid:54)(cid:70)(cid:82)(cid:83)(cid:72)(cid:3)(cid:21) (cid:42)(cid:43)(cid:42)(cid:3)(cid:40)(cid:80)(cid:76)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:86)(5) ABOUT TALOS >750 EMPLOYEES(6) 5th LARGEST (cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:82)(cid:85)(cid:3)(cid:76)(cid:81) (cid:87)(cid:75)(cid:72)(cid:3)(cid:42)(cid:88)(cid:79)(cid:73)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:72)(cid:91)(cid:76)(cid:70)(cid:82)(5) 4th LARGEST (cid:36)(cid:70)(cid:85)(cid:72)(cid:68)(cid:74)(cid:72)(cid:3)(cid:43)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:3)(cid:76)(cid:81)(cid:3) (cid:87)(cid:75)(cid:72)(cid:3)(cid:42)(cid:88)(cid:79)(cid:73)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:72)(cid:91)(cid:76)(cid:70)(cid:82)(6) (cid:11)(cid:20)(cid:12)(cid:3) (cid:53)(cid:72)(cid:193)(cid:72)(cid:70)(cid:87)(cid:86)(cid:3)(cid:55)(cid:68)(cid:79)(cid:82)(cid:86)(cid:3)(cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:79)(cid:82)(cid:81)(cid:72)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:92)(cid:72)(cid:68)(cid:85)(cid:3)(cid:72)(cid:81)(cid:71)(cid:72)(cid:71)(cid:3)(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:22)(cid:17)(cid:3) (cid:11)(cid:21)(cid:12)(cid:3) (cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:40)(cid:37)(cid:44)(cid:55)(cid:39)(cid:36)(cid:3)(cid:76)(cid:86)(cid:3)(cid:68)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:17)(cid:3)(cid:51)(cid:79)(cid:72)(cid:68)(cid:86)(cid:72)(cid:3)(cid:85)(cid:72)(cid:73)(cid:72)(cid:85)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:55)(cid:68)(cid:79)(cid:82)(cid:86)(cid:3)(cid:54)(cid:88)(cid:83)(cid:83)(cid:79)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:70)(cid:82)(cid:81)(cid:70)(cid:76)(cid:79)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51)(cid:3)(cid:44)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:17)(cid:3) (cid:11)(cid:22)(cid:12)(cid:3) (cid:56)(cid:83)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:44)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:3)(cid:83)(cid:79)(cid:88)(cid:74)(cid:74)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:69)(cid:68)(cid:81)(cid:71)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:86)(cid:72)(cid:87)(cid:87)(cid:79)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:71)(cid:72)(cid:70)(cid:82)(cid:80)(cid:80)(cid:76)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:69)(cid:79)(cid:76)(cid:74)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17) (cid:11)(cid:23)(cid:12)(cid:3) (cid:53)(cid:72)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:54)(cid:70)(cid:82)(cid:83)(cid:72)(cid:3)(cid:20)(cid:3)(cid:42)(cid:43)(cid:42)(cid:3)(cid:72)(cid:80)(cid:76)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:86)(cid:76)(cid:87)(cid:92)(cid:3)(cid:89)(cid:72)(cid:85)(cid:86)(cid:88)(cid:86)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:70)(cid:68)(cid:79)(cid:70)(cid:88)(cid:79)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:88)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:70)(cid:82)(cid:80)(cid:69)(cid:76)(cid:81)(cid:72)(cid:71)(cid:3)(cid:21)(cid:19)(cid:21)(cid:21)(cid:3)(cid:71)(cid:68)(cid:87)(cid:68)(cid:15)(cid:3)(cid:55)(cid:68)(cid:79)(cid:82)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:85)(cid:82)(cid:3)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:3)(cid:40)(cid:81)(cid:57)(cid:72)(cid:81)(cid:17) (cid:11)(cid:24)(cid:12)(cid:3) (cid:54)(cid:70)(cid:82)(cid:83)(cid:72)(cid:3)(cid:21)(cid:3)(cid:85)(cid:72)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:86)(cid:3)(cid:55)(cid:68)(cid:79)(cid:82)(cid:86)(cid:3)(cid:82)(cid:81)(cid:79)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:89)(cid:72)(cid:85)(cid:86)(cid:88)(cid:86)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:79)(cid:76)(cid:81)(cid:72)(cid:17)(cid:3)(cid:40)(cid:81)(cid:57)(cid:72)(cid:81)(cid:3)(cid:71)(cid:76)(cid:71)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:70)(cid:68)(cid:79)(cid:70)(cid:88)(cid:79)(cid:68)(cid:87)(cid:72)(cid:3)(cid:54)(cid:70)(cid:82)(cid:83)(cid:72)(cid:3)(cid:21)(cid:3)(cid:72)(cid:80)(cid:76)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:83)(cid:85)(cid:76)(cid:82)(cid:85)(cid:3)(cid:87)(cid:82)(cid:3)(cid:21)(cid:19)(cid:21)(cid:21)(cid:17) (cid:11)(cid:25)(cid:12)(cid:3) (cid:53)(cid:72)(cid:193)(cid:72)(cid:70)(cid:87)(cid:86)(cid:3)(cid:70)(cid:82)(cid:80)(cid:69)(cid:76)(cid:81)(cid:72)(cid:71)(cid:3)(cid:55)(cid:68)(cid:79)(cid:82)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:52)(cid:88)(cid:68)(cid:85)(cid:87)(cid:72)(cid:85)(cid:49)(cid:82)(cid:85)(cid:87)(cid:75)(cid:17)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:82)(cid:85)(cid:3)(cid:71)(cid:68)(cid:87)(cid:68)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:42)(cid:50)(cid:48)(cid:54)(cid:80)(cid:68)(cid:85)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:37)(cid:54)(cid:40)(cid:40)(cid:3)(cid:88)(cid:87)(cid:76)(cid:79)(cid:76)(cid:93)(cid:76)(cid:81)(cid:74)(cid:3)(cid:21)(cid:19)(cid:21)(cid:21)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:72)(cid:71)(cid:3)(cid:192)(cid:74)(cid:88)(cid:85)(cid:72)(cid:86)(cid:17)(cid:3)(cid:36)(cid:70)(cid:85)(cid:72)(cid:68)(cid:74)(cid:72)(cid:3)(cid:71)(cid:68)(cid:87)(cid:68)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:42)(cid:50)(cid:48)(cid:16)(cid:38)(cid:88)(cid:69)(cid:72)(cid:71)(cid:17)(cid:3)(cid:36)(cid:70)(cid:85)(cid:72)(cid:68)(cid:74)(cid:72)(cid:3) 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(cid:72)(cid:91)(cid:83)(cid:79)(cid:82)(cid:76)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:72)(cid:91)(cid:87)(cid:72)(cid:81)(cid:71)(cid:72)(cid:71)(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:17)(cid:3) TALOS ENERGY 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:58)(cid:76)(cid:87)(cid:75)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:82)(cid:76)(cid:79)(cid:16)(cid:90)(cid:72)(cid:76)(cid:74)(cid:75)(cid:87)(cid:72)(cid:71)(cid:3)(cid:83)(cid:82)(cid:85)(cid:87)(cid:73)(cid:82)(cid:79)(cid:76)(cid:82)(cid:3)(cid:70)(cid:82)(cid:81)(cid:70)(cid:72)(cid:81)(cid:87)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3) 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(cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:86)(cid:76)(cid:69)(cid:79)(cid:92)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:72)(cid:71)(cid:3)(cid:72)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:90)(cid:82)(cid:85)(cid:79)(cid:71)(cid:17)(cid:3) (cid:50)(cid:81)(cid:3)(cid:69)(cid:72)(cid:75)(cid:68)(cid:79)(cid:73)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:79)(cid:79)(cid:3)(cid:82)(cid:73)(cid:3)(cid:55)(cid:68)(cid:79)(cid:82)(cid:86)(cid:15)(cid:3)(cid:87)(cid:75)(cid:68)(cid:81)(cid:78)(cid:3)(cid:92)(cid:82)(cid:88)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:92)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:88)(cid:72)(cid:71)(cid:3) (cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:86)(cid:88)(cid:83)(cid:83)(cid:82)(cid:85)(cid:87)(cid:17) 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) LOUISIANA TEXAS Viosca Knoll Gulf of Mexico Shelf Mississippi Canyon DeSoto Canyon Ewing Bank U.S. GULF OF MEXICO ACREAGE POSITION Garden Banks Green Canyon Atwater Valley (cid:42)(cid:88)(cid:79)(cid:73)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:72)(cid:91)(cid:76)(cid:70)(cid:82) Walker Ridge OFFSHORE MEXICO MEXICO ZAMA DISCOVERY 18 KEY FACILITIES Operated and Non-Operated Talos Acreage Talos Facility PROVED RESERVES PROJECT INVENTORY DEEPWATER FOOTPRINT 21% 8% 216 MMBOE 71% 115 Projects 52 29 34 23% 1.5 Million Acres 77% Oil NGL Gas Development Exploitation Deepwater Shelf and Mexico Exploration 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(cid:46)(cid:81)(cid:82)(cid:79)(cid:79)(cid:17)(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: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)(cid:17) 2023 ANNUAL REPORT We provide energy prosperity to improve lives. TALOS ENERGY 2023 ANNUAL REPORT 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, 2023 OR ☐ TRANSRR ITION 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 offiff ces) 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 New York Stock Exchange 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 definff ed in Rule 405 of the Securities Act. Yes ☑ No ☐ Indicate by check mark if the registrant is not required to fileff Indicate by cy heck mark whether the regig strant: ((1)) has fileff such shorter period that the registrant was required to fileff reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☑ d all reporp ts requiq red to be fileff d by Sy ection 13 or 15((d)) of the Securities Exchangeg Act of 1934 during tg he prp eceding 1g 2 months (o( r forff such reports), and (2) has been subju ect to such filing requirements forff the past 90 days. Yes ☑ No ☐ Indicate by check mark whether the registrant has submitted electronically every I chapter) during the preceding 12 months (or forff rr such shorter period that the registrant was required to submit such files). Yes ☑ No ☐ nteractive Data File required to be submitted pursuant to RulRR e 405 of Regulation S-T (§232.405 of this 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 ☑ ☐ Accelerated filer Smaller reporting company ☐ ☐ ☐ Emerging growth company If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised finff ancial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant has filff ed a report on and attestation to its management’s assessment of the effeff ctiveness of its internal control over finff ancial reporting under Section 404(b) of the Sarbar nes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firff m that prepared or issued its audit report. ☑ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing refleff ct the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive offiff cers durd ing the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark whether the registrant is a shell company (as defined in RulRR e 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, 2023, was $1,493,763,437. The number of shares of registrant’s Common Stock outstanding as of Februarr Portions of the registrant’s definff itive proxy statement relating to the 2024 Annual Meeting of Stockholders are incorpor ated by reference into Part III of this report. ry 21, 2024 was 158,632,597. r TABLE OF CONTENTS GLOSSARY ................................................................................................................................................................................... CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS................................................... SUMMARY RISK FACTORS ..................................................................................................................................................... Items 1 and 2. Item 1A. Item 1B. Item 1C. Item 3. Item 4. Item 5. Item 6. Item 7. Item 7A. Item 8. Item 9. Item 9A. Item 9B. Item 9C. Item 10. Item 11. Item 12. Item 13. Item 14. Item 15. Item 16. PART I Business and Properties ...................................................................................................................................... Risk Factors ........................................................................................................................................................ Unresolved Staff Comments............................................................................................................................... Cybersecurity...................................................................................................................................................... Legal Proceedings............................................................................................................................................... Mine Safety Disclosures ..................................................................................................................................... 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 Suppl ementary 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 u r Directors, Executive Officers and Corpor ate 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 Scheduld es ...................................................................................................... Form 10-K Summary.......................................................................................................................................... Page 3 5 7 9 33 58 58 59 60 61 62 63 80 81 81 81 82 82 83 83 83 83 83 84 88 2 GLOSSARY The folff natural gas industry:rr lowing are abba reviations and definff itions of certain terms used in this document, which are commonly used in the oil and 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 naturt al gas to one barrel of crude oil or condensate. BOEMOO — Bureau of Ocean Energy Management. BSEESS — Bureau of Safety and Environmental Enforff cement. Boepd — Barrels of oil equivalent per day. Btu — British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit. CCS — Carbon capture and sequestration. CO2 — Carbon dioxide. Completion — The installation of permanent equipment forff the production of oil or naturt al gas. Deepwater — Water depths of more than 600 feet. ll Develope d acres — The number of acres that are allocated or assignabla e to producing wells or wells capable of production. Field —ll structurt al featurt e or stratigraphi a c condition. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological GAAP — Accounting principles generally accepted in the United States of America. Gross acres or gross wellsll — The total acres or wells in which the Company owns a working interest. MBbls —ll One thousand barrels of crude r oil or other liquid hydrocarbons r . MBblpdll — One thousand barrels of crude r oil or other liquid hydrocarbons r per day. MBoe — One thousand barrels of oil equivalent. MBoepdee — One thousand barrels of oil equivalent per day. Mcf —c One thousand cubic feet of natural gas. McMcfpfpcc dd — OnOne te thous housanand cd cububicic fefeetet ofof nanatuturaral gl gasas peper dr dayay. MMBoe — One million barrels of oil equivalent. MMBtu — One million British thermal units. MMcf —c One million cubiu c feet ff of natural gas. MMcfpc d — One million cubiu c feet ff of natural gas per day. Net acres or net wellsll — The sum of the fraff ctional working interests the Company owns in gross acres or gross wells. NGL — Natural gas liquid. Hydrocarbons which can be extracted from wet naturt al gas and become liquid under various combinations of increasing pressure and lower temperaturt e. NGLs consist primarily of ethane, propane, butane and natural gasoline. r NYMEYY X —EE The New York Mercantile Exchange. X HEE NYMEYY It is frequently referff red to as the Henry Hrr ub index. enHH ry Hub — Henry Hrr ub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. OPECPP — Organization of Petroleum Exporting Countries. Productivtt e well —ll ff the sale of such production exceed production expenses and taxes. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from ll Proved develope d reserves — In general, proved reserves that can be expected to be recovered froff m 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. 3 Proved reserves — Proved reserves are those quantities of oil and naturt al gas, which, by analysis of geoscience and engineering data, can be estimated with reasonabla e certainty to be economically producible – froff m a given date forff ward, froff m 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 reasonabla y certain, regardless of whether deterministic or probabia listic methods are used forff must have commenced r or the operator must be reasonabla y certain that it will commence the project within a reasonabla e time. the estimation. The projeo ct to extract the hydrocarbons dd ope ll Proved undevel or from existing wells where a relatively major expenditure is required forff of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X. d reserves — In general, proved reserves that are expected to be recovered froff m new wells on undrilled acreage recompletion. The SEC provides a complete definition PV-1VV 0 — The present value of estimated futff urt e revenues, discounted at 10% annually, to be generated froff m 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 effeff ct to (i) non-property related expenses such as general and administrative expenses, derivatives, debt service and futff urt e income tax expense or (ii) depreciation depletion and amortization expense. SEC — The U.S. Securities and Exchange Commission. SEC pricingii — The unweighted average firff st-day-of-the-month commodity price forff each month within the 12-month period prior to the end of the reporting period, adjud sted by lease forff market differff entials (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). oil or naturt al gas forff r crude Shelf — Water depths of up to 600 feet. dardizeii d MeaMM sure — The present value of estimated futff urt e net revenue to be generated froff m the production of proved Stantt reserves, determined in accordance with the rulr es, regulations or standards established by the SEC and the Financial Accounting Standards Board (using prices and costs in effeff ct as of the date of estimation), less futff urt e development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of futff urt e net revenue. ll Undevelope production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves. d acreagea — Lease acreage on which wells have not been drilled or completed to a point that would permit the Working intii ertt est — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. e oil produced in the United States with an American Petroleum Institute gravity WTI oTT r WesWW t TexTT as Intermediadd te — A light crudr aa ofof apapprproxioximamatetelyly 38-38 4040 anand td thehe susulflfururffff oxioximamatetelyly 0.3%0.3%.. cocontntenent it is as apprppr 4 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS The inforff mation 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, finff ancial position, estimated revenues and losses, projeo cted costs, prospects, plans and objectives of management are forff ward-looking statements. When used in this Annual Report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “projeo ct,” “forff ecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward-looking statements, although not all forff ward-looking statements contain such identifyiff ng words. These forff ward-looking statements are based on our current expectations and assumptions about future events and are based on currently availabla e informff ation as to the outcome and timing of futff urt e events. These forff ward-looking statements are based on management’s current belief, based on currently availabla e inforff mation, as to the outcome and timing of futff urt e events. Forward-looking statements may include statements about: ff • • • • • • • • • • • • • • • • • • • • • • • • • business strategy; recoverabla e resources, reserves and prospective storage resources; drilling prospects, inventories, projects and programs; our ability to replace the reserves that we produce through drilling and property acquisitions; financial strategy, liquidity and capital required forff our development program and other capital expenditures; realized oil and natural gas prices; risks related to the pending and futff urt e mergers and acquisitions, such as the acquisition of QuarterNor rth Energy Inc. (“QuarterNorth,” and such transaction, the “QuarterNorth Acquisition”), including the risk that we may fail to complete such transaction on the terms contemplated or at all, and/or to realize the expected benefits of any such transaction; timing and amount of future production of oil, naturt al gas and NGLs; our hedging strategy and results; future drilling and low carbon r solutions plans; availabia lity of pipeline connections on economic terms; competition, government regulations and legislative and political developments; our babiliilitty tto btobt iain per itmits andd governme tnt lal approvalls; pending legal, governmental or environmental matters; our marketing of oil, natural gas and NGLs; our integration of acquisitions, including the QuarterNor rth Acquisition, and futff urt e performance of the combined company; future leasehold or business acquisitions on desired terms; costs of developing properties; general economic conditions, including the impact of continued inflaff tion and associated changes in monetary policy; political and economic conditions and events in forff eign oil, natural gas and NGL producing countries and acts of terrorism a or sabot age; credit markets; volatility in the political, legal and regulatory e elections; rr estimates of futff urt e income taxes; nvironments ahead of the upcu oming domestic and foreff ign presidential our estimates and forecasts of the timing, number, profitff ability and other results of wells we expect to drill and other exploration activities; the success of our low carbonr to capia tal to finff ance such opportunities, the timing and amount of revenues therefrom and potential futff urt e customers; solutions business, including as a result of any development opportunities, permitting, access 5 • • • • • the uncertainty inherent in estimating subsurface storage resources in our low carbon r solutions projects; our ongoing strategy with respect to our Zama asset; uncertainty regarding our future operating results and our future revenues and expenses; impact of new accounting pronouncements on earnings in future periods; and plans, objectives, expectations and intentions contained in this Annual Report that are not historical. We caution you that these forff ward-looking statements are subject to numerous risks and uncertainties, most of which are difficff ult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility; global demand for oil and naturt al gas; the abia lity or willingness of OPEC and other state-controlled oil companies (“OPEC Plus”) to set and maintain oil production levels and the impact of any such actions; the lack of a resolution to the war in Ukraine and increasing hostilities in the Middle East, and their impact on commodity markets; the impact of any pandemic and governmental measures related thereto; lack of transportation and storage capacity as a result of oversupply, government and regulations; the effeff ct of a possible U.S. government shutdown and resulting impact on economic conditions and delays in regulatory a ovals; lack of availabia lity of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter tion and the impact of central bank policy in response thereto; storms and loop currents; cybersecurity threats; sustained inflaff ly develop and produce environmental risks; faiff from our current discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory crr hanges; the uncertainty inherent in estimating reserves and in projecting futff urt e rates of production; cash floff w 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, off r problems arising froff m, the integration of acquired assets and operations, risks associated with permitting forff —a nd access to capital to finff ance— our CCS opportunities; and the other risks discussed in Part I, Item 1A. Risk Factors which are included herein. lure to find, acquire or gain access to other discoveries and prospects or to successfulff nd permitting appr a rr rr 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 availabla e data, the interprrr etation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify uff ard or downward revisions of estimates that were made previously. If significant, such revisions would change the scheduld e of any further production and development drilling. Accordingly, reserve estimates may diffeff l gas and NGLs that are ultimately recovered. r significantly froff m the quantities of oil, naturat pwu Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our r materially froff m those expressed in any forward-looking statements. All forward-looking statements, l results and plans could diffeff actuat expressed or implied, included in this Annual Report are expressly qualifieff d in their entirety by this cautionary statement. This cautionary ookingng ststatatememenentsts ththatat wewe oror pepersrsonsons ststatatememenent st shoul te any forff ward-looking acting on our behalf may issue. Except as otherwise required by appl statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances afteff r the date of this Annual Report. hould ad alslso bo be ce consonsididerereded inin coconnennectctioion wn withith anany sy subsubseqequeuentnt wrwrititteten on or or oraral fl fororffff wawardrd l-looki icable law, we disclaim any dutd y to upda u a 6 Riskii s Rkk elatll edtt to our Business and the Oil and NatNN ural Gas IndII ustryr SUMMARY RISK FACTORS • • • • • • • • • • • • • • • • • • • • Oil and natural gas prices are volatile. Stagnation or declines in commodity prices may adversely affect our financial condition and results of operations, cash floff ws, access to the capia tal markets and available borrowings under our Bank Credit Facility and our ability to grow. Future exploration and drilling results are uncertain and involve subsu tantial costs. Our production, revenue and cash floff w froff m operating activities are derived froff m assets that are concentrated in a single geographic region, making us vulnerabla e to risks associated with operating in one geographic area. Production periods or relatively short reserve lives for U.S. Gulf of Mexico properties may subju ect us to higher reserve replacement needs and may impair our ability to reduce production durd ing periods of low oil and naturt al gas prices. Our actuat l recovery of reserves may substantially differ froff m our proved reserve estimates. Our acreage must be drilled beforff e lease expirations in order to hold the acreage by production. If commodity prices become depressed forff 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 marketabia lity of our production depends mostly upon the availabia lity, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facff ilities. Inflationary issues and associated changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turt n could cause our capia tal expenditures and operating costs to rise. We may be unabla e to pursue our CCS business, either wholly or in significant measure, which could have a material adverse effeff ct on our business, results of operations and finff ancial condition. Our inabia lity to benefit froff m 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 finff ancial condition. We may be unabla e to provide the finff ancial assurances in the amounts and under the time periods required by BOEM if it its future demands to cover our decommissioning obligations. If in the future BOEM issues orders to provide additional submu financial assurances and we faiff l to comply with such future orders, 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 associated fedff eral offsff hore leases. Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other r disrupt ions. Global geopolitical tensions may create heightened volatility in oil, gas and NGL prices and could adversely affect our business, financial condition and results of operations. 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 froff m our non-operated properties. Hedging transactions may limit our potential gains. Our operations may incur subsu tantial liabia lities to comply with environmental laws and regulations as well as legal requirements appl nd endangered and threatened species. icable to marine life aff a Additional drilling laws, regulations, executive orders and other regulatory i nitiatives 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 effeff ct on our business, financial condition or results of operations. rr Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local governmental regulations that materially affeff ct our operations. If we are forff ced to shut-in production, we will likely incur greater costs to bring the associated production back online, and will be unabla e to predict the production levels of such wells once brought back online. We may experience significant shut-ins and losses of production dued to the effects of events outside of our control, including tropical storms and hurricanes in the U.S. Gulf of Mexico and in the shallow waters off tff he coast of Mexico and epidemics, outbreaks or other public health events. 7 • We are upgru experience difficulties with the migration, we may be unabla e to timely or accurately prepare finff ancial reports. ading our accounting system to a more recent version and, if this upgraded version proves ineffecff tive or we Riskii s Rkk elatll edtt to our CapiCC taii l StrSS ucture and Ownershrr ip of our ComCC mon StoSS ck • • • • • • • • • Our debt level and the covenants in our current or futff urt e agreements governing our debt, including our Bank Credit Facility, and the indenturt es governing our New Senior Notes, could negatively impact our financial condition, results of operations lure to comply with these covenants could result in the acceleration of our outstanding and business prospects. Our faiff indebtedness. A finff ancial crisis may impact our business and financial condition and may adversely impact our ability to obtain fundi under our Bank Credit Facility or in the capital markets. ff ng We require subsu tantial capital expenditures to conduct our operations and replace our production, and we may be unabla e to obtain needed financing on satisfactory t erms necessary to fund our planned capital expenditures. rr 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 futff urt e asset retirement obligations may vary s decommissioning costs could materially adversely affecff ignificantly froff m period to period and unanticipated t our current and futff urt e finff ancial position and results of operations. rr We may not realize the anticipated benefits from our current and future acquisitions, and we may be unabla e to successfulff integrate futff urt e acquisitions. ly Our current and futff urt e acquisitions could expose us to potentially significant liabia lities, including P&A liabia lities. Resolution of litigation could materially affeff ct our financial position and results of operations. The interests of the Slim Family and its affiff liates may differ froff m the interests of our other stockholders. Riskii s Rkk elatll edtt to the Quartertt Norr rth Att cquisiii tiii on and our Integre atiott n of Qo uartertt Norr tt rth I ntII o ott ur Busineii ss • • We may not consummate the QuarterNor rth Acquisition on the terms currently contemplated or at all. The faiff lure to successfulff adversely affect our future results. ly integrate our business and operations with QuarterNorth in the expected time frame may 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 subsu idiaries. We are a publicly traded Delaware corporation and our common stock is listed on the New York Stock Exchange under the symbol “TALO.” We are a technically driven independent exploration and production company focff used on safely and efficiently maximizing long- term value through our operations, currently in the United States (“U.S.”) and offsff hore Mexico both through oil and gas exploration and production (“Upstream”) and the development of low carbon solutions opportunities. We leverage decades of technical and offsff hore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offsff hore basins around the world. We are also utilizing our expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico (“Gulf Coast”). r 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 optimize our assets’ production and reserve recovery, safelff y and responsibly. Finally, we leverage our commercial and corporate management experience to most effeff ctively allocate our capia tal 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 Upstream reserves, production, cash floff w and future growth opportunities in a capital efficient manner while also exploring CCS opportunities. Our deep technical expertise and extensive physical operating experience also allows us to successfulff ly manage our Upstream business and consistently make attractive acquisitions. We believe these same core competencies can be utilized to develop large-scale decarboni zation projeo cts to reducd e industrial emissions. r Upstrett am Stratt tegye We maintain a large and diverse in-house technical staff f ocff used on geology, geophysics, engineering and other technical disciplines, providing many decades of exploration and production experience in the key resource trends in which we focff us. Our f seismic data resources, which focuses on the U.S. Gulf of Mexico and offshore Mexico, allows our technical team significant library orr to apply proprietary seismic reprocessing techniques to evaluate or re-evaluate potential resources across our asset portfolff io. We also maintain deep in-house experience across our offsff hore operations, production operations, safetff y, facilities and business development teams. ff 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 venturt es and acquisitions, among others. Our proven track record of success through organic drilling opportunities freff quently attracts potential drilling partners in projects that we operate, while in non- operated projeo cts 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 primarily focused on assets with a geological setting se and technical expertise to re-evaluate and improve the acquired properties. that can benefit froff m our ability to use our seismic databaa tions and sellers that are currently availabla e in offshore basins, Specifically, our acquisition focff us areas target a variety of potential situat including single asset acquisitions, consolidation of private companies and broader asset package transactions. We seek to actively participate in government lease sales to identify aff nd 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 pff reviously unknown drilling prospects. 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 favff orable geologic and economic conditions, including multiple geologic trends, comprehensive geologic and geophysical seismic databaa int, which includes operational control of several key shallow and Deepwater facff ilities, allows us to invest in a diverse set of opportunities ranging from in- field development to high impact exploration projeo cts while optimizing our facilities to lower incremental operating costs structures. We also believe our operated infraff structurt e can be attractive to other operators looking for a host facff ility for their subsu ea tie-back projects, which allows us either to be involved in new investment opportunities or to offset the operating cost of these facilities. ses, extensive infraff structurt e and an attractive asset acquisition market. Our asset foot prt ff 9 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: • • • • • Contintt uously Optimizing our Existing Asset Base — We benefit froff m our proven ability to enhance and extend the life off f existing projeo cts within our portfolff io. Investments in optimization projeo cts across our asset base aim to stabilize and improve the profile of producing assets by increasing recovery, production and cash floff w with typically relatively low investment capia tal and risk. These projects allow for subsequent investment opportunities in exploitation and exploration projeo cts. ent and Near-Frr Conducting Developmll int — We undertake asset development and exploitation drilling projeo cts in close proximity to our existing assets as well as facilities that we either own or have access to. These projeo cts leverage ongoing operations and existing technical knowledge of the area, ofteff n coupled with recent proprietary seismic reprocessing evaluations to provide attractive incremental investment opportunities to grow reserves, production and cash floff w in well-understood areas. nd Around Our ExiEE stii ieFF ld Projects Itt n aII intt g Asset FootFF prtt ities to Gtt in Explxx orll atiott n Activtt roGG w our Asset Base and Potentiatt Engagingii nlUU ocll k SigSS nigg fii cant New Resources — We conduct exploration drilling activities across our acreage set with risk-weighted investments that could establish significant io of prospective new reserves and production. These projeo cts are intended to optimize risk and reward across our portfolff drilling opportunities by finff ding and developing previously undiscovered resources along existing or emerging geological trends with the most efficient deployment of capital. When successfulff , exploration drilling activities can organically generate material new assets for the Company. lly Ull xpan EE ities to Ett ent Activtt r Business Developmll d our Asset Base, Oppor ziii ngii Acquisitions and Othett tunityii Set and Value tt Utili Creation PotPP entt tial — 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 upsu ide. Additionally, we utilize business development to acquire new leaseholds, enter new projeo cts and increase or decrease working interests in various existing projects to optimize capital planning and our targeted risk/rkk eturt n profile for varyirr ng business conditions. Acquisition 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 variabla es. 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. pp sibii ii y att espons nd Corporate Rtt reas of Maintaining SafSS etff y,tt Sustainabilit ate r our Business — We are focff used on maintaining high standards of safetff y, environmental responsibility and corpor citizenship across all elements of our business. We closely monitor safetff y performance and consistently take steps to imimprproveove ourour peperforformrmanancece. WWe se strtrivive te to eo exexecucutete ourour busbusininesess ps plalan wn whihilele sisimumultaltaneneousouslyly mimininimizmizining og ourur enenvivironronmementntalal footprt int, including emissions, potential spills and other impacts. Production from the Gulf of Mexico continues to provide some of the lowest greenhouse gas (“GHG”) emissions intensity due to the naturt e of subsea wells and established offsff hore pipeline and we continue to strive to lower our GHG emissions. Finally, we aim to be a good corporate citizen in the regions and communities where we operate. iples forff Operatiott ns Across All All as Key Pe riPP ncii lityii ygg Low CarCC bon Solutions StrSS ategtt Our CCS business is operated through our Talos Low Carbon Solutions (“TLCS”) subsidiary. TLCS intends to leverage its experience and technical expertise along the Gulf Coast, including subsu urface engineering expertise, seismic interpretation capabilities, operations experience along the Gulf Coast and a solid track record of safetff y and environmentally responsible operations. The Gulf int, while the underlying conventional geology in the area is believed to Coast is a critical industrial region with a large emissions footprt emissions r be ideal for carbon capture, transportation and injen ction into sequestration sites in the region. zation solutions to assist industrial partners with carbon sequestration. TLCS intends to provide decarboni r r Upstream Properties United StaSS tes Gulf oll f Mo exMM ico Our area of focff us in the United States is the Gulf of Mexico Deepwater. Our strategy is concentrated in areas characterized by clearly definff ed infrastructurt e, well-known production history and geological well control, which reducd es operational and investment risk. 10 We believe our Deepwater operations in the U.S. Gulf of Mexico provide significant potential growth opportunities through our drilling program. Through our technical appa systems and applying modern seismic roach of starting with known hydrocarbon f Deepwater prospects that we believe are capable of delivering reprocessing techniques, we have generated a subsu tantial inventory orr production growth. We primarily focus our exploitation and exploration efforts around our existing infrastructurt e. This subsu ea tie-back strategy allows for better projeo ct economics and shorter periods between discovery and production as compared to design, construcrr tion and installation of a new faci lowing a discovery. lity folff ff r As of December 31, 2023, our core areas in the United States are summarized in the illustration below: The folff lowing tabla e sets forff th a summary of certain key 2023 information regarding our core areas in the United States: Estimated Proved Reserves MBoe % Oil % Natural Gas % NGLs Green Canyon Mississippi Canyon Shelf & Gulf Coast Total United States 41,342 87,183 24,241 152,766 75 % 77 % 51 % 73 % 17 % 15 % 42 % 20 % % Proved Developed Net Production (MBoe) % Operated 8 % 8 % 7 % 7 % 82 % 91 % 75 % 86 % 7,807 11,608 4,780 24,195 88 % 71 % 60 % 74 % Green Canyon — Green Canyon is a Deepwater region in the Central U.S. Gulf of Mexico and is a key focus area both industry-rr lities in the region including Green Canyon 18, Lobster, lities. Additionally, we have a floff ating production unit, the Helix Producer I (“HP-I”), that is our exploration activities. We operate several production faci wide and forff Prince, Neptune t leased from Helix Energy Solutions Group, Inc. (“Helix”). , and Brutr ust / Glider faci ff ff ppi ii Missi ii ii ssi a track record of prolificff production faci ff active as both an operator and non-operating partner in numerous development projeo cts and producing fieff Canyon — Mississippi Canyon is a Deepwater region in the eastern portion of the Central U.S. Gulf of Mexico with production and ongoing exploration success that continues to unlock new resources. We operate several lities in the region including Pompano, Amberjack, Ram Powell, Cognac and our non-operated Delta House. We are lds. Shelf and Gulf Cll oasCC across the basin and provides diverse production froff m numerous operated production facff the basin with attractive redevelopment and recovery enhancement opportunities. t — The U.S. Gulf of Mexico Shelf (the “Shelf”) and Gulf Coast area spans an enormous geographical area ilities. The Shelf area is a producing region of 11 Mexiee co As of December 31, 2023, our area of focus in Mexico is the Block 7, Zama Unit Area segment located within the Sureste Basin, a prolific proven hydrocarbon r province, in the shallow waters off tff he coast of Mexico’s Tabasco state. Such area is illustrated below: Blocll k 7 — On July 15, 2015, a Talos-led consortium was awarded Block 7 (“Block 7 Consortium”) with a term of thirty years, two additional fivff e-year periods. The Company’s participation interest in Block 7 is 35% starting in September 2015, and extendabla e forff r drilling the Zama-1 in 2017, less than and we are the operator. The Block 7 Consortium made a significant discovery in Block 7 afteff two years after signing a production sharing contract (“PSC”) for the block with Mexico's upsu tream oil and gas regulator, the National Hydrocarbon aise the r discovery. Commission (“CNH”). Subsu equent to the Zama-1 discovery, we drilled three additional wells to further appr a Upon conclusion of the three well appraisal program, we determined that the Zama Field likely extended into a nearbyr offsff hore block owned by Petróleos Mexicanos (“PEMEX”). The Block 7 Consortium and PEMEX engaged a third-party reservoir engineering firm to evaluate initial tract participation within the Zama reservoir and concluded that the Block 7 Consortium holds 49.6% of the gross interest in the Zama Field and PEMEX holds 50.4%, which resulted in us holding a 17.35% interest in the unitized Zama Field. Mexico’s Secretaría de Energía (“SENER”) has designated PEMEX as the operator of the Zama unit. itted by PEMEX to CNH forff The Zama Unit Development Plan was submu formal approval in March 2023 and was approved in June 2023. Modifications to the development plan were appr infrastructure development activities. Additionally, an Integrated Projeo ct Team (“IPT”) comprised of individuals from all four Zama Unit Holders has been establa ished to manage the development and operation of Zama going forward. The IPT is designed to provide technical, operational and execution expertise, leveraging the talents froff m each of the Zama Unit Holders. The IPT will report to the Zama Unit Operating Committee, which includes representatives from each of the companies. We will co-lead the planning, drilling, construcr tion, and completion of all Zama wells and co-lead the planning, execution, and delivery orr f Zama’s offshore infraff structurt e. Additionally, we will co-lead the project management offiff ce. ry 2024 due to a revised timeline forff oved by CNH in Februar a On September 27, 2023, we sold a 49.9% interest in Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”), a wholly Carso. See Part IV, Item 15. Exhibits tions and Divestitures and Note 7 — Equity Method Investments for additional owned subsidiary of the Company to Zamajaa l, S.A. de C.V., a wholly owned subsidiary of Grupo and Financial Statement Scheduld es — Note 3 — Acquisiii information. r 12 Carbon Capture & Sequestration TLCS is leveraging decades of experience with conventional geology and Gulf Coast operations to pursue the development of future CCS projects. Project opportunities are actively being evaluated along the Gulf Coast. TLCS intends to identify,ff lease, mature and operate future CCS project opportunities and the associated sequestration sites. Areas of development are illustrated below as of December 31, 2023: Bayoa u Bend CCS — On March 11, 2022, Bayou Bend CCS LLC (“Bayou Bend”) executed definff itive lease documentation with the Texas General Land Office, forff malizing the Jeffeff rson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. Chevron U.S.A Inc. (“Chevron”), which owns a 50% tive March 1, 2023. During March 2023, Bayou Bend expanded its membership interest in Bayou Bend, became the operator effecff storage foot int through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located within the Houston Ship ChChanannenell, BeBeauaumomontnt anand Pd Porort At Artrthurhur reregigionsons E. Equiquinornor ASASA aA acqcquiuirered ad a 25%25% memembmberershshipip inintetererestst inin AuAugusgust 2t 2023023. AsAs ofof DeDecemcembeber 3r 311, 2023, we own a 25% membership interest in Bayou Bend. For additional inforff mation on Bayou Bend, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 7 — Equity Method Investmett sequestration site located in state waters offshore Jeffeff rson County carbon ntstt . prt ff r In Februar al provisions on additional acreage, will allow forff Harvest Bend CCS (formerly River Bend CCS) —S ry 2022, Harvest Bend CCS LLC (“Harvest Bend”) executed two agreements to lease acreage along the Mississippi River industrial corridor for a future CCS project. The agreements, which contained right of first refusff sequestration sites near existing pipeline infraff structure that may be al agreement on incremental acreage was also executed in September 2023. In October used for the project. A separate right of first refusff 2023, Harvest Bend executed an additional agreement to lease acreage along the Mississippi River industrial corridor and two EPA Class VI permits were filff ed. In November 2023, seven additional agreements were conveyed to Harvest Bend from another wholly owned TLCS subsidiary that had nearbyr acreage. In December 2023, Harvest Bend became a multi-member limited liabia lity company and entered into an operating agreement with a TLCS subsidiary to be operator. As of December 31, 2023, we own a 65% membership interest in Harvest Bend and an affiliate of Storegga Limited owns the remaining equity interest. For additional inforff mation on Harvest Bend, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 7 — Equity Method Investments. Coastal Bend CCS — Pursuant to an option agreement with the Port of Corpus ry 2022, TLCS and Howard Energy Partners (“HEP”) began pursuing commercial CCS opportunities on-site at the PCCA. On March 17, 2023, Coastal Bend CCS LLC (“Coastal Bend”) became a multi-member limited liabia lity company. As of December 31, 2023, we own a 50% membership interest in Coastal Bend. For additional inforff mation on Coastal Bend, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 7 — Equity Method Investmett Christi Authority (“PCCA”) executed in Februarr ntstt . r 13 Summary of Reserves The folff lowing tabla e summarizes our estimated proved reserves which are all located in the United States: s: Consolidll atdd edtt Entitieii December 31, 2023 Proved developed producing Proved developed non-producing Total proved developed Proved undeveloped Total proved December 31, 2022 Proved developed producing Proved developed non-producing Total proved developed Proved undeveloped Total proved December 31, 2021 Proved developed producing Proved developed non-producing Total proved developed Proved undeveloped Total proved Oil (MBbls) Natural Gas (MMcf)ff NGL (MBbls) MBoe Standardized Measure (in thousands) PV -10 (in thousands) 75,132 23,093 98,225 12,590 110,815 63,049 17,236 80,285 10,774 91,059 70,183 23,237 93,420 14,344 107,764 90,279 51,544 141,823 38,048 179,871 103,245 58,482 161,727 57,824 219,551 108,238 78,204 186,442 49,911 236,353 6,440 3,517 9,957 2,016 11,973 6,194 3,121 9,315 3,613 12,928 7,426 4,366 11,792 2,643 14,435 $ 2,911,256 96,619 388,794 35,200 3,300,050 131,819 198,768 20,947 152,766 $ 3,043,488 $ 3,498,818 $ 3,935,208 86,451 661,882 30,104 4,597,090 116,555 24,024 584,009 140,579 $ 4,368,448 $ 5,181,099 $ 3,073,168 95,649 599,010 40,637 3,672,178 136,286 253,819 25,306 161,592 $ 3,440,611 $ 3,925,997 Reconciliall tion of So taSS ndardd dizeii d MeaMM sure to PV-1VV 0 PV-10 is a non-GAAP financial measure and diffeff rs from the standardized measure of discounted future net cash floff ws, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash floff ws on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash floff ws at the appl icable date, before deducting futff urt e 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 floff ws 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 prp opep rties. Further, investors mayy utilize the measure as a basis forff compparison 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 returt n on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of discounted t to represent future net cash floff ws. Our PV-10 measure and the standardized measure of discounted future net cash floff ws do not purpor the faiff r value of our oil and natural gas reserves. a r The folff lowing tabla e provides a reconciliation of the standardized measure of discounted future net cash floff ws to PV-10 of our proved reserves (in thousands): s: Consolidll atdd edtt Entitieii Standardized measure Present value of future income taxes discounted at 10% PV-10 (Non-GAAP) 2023 Year Ended December 31, 2022 2021 $ $ 3,043,488 $ 455,330 3,498,818 $ 4,368,448 $ 812,651 5,181,099 $ 3,440,611 485,386 3,925,997 14 Changes in Pii roPP ved Develope ll d Reserves The folff lowing tabla e discloses our estimated changes in proved developed reserves: Consolidll atdd edtt Entitieii Proved developed reserves at December 31, 2022 Changes durd ing the year: s: Production Revisions of previous estimates Additions Acquired Conversion to proved developed Total proved developed reserves changes Proved developed reserves at December 31, 2023 Oil, Natural Gas and NGLs (MBoe) 116,555 (24,195) (14,251) 1,322 42,684 9,704 15,264 131,819 Our proved developed reserves at December 31, 2023 increased by 15.3 MMBoe, or 13% primarily due to: Revisiii ons of Po atestt — There was a decrease of 14.3 MMBoe from revisions of previous estimates. The revisions were primarily due to a 9.2 MMBoe decrease in reserve volumes due to the decrease in SEC Pricing of $17.47 per Bbl of oil and $4.05 ld located in the Green Canyon core area due to well performance. per Mcf of natural gas and an additional decrease in the Phoenix fieff rePP vious EstEE imtt ration Acquired — Acquired proved developed reserves of 42.7 MMBoe are attributable to the acquisition of EnVen Energy Corporr (“EnVen,” and such acquisition, the “EnVen Acquisition”) located primarily in the Green Canyon and Mississippi Canyon core areas. tions and Divestitures for additional information. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 3 — Acquisiii Developmll ent of Po roPP ved UndUU evdd elope ll d Reserves The folff lowing tabla e discloses our estimated proved undeveloped (“PUD”) reserve activities: Consolidll atdd edtt Entitieii Proved undeveloped reserves at December 31, 2022 Changes durd ing the year: s: Extensions and discoveries Revisions of previous estimates Acquired Conversion to proved developed Total proved undeveloped reserves changes Proved undeveloped reserves at December 31, 2023 Oil, Natural Gas and NGLs (MBoe) Future Development Costs (in thousands) 24,024 $ 4,040 (3,831) 6,418 (9,704) (3,077) 20,947 $ 478,511 29,624 (176,869) 141,651 (188,161) (193,755) 284,756 Our PUD reserves at December 31, 2023 decreased by 3.1 MMBoe, or 13% primarily due to: Extensions and Discoveries — Extensions and discoveries of 4.0 MMBoe are primarily attributable to the Brutust Field located in the Green Canyon core area. Revisiii ons of Po tes — Downward revisions of 3.8 MMBoe are primarily due to a decrease of 3.2 MMBoe from the removal of a natural gas weighted opportunity in the Mississippi Canyon core area as a result of the change in the naturt al gas commodity environment. rePP vious EstEE ima tt Acquired — Acquired proved undeveloped reserves of 6.4 MMBoe are attributable to the EnVen Acquisition located primarily in the Green Canyon and Mississippi Canyon core areas. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 3 — Acquisiii tions and Divestitures for additional inforff mation. Conversirr on to Proved Develope ll Lime Rock, which tie back to our Ram Powell faci in the Mississippi core area. d — Conversions of 9.7 MMBoe are attributable to successfulff drilling of our wells Venice and lity as well as our MC 28 Mt. Hunter well in the Pompano Field, which are all located ff 15 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 fivff e years of the date they are firff st booked as PUD reserves, unless the reserves are associated with an existing producing zone. Futurt e development costs associated with our PUD reserves at December 31, 2023 totaled approximately $284.8 million, of which $131.0 million, $77.5 million and $76.2 million is attributable to our Mississippi Canyon, Green Canyon and Shelf and Gulf Coast core areas, respectively. When considering capital expenditures associated with other exploration projects and abandonment obligations, we expect to funff d the development of PUD reserves using cash floff ws from operations and, if needed, availabia lity under the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”), in each future annual period prior to the fivff e year expiration. Our 2024 drilling program includes development of PUD reserves, and the conversion rate may not be uniform due to obligatory wrr ells, newly acquired PUD reserves and production performance targets. Internal Controls over Reserve Estimates and Reserve Estimation Procedures At December 31, 2023, 2022 and 2021, proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural es by our reservoir engineers and audited by Netherland, Sewell & gas properties were estimated and compiled forff Associates, Inc. (“NSAI”), independent petroleum engineers and geologists, as described in furff ther detail below. reporting purpos r Our policies regarding internal controls over the determination of reserves estimates require reserves quantities, reserves categorization, future producing rates, futff urt e net revenue and the present value of such future net revenue prepared using the definitions set forff th in Regulation S-X, RulRR e 4-10(a) and subsequent SEC staff interpretations and guidance. These internal controls, which are intended to ensure reliabia lity of our reserves estimations, include, but are not limited to, the folff lowing: • • • • • • • reserve inforff mation, as well as models used to estimate such reserves, is stored on secure databaa only authorized personnel are given access rights consistent with their assigned job function; se applications to which 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 appa Executive Offiff cer; roved by certain members of senior management, including our President and Chief 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 transferff red to NSAI through a secure file transferff protocol site; and mamateteririalal rereseservrve ve varariaiancnceses arare de disiscucussessed ad amomongng NSNSAIAI, a, as as applppl Reserves to ensure the best estimate of remaining reserves. aa icicabablele, o, ourur ininteternrnalal rereseservrvoioir er engingineneerers as andnd ourour DiDirerectctoror ofof Because these estimates depend on many assumptions, any or all of which may diffeff r substantially froff m actuat l results, reserve estimates may be different from the quantities of oil, naturt al gas and NGLs that are ultimately recovered. During the reserves audit, NSAI did not independently verify the accuracy and completeness of inforff mation and data furff nished by us with respect to ownership interests, oil, natural gas and NGL production, well test data, historical costs of operation and lds and sales of production. However, development, product prices or any agreements relating to current and futff urt e operations of the fieff 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 definff itions and regulations of the SEC, including the criteria of “reasonabla e certainty,” as it pertains to expectations about the recoverabia lity of reserves in futff urt e years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. NSAI issued unqualifieff d audit opinions on our reserves as of December 31, 2023, its evaluations. NSAI concluded that our estimates of reserves were, in the aggregate, reasonabla e and have 2022 and 2021 based upon been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPEE. The 2023 NSAI report is filff ed as Exhibit 99.1 to this Annual Report. u 16 Technologies Used in Reserve Estimation The SEC’s reserves rules allow the use of techniques that have been proved effective by actuat l production froff m projeo cts in the same reservoir or an analogous reservoir or by other evidence using reliabla e technology that establa ishes reasonabla e certainty. The term “reasonabla e certainty” implies a high degree of confidff ence that the quantities of oil, naturt al gas and/or NGLs actuat lly recovered will equal or exceed the estimate. To achieve reasonabla e 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 inforff mation and property ownership interests. The accuracy of the estimates of our reserves is a func tion of: ff • • • • the quality and quantity of availabla e data and the engineering and geological interprr etation of that data; estimates regarding the amount and timing of futff urt e operating costs, development costs and workovers, all of which may vary considerably from actuat l 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. Qualificff ations of Primary Internal Engineer Our Director of Reserves is the technical person primarily responsible for overseeing the preparation of our internal reserve xperience with positions of estimates and for coordinating reserve audits conducted by NSAI. He has over 48 years of industry e increasing responsibility, including 40 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 roups, and has been a member of the Society of Petroleum active participant in industry r sional industry grr r Engineers forff over 48 years. He reports directly to our Vice President of Corpor eserve seminars and profesff ate Development. rr rr Drilling Activity The folff lowing tabla e sets forff th our drilling activity: Exploratory and Appraisal Wells Dry(2) Total Gross Net Gross Net Productive(1) Net Gross Productive(1) Net Gross Development Wells Dry(2) Total Total Gross Net Gross Net Gross Net s: Consolidll atdd edtt Entitieii Year Ended December 31, 2023 3.0 United States — Mexico 3.0 Total Year Ended December 31, 2022 — United States — Mexico — Total Year Ended December 31, 2021 — United States — Mexico — Total EEquityii Method Investees: Year Ended December 31, 2023 — Mexico 1.3 — 1.3 5.0 — 5.0 — 1.0 — — — 1.0 — 2.0 — — — 2.0 2.1 — 2.1 1.0 — 1.0 1.5 — 1.5 8.0 — 8.0 1.0 — 1.0 2.0 — 2.0 3.4 — 3.4 1.0 — 1.0 1.5 — 1.5 7.0 — 7.0 6.0 — 6.0 5.0 — 5.0 3.0 — 3.0 2.8 — 2.8 2.4 — 2.4 — — — — — — — — — — 7.0 — — — 7.0 — 6.0 — — — 6.0 — 5.0 — — — 5.0 3.0 — 3.0 2.8 — 2.8 2.4 — 2.4 15.0 — 15.0 7.0 — 7.0 7.0 — 7.0 6.4 — 6.4 3.8 — 3.8 3.9 — 3.9 — — — — — — — — — — — — — (1) (2) A productive well is an exploratory orr ompletion as an oil or naturt al gas producing well. Productive wells are included in the tabla e in the year they were determined to be productive, as opposed to the year the well was drilled. A dry wrr productive, as opposed to the year the well was drilled. to be capaa bla e of producing either oil or naturt al gas in suffiff cient quantities to justify cff ells are included in the tabla e in the year they were determined not to be r development well that is not a productive well. Dry wrr r development well found ell is an exploratory orr ff 17 As of December 31, 2023, we had wells actively drilling or completing and wells suspended or awaiting completion, as follows: Consolidll atdd edtt Entitieii ited States s: Equityii Method Investees: xico Productive Wells Actively Drilling or Completing Exploratory Development Wells Suspended or Waiting on Completion Exploratory Development Gross Net Gross Net Gross Net Gross Net — — — — — — — — 1.0 4.0 0.5 0.4 1.0 — 0.1 — The number of our productive wells is as follows forff the year ended December 31, 2023: s: oil Consolidll atdd edtt Entitieii Crude rr Natural gas Total(1) Gross Net 259.0 76.0 335.0 191.3 37.7 229.0 (1) Includes 8.0 gross and 7.1 net wells with dual completions. Acreage Gross and net developed and undeveloped acreage is as folff lows for the year ended December 31, 2023: Developed Acres Gross Net Undeveloped Acres Net Gross Total Acres Gross Net s: Consolidll atdd edtt Entitieii United States: Deepwater Shelf Total United States Equityii Method Investees: Mexico(1) 362,000 261,929 623,929 186,247 175,775 362,022 592,712 53,572 646,284 368,238 33,088 401,326 954,712 315,501 1,270,213 554,485 208,863 763,348 — — 3,261 572 3,261 572 (1) Gross acreage forff Mexico represents the gross acreage in Block 7, which Talos Mexico has a 35% participation interest. We hold a 50.1% equity interest in Talos Mexico. See Part IV, Item 15. Exhibits and Financial Statement Scheduldd es — Note 7 — Equity Method Investmett ntstt for additional inforff mation. Undeveloped acreage is considered to be 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 naturt al gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are 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, 2023 are scheduld ed to expire as shown in the tabla e below (the terms of which may be extended by drilling and production operations): 2024 2025 2026 2027 2028 2029 and beyond Total Consolidated Entities Net Gross Equity Method Investees Gross Net 94,043 85,046 74,880 92,160 17,280 282,875 646,284 45,873 60,921 58,473 44,086 4,367 187,606 401,326 — — — — — 3,261 3,261 — — — — — 572 572 18 Crude Oil, Natural Gas and NGL Production, Prices and Production Costs Our production volumes, average sales prices and average production costs are as folff lows: Consolidll atdd edtt Entitieii s: Production Volumes: oil (MBbls) Crude r Natural gas (MMcf) NGLs (MBbls) Total (MBoe) 2023 Year Ended December 31, 2022 2021 18,062 26,194 1,767 24,195 14,561 32,215 1,793 21,723 16,159 32,795 1,875 23,500 Percent of MBoe froff m crude oil 75 % 67 % 69 % Average Sales Price (including commodity derivatives): oil (per Bbl) Crude r Natural gas (per Mcf) NGLs (per Bbl) Average (per Boe) Average Sales Price (excluding commodity derivatives): oil (per Bbl) Crude r Natural gas (per Mcf) NGLs (per Bbl) Average (per Boe) Average Lease Operating Expense (per Boe) Expenditures and Costs Incurred $ $ $ $ $ $ $ $ $ 73.59 3.32 18.18 59.86 75.17 2.60 18.18 60.26 16.10 $ $ $ $ $ $ $ $ $ 68.40 5.30 33.20 56.46 93.75 7.06 33.20 76.05 14.18 $ $ $ $ $ $ $ $ $ 49.67 3.11 26.54 40.61 65.86 3.98 26.54 52.96 12.07 For inforff mation on property development, exploration and acquisition costs, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 16 — Supplemental Oil and Gas Disclosures (Unaudi UU ted). Title to Properties rr We believe that we have satisfactory t itle to our oil and natural gas properties in accordance with generally accepted industryrr standards. Individual properties may be subju ect to burdens such as royalties, overriding royalties, and carried, net profitff s, working and other outstanding interests customary in the industry.rr icable laws a or burdens such as production payments, ordinary course liens incidental to operating agreements and forff current taxes and development obligations under oil and naturt al gas leases. As is customary i n 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 defect s affecting such undeveloped properties, we are typically responsible for curing any such title defects at our expense. In addition, interests may be subju ect to obligations or duties under appl n the industry i ff rr rr Commodity Price Risks and Price Risk Management Activities Production froff m our properties is marketed using methods that are consistent with industry prr ractices. Sales prices for oil and natural gas production are negotiated based on factors normally considered in the industry,rr such as an index or spot price, price regulations, distance froff m 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 floff ws and reducd e the risk and finff ancial impact of downward commodity price movements on commodity sales. For additional inforff mation regarding our commodity price risk and commodity derivative instruments, see Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk. Significff ant 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 subju ect to many external factors which may contribute to significant volatility in future prices. We market the majoa rity of our oil, natural gas and NGL production from the properties we operate and those we do not operate. Our customers consist primarily of majoa r oil and gas companies, well-established oil and iers. We perform ongoing credit evaluations of our customers pipeline companies and independent oil and natural gas producers and suppl and provide allowances for probabla e credit losses when necessary. For the year ended December 31, 2023, 54% and 21% of our oil, natural gas and NGL revenues were attributable to Shell Trading (US) Company and Valero Energy Corporation, respectively, which are the customers that individually represented 10% or more of our oil, natural gas and NGL revenues. u 19 Competitive Conditions The oil and naturt al gas business is highly competitive in the exploration forff and acquisition of reserves, the acquisition of oil and natural gas leases, equipment and personnel required to finff d and produce reserves and in the gathering and marketing of oil, natural gas and NGLs. We compete with large integrated oil and naturt al gas companies as well as independent exploration and production companies. Certain of our competitors may have significantly more finff ancial or other resources available to them. In addition, certain of the larger integrated companies may be better abla e to respond to industry crr tion, oil and natural gas demand and governmental regulations. hanges, including price fluff ctuat However, we believe our high quality oil-weighted producd tion 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 affeff ct the demand forff tions, 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. il and naturt al gas. Due to these seasonal fluff ctuat , and prices of, off Insurance Matters Our oil and naturt al 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 fluff ids 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 vulnerabla e to tropical storms, loop currents and hurricanes. tion of property and equipment, pollution or These hazards can cause personal injury orr environmental damage and the suspension of operations. Damages arising froff m 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 subju ect. A successfulff claim forff which we are not fully insured could have a material adverse effect on our financial condition, results of operations and cash floff w. 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. severe damage to and destrucrr r loss of life,ff We have insurance policies to cover some of our risk of loss associated with our operations, and we maintain the amount of nt. However, not all of our business activities can be insured at the levels we desire because of either insurance we believe is prude limited market availability or unfavorable economics (limited coverage for the underlying cost). r ff u several fl fact OOur gener lal propert dy damag ie insurance pr ioviddes var iyirr ng ranges off coverage bbasedd upon ors, iin lcl dudiing w lelll counts lities. Our general liabia lity insurance program provides a limit of $500.0 million for each occurrence and the cost of replacement faci o $150.0 million and in the aggregate, and includes varyirr ng deductibles. Our Oil Pollution Act insurance is subju ect to a maximum of up tu for each occurrence and in the aggregate, including a $100,000 retention. Coverage is provided forff damage to our assets resulting froff m a named U.S. Gulf of Mexico windstorm; however, such coverage is subju ect to a maximum of $250.0 million per named windstorm and in the aggregate, and is also subjeb ct to a maximum of $15.0 million per occurrence retention dependent on location. We separately maintain an operators extra expense policy with additional coverage for an amount up to $500.0 million for U.S. Gulf of Mexico Deepwater drilling wells, $150.0 million forff U.S. Gulf of Mexico Shelf drilling wells, $75.0 million forff U.S. Gulf of Mexico producing and shut-in wells, $75.0 million forff lds that would cover costs involved in making a well safe afteff r 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 abaa ndoning the well; and costs for clean-up and containment and for damages caused by contamination and pollution. For our Mexico insurance policies, we maintain $250.0 million in operators extra expense coverage forff operations and $500.0 million per occurrence and aggregate limit for general liability. drilling and workover in inland waters and $25.0 million forff drilling and workover in onshore fieff ff We may increase or decrease insurance coverage around our key strategic assets, including potentially purchasing catastrophic bond instruments. A portion of our highest value assets, which are located in the Phoenix Field, produce through the HP-I floff ating 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 liabia lity related to work performed for us. Under these agreements, we generally are indemnifieff d against third respective personnel forff party claims related to the injun ry or death of our customers’ or vendors’ personnel, subju ect to the appl ication of various states’ laws. a 20 Government Regulation rr Exploration and development and the production and sale of oil, natural gas and NGLs are subju ect to extensive fedff eral, state, local and forff eign 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 floff ws. However, current regulatory r incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Because such laws and regulations are freff quently amended or reinterprr eted, we urden increases our cost of doing business and, are unabla e to predict the futff urt e cost or impact of compliance. Although the regulatory brr consequently, affects our profitff ability, these burdens generally do not affeff ct us any diffeff rently or to any greater or lesser extent than they ith similar types, quantities and locations of production. affeff ct others in our industry wrr equirements may change, currently unforff eseen environmental General Overview — Our oil and natural gas operations and CCS projects are subju ect 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 naturt al gas properties; drilling and casing of wells; issuance of permits in connection with exploration, drilling and production and CCS activities; well production; spill prevention plans; protection of private and public surface and ground water supplies; emissions permitting or limitations; protection of marine life aff nd 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 u which wells have been drilled; calculation and disbursement of royalty payments and production taxes; requirements forff the plugging and the posting of supplemental bonds or providing other forff ms of financial assurance forff abandonment of wells located in the U.S. Gulf of Mexico and offsff hore Mexico and, following cessation of operations, the ilities, structurt es and pipelines in those areas (“P&A” or removal or appr “decommissioning” obligations); opriate abandonment of all production facff a performance of P&A obligations; and transportation of production. egulatll Outer ConCC tinental SheSS lf (“OCS”CC ) R” iott n — Our operations on federal oil and naturt al gas leases in the U.S. Gulf of Mexico are subju ect to extensive regulation by BSEE, BOEM and the Offiff ce of Natural Resources Revenue (“ONRR”) under the purview of the U.S. Department of the Interior (“DOI”). Federal leases are awarded by BOEM based on competitive bidding with relatively standardized lease terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the fedff oval forff exploration, development and production plans prior to the commencement of their operations. In addition to permits required froff m other agencies such as the U.S. Environmental Protection Agency (“EPA”), lessees must obtain a permit from BSEE prior to the tion specifications for commencement of drilling and comply with regulations governing, among other things, engineering and construcr production faci lities, safety procedurd es, P&A of wells on the OCS, calculation of and valuation of production related to royalty payments, and decommissioning of facilities, structurt es and pipelines. eral Outer Continental Shelf Lands Act (“OCSLA”). For offsff hore operations, lessees must obtain BOEM appr a ff 21 U.S. federal offshore oil and gas leasing and permitting practices have been subju ect to numerous challenges, delays, and moratoriums over the last three years which has curtailed our ability to seek additional new federal leases and may continue to delay or eral leases. Additionally, in response to a November 2021 report froff m the DOI on federal prevent us froff m bidding and obtaining new fedff oil and gas leasing and permitting practices, the Inflation Reducd tion Act of 2022 (the “IRA 2022”) increased onshore royalty rates to 16.7% and offshore royalty rates to no less than 16.7% but not more than 18.8% for the next ten years, thereby ensuring the full value of the leased tracts are captured. The extent to which the Biden Administration will act upon the DOI report’s other recommendations cannot be predicted at this time, but any additional action may cause delay or prevent us from obtaining new fedff eral leases. In January 2023, BOEM released its final environmental impact statement forff Lease Sales 259 and 261 and, in March 2023, announced the results of Lease Sale 259, in which we were the high bidder on four offsff hore blocks, and were awarded leases on all four blocks. BOEM held Lease Sale 261 on December 20, 2023, in which we were the high bidder on thirteen offsff hore blocks and were ry 16, 2024. As BOEM is still in its bid evaluation process, we are awaiting BOEM’s award decisions awarded four on our remaining high bids. Any reducd tion in the size or number of offshore blocks designated by BOEM forff future leasing activities, as well as delays in BOEM awarding leases to operators either as a result of NEPA-related days or legal challenges to BOEM leasing decisions, has the potential to materially and adversely affect our business and results of operations. leases as of Februarr ff ff ff Laws and regulations related to our business continually evolve and change depending on the political climate, but generally our business has experienced increased safetff y and environmental restrictions and permitting and performance requirements durd ing our existence. Our operations are currently subju ect to rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of Deepwater, high temperaturt e, high pressure drilling activities, and enhanced reporting requirements. The Biden Administration has taken a number of actions to adopt more stringent safety, permitting and performance requirements. drilling, workover, completion and decommissioning For example, on August 23, 2023, BSEE published a final well control rulr e forff operations, revising the 2019 rule and increasing the requirements forff blowout preventer systems (“BOPs”) and other well control and operations requirements. The finff al rule requires, among other things, that BOPs are always able to close and seal the wellbore to the lure data is well’s maximum anticipated surface pressure, faiff reported to both a designated third party and BSEE, and independent third-party qualificff ations are submitted to BSEE with associated permit applications. Compliance with Biden Administration legislative, executive and regulatory arr ctions 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 lure to comply with legal increased capital expenditures and operating costs, and could adversely impact our business. Our faiff requirements under the OCSLA, our lease or appl icable regulations may ultimately result in BOEM canceling one or more of our leases, which such cancellation could adversely affect our financial condition and operations. lure analysis and investigations start within 90 days of an incident, faiff a Furthermore, tropical storms, loop current, hurricanes and other adverse weather conditions in the U.S. Gulf of Mexico can have a significant impact on oil and naturt al gas operations and can result in suspended operations and significant damage to key infrastructure rt to reduce the potential for futff urt e damage, BOEM and BSEE have periodically issued guidance and extensive pollution. In an effoff iaimedd at it impro iving lpl tatfform surviiv babililitity bby ttakiking iintto acco tunt en ivironmenttall a dnd ocea inic c di s a dnd related strucr tures. More stringent, requirements could be proposed or finalized in the futff urt e, which could increase our operating costs and/or capia tal expenditures. ondititions iin thth de desiign off pllatftformff In addition, in order to cover the various decommissioning obligations of lessees on the OCS, BOEM generally requires that lessees post some forff m of acceptabla e finff ancial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other finff ancial assurance can be subsu tantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. BOEM requires that lessees demonstrate finff ancial strength and reliabia lity according to its regulations and provide acceptabla e financial assurances to assure satisfacff tion of lease obligations, including decommissioning activities on the OCS. There has been subsu tantial uncertainty with respect to BOEM’s financial assurance requirements in recent years and BSEE’s approach to predecessor liabia lity for decommissioning obligations. In April 2023, BSEE published its Final RulRR e entitled, “Risk Management, Financial Assurance, and Loss Prevention – Decommissioning Activities and Obligations,” wherein BSEE clarified decommissioning responsibilities forff RUE grant holders and forff malized BSEE’s policies regarding performance by predecessors ordered to decommission OCS facff p Administration that sought to amend BSEE’s regulations requiring the agency to proceed in reverse chronological order against predecessor lessees, owners of operating rights and grant holders when requiring such entities to perform their accruer d decommissioning obligations upon failure to perform by current lessees, owners, or holders. Under the final rulr e, BSEE may issue an order to predecessors to perform accruer d decommissioning obligations, including beginning maintenance and monitoring within thirty days, designating an operator forff decommissioning within ninety days, and submu ilities. The finff al rule withdraws a rule proposed during the Trumr itting a decommissioning plan within one hundred fifty days. 22 a u In addition, in June 2023, BOEM published a proposed rule that, if adopted as initially proposed, would substantially revise the suppl u icable to offsff hore oil and gas operations. The proposed rule would change the current emental finff ancial assurance requirements appl emental finff ancial assurance. The proposed criteria used to determine whether OCS lease and grant holders are required to secure suppl rule would no longer use the current 5-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead proposes a simplified test: (1) the credit rating of the lessee and, where appl icable, (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. Under the the finff ancial strength of predecessors in determining whether, or how proposed rule, BOEM would no longer consider or rely upon much, supplemental finff ancial assurance should be provided by current lessees and grant holders. BOEM would not require suppl emental financial assurance aboa ve the base bond requirements in three cases: (1) where a lessee has an investment grade credit rating (i.e., a credit rating froff m a Nationally Recognized Statistical Ratings Organizations, or NRSRO, that is greater than or equal to either BBB- from S&P or Baa3 from Moody’s, or its equivalent, or a proxy credit rating greater than or equal to either BBB- or Baa3, as determined a company’s audited finff ancial information with an accompanying auditor’s certificate); (2) by the Regional Director and based upon where there are multiple co-lessees on a lease and any one of those lessees meets the credit rating threshold; and (3) for any lease on which all lessees are rated below investment grade, where the value of the lease’s proved oil and gas reserves is at least three times that of the estimated decommissioning cost estimate. BOEM proposes to phase in compliance with the new requirements over a three-year period. The extended public comment period closed on September 7, 2023, and BOEM is reviewing the comments received. At this time, we cannot predict whether BOEM will adopt the finff al rule in its current form or at all, the timing forff any finff al decision, or whether any changes will result from the public notice and comment process, but will continue to monitor this rulr emaking. According to the Fall 2023 Unifieff d Agenda, the final rulr e is expected in the second quarter of 2024. u u u a Separately, in August 2021, BOEM published a Note to Stakeholders detailing an expansion of its suppl emental finff ancial assurance requirements currently applicable to all sole liabia lity properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-lff ife i er than five years, or with damaged infraff structure irrespective of the remaining property life off f the surrounding producing assets. BOEM has stated it will prioritize non-sole liabia lity properties where it believes that the current owner does not meet applicable requirements related to financial strength and has no co- owners or predecessors that are finff ancially strong, as determined by BOEM. s fewff u ff The futff urt e cost of compliance with respect to suppl emental 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 rulr es on suppl emental bonding published by BOEM under the Biden Administration, could materially and adversely affect our financial condition, cash floff ws and results of operations. Moreover, BOEM has the right to issue liabia lity orders in the futff urt e, including if it determines there is a subsu tantial risk of nonperformance of the interest holder’s decommissioning liabia lities. u u s Orr Regue t of Mo ffO the CoasCC lation in Shalloll w WatWW ertt sco state are subjeb ct to regulation by SENER, the CNH and other Mexican regulatory brr exMM ico — Our oil and gas operations in shallow waters off the coast of Mexico’s odies. The CNH is responsible for, among Tabaa the explp oration and prp oduction of oil and natural ggas in Mexican other thingsg , o, verseeing tg he tender pprocedurd es for awarding cg ontracts forff waters, managing and supeu rvising contracts that have been awarded, and appr oving exploration and production plans. The PSC that the a Block 7 Consortium entered into for the development of this acreage contains 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 forff industrial safetff y, operational security, and facility decommissioning. Failure to comply can result in the imposition of monetary penalties, revocation of permits, rescission of the PSC, suspension of operations, and ordered decommissioning of offsff hore facilities and systems. The laws and regulations governing activities in the Mexican energy sector were significantly reformed in 2013, odies issue new regulations and the legal regulatory f and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory brr odies may impose new or revised requirements that could increase our operating costs and/or capital expenditures forff operations in Mexican offsff hore shallow waters. raff mework continues to evolve as SENER, the CNH and other Mexican regulatory brr r rr 23 r r r xx t Regulatll iott n in Mii Hydrocarbon Expor Sector (“ASEA”) or other Mexican regulatory brr exMM ico — Our oil and gas operations in shallow waters off the coast of Mexico’s Tabaa sco state are subject to regulation by SENER. Such regulations are subject to change, and it is possible that the Mexican National Agency of odies may impose Industrial Safetff y and Environmental Protection of the Hydrocarbons new or revised requirements that could increase our operating costs and/or capia tal expenditures forff operations in Mexican offsff hore waters. For example, in December 2020, SENER published regulations affeff cting 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. Subsu equently, in May 2021, the Mexican government amended its Law in a manner that is anticipated to be beneficial to PEMEX, but have an adverse impact on privately-held oil federal Hydrocarbons and gas energy companies including by way of example, (i) authorizing SENER and the Mexican Energy Regulatory Crr ommission (the permits if there is imminent danger to national security, energy security or the national “CRE”) to suspend or revoke hydrocarbon permit-holders to safeguard the national r economy; (ii) allowing the government to temporarily occupy the facff interest and hand over the operation of such faci lt 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 petroleum products and petrochemical markets, which regulation obligates PEMEX to comply with regulation in the hydrocarbon, certain obligations that effeff ctively 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, Law (such suspension including the authorization to partially suspended portions of the firff st amendment to the Hydrocarbons Law in May temporarily occupyu 2021. facilities of permit-holders) in May 2021 and suspended the second amendment to the Hydrocarbons lities to State-owned entities, such as PEMEX; and (iii) allowing for denial by defauff ilities of hydrocarbon ff r r r r r Environmental and Occupational Safety and Health Regulations We are subject to various federal, state, local and forff eign regulations concerning occupau tional safetff y 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: • • • • • • • • assessing the environmental impact of seismic acquisition, drilling or construcrr tion 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 forff mer operations; various environmental permitting requirements, such as permits forff wastewater discharges; the developmp ent of emerggencyy respponse and sppill contingeg ncy py plans;; specific operating criteria addressing worker protection; and protection of private and public surface and ground water supplies. rr Based on regulatory t rends 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 reasonabla e 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, naturt al resource damages or the issuance of injun nctive relief (including orders to cease operations). Both onshore and offsff hore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. Additionally, President Biden has made climate change arising froff m GHG emissions a priority under his administration. Some environmental laws and regulations may impose strict liabia lity, which could subju ect us to liability for conduct that was lawfulff 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 i n general, our business and financial results could be adversely affected. rr 24 the reimbursement to us of certain costs incurred forff 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 f materials that may be coverage provides forff 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 freff quently 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 liabia lities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production. the containment and clean-up ou Water Discharger s — 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 subsu tances, 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 enforff cement actions. Violations of the CWA can result in suspension, debarment or the imposition of statutory disabia lity, 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. ff ff a tion Act — The Oil Pollution Act of 1990, as amended (“OPA”), holds owners and operators of offsff hore oil production or olPP lull Oil Pii handling facff lity is located, strictly liable for the costs of ilities, including the lessee or permittee of the area where an offshore faci removing oil discharged into waters of the United States and for certain damages froff m such spills. OPA assigns joint and several strict all containment and oil removal costs and a variety of public and private damages liabia lity, without regard to fault, to each liable party forff including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffeff red by ed by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. OPA’s damages persons adversely affect s currently $167.8 million; however, a party cannot take advantage of liabia lity limits if a spill was caused by gross liabia lity cap i negligence or willfulff misconduct, resulted from violation of a federal safetff y, construcrr tion or operating regulation, or if the party failed to report a spill or cooperate fully in the clean-up.u OPA also requires responsible parties to maintain evidence of finff ancial responsibility in prescribed amounts. OPA currently requires a minimum finff ancial 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 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 finff ancial 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 forff companies operatiting on thth Oe OCSCS iwillll bbe iincreasedd. IIn any eve tnt i, iff an oilil didischharge or s bubstta tntiial tl thhr te to occur, we ma by be liabla e forff costs and damages, which costs and liabia lities could be material to our results of operations and finff ancial position. fof didischharge wer teat u National EnvE ironmentaltt Policy Ac ct — The National Environmental Policy Act, as amended (“NEPA”), requires fedff eral agencies, including the DOI, to consider the impacts their actions have on the human environment, and to prepare detailed statements forff majoa r 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 t the Environmental Impact Statements (“EIS”) in suppor quality of the environment. If the EA indicates that no significant impact is likely, then the agency can release a finff ding of no significant n with the proposed action. Otherwise, the agency must then conduct a full-scale EIS. In July 2020, the Council on impact and carry orr p’s Administration published a final rulrr e modifying the NEPA including, Environmental Quality (“CEQ”) under forff mer President Trumrr among other things, establishing a time limit of two years forff 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 was subju ect to litigation in several federal district courts, the CEQ, under the Biden Administration, announced in October 2021, that it intended to make three significant changes to the 2020 final rulr e, including authorizing agencies to consider direct, indirect and cumulative effects l projeo cts, allowing agencies to of majoa r fedff rding agencies greater determine the purpos flexibility in craftinff g their own NEPA procedurd es, consistent with CEQ regulations, so as to meet the agencies’ and public’s needs. e and need of a projeo ct, which allows consideration of less-harmful alternatives, and affoff eral actions including upstream and downstream GHG emissions impacts of fossil fueff t of its leasing and other activities that have the potential to significantly affecff r 25 a To that end, in April 2022, the CEQ issued a finff al rule in line with the proposed changes, a move considered as “Phase I” of the Biden Administration’s two-phased appr oach to modifying the NEPA. On July 28, 2023, the CEQ announced a “Phase 2” Notice of Proposed Rulemaking, the “Bipartisan Permitting Reforff m Implementation RulRR e,” which revises the implementing regulations of the procedurd al provisions of NEPA and implements the amendments to NEPA included in the June 3, 2023, Fiscal Responsibility Act of 2023. The public comment period for the proposed rule closed on September 29, 2023, and the final rulr e is expected in the second 023, the CEQ released guidance to assist federal agencies in assessing the GHG emissions quarter of 2024. Additionally, in January 2rr publication, encourages and climate change effeff cts of their proposed actions under NEPA. The CEQ’s interim guidance, effeff ctive upon agencies to consider, among other things, effecff ts from upsu tream and downstream GHG emissions of fossil fuel projects and, in many cases, use estimates of the social costs of GHG emissions when communicating those finff dings to the public. 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 projeo ct or requiring resource-specific mitigation. The adequacy of the eral court by process participants. This process may result in delaying the permitting agency’s NEPA process can be challenged in fedff and development of projeo cts, and result in increased costs. u ry 9, 2023, the FWS published a proposed rule that revised the requirements forff Endangered SpeSS cies Act — The Endangered Species Act, as amended (“ESA”), restricts activities that may affect federally identifieff d 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 brr irds is unlawful without a permit. The U.S. Fish and Wildlife Service (“FWS”) under forff mer President Trumrr p issued a finff al rule on January 7, 2021, which notably clarifieff s that criminal liabia lity 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 p Administration’s rulr e on incidental take and published an advanced notice of proposed rulemaking Administration revoked the Trumr to codify a general prohibition on incidental take while establa ishing a process to regulate or permit exceptions to such a prohibition. On Februar an incidental take permit application. A finff al rule is scheduled for release in the firff st quarter of 2024. 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 statutt es are known to exist. The FWS or the National Marine Fisheries Service (“NMFS”) may designate critical habia tat that it believes is necessary for survival of a threatened or endangered species. A critical habia tat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for oil and naturt al gas development. For example, in April 2019, the NMFS listed the Rice’s whale, determined to be a subspecies of the Bryde’s whale, as endangered under the ESA. On July 24, 2023, NMFS proposed to designate approximately 28,270.65 square miles of the Gulf of Mexico the Rice’s whale. NMFS is currently reviewing comments and is expected to issue a finff al critical habia tat designation as critical habia tat forff for the Rice’s whale in 2024. These statutes mayy result in opep rating rg estrictions or a temporp ary,y,rr ted areas. Consequently, the designation of new species or their critical habia tat forff protection under the ESA, MBTA, and MMPA could adversely affect our business and results of operations and increase our operating costs. seasonal or ppermanent ban in affecff s Substantt Hazardoudd ces and WasWW te Managea ment — The Resource Conservation and Recovery Act, as amended (“RCRA”RR ), generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes froff m the definition of hazardous waste “drilling fluff ids, 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 classifieff d as hazardous wastes in the futff urt e. Any futff urt e loss of the RCRA exclusion forff 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, labor astes and waste oils, may be regulated as hazardous waste. atory wrr a r omCC pem nsatiott n and Liabilityii Comprehensive Environmentaltt Response, Ce Act — The Comprehensive Environmental Response, Compensation and Liabia lity Act, as amended (“CERCLA”), and comparabla e state laws impose liabia lity, 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 subsu tance” into the environment. Such “responsible persons” may be subju ect to joint and several liabia lity under CERCLA forff he hazardous subsu tances 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 fileff nd property damage allegedly caused by the hazardous subsu tances released into the environment. claims for personal injury arr the costs of cleaning up tu 26 Air Eii miEE ssii ions — The Clean Air Act, as amended (“CAA”), and comparabla e state statutt es restrict the emission of air pollutants and affeff ct both onshore and offsff hore oil and naturt al gas operations. New facilities may be required to obtain separate construcrr tion and lities may be required to incur capia tal operating permits before construction work can begin or operations may start, and existing faci 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 rulr e under the CAA, making the National Ambient Air Quality Standard ground-level ozone more stringent. The EPA is currently reconsidering a prior decision to retain the 2015 ozone (“NAAQS”) forff standard. Any revision to the NAAQS and state implementation of the same could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures forff pollution control equipment, the costs of which could be significant. ff Worker Healthll and SafSS etff ytt — The Occupau tional Safetff y and Health Act, as amended (“OSHA”), and comparabla e state statutt es regulate the protection of the health and safetff y 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 safetff y aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties. a Climll ate Ctt haCC nge —The threat of climate change continues to attract considerable publu ic, governmental and scientific attention in the United States and in foreign countries. President Biden has made action on climate change a priority of his administration’s agenda and laws such as the IRA 2022 advance numerous climate-related objectives. Additionally, 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 futff urt e emissions. These effoff rts 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 eral level. However, the EPA has adopted regulations under comprehensive climate change legislation has been implemented at the fedff the existing CAA that, among other things, impose pre-construcr tion 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 reconstrucr ilities in the oil and naturt al gas sector. Compliance with these rulrr es or others could result in increased compliance costs on our operations. ted facff On December 2, 2023, the EPA published its final rulr e establishing more stringent methane rulr es for new, modified, and reconstrucrr ted facilities, known as Quad Ob, as well as standards forff existing sources for the first time ever, known as Quad Qc. Under the final rulr es, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rulr e are generally the same forff both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reducd e methane emissions, reducd tion of emissions by 95% through capture and control systems, zero-emission requiq rements forff certain devices, a, nd the establishment of a “supepu r emitter” respponse pprogrg am that would allow third pap rties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties forff violations of these rulr es can be substantial. It is likely, however, that the final rulr e and its requirements will be subject to legal challenges, equirements and the expected cost to comply with such so we are unabla e to predict at this time the scope of any finff al regulatory r requirements. Any increase in regulatory s cope and oversight may increase compliance expenditure or mitigation costs for our operations. rr rr At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement among ivff e years after participating nations to limit their GHG emissions through individually-determined emissions reduction goals every f 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. Subsu equent climate conferff ences have resulted in pledges by the United States and others to monitor, report and reduce methane emissions (including all feaff sible reducd tions for the energy sector) l subsidies. Most recently, at the 28th Conference of the and calls for accelerated effoff ls in energy systems in a just, orderly and Parties (“COP28”), participants signed onto an agreement to transition “away froff m fosff equitabla e manner” and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline forff doing so was set. The impacts of these orders, pledges and agreements, and any legislation or regulation promulgated to fulfilff l the United States’ commitments under the Paris Agreement and subsequent climate conferff ences or other international conventions cannot be predicted at this time and it is unclear what additional initiatives may be adopted or implemented that may have a negative impact on our financial condition. rts toward the phase out of ineffiff cient fosff sil fueff sil fueff rr 27 ff oil and gas faci Governmental, scientificff lities. For example, on January 26, 2024, President Biden announced a temporary prr and public concern over the threat of climate change arising froff m 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 forff more information. Other actions that could be pursued by the Biden Administration include more restrictive requirements forff the establishment ilities, as well as more stringent emissions of pipeline infraff structurt e or the permitting of liquified natural gas (“LNG”) export facff ause on pending standards forff decisions on new exports of LNG to countries that the United States does not have free trade agreements with, pending Department of Energy review of the underlying analyses for authorizations. The pause is intended to provide time to integrate certain considerations, urt ers and the latest assessment of the impact of GHG emissions, including potential energy cost increases for consumers and manufact ff 022 was signed into law in August 2022, and to ensure adequate safeguards against health risks are in place. Additionally, the IRA 2RR ls, electric vehicles and contains hundreds of billions of dollars in incentives forff suppor ther accelerate the u transition of the United States’ economy away froff m the use of fosff emissions alternatives. The IRARR 2022 also imposes the firff st ever federal feeff on the GHG emissions through a methane emissions charge. Litigation risks are also increasing, as a number of cities, local governments and other plaintiffsff have sought to bring suit against oil and natural gas companies in state or fedff ls that contributed ts, such as rising sea levels and therefore are responsible for roadway and infraff structurt e damages as a result, or to global warming effecff alleging that the companies have been aware of the adverse effect s of climate change for some time but defrauded their investors or ling to adequately disclose those impacts. We are not currently a defenff dant in any of these lawsuits but could be named customers by faiff in actions making similar allegations. An unfavff orable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. ting infraff structurt e, and carbon capture and sequestration, among other provisions. These incentives could furff eral court, alleging, among other things, that such companies created public nuisances by producing fueff the development of renewable energy, clean fueff ls toward lower- or zero-carbon sil fueff ff r a l energy related sectors. Institutional lenders who provide financing to fosff Additionally, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested the potential effects of climate change, may elect in the future to shiftff in fossil fuel energy companies such as ours, but concerned about some or all of their investments into non-fossil fueff sil-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 fosff l energy companies. Many emission commitments and have announced that they will be assessing financed r of the largest U.S. banks have made “net zero” carbon emissions across their portfolff nd reduce those emissions. At COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments froff m over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-u alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their finff ancing, investing, and/or underwriting activities to net zero emissions by 2050. These and other or divesting froff m certain industries or developments in the finff ancial sector could lead to some lenders restricting access to capital forff r reqquiringg that borrowers take additional stepsp to reduce their GHG emissions. comppanies,, includingg the oil and naturt al gag s sector, o, Additionally, there is the possibility that financial institutions will be required to adopt policies that limit fundi ng to fossil fuel energy companies. ios and taking steps to quantify aff sil fueff ff In late 2020, the Federal Reserve announced that it had joined the Network forff Greening the Financial System (“NGFS”), a consortium of finff ancial regulators focff used on addressing climate-related risks in the financial sector, and, in September 2022, announced that six of the U.S. largest banks will participate in a pilot climate scenario analysis exercise to enhance the ability of firff ms and supeu rvisors to measure and manage climate-related finff ancial risk. The Federal Reserve released its pilot exercise in January 2023 which ios. is designed to analyze the impact of both physical and transition risks related to climate change on specificff In October 2023, the Federal Reserve, Offiff ce of the Comptroller of the Currency and the Federal Deposit Insurance Corpor ration (the “FDIC”) released a finff alized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change. While we cannot predict what additional developments may arise from ould make it more diffiff cult to secure these various activities, a material reducd tion in the capital availabla e to the fossil fueff funding for exploration, development, production, transportation, and processing activities, which could impact our business and operations. Separately, the SEC released a proposed rule in March 2022 that would establish a framework for the reporting of climate risks, targets and metrics. A finff al rule is anticipated to be released in the second quarter of 2024. The SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential forff enforcement if the SEC were to allege that an issuer’s existing climate disclosures are misleading, deceptive or deficient. Such agency action could also increase the potential for private litigation. Relatedly, California has enacted new laws requiring additional disclosure with respect to certain climate- related risks and GHG emission reduction claims. Non-compliance with these new laws may result in the imposition of substantial finff es or penalties. Other states are considering similar laws. Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs resulting froff m the development of any disclosures, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations or requirements of financial institutt assets of the banks’ portfolff l industry crr ions. 28 Finally, some scientists have concluded that increasing concentrations of GHG emissions in the Earth’s atmosphere may producd e 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 forff energy or the products we produce. While our consideration of changing weather conditions and inclusion of safety factors in design is intended to reducd e 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 everyrr eventuality. s Orr iott n in Sii haSS llow WatWW ertt Enviroi nmental Regulatll ffO the CoaCC st of Mexiee co — Our oil and gas operations in shallow waters off the coast sco state are subject to regulation by the ASEA. We must obtain ASEA-issued permits and comply with ASEA of Mexico’s Tabaa environmental impact and risk assessments, industrial safetff y, regulations governing hydrocarbonr activities, including requirements forff waste management, water and air emissions, operational security and faci icable laws lity decommissioning. Failure to comply with appl and regulations can result in the imposition of monetary penalties, revocation of permits, suspension of operations and ordered decommissioning of offsff hore facff ilities and systems. The laws and regulations governing the protection of health, safetff y and the environment froff m activities in the Mexican energy sector are relatively new, having been significantly reformed following the establa ishment of ASEA in 2014 as a result of fedff raff mework odies issue new regulations and guidance. Such regulations are subject to continues to evolve as ASEA and other Mexican regulatory brr odies may impose new or revised requirements that could increase change, and it is possible that ASEA or other Mexican regulatory brr our environmental compliance-related operating costs and/or capital expenditures forff eral constitutional amendments approved in 2013, and the legal regulatory f operations in Mexican offshore shallow waters. a rr ff r For example, in May 2020, the ASEA published the Industrial Safetff y, Operational Safetff y and Environmental Protection Sector Facilities (the “Dismantling Guidelines”). The Guidelines for the Closing, Dismantling and Abandonment of Hydrocarbons sector facilities that perform dismantling, abandonment and closing of Dismantling Guidelines are mandatory for all hydrocarbon hydrocarbon sector activities. The Dismantling Guidelines set out several obligations in terms of safetff y, reporting and risk, including establa ishing a closing, dismantling and/odd r abaa ndonment activities program for each of the relevant phases. Additionally, durd ing 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, forff spills and pollution events. We anticipate that ASEA will conduct investigations to subsu tantiate the incidents identified in the new reporting system. example, hydrocarbon r r r Under the Block 7 PSC, we are jointly and severally liabla e forff the performance of all obligations under the PSC, including exploration, appraisal, extraction and abandonment activities and compliance with all environmental regulations, and failure to perform such obliggations could result in contractuat l rescission of the PSC. alSS esll iott n of So and TraTT nspor Federal Regulatll s tation of Natural GasGG — Our sales of naturt al gas are affeff cted directly or indirectly by the availability, terms and cost of naturt al gas transportation. The prices and terms forff access to pipeline transportation of naturt al gas are eral and state regulation. The transportation and sale for resale of naturt al gas in interstate commerce is regulated subju ect to extensive fedff primarily under the Natural Gas Act of 1938 (“NGA”) and the Naturt al Gas Policy Act of 1978 (“NGPA”) and by regulations and orders promulgated under the NGA and/or NGPA by the Federal Energy Regulatory Crr ommission (“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 are subject to States Congress and by FERC regulations. However, certain offsff hore gathering and transportation services we rely uponu 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 establa ishing violation enforff cement mechanisms that make it unlawfulff for any entity, directly or indirectly, in connection with the purchase or sale of naturt al gas or the purchase or sale of transportation services subju ect 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 facff t 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 fraff ud or deceit upon any entity. The EPAct violations of these statutes and 2005 also amended the NGA and the NGPA to give FERC authority to impose civil penalties forff regulations, up tu tion). FERC may also order disgorgement of profitff s and corrective action. The anti-market manipulation rulr e does not apply to activities that relate only to intrastate or other non-ju- y to activities of naturt al gas pipelines and storage companies that provide risdictional entities to the extent the activities are conducted “in connection with” naturt al interstate services, as well as otherwise non-ju- gas sales, purchases or transportation subject to FERC jurisdiction, which includes annual reporting requirements forff entities that purchase or sell a certain volume of naturt al 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 affeff ct us in a way that materially differs from the way they affect other naturt al gas producers, gatherers and marketers with which we compete. o $1,544,521 per violation, per day for 2024 (this amount is adjud sted annually for inflaff risdictional sales or gathering, but does appl a 29 Our sales of oil and natural gas are also subject to market manipulation and anti-disrupt ive requirements under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Wall Street Reforff m 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 futff urt es 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 affeff ct or tend to affeff ct the price of a commodity. r rr nd regulatory f The current statutt ory arr raff mework governing interstate naturt al gas transactions is subju ect to change in the futff urt e, and the naturt e of such changes is impossible to predict. We cannot predict whether new legislation to regulate naturt al gas might be proposed, icable federal agencies, or the various state what proposals, if any, might actually be enacted by the United States Congress, the appl legislaturt es, and what effeff ct, if any, the proposals might have on our operations. The natural gas industry hrr istorically has been very heavily regulated. In the past, the federal government regulated the prices at which naturt al 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 naturt al gas sold in “firff st 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 futff urt e. Changes in law and to FERC policies and regulations may adversely affeff ct the availabia lity and reliabia lity of firm and/or interruptu ible transportation our operations, and we cannot predict what service on interstate pipelines or impose additional reporting or other requirements upon a future action FERC will take. Therefore, there is no assurance that the current regulatory arr oach recently pursued by FERC and the ppr United States Congress will continue. We do not believe, however, that any regulatory crr hanges will affeff ct us in a way that materially differs from the way they will affeff ct other naturt al gas producers, gatherers and marketers with which we compete. u a s iott n of So and TraTT nspor Federal Regulatll tation of Co alSS esll ruCC de Oilii — FERC regulates the interstate pipeline of crude oil, petroleum products and other liquids, such as NGLs. Our sales of crudr e 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 futff urt e. We cannot predict whether new legislation to regulate crude oil, or the prices charged forff oil might be lly be enacted by the United States Congress or the various state legislatures and what proposed, what proposals, if any, might actuat effeff ct, if any, the proposals might have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements. r crude rr Our abia lity to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subju ect to FERC jurisdiction under the Interstate Commerce Act (“ICA”), and intrastate oil pipeline transportation rates are subject to regulation by state regulatory crr ommissions. 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 forff versight and scrutrr intrastate oil pipeline regulation, and the degree of regulatory orr iny given to intrastate oil pipeline rates, varies froff m hanges will affect us in a way that materially differs from the way they state to state. We do not believe, however, that any regulatory crr will affeff ct other crude oil and condensate pproducers with which we compep te. 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 . th in the pipelines’ published tariffsff oil pipelines operate at full capacity, access is governed by prorationing provisions set forff Accordingly, we believe that access to oil pipeline transportation services generally will be availabla e to us to the same extent as to other r crude oil and condensate producers with which we compete. We own an undivided interest in a pipeline that extends from South Pass Block 89 in federal waters, offsff hore Louisiana, to the West Delta Receiving Station in Venice, Louisiana. Although the pipeline is subject to FERC jurisdiction under the ICA, FERC has granted us a temporary wrr which the waiver was granted change materially, we are required to inforff m FERC, which may result in revocation of the waiver. If conditions change such that the pipeline no longer a waiver, we may be subject to regulation by FERC of the rates, terms and conditions of service on the pipeline; however, qualifieff s forff ith these burdens generally would not affeff ct us any diffeff similar pipelines. rently or to any greater or lesser extent than they affeff ct others in our industry wrr aiver of the filing and reporting requirements. If the fact u s upon ff FERC also implements the OCSLA pertaining to transportation and pipeline issues, which requires that all pipelines operating on ransportation service. We own and operate pipelines that are located in the OCS and are rr or across the OCS provide nondiscriminatory t subju ect to the non-discrimination requirements in the OCSLA. Human Capital We have experienced significant growth in our workforce since our formation as a private equity backed start-up company with oximately 600 employees as of December 31, 2023. oach to human capital management has adapta ed as we have matured as a company and continues to evolve as we grow our ts our business strategy, underscores our entrepreneurial spirit and six (6) original employees in 2012 to a NYSE publicly listed company with appr Our appr a business. We strive to manage our employees in a way that suppor promotes employee development. u a 30 Policies — Our Code of Business Conduct and Ethics addresses our commitment to providing equal opportunities in employment without regard to race, color, gender identity or expression, religion, age, national origin, citizenship statust , military service or reserve or veteran status, sexual orientation, or disabia lity. We make employment and compensation decisions based on a person’s abia lity to perform the tasks required by their position. Our Human Rights Policy embodies key tenets which we expect all individuals involved in our operations to follow, such as respect for human rights; freedom of association and collective bargaining; freedom of religion, opinion, and assembly; maintaining a ; right to a living wage; and safe and healthy workplace; the prohibition of forff ced labor; prevention of human traffiff cking and child labor open communication to report violations to the appr opriate individuals. a a Each of our Code of Business Conduct and Ethics and Human Rights Policy is overseen at the highest level by our Board of Directors (our “Board” or “Board of Directors”). Please referff to https://www.talosenergy.com/investor-relations/Corpor ate-Governance-New on our website for additional information regarding our corporate policies. The policies referff enced herein, and the information contained on or accessible through our website, are not incorporated by reference herein or otherwise made a part of this Annual Report or any of our other filinff gs with the SEC. rr Oversirr ghi t and Managea ment — The Company's executive leadership team, with oversight from various committees of the Board, tion which administers sets the Company's human capital management philosophy and goals with the support of the human resources func the Company's workforff ce programs. ff The Compensation Committee of our Board (the “Compensation Committee”) provides oversight, subject to Board approval, of the Company’s executive compensation program, the annual incentive plan (“AIP”), the long-term incentive plan, and the overall budget for non-executive compensation. In addition, the Compensation Committee evaluates material risks related to the Company’s compensation policies and practices. The Compensation Committee also periodically assesses the Company’s compensation programs related to all employees. The Nominating & Governance Committee of our Board (the “NGC”) reviews succession planning for the Chief Executive Officff er position, monitors and reviews the development and progression of potential successors and consults with the Chief Executive Offiff cer on senior management succession planning. The NGC reviews with management the Company’s executive succession risks. The Safetff y, Sustainabia lity and Corpor ate Responsibility Committee of our Board (the “SSCR Committee”) reviews the Company’s strategies, policies and procedurd es related to material safetff y matters, and reviews the Company’s major operational risks, environmental, health and safetff y risks, climate change and other sustainabia lity risks, social and human capia tal risks, including the welfare of employees in the workplkk ace, and the Company’s safetff y statistics, such as the Total Recordable Incident Rate and Significant Injuryrr or Fatality Rate. r r at AAt hthe corpor le lev lel, thhe ViVice PPresidident of Hf Human RResources, toge hther iwi hth our execu itiv le l deader hshiip team i, is responsibiblle ffor our workforce management policies and programs, reporting directly to our President and Chief Executive Officer (“CEO”), and providing regular updates to the Compensation, NCG, and SSCR Committees on human capital matters. Our President and CEO and other executive officers are accessible to all employees through town hall meetings where our President and CEO discusses corpor ate matters and other topics pertinent to employees, answers questions and receives employee feedff bad ck. r Workfok rce ComCC posm ition — As of December 31, 2023, we employed appr a oximately 600 employees located primarily in Texas, roximately 320 (53%) of which are employed in our offsff hore operations and seven (7) of which are Mexican ement our workforce with independent contractors and consultants to perform various offsff hore and u Louisiana and Mexico, appa nationals. In addition, we suppl corporate services. None of our employees are represented by labor a unions or covered by any collective bargaining agreement. Safea ty — “Embody Integrity and Safetff y” is a core value and our number one priority in the operation of our business. Our focff us on safety starts at the top with our Board of Directors, our President and CEO, our Executive Vice President and Head of Operations, who is directly responsible for all safety initiatives, and our Vice President of HSE, Regulatory arr nd Compliance, who is dedicated exclusively to health, safetff y, and environmental matters. Workforff ce safety is also a key focus within our enterprise risk management assessment. Our Safetff y and Environmental Management System includes a stringent “Stop Work Authority” which empowers all employees and any safetff y or environmental concern without fear of retaliation or intimidation. In addition, contractors to stop work immediately forff our behavior-based safety program and our “Keystones to Saving Lives” program are core components forff effeff ctive pre-work planning and maintaining a safetff y-focused culture. We seek to reinforff ce our safety-first mindset by linking employees’ compensation to safetff y performance through our annual bonus plan. Offshore employees are eligible to receive an additional quarterly safety bonus based on safety results at our offsff hore faci information regarding lities. Please referff our safety governance, programs and performance. to our 2023 Sustainabia lity Report posted on our website forff ff 31 Recruitmii ent, Developmll ent and Leadership Tii oach to recruirr ting top talent, utilizing online recruiting raTT ining — We take a broad appr platforms, referrals, universities and colleges, internships and professional recruir ters to access a skilled candidate pool. We encourage employee development through an interactive performance management process to provide feedbad ck and growth opportunities that t Talos’s strategic business goals. In 2022, we launched the Leadership enable employees to advance their careers and suppor tering dynamic and engaged leaders. In 2023, approximately 200 Development Program availabla e to all employees with the goal of fosff employees participated in this leadership training. We also reimburse for outside training and tuit approved higher education in tion forff further support of developing our employees. u a Compensation and Benefie tsii — Our success is based on our financial performance and operational results, and we believe that our compensation program is an important driver of these goals. Our program is designed to tie compensation to corporate and individual performance and align the interests of our employees with those of our stockholders. All full-time employees are eligible forff our AIP focused on attaining finff ancial, operational and strategic goals. We also utilize long-term incentive awards to motivate and retain key to the section entitled “Compensation Discussion and Analysis” in our Definitive Proxy Statement on Form DEF talent. Please referff ther compensation information on our executive compensation program and philosophy. 14A filed with the SEC on April 5, 2023, for furff We also seek to attract and retain employees by offeff ring a broad array of health and welfare benefit programs designed to meet r matching contributions to 401(k) accounts, a company health savings account the needs of a varied workforff ce. In addition, we offeff nd leave of contribution, subsu idized counseling, legal and financial support, a subsidy forff absence, and a work-from-home program. We also began offeff t employees and their families’ mental well-being. In 2024, we expect to open an employee health clinic in our corporate offices to provide easy access for basic health needs. ring a mental health plan in 2023 to suppor ess memberships, paid time off aff health & fitnff u Social Investment — We support our employees and the communities where we live and work through active corpor rts. Our employee-led community committee supports outreach programs, fundraising effoff ate philanthropic r effoff rts, and community involvement events to benefit charitabla e organizations. In addition, we (i) provide an annual allowance to every employee that can be donated to a charitable corporate contributions to charitabla e organization of their choice, (ii) match funds organizations and (iv) provide a paid volunteer day off fff orff raised by community committee events, (iii) budget forff each employee each year. ff Available Inforff mation We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, all amendments to through our website, r those reports and other information are electronically filed with or those reports, and all other information filff ed with or furnished to the SEC available, freff e of charge, https://www.talosenergy.com, as soon as reasonabla y practicable afteff furnished to the SEC. The filinff gs are also available by accessing the SEC’s website at https://www.sec.gov. We voluntarily publish annual sustainability reports which are availabla e freff e of charge on our corporate website at: https://www.talosenergy.com/sustainability/. Information included in these sustainabia lity reports is not incorporated into this Annual Report o ir in any othher report o dr document w fe fililefff iwi hth hth Se S CEC. 32 Item 1A. Risk Factors Certain fact ors may have a material adverse effecff t on our business, financial condition, and results of operations. You should ff ly the risks and uncertainties described below, in addition to other information contained in this Annual Report, including consider carefulff our Consolidated Financial Statements and related notes. The risks and uncertainties described below are not the only ones we face . r that we currently believe are not material, may also become important Additional risks and uncertainties that we are unaware of, off factors that adversely affect lly occur, our business, financial condition, results of operations and futff urt e 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. our business. If any of the following risks actuat ff ff Risks Related to our Business and the Oil and Natural Gas Industry Oil aii nd natural gas prices are volatll and resultsll of operations, cash flowll abiliii tyii to grow.ww iltt e.ll Stagntt s, access to t tt hett atiott n or decldd capia taii l markerr inll es in commodityii ts and availabl ll e bll prices may aa s ugg orrowingii dverserr nderdd ly affeff ct our finff ancial conditidd on and our our Bank CreCC dit Fii acFF ilityll capia tal expenditures and our ability to access funds Our revenues, cash floff ws, profitabia lity and futff urt e rate of growth substantially depend upon the market prices of oil and naturt al under our Bank Credit Facility and gas. Prices affeff ct our cash floff ws availabla e forff through the capital markets. The amount availabla e forff borrowing under our Bank Credit Facility is subju ect to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves and is subju ect to periodic redeterminations based on pricing models to be determined by the lenders at such time. Further, because we use the fulff our oil and gas operations, we perform a ceiling test each quarter, and 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 subsu tantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated futff urt e development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other facff tors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the futff urt e, and incur additional charges against futff urt e earnings. Any required write-downs or impairments could materially affeff ct the quantities and present value of our reserves, which could adversely affect our business, results of operations and finff ancial condition. l cost method of accounting forff ff ff In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can l in our l. Any of these factors economically producd e. A reducd tion in production and/or the prices we receive for our production could result in a shortfalff expected cash flows and require us to reduce our capital spending or borrow funds could negatively impact our ability to replace our production and our future rate of growth. to cover any such shortfalff ff The markets for oil and naturt al gas have been volatile historically and are likely to remain volatile in the future. For example, during the period January 1, 2021 through December 31, 2023, the daily NYMEX WTI crude oil price per Bbl ranged froff m a low of aturt al gas price per MMBtu ranged froff m a low of $1.74 to a high of $47.47 to a high of $123.64, and the daily NYMEX Henry Hub nu $23 86 lal gas p irices reco drded dd d iailly llows fof ioill a dnd NYNYMEMEX HX Henry HHubb nu $23.86. SSubbsu eque tnt tto DDecembbe 3r 311, 2023 $70.62 per Bbl and $1.61 per MMBtu, respectively. 2023, NYNYMEMEX WX WTITI cr dude taturt r The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others: • • • • • • • • • • • changes in domestic and global supply of and demand for oil and naturt al gas; market uncertainty; level of consumer product demands; the cost of exploring forff , developing and producing oil and naturt al gas; changes in climate, weather and naturt al disasters such as 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 forff eign governmental actions, regulations and taxes; price and availabia lity of alternative fueff ls and competing forms of energy; political and economic conditions in oil and natural gas producing regions, particularly in the Middle East, Russia, South America and Afriff ca; armed conflicff East; ts and hostilities such as RusRR sia’s ongoing war in Ukraine and increasing hostilities in Israel and the Middle the occurrence or threat of epidemic or pandemic diseases and other public health events; 33 • • • • • • • • • • • actions by OPEC Plus and other significant producers and governments relating to oil and naturt al gas price and production controls; volatility in the political, legal and regulatory err nvironments ahead of the upcu oming U.S. and Mexico presidential elections; U.S. and forff eign suppl u y of oil and naturt al gas; price and quantity of oil and natural gas imports and exports; the level of global oil and naturt al gas exploration and production and inventories; localized suppl u y and demand fundamentals and transportation availabia lity; infrastructurt e availabia lity and constraints such as capacity of processing, gathering, storage and transportation faci ff lities; speculation as to the futff urt e price of oil and the speculative trading of oil and naturt al gas futff urt es contracts; price and availabia lity of competitors’ supplies of oil and naturt al gas; technological advances affecting energy consumption; and overall economic conditions worldwide. These facff tors make it very difficult to predict futff urt e commodity price movements with any certainty. Substantially all of our oil and naturt al 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 appa roximately 73%, 20%, and 7%, respectively, of our estimated proved reserves as of December 31, 2023, and appr oximately 75%, 18%, and 7%, respectively, of our 2023 production on an MBoe basis, our financial results are sensitive to a movements in oil, natural gas and NGL prices. Future explxx orll atiott n and drillingii results att re uncertain and invii olvell substantiatt l costs. Drilling forff oil and natural gas involves numerous risks including the risk that we may not encounter commercially productive reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including: • • • • • • • • unexpected drilling conditions; pressure or irregularities in forff mations; equipment faiff lures or accidents; inflation in exploration and drilling costs; fires, explosions, blowouts or surface cratering; lack of, off r disruptu ion in, access to infrastructurt e and transportation; lack of availabla e skilled labor; and shortages or delays in the availabia lity of services or delivery orr f equipment. Our productiott n, revenue and cash flowll ll o rtt geographic regie on, makingii us vulnerable t from operatingii isks associatedtt withii activitiett s are derived from assets that are concentratt ne geographic area. operating in oii ted in aii singii legg We currently operate in a concentrated geographic region, in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. As such, the success and profitabia lity of our operations may be disproportionately exposed to the effect of regional conditions such as: • • • • severe weather, such as hurricanes, winter storms, loop currents, tornadoes and other adverse climatic conditions; changes in state or regional laws and regulations affeff cting our operations (including regulations that may, in certain circumstances, impose strict liabia lity forff pollution damage or require posting substantial bonds to address decommissioning and P&A costs) and interruptu ion or termination of operations by governmental authorities based on environmental, safetff y or other considerations; local price fluff ctuat transportation and storage capaa city constraints; tions and other regional supply and demand factors, including availabia lity of gathering, pipeline, production delays or decreases in the region; 34 • • • • • limited potential customers; infrastructurt e capacity and availability of rigs, equipment, oil fieff ld services, supplies and labor a ; changes in the statust of pipelines that we depend on forff transportation of our production to the marketplace; changes in guidelines issued by BOEM related to finff ancial 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 offsff hore oil and naturt al gas exploration and production activities, including with respect to leasing, permitting, site development or operation in fedff eral waters or hydraulic fracturt ing. 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. Productiott n periods or relatively sll hort reserve livll es for U.SUU . GSS f Mo to reduce productiott n during periods of low oil and natural gas prices. exMM ico propeo rtiett s may subject us to highi ulf oll needs add nd may ia mpii air oii ur abiliii tyii er reserve replacement Subsu tantially all of our operations are in the U.S. Gulf of Mexico. As a result, our reserve replacement needs fromff may be greater than those of other companies with longer-life rff is highly dependent upon finding and/or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices. new prospects eserves in other producing areas. Our future oil and natural gas production Exploring forff , 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 capia tal investments if our cash floff ws from operations decline or external ongoing capital commitments and/or repay debt sources of capia tal become limited or unavailabla e. Our need to generate revenues to fund may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and naturat l 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 acceptabla e costs. Further, current market conditions may adversely impact our ability to obtain finff ancing to fund acquisitions, and further lower the level of activity and depressed values in the oil and natural gas property sales market. ff Our actual recovery or f ro eserves may substantiatt lly dll ifdd feff r froff m our proved reserve estima tt tes. Reserve estimation is a subju ective and complex process that requires significant decisions and assumptions in the evaluation of availabla e geological, geophysical, engineering and economic data to estimate volumes to be recovered froff m underground accumulations of oil and natural ggas that cannot be directlyy measured. These estimates of our prp oved oil and naturt al gag s reserves and the estimated future net cash floff ws from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and naturt al gas prices, drilling and operating expenses, capital expenditures, taxes and availabia lity of funds. Our interpretations of the uthorities resulting rules governing the estimation of proved reserves could diffeff in estimates that could be challenged by these authorities. r froff m the interpretation of staff members of regulatory arr u Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverabla e oil and naturt al gas reserves will most likely vary f roff m those estimated. Any significant variance in these fact rr ors could drainage materially affeff ct the estimated quantities and present value of reserves. Our properties may also be susceptible to hydrocarbon from production by other operators on adjad cent properties. In addition, we may adjust estimates of proved reserves to refleff ct production results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our history,rr control. See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for furff ther discussion on 2023 changes in estimates of our proved reserves. ff r You should not assume that any present value of futff urt e net cash floff ws from our proved reserves represents the market value of our estimated oil and naturt al gas reserves. We base the estimated discounted future net cash floff ws from our proved reserves at December 31, 2023 on historical 12-month average prices and costs as of the date of the estimate. Actuat l futff urt e prices and costs may be materially higher or lower. Further, actuat l futff urt e net revenues are affeff cted by factors such as: • • • • • 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; u suppl y of and demand for oil and naturt al gas; 35 • • actuat l prices we receive forff oil and natural gas; and our actuat l operating costs in producd ing oil and naturt al gas. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties affect l present value. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash floff ws may not necessarily be the most appropriate discount factor based on our cost of capia tal in effect from time to time and the risks associated with our business and the oil and naturt al gas industry i l futff urt e net cash floff ws from reserves, and thus their actuat s the timing of actuat n general. rr ff At December 31, 2023, approximately 14% of our estimated proved reserves (by volume) were undeveloped and approximately 23% 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 drilling or waterflood operations. Our reserve undeveloped reserves generally requires significant capital expenditures and successfulff estimates include the assumptions that we incur capital expenditures to develop these undeveloped reserves and the actuat l costs and results associated with these properties may not be as estimated. Any material inaccuracies in these reserve estimates or underlying assumptions materially affeff cts the quantities and present value of our reserves, which could adversely affect our business, results of operations and finff ancial condition. Our acreagea must be drillell d beforff an extendeddd expixx ryii essed forff esult ill n t ii hett depree could rll period of timeii e leall se expixx raii ightgg , ie t mii of a portion of oo ur acreage, we tions in order to htt ll old t not be economical forff hich could hll hett us to drill sll uffiff cient wellsll acreage by productiott n. If commodityii old all in order to htt prices become hich creagea , we ave an adverserr effeff ct on our business. Our leases may expire unless production is established as required by leases covering undeveloped acres. Our drilling plans for areas not held by production are subju ect to change based upon various factors. As of December 31, 2023, approximately 53% of our net further discussion. Many of these acreage was undeveloped acres. See Part I, Items 1 and 2. Business and Properties—Ac— reage forff factors are beyond our control, including drilling results, oil and naturt al 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. u The markerr s, pipeii tabiliii tyii of our productiott n depdd ends mostlytt upon the availabilityii lines and processing facff ilitiell s. systemtt , pyy ii roxioo mity and capacity of oil aii nd natural gas gathett ringii The marketabia lity of our production depends upon the availabia lity, proximity, operation and capacity of oil and natural gas ilities. The lack of availabia lity or capacity of this infrastructurt e could result in the shut- gathering systems, pipelines and processing facff oducining wg welellsls oror dedelalaysys oror didiscscontontininuauancnce oe of df devevelelopmopmenent pt plalansns fofor or ourur prpropeopertrtieiess. ThThe de disisruruptptuu ioion on of tf thehesese gagaththererining sg sysystetemsms, inin ofof prproduc pipelines and processing facilities dued to maintenance and/or weather could negatively impact our ability to market and deliver our products. Federal, state, and local regulation of oil and naturt al gas production and transportation, general economic conditions and tors change changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market facff dramatically, the financial impact could be substantial. The availabia lity of markets and the volatility of product prices are beyond our control and represent a significant risk. Infln atll iott nary issues and associatedtt changes in mii onetartt y pr olicll y mc ay result in increases to t hett tt cost of our goods, ss ervices and personnel, which in t ii urn could cause our capia taii ee l expe .ee nditdd ures and opeo rating costs to riseii The U.S. inflaff tion rate steadily rose in 2021 and into 2022 before eventually declining throughout 2023. These inflaff tionary pressures resulted in increases to the costs of our goods, services and personnel, which in turt n, caused our capital expenditures and operating costs to rise. The U.S. Federal Reserve (the “Fed”) and other central banks increased interest rates multiple times in 2022 and 2023 in an effoff rt to curb inflationary pressure on the costs of goods and services across the U.S. and globally. While the Fed indicated in December 2023 that it may reducd e benchmark interest rates in 2024, the continuation of elevated rates could have the effeff cts of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—c ould hurt the financial and operating results of our business. ff Higher crude oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflaff tion or the monetary policies in response thereto. We may ba ursurr effeff ct on our business, results ott e unable t o ptt e our CCS busineii f oo ll peo rations and finaii ncial conditioii n. ss, eithii er whollyll or in signi ificff ant measure, we hich could hll ave a material adverserr The successfulff lure to satisfy, wholly or in significant measure, any of such fact development of our CCS projects is dependent on various economic, regulatory,rr operational and technical facff tors. ors could have a material adverse impact on our business, results ff The faiff of operations and finff ancial condition. 36 Risks related to our CCS business include but are not limited to: • • • • • • • • • • • the uncertainty of evolving government regulations; adequate capital finff ancing to develop our projects; the availabia lity of necessary infrastructurt e, equipment, services and skilled personnel to develop our CCS business; sufficient infraff structurt e to capture CO2 at the source, and transport it to CCS sites; the availabia lity, appl a icability and adequacy of various federal and state incentive programs related to CCS projects; the availabia lity and cost of acquiring necessary federal and state permits, including permits applicable to subsu urface the injen ction, and air emissions or impacts to environmental, natural, historic or cultural resources resulting fromff construcrr tion and operation of a CCS facff ility; our ability to maintain adequate financial assurances to cover the cost of corrective action, injen ction well plugging, post injen ction site care and site closure, and emergency and remedial response; public and political opinion regarding CCS development in local communities; locating suitabla e sources of anthropogenic CO2; obtaining sufficient quantities of CO2 from, and entering into suitabla e agreements with, emitters on terms that are acceptabla e and economical to us; and complex recordkeeping and GHG emissions/sequestration accounting which may increase our costs. The availabia lity and appl icability of various federal finff ancial incentives related to our projects is uncertain and there is no assurance that if availabla e, such incentives would be adequate for our CCS projeo ct needs or that such incentives will continue to be availabla e in the futff urt e. a rr Additionally, successfulff development of CCS projects in the United States requires us to comply with stringent and varied chemes requiring permits applicable to subsu urface injen ction of CO2 for geologic sequestration. Moreover, as operator forff regulatory s two of our CCS projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injen ction well plugging, post injection site care and site closure, and emergency and remedial response. As carbon management represents an emerging sector, regulations may evolve rapidly and unpredictabla y, which could impact the feaff sibility of one or more of our anticipated projeo cts. There is no assurance that we will be successfulff eral and state permits or adequate levels of financial assurance for one or more of our CCS projeo cts or that permits can be obtained on a timely basis, whether due to difficulty wy pp ition or otherwise. Sepparately,y CCS prp ojjects rovals unrelated to subsu urface injen ction froff m various U.S. federal and state agencies, such are also subject to additional permits and appa as for air emissions or impacts to environmental, natural, historic or cultural resources resulting froff m the construcrr tion and operation of equirements are imposed, are increased or more stringently enforced, we may incur additional a CCS facility. To the extent regulatory r costs in the development of our CCS projects, which costs may be material or may render any one or more of our projects uneconomic. ith the technical demonstrations requiq red to obtain such ppermits, ppublic oppos in obtaining sufficient fedff rr r CCS projects also require satisfyiff ng certain operational facff tors, such as locating a suitabla e source of anthropogenic CO2 and reaching suitabla e agreements to capta urt e that CO2. Such agreements are complex and may involve allocation of not only feeff s but also various credits, incentives and environmental attributes associated with the sequestration 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 usabla e in one or more of our CCS projects. As a result, we may not be able to obtain suffiff cient quantities of CO2 from emitters on terms that are acceptable to us, and the faiff lure to do so may have a material impact on our ability to execute our CCS strategy. Additionally, development of successful CCS projects will require infrastructurt e 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. Inabia lity to reach a suitabla e agreement may render a project uneconomic or impracticable. 37 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 eral and state agencies, as well various environmental and other permitting requirements to include increased regulation froff m U.S. fedff 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. Diffeff rent ccounts regarding GHG emissions/sequestration at one or nd non-regulatory arr methodologies may be required forff 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 fueff ls, notwithstanding that CO2 emissions are intended to be capta urt ed, there may be organized opposition to CCS, including as it relates to our projects. various regulatory arr We can provide no assurance that we will be able to execute 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. Our inaii may aa dverserr bilityii to benefie t fii ly impact our busineii roff m SecSS tion 45Q tax caa ss, results ott f oo peo rations and finff ancial conditiodd n. reditsii could mll atertt ially rll educe our abiliii tyii to developll CCS projects att nd, add s a result, r a The successfulff development of our CCS projects is dependent upon our ability to benefit froff m certain financial and tax incentives availabla e with respect to CCS projects. The development of CCS projects is incentivized by tax credits provided under Section 45Q of the Internal Revenue Code of 1986, as amended (such credits, “Section 45Q tax credits”), which provides a tax credit forff qualifieff d CO2 capta urt e equipment and disposed of in secure geological storage. The amount of Section 45Q tax credits that is capta urt ed using carbon from which we may benefitff enticeship requirements, which we cannot is dependent upon our ability to satisfy certain wage and appr assure you that we will satisfy. With respect to the firff st five tax years a qualifyiff ng CCS project is in service, but not beyond December 31, 2032, we may elect a “direct pay” option with respect to availabla e Section 45Q tax credits to effiff ciently monetize their value (i.e., we may receive a payment for the tax credits through a tax refund as if there had been an overpayment of taxes). Following the period in which the direct pay election is availabla e and for the remaining period in which the appl icable Section 45Q tax credits are otherwise availabla e, we may elect to transferff the Section 45Q tax credits to unrelated taxpayers. We cannot assure you that we will be able to effiff ciently monetize Section 45Q tax credits that are transferred to unrelated taxpayers. We will benefit froff m Section 45Q tax credits obtaining the Section 45Q tax credits, including that we own only if we satisfy the appl carbon lly capta urt e and securely store, or if another party r that owns carbon capture equipment elects to pass through Section 45Q tax credits to us, that we dispose of the qualifieff d CO2 in secure storage. If we are unabla e to satisfy such statutt ory arr or obtain the Section 45Q tax credits, our CCS projects may no longer be economically viable and may not be completed. We cannot assure you that we will be in satisfying such requirements or otherwise qualifyiff ng for or obtaining the Section 45Q tax credits currently availabla e or that successfulff we will be able to effeff ctively by enefitff from such tax credits. Section 45QQ tax credits are also subjject to recappture with resppect to anyy CO22 that ceases to be disposed of in secure storage, which recapta urt e is treated as an increase in tax liabia lity 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. capture equipment that captures qualified CO2 that we physically or contractuat equirements or otherwise qualify f icable statutt ory arr equirements forff nd regulatory r nd regulatory r orff a a rr ff rr Additionally, the availabia lity of Section 45Q tax credits may be reducd ed, modified or eliminated as a matter of legislative or regulatory prr olicy. There can be no assurance that Section 45Q tax credits will not be reduced, modified or eliminated in the futff urt e, including as a result of any change in presidential administration as a result of the 2024 U.S. presidential election. Any such reducd tion, from Section 45Q tax credits, could materially modification or elimination of Section 45Q tax credits, or our inability to otherwise benefitff reduce our ability to develop CCS projects and, as a result, may adversely impact our business, results of operations and finff ancial condition. Even if we are abla e to benefitff from Section 45Q tax credits, we may determine that additional finff ancial incentives are required for our CCS projects to be economically viable. If such additional incentives do not emerge, we may not be able to achieve an economic tion or operation of our CCS projects may be subsu tantially delayed, return from our CCS business or, alternatively, the construcr unprofitaff bla e or otherwise infeasible. 38 ll o ptt e unable t o ctt rovide the finff ancial assurances in the amounts att We may ba future demands tdd assurances and we faiff our opeo rations and our propertiett s, includindd g commencing proceedindd gs to suspend our operations or cancel our associatedtt offsff hore leases. over our decdd ommissioning obligll atiott ns. If iII n t l tii o ctt ii ith such future orders, BOEMOO tt the time issues orders to provide add if it submits dditioii nal finff ancial ly impact federal lect to take actions that would mll nd underdd future BOEMOO periods required by BOEMOO hett could ell omplm y wll dverserr ially all atertt BOEM requires that lessees demonstrate finff ancial strength and reliability according to its regulations or provide acceptabla e tion of lease obligations, including decommissioning activities on the OCS. In 2016, BOEM under financial assurances to assure satisfacff the Obama Administration had sought to implement more stringent and costly standards under the existing fedff eral financial assurance requirements through issuance and implementation of the 2016 NTL, but the Trump Administration firff st suspended, and then in 2020 rescinded, the implementation of the 2016 NTL. Following the effeff ctiveness of the 2016 NTL, we received orders fromff BOEM in late 2016 directing us to provide additional finff ancial assurance in material amounts relating to our OCS properties. We entered into discussions with BOEM regarding the requested additional finff ancial security and submitted a proposed tailored plan (applicable to our sole and non-sole liabia lity properties) for the posting of additional finff ancial security to the agency forff p review. However, as the Trumrr Administration rescinded the 2016 NTL, BOEM withdrew the previously issued orders under the 2016 NTL. ff s fewff In August 2021, BOEM published a Note to Stakeholders detailing an expansion of its suppl emental finff ancial assurance requirements currently applicable to all sole liabia lity properties and now to certain high-risk, non-sole liabia lity properties; namely, those properties that are inactive, where production end-of-lff ife i er than five years, or with damaged infraff structurt e irrespective of the remaining property life off f the surrounding producing assets. BOEM has stated it will prioritize non-sole liabia lity properties where it believes that the current owner does not meet applicable requirements related to financial strength and has no co-owners or predecessors that are finff ancially strong, as determined by BOEM. In connection with this Note to Stakeholders, BOEM initially assessed the required oximately $70 million. However, following the opportunity to review BOEM’s financial assurance forff sole liability assessment, we were able to reduce the financial assurance required to appr oximately $37.7 million. The bonds covering this amount were posted in 2021. Notwithstanding the above , BOEM, now under the Biden Administration, could, in the futff urt e, continue to make new demands for additional finff ancial assurances in material amounts relating to the decommissioning of our OCS properties. BOEM may reject our proposals to satisfy any such additional finff ancial assurance coverage and make demands that exceed our capabilities. our sole liabia lity properties as appr u a a a If we fail to comply with the current or future orders of BOEM to provide additional surety bonds or other finff ancial assurances, BOEM could commence enforff cement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedurd es to cancel leases associated with our noncompliance, which, if upheld, would have a material adverse effect on our business, properties, results of operations and finff ancial condition. BOEM has the right to issue finff ancial assurance orders in the future, including if it determines there is a subsu tantial risk of nonperformance of the current interest holder’s decommissioning liabia lities and the Biden Administration may elect to pursue more stringent suppl emental bonding requirements. u rr u emental finff ancial assurance requirements appl IIn ththe eve tnt thth tat BOBOEMEM fifinalilizes new reg lul tatiions isi ilmilar tto or more tst iringe tnt ththan thth 2e 2016016 NTNTLL, su hch as BOBOEMEM’’s JJune 2023 2023 icable to offsff hore oil and gas operations, proposed rule that subsu tantially revises the suppl the surety bond market has very l imited capacity to provide additional finff ancial assurance and we thereforff e may not be able to procure and provide the finff ancial assurance required by such new regulations. Moreover, the implementation of such new regulations could result in sureties seeking additional collateral to support existing or futff urt e bonds, such as cash or letters of credit, and we cannot provide assurance that we will be abla e to satisfy collateral demands for such bonds to comply with suppl emental bonding requirements of BOEM. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted and ed to reduce we may be required to seek alternative finff ancing. To the extent we are unabla e to secure adequate financing, we may be forcff our capia tal expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and finff ancial assurance requirements could result in increased costs on our operations, reducd ed cash floff ws if unabla e to comply and consequently have a material adverse effect on our business and results of operations. u a See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation forff more discussion on orders and regulatory i rr nitiatives impacting the oil and natural gas industry orr n the OCS. 39 Our business could be negat ptu iott ns. e disruii ivtt ely all ffea ctedtt by securityii threats,tt includindd g cybc erserr curityii threats,tt terrorist attactt ks and other As an oil and gas producer, we have various security threats, including cybersecurity threats to gain unauthorized access to sensitive inforff mation or to render data or systems unusable, threats to the security of our facilities and infrastructurt e or third-party facilities and infrastructurt e, such as processing plants and pipelines, and threats froff m terrorist acts. The potential forff such security threats subju ects our operations to increased risks that could have a material adverse effect on our business. In particular, the implementation of various procedurd es and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructurt e may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls are suffiff cient to prevent security breaches froff m occurring. If any of these security breaches were to occur, they could lead to losses of sensitive inforff mation, critical infrastructurt e or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash floff ws. 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 disruptu ions in critical systems, unauthorized release of confidff ential or otherwise protected information and corruptu ion of data. These events could damage our reputation and lead to financial losses froff m remedial actions, loss of business or potential liabia lity. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subju ect our operations to increased risks. Any futff urt e terrorist attack at our facilities, or those of our purchasers or vendors, could have a material adverse effecff t on our financial condition and operations. Global ll geopoliti ll cal tentt sions may create heightgg entt ed volatility i tt n oii il, gas and NGLNN prices and could adverserr ly affeff ct our business, finaii ncial conditiii on and resultsll of operations. Our oil and gas activities are subju ect to numerous geopolitical and economic risks, uncertainties (including but not limited to changes, sometimes freff quent 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, foreff ign exchange tions, royalty and tax increases, and other risks arising out of governmental sovereignty over the areas in restrictions, currency fluff ctuat which our operations are conducted, as well as risks of loss dued to acts of terrorism, piracy, disease, illegal cartel activities and other political risks, including tension and confroff ntations among political parties. The upcu oming presidential election in the U.S., the expected change in presidential administration in Mexico, the extended war between Russia and Ukraine and increasing hostilities in the Middle East may cause prolonged uncertainty and volatility in commodity prices. Mexico’s most recent presidential election was held in July 2018. Presidential reelection is not permitted in Mexico. President to be elected in June of 2024. At this time ill result from this changeg in administration. Political events in Mexico could adversely ay ffect Andrés Manuel López Obrador, took offiff ce on December 1, 2018, and his successor is dued we cannot prp edict what changges (i( f anyy) w) economic conditions and/or the oil and gas industry arr nd, by extension, our results of operations and finff ancial position. On Februar region is likely. ry 24, 2022, Russian military forces invaded Ukraine, and sustained war and continued and prolonged disruptu ion in the Russia’s recognition of two separatist republics in the Donetsk and Luhansk regions of Ukraine and subsu equent military action against Ukraine have led to an unprecedented expansion of sanction programs imposed by the U.S., the European Union, the United Kingdom, Canada, Switzerland, Japaa n and other countries against RusRR sia, Belarus, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic and the so-called Luhansk People’s Republic, including, among others: • • • blocking sanctions against some of the largest state-owned and private Russian finff ancial institutions (and their subsequent removal froff m the Society forff Worldwide Interbar nk Financial Telecommunication payment system) and certain RusRR sian businesses, some of which have significant finff ancial and trade ties to the European Union; blocking sanctions against RusRR sian and Belarusr with government connections or involved in RusRR sian military activities; and ian individuals, including the RusRR sian President, other politicians and those blocking of Russia’s forff eign currency reserves as well as expansion of sectoral sanctions and export and trade restrictions, limitations on investments and access to capital markets and bans on various Russian imports. 40 In retaliation against new international sanctions and as part of measures to stabilize and suppor t the volatile Russian financial and currency markets, the Russian authorities also imposed significff ant currency control measures aimed at restricting the outfloff w of foreign currency and capital froff m RusRR sia, imposed various restrictions on transacting with non-Russian parties, banned exports of various products and other economic and finff ancial restrictions. The situation is rapidly evolving as a result of the war in Ukraine, and the U.S., the European Union, the United Kingdom and other countries may implement additional sanctions, export controls or other measures against RusRR sia, Belarus and other countries, regions, officials, individuals or industries in the respective territories. Such ther responses from RusRR sia or other countries to such sanctions, sanctions and other measures, as well as the existing and potential furff tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect our business, financial condition and results of operations. u u We are actively monitoring the situat tion in Ukraine and assessing its impact on our business, including our business partners and ies, technology systems or networks t our operations. We have no way to predict the progress or outcome of the war in Ukraine or its impacts in Ukraine, as the war, and any resulting government reactions, are rapia dly developing and beyond our control. Continued ction, sanctions and resulting market disruptions — or escalation in the objectives thereof or the methods used by the combatants to achieve such objectives —could be customers. To date we have not experienced any material interruptu ions in our infrastructurt e, suppl needed to suppor Russia or Belarusrr hostilities, or any significant increases in the extent and duration of the military arr any meaningfulff significant and could potentially have subsu tantial impact on the global economy and our business forff an unknown period of time. u Alternatively, a cessation of hostilities as a result of a negotiated withdrawal or otherwise—pa— rticularly if coupled with an easing of international sanctions — could cause commodity prices to decline in a manner that would reducd e the revenues we receive for our oil and gas production. During the firff st quarter of 2022, we experienced an increase in commodity prices as sanctions imposed on Russia severely limited the access of RusRR sian oil and gas producers to international markets. In the months that followed, commodity prices subsu equently decreased and remained stagnant during the second half of 2022. If the military action concludes and the related sanctions are dropped, commodity prices could significantly decrease. Any of the above tors could affect our business, financial condition and results of operations. mentioned facff a Additionally, on October 7, 2023, Hamas, a U.S.-designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel. On October 8, 2023, Israel formally declared war on Hamas, and the armed confliff ct is ongoing as of the date of this filing. Hostilities between Israel and Hamas have escalated and involved surrounding countries in the Middle East. Iranian-backed groups have launched attacks on U.S. military bases and assets in Syria, Iraq, and Jordan, and have targeted international shipping in the Red Sea. Afteff r three American troops were killed in a drone attack by an Iran-backed militant group, the U.S. launched retaliatory strikes on multiple sites in Iraq and Syria used by Iranian forces and Iran-backed militants. U.S. and British forces then launched a series of strikes on Houthi targets in Yemen in response to continuing attacks on shipping in the Red Sea and Gulf of Aden. Although the length, impact and outcome of the military conflicff ts between Ukraine and Russia and Israel and Hamas, respectively, are highly unpredictabla e, these confliff cts could lead to significant market and other disruptu ions, including significant volatility in commodity prices and supplpp y oy f energgy ry esources,, instabilityy in financial markets, s, upplpp y cy hain interruptpu ions, p, political and social instabia lityy and other material and adverse effects on macroeconomic conditions. It is not possible at this time to predict or determine the ultimate consequence of these regional conflicts. These conflicff ts and their broader impacts could adversely affect our business, financial condition and results of operations and the global economy. We may na ot be in a position to contrott reserves from our non-opeo rated propeo rtiett s. l thett timinii g of do evdd elopmll ent effoe rts,tt the associatedtt costs ott r thett rate of productiott n of to hett As we carry out our drilling program, we may not serve as operator of all planned wells. For example, in March 2022, the finff al ntment of PEMEX as operator UR from SENER regarding the development of the Zama Field in offshore Mexico, affiff rmed the appoi of the unit, despite our discovery orr f the Zama Field in 2017 and subsequent operatorship. We may have limited abia lity 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 abia lity 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 fact ors that could be largely outside of our control, including: a ff • • • • • the timing and amount of capital expenditures; the availabia lity of suitabla e offshore drilling rigs, drilling equipment, suppor infrastructurt e and qualifieff d operating personnel; u t vessels, production and transportation 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; 41 • • • selection of technology; the rate of production of the reserves; and the timing and cost of P&A operations. In addition, with respect to oil and natural gas projects that we do not operate, we have limited influff ence over operations, including limited control over the maintenance of safetff y 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 projeo cts; initiate exploration or development projeo cts on a slower or faster schedule than we would prefer; delay the pace of exploratory drr rilling or development; and/or drill more wells or build more facilities on a projeo ct than we can afford, whether on a cash basis or through financing, which may limit our participation in those projeo cts or limit the percentage of our revenues froff m those projeo cts. The occurrence of any of the forff egoing events could have a material adverse effect on our anticipated exploration and development activities. Hedgingii transactiott ns may la imit ll our potentt tial gainsii . 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 NGL price hedging arrangements with respect to a portion of our expected production. These arrangements may include futures contracts on the NYMEX. While intended to reducd e the effeff cts of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and naturt al gas prices were to rise subsu tantially over the price establa ished 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 forff extended periods due to hurricanes or other fact ff ors; there is a widening of price diffeff the hedge arrangement; rentials between delivery prr oints forff our production and the delivery prr oint to be assumed in the counterpar rties to our futures contracts faiff ls to perform the contracts; a sudden, unexpected event materially impacts oil or natural gas prices; or we are unabla e to market our prp oduction in a manner contemplp ated when enteringg into the hedgeg contract. Our outstanding commodity derivative instruments are with certain lenders or affiff liates 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. Futurt e collateral requirements forff 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 opeo rations may incur substantt arine lifll e aff s to ctt nd endangered and threatentt tial liabilitie ll o mtt applicll able t ii omplm y wll ed species. ith ett nvironmentaltt laws and regulatll iott ns as well as legal e requirements a Our oil and naturt al 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 permits or other appr ovals 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 affeff ct certain wildlife, including marine species and endangered and threatened species and impose substantial liabia lities for pollution resulting froff m our operations. Additionally, the threat of climate change continues to be a heightened area of focus and regulatory arr nd disclosure requirements in the United States. For example, in March 2022, the SEC proposed rules which could require additional disclosure of climate change-related information, including, among other things, climate change risk management; short-medium-and long-term climate-related finff ancial risks; and reporting Scope1, Scope2 and (for certain companies) Scope3 emissions. The SEC’s proposed climate disclosure rules have not yet been finalized, but implementation of the rulr es as proposed could impose additional costly and time-consuming requirements on our business. For additional inforff mation about government regulation related to environmental and worker safety matters, please see Part I, Items 1 and 2. Business and Properties — Government Regulation — Environmental and Occupau tional Safetff y and Health Regulations. Any regulatory drr evelopments that impact, curtail or increase the cost of our oil and natural gas exploration and production activities on the OCS could have a material adverse effeff ct on our business, results of operations and finff ancial condition. 42 Addidd tiii onal drillinll s, regue natural gas explxx orll atiott n, developmll material adverserr g lawll effeff ct on our business, finaii ncial conditioii n or resultsll of operations. xeee lations, es ent and productiott n activtt cutive orderdd s arr nd othett tiaii itiett s or access to locations where such activities may oa tives that restritt ct, dtt r r regulatll ortt eldd ayll or prohibit oil aii ccur could hll nd ave a y i niii rr articipants submu The Biden Administration has taken a number of actions that may result in stricter environmental, health and safetff y standards applicable to our operations and those of the oil and gas industry mrr ore 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 f the Interior to halt indefinitely new oil and naturt al gas leases on federal lands and offshore waters pending order directed the Secretary orr f the Interior of federal oil and gas permitting and leasing practices in light of the Biden completion of a review by the Secretary orr Administration’s concerns regarding the impact of these activities on the environment and climate. The Secretary orr f 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 forff the Western District of Louisiana issued a nationwide preliminary i njunction barring the Biden Administration froff m implementing the pause in new federal oil and gas leases, an injunction which was made permanent in August 2022. This effeff ctively halts implementation of the leasing suspension with respect to those lease sales canceled or postponed prior to March 24, 2021. In November 2021, the Biden Administration conducted Lease Sale 257 and leases in the Gulf of Mexico; however, on January 27, 2022, in litigation brought by various industry prr Friends of the Earth and other plaintiffsff the District of Columbia vacated Lease Sale 257 and the related agency decision making process, finding that BOEM failed to consider the impact on forff eign greenhouse gas emissions if Lease Sale 257 was not held and the court determined that this failure was a violation of the NEPA. In September 2022, BOEM announced that it 022. In addition, there is increasing uncertainty was reinstating Lease Sale 257 results in line with congressional direction in the IRA 2RR regarding the near-term futff urt e 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 most recent Five-Year Leasing Program expired on June 30, 2022 and on July 1, 2022, BOEM released a proposed program for 2023 through 2028. The proposed program, which was subject to public comment through October 6, 2022, proposes no more than ten potential lease sales in the Gulf of Mexico. On September 29, 2023, the proposed final program for 2024-2029 was published and includes a maximum of three potential oil and gas lease sales in the Gulf of Mexico scheduld ed to be held in years 2025, 2027 and 2029. The Secretary of the Interior appr oved the 2024-2029 program via a combined decision memo and Record of Decision. It is likely, however, that the new Five-Year Leasing Program will be subju ect to heightened environmental 2, 2024 by the American review. It is also possible that the program could be delayed by opposing lawsuits that were filed on February 1rr Petroleum Institutt e and by Earthjustice representing multiple environmental groups both of which are challenging BOEM’s actions. Future actions taken by the Biden Administration to limit the availability of new oil and gas leases on the OCS would adversely impact the offshore oil and gas industry arr nd impact demand for our products. , the U.S. District Court forff itted bids forff a rr new wells to be drilled in fedff Over the past decade, BSEE and BOEM, primarily under the Obama Administration, have imposed new and more stringent permitting procedures and regulatory srr eral waters. While actions afetff y and performance requirements forff bby BSBSEEEE or BOBOEMEM dunde tr thhe TTrumr Ap Addmiiniisttr tatiion s ought tto itimitig tate o dr d lelay certtaiin fof ththose more riigorous tstandda drds, thth Be Bididen ht Administration could reconsider rules and regulatory i nitiatives implemented under the previous administration and replace them with more stringent requirements and also provide more rigorous enforcement of existing regulatory r equirements. For example, in August rr nd modify certain blowout preventer system requirements. 2023, BSEE published a final rulr e, effeff ctive October 23, 2023, to clarify aff The rulr e requires, among other things, that the blowout preventer system is abla e to close and seal the wellbore at all times to the wells maximum kick tolerance design limits and includes more stringent requirements forff failure reporting. Compliance with any added or more stringent regulatory requirements or enforff cement initiatives and existing environmental and spill regulations, together with oval of drilling uncertainties or inconsistencies in decisions and rulr permits and exploration, development, oil spill response and decommissioning plans could result in diffiff cult 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. ings by governmental agencies and delays in the processing and appr a ff These regulatory arr ctions, 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 emental 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, l gas exploration may froff m time to time issue further safetff y and environmental laws and regulations regarding offshore oil and naturat and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the fulff l impact of any new laws or regulations on our drilling and production operations or on the cost or availabia lity of insurance to cover some or all of the risks associated with such operations. our operations, result in increased suppl u rr See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation forff more discussion on orders and regulatory i rr nitiatives impacting the oil and natural gas industry orr n the OCS. 43 Our oil and gas operations are subject to vtt arious internatiott nal, foreign agg that materiallyll affeff ct our opeo rations. nd U.S. federal, stattt e att nd local governmental regulatll iott ns 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 habia tats, and restrictions on the way we can discharge materials and/or GHG emissions into the environment; bonds or other finff ancial 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 eral leases, the federal and the imposition of injunctions limiting or prohibiting certain of our operations. In addition, because we hold fedff government requires that we comply with numerous additional regulations applicable to government contractors. oving The SENER has promulgated guidelines to establa ish procedures for conducting the unitization of shared reservoirs and appr 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 appr aise and potentially forff m a unit forff development of such reservoir. a a If we are forff ced to stt hut-in production, we willii be unable t ll o ptt redict the productiott n levll els oll likeii ly incur greatertt f so uch wellsll once broughu t back onlinll e. costs t tt o btt ringii the associatedtt productiott n back onlinll e, and will If we are forff ced 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 folff lowing 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. ee We may ea xpe rience signi ificff ant shut-ins and losses of po ii hett U.S. Gulf of Me xiee co and in t ff roductiott n due to the effee s orr shalloll w watertt ii hett cts ott f eo ffo the coast of Mo vents outside odd f oo exMM ico and epidemdd ur contrott l, includindd g ics, outbreaks tropical storms and hurricanes in t or othett r public healthll events. 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 vulnerabla e to significant risk froff m hurricanes, tropical storms, loop currents and other adverse weather conditions in the U.S. Gulf of Mexico. We are unabla e to predict what impact future incidents might have on our future results of operations and production. our Epidemics, pandemics, outbrt eaks or other publu ic health events that are outside of our control could significantly disruptu operations and adversely affeff ct our financial condition. The global or national outbrt eak of an illness or other communicable disease, or ions to our business and operational plans, which may include (i) any other public health crisis, such as COVID-19, may cause disrupt shortages of employees, (ii) unavailabia lity of contractors or subcontractors, (iii) interruptu ion of supplies froff m third parties uponu which we rely, (iv) recommendations of, off r restrictions imposed by government and health authorities, including quarantines, to address an outbrt eak and (v) restrictions that we and our contractors, subcu ontractors and our customers impose, including facility shutdowns, to ensure the safetff y of employees. r We are not insured agai a nsii t all of the opeo ratingii riskii s tkk o wtt ee hich our business is eii xpos ed.dd In accordance with industry prr ractice, 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 froff m operational loss-related events. We have insurance policies that include coverage for general liabia lity, physical damage to our oil and gas properties, operational control of well, named U.S. Gulf of Mexico windstorm, oil pollution, construcrr tion risk, workers’ compensation and employers’ liabia lity and other coverage. Our insurance coverage includes deducd tibles 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 liabia lity from all potential ation on our consequences, damages or losses. See Part I, Items 1 and 2. Business and Properties – Insurance Matters for more informff insurance coverage. An operational or hurricane or other adverse weather-related event may cause damage or liabia lity in excess of our coverage that might severely impact our financial position. We may be liabla e forff damages froff m an event relating to a project in which we own a non- operating working interest. Such events may also cause a significant interruptu ion to our business, which might also severely impact our financial position. We may experience production interruptu ions for which we do not have production interruptu ion insurance. 44 ould We reevaluate the purchase of insurance, policy limits and terms annually. Futurt e insurance coverage for our industry crr increase in cost and may include higher deducd tibles or retentions. In addition, some forms of insurance may become unavailabla e in the future or unavailable on terms that we believe are economically acceptabla e. No assurance can be given that we will be abla e to maintain insurance in the future at rates that we consider reasonabla e, 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. Our actual productiott n could diffei r matertt ially from our forff ecasts.tt From time to time, we may provide forff ecasts of expected quantities of futff urt e oil and gas production. These foreff casts are based on a number of estimates, including expectations of production froff m 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 malfunc tions, adverse weather effeff cts, adverse resolutions to disputes relating to operatorships or significant declines in commodity ff prices or material increases in costs, which could make certain production uneconomical. Our opeo rations are subject to ntt umerous risks of oil aii nd natural gas drillingii and productiott n activtt ities. Oil and gas drilling and production activities are subju ect 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 ofteff n uncertain. To the extent we drill additional wells in the U.S. Gulf of Mexico Deepwater and/odd r 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 naturt al 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 fact ors, many of which are beyond our control. These fact ors include: ff ff • • • • • • unexpected drilling conditions; pressure or irregularities in forff mations; equipment faiff lures or accidents; hurricanes and other adverse weather conditions; shortages in experienced labor a ; and shortages or delays in the delivery orr f equipment. The prevailing prices of oil and natural gas also affeff ct the cost of and the demand forff 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 iinve tstme tnt D. D irillillin fg forff loles andd w lellls thth tat are p droducd titive but do not produce suffiff cient cash floff ws to recoup drilling costs. ioill a dnd natturall gas ma by be unpr fofititaffff illing a tctiivitiities can resultlt iin ddr hy hrr blbla e. DDrilli In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without containment and oil removal costs and a variety of public and private damages, including, but red by persons adversely costs and damages, regard to fault, under appl not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffeff affeff cted by an oil spill. If an oil discharge or subsu tantial threat of discharge were to occur, we could be liabla e forff which costs and damages could be material to our results of operations and finff ancial position. icable law forff a We have an interest in Deepwater fieff lds and leases in the Deepwaters of the U.S. Gulf of Mexico. Exploration forff lds and may attempt to pursue additional operational activity in the future and acquire additional fieff oil or naturt al 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 eepwater drilling generally requires more time and more advanced drilling technologies, involving a of Mexico conventional shelf. Dff higher risk of technological faiff lure 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 ofteff n use subsu ea completion techniques with subsu ea 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 faiff lures that could result in cost overruns. Furthermore, the Deepwater operations ld service infraff structurt e present in the shallower waters of the U.S. Gulf of Mexico conventional generally lack the physical and oilfieff shelf. As a result, a considerable amount of time may elapsa e 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 infrastructurt e, some reserve discoveries in the Deepwater may never be produced economically. 45 If any of these industry orr r loss of life,ff 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. perating risks could have a material adverse effect on our business, results of operations and finff ancial condition. Any of these industry orr perating risks occur, we could have substantial losses. Subsu tantial losses may be caused by injury orr Competittt iott n within our indii ustry mr ay adverserr finaii ncial resources. ly affeff ct our opeo rations. ManMM y on f oo ur competittt ortt s arr re larger and have more availablell rr The oil and gas industry i s highly competitive, and many companies in our industry arr re larger and have substantially greater financial resources than we do. We compete with these companies for oil and naturt al gas leases and other properties; equipment and personnel; and marketing our product to end-users. Such competition can significantly increase costs and the availabia lity of resources availabla e to us, which could provide larger companies a competitive advantage. Larger competitors may also be able to more easily attract and retain experienced personnel. In addition, larger competitors may be better abla e to respond and adapta to adverse economic and industry crr tions, reducd ed oil and gas demand, political changes and current and futff urt e governmental regulations and taxation. onditions, including price fluff ctuat 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 abla e to outbit d us forff acquisitions, productive oil and gas properties and exploratoryrr prospects. Further, our competitors may be abla e to expend greater resources on the existing and changing technologies to gain competitive advantages. If we are unabla e to compete successfulff ly in the futff urt e, our future revenues and growth may be diminished or restricted. The losll s of oo ur larger customers could mll conditidd on and resultsll of operations. atertt ially reduce our revenue and matertt ially all dverserr ly affeff ct our business, finaii ncial 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 Valero Energy Corporation, could adversely affect our current and futff urt e revenue, and could have a material adverse effect on our business, financial condition and results of operations. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Signi fici ant Accounting Policies for additional inforff mation. ff i The losll s of ko ey personnel could adverserr ly affeff ct our abiliii tyii to operate.ee Our industry hrr as lost a significant number of experienced profesff 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. sionals over the years dued In addition, our exploration, production and decommissioning activities require personnel with specialized skills and experience. de dependds upon our babiliility to em lploy andd ret iain skikilllledd workkers O. Our babiliility to AAs a res lult, our babililiity to remaiin pr doduc itive a dnd pr fofiitaffff blbla 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 y is limited. A significant increase in the wages paid by competing demand for skilled workers in our industry i 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 profitabia lity could be diminished and our growth potential could be impaired. s high, and the suppl u a a rr We have operations in multiple jurisdii administratiott n may change. Aee could bll profitaff or any on ther jurisdii operations, ws filinii legie slii atll e lowll icdd tion in which we opeo rate or have subsidiadd ries could r ll ly impact our afteff r-tax paa icdd tions, includindd g jurisdictiott ns in which thett gs are complm exll ivtt e or regulatll ortt ii ll n c esult i bligll atiott ns and relatll edtt s a result, ott ur tax oaa er than anticipat hich could all , fyy utff ure taxtt .yy rofio taii bilityii lso adverserr dditiii onallyll biliii tyii . Add edtt ii ii awll etattt ntii ertt prrr s, their i tax l aa and subjeb ct to change, ae nd our afta ertt y cr ir -trr axtt hanges in the UniUU teii d StaSS tes, Mexiee co ur income and iott n or thett iott n of oo hanges to the taxat tt We are subject to income, withholding and other taxes in the United States on a worldwide basis and in numerous state, local and r-tax profitabia lity could be foreign jurisdictions with respect to our income, operations and subsidiaries in those jurisdictions. Our afteff (including refunds of value added taxes) and affeff cted by numerous factors, including the availability of tax credits, exemptions, refunds other benefitff s to reducd e our tax liabia lities, changes in the relative amount of our earnings subju ect to tax in the various jurisdictions in which we operate or have subsu idiaries, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing business strucr ture and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions. ff 46 ff a Our after-tax profitaff bia lity may also be affect ed 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. From time to time, fedff eral 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. fedff eral and state income tax provisions currently availabla e to oil and naturt al gas exploration and development companies. Such proposed legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and naturt al gas properties, (ii) the elimination of current deductions for intangible drilling and certain geological and geophysical expenditures, (iv) the elimination development costs, (iii) an extension of the amortization period forff of certain other tax deductions and relief previously availabla e to oil and naturt al gas companies, and (v) an increase in the U.S. federal income tax rate appl icable to corporations (such as us). U.S. states in which we operate or own assets may also impose new or increased on oil and natural gas extraction. It is unclear whether these or similar changes will be enacted and, if enacted, how soon taxes or fees ff t. Additionally, the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent any such changes could take effecff ent”) has entered into forff ce among the jurisdictions that have ratified it, Base Erosion and Profitff Shiftiff ng (the “Multilateral Instrumr ent. Such proposed legislative changes and although the United States has not yet become a signatory to the Multilateral Instrumrr ratificff ation of the Multilateral Instrumrr ther changes to our global taxation. Additionally, Mexico has enacted tax reforff m legislation, and a majoa rity of the provisions became effective on January 1, 2020. These new and complex provisions that significantly change how Mexico tax entities and operations and are subju ect tax reforff ms provided forff to further legislative change and administrative guidance and interpretation, which may differ froff m our interpretation. Futuret tax legislative or regulatory crr hanges in the United States, Mexico or in any other jurisdictions in which we operate now or in the futff urt e could also adversely impact our afteff ent in the jurisdictions in which we operate could result in furff r-tax profitaff bia lity. Our MexMM ican operations are subject to certain offsff hore regue latory and environmentaltt laws and regulatll iott ns promulgall ted byb Mexiee co. Our oil and gas operations in shallow waters off the coast of Mexico’s Tabaa sco state are subject to regulation by the SENER, the odies. The laws and regulations governing activities in the Mexican energy sector have undergone CNH and other Mexican regulatory brr raff mework continues to evolve as SENER, the CNH and other significant reformation over the past decade, and the legal regulatory f odies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, Mexican regulatory brr odies may impose new or revised requirements that could increase our operating costs and/or the CNH or other Mexican regulatory brr capital expenditures forff operations in Mexican offsff hore 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 — Hydrocarbonr additional disclosure relating to the legal requirements imposed by SENER, CNH or other Mexican regulatory brr odies to which we may be subju ect in the pursuit of our operations. Export Regulation in Mexico forff rr In addition, our oil and gas operations in shallow waters off the coast of Mexico’s Tabaa sco state are subject to regulation by the ASEA. The laws and regulations governing the protection of health, safetff y and the environment froff m activities in the Mexican energy sector are also relatively ny ew, h, aving bg een signig ficantlyy reformed in 2013 and 2014,, and the legag l reggulatory fyrr raff mework continues to odies issue new regulations and guidance. Such regulations are subject to change, and evolve as ASEA and other Mexican regulatory brr it is possible that ASEA or other Mexican regulatory brr odies may impose new or revised requirements that could increase our operating operations in Mexican offsff hore waters. See Part I, Items 1 and 2. Business and Properties — costs and/or capital expenditures forff Environmental and Occupau tional Safetff y and Health Regulations — Environmental Regulation in Shallow Waters Off the Coast of odies to which we Mexico for additional disclosure relating to the legal requirements imposed by ASEA or other Mexican regulatory brr may be subject in the pursuit of our operations. The permit holders must comply with requirements relating to insurance, facff ility construcr tion and design, law compliance, and risk analysis scenarios. Under the Block 7 PSC, we are also jointly and severally liable for the performance of all obligations under the PSC, including exploration, appraisal, extraction and abandonment activities and compliance with all environmental regulations, and failure to perform such obligations could result in contractuat l rescission of the PSC. Three-dimeii nsional seismii ic interpretation doedd s not guarantee thatt t hydh rodd carbons are present or if pi resent, ptt roduce in economic quantities. t We rely on 3D seismic studi es to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studi es are merely an interprr etive tool and do not necessarily guarantee that hydrocarbons saturation are generally not reliabla e are present or, if present, produce in economic quantities, and seismic indications of hydrocarbon indicators of productive reservoir rock. These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition. r r t 47 We may ba e expee osed to liabiliii tieii s underdd the U.SUU . FSS orFF eigni Corrupt PraPP ctictt es Act. We are subject to the U.S. Foreign Corruptu Practices Act (the “FCPA”) and other laws that prohibit improper payments or offerff s e of obtaining or retaining business. We may of payments to foreign governments and their officials and political parties forff demands by offiff cials, tribal or do business in the future in countries and regions in which we may face, directly or indirectly, corruptu insurgent organizations or private entities. Thus, we face rs of payments by one of our the risk of unauthorized payments or offeff employees or consultants, given that these parties may not always be subju ect to our control. Our existing safegff uards and any futff urt e improvements may prove to be less than effeff ctive, and our employees and consultants may engage in conduct forff which we might be held responsible. the purpos r ff Under the Block 7 PSC 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 liabia lities, which could negatively affect our business, operating results and finff ancial condition. In addition, the CNH has the authority to rescind the PSC if these violations occur. Our opeo rations are subjeb ct to various risks arising out of the thrtt ll limit the areas in which oil and natural gas productiott n may occur and reduce demand for thett te change that could r eat of co limaii ii esult i reased operatingii ll n i il and natural gas that crude odd ncii costs,tt we produce. r capture and sequestration and imposes the firff st ever federal feeff Climate change continues to attract considerable public, political and scientificff attention both domestically and abra oad. For ls, supporting example, the IRA 2022 contains significant finff ancial incentives for the development of renewable energy, alternative fueff infrastructurt e and carbon on the emission of greenhouse gases through a methane emissions charge generated froff m sources in the onshore petroleum and natural gas production categories. Beginning in 2024, the methane emissions charge is set at $900 per ton of methane, and is expected to increase to $1,200 in 2025, and $1,500 in 2026 and each year afteff various clean ls towards lower- or zero-carbon energy industries could furff emissions alternatives. These regulatory c oil and natural gas, increase our rr compliance and operating costs and consequently adversely affect our business. ther accelerate the transition of the economy away froff m the use of fosff r crude s could significantly impact our operating costs. Further, the incentives offeff hanges could ultimately decrease demand forff r. Such additional feeff red forff sil fueff r r Numerous other executive actions and legislative and regulatory i nitiatives have been enacted or may be anticipated, such as cap- and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. Further, regulations or legal actions are likely at the state, regional or international levels of government to monitor and limit existing GHG emissions as well as to restrict or eliminate such future emissions. Additionally, the threat of climate change has resulted in increasing political, litigation and financial risks associated with the production of fosff ls and GHG emissions. See Part I, Items 1 and 2. Business and Properties — Environmental and Occupau tional Safetff y and Health Regulations — Climate Change for additional disclosure relating to risks arising out of the threat of climate change. sil fueff rr r reporting requirements. Any such legislation or regulatory prr The adoption of legislation or regulatory programs to reducd e or eliminate futff urt e GHG emissions could require us to incur ignififica tnt operatiting costts, suchh as costts tto pur hchase a dnd operatte emiis isions co tntroll systtems t, to acq iuire emiis isions lalllowances or complly isi rograms could also increase the cost of consuming, with new regulatory orr and thereby reduce demand forff rograms to reducd e or eliminate futff urt e GHG emissions could have an adverse effeff ct on our business, financial condition and results of operations. Also, political, finff ancial and litigation risks may result in our restricting or canceling production activities or impairing the abia lity 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. , the oil and natural gas we produce. Consequently, legislation and regulatory prr Increasingii attett ntiott n to ett nvironmentaltt , sll ocial and governarr nce mattett rs may ia mpii act our busineii ss. Increasing attention to climate change and societal expectations on companies to address climate change and substitute energy sources for fosff ls may result in increased costs, reducd ed demand for our products and our services and the products and services of our customers, reduced profitff s, increased compliance measures, investigations and litigation, and negative impacts on our stock price and access to capital markets. sil fueff Moreover, while we endeavor to publish transparent sustainabia lity reports, the voluntary drr on assumptions and calculations that may or may not be representative of actuat associated therewith. Such assumptions and calculations are necessarily uncertain and may be prone to error or subju ect misinterpretation given the long timelines involved and the lack of an establa ished single appr on many environmental, social and governance (“ESG”) matters. isclosures therein are sometimes based l or forff ecasted risks or events, including the costs to oach to identifying, measuring and reporting a 48 The Board’s SSCR Committee is the primary committee responsible for overseeing and managing our ESG initiatives. Our Director of ESG is responsible for driving our sustainabia lity initiatives, engaging with stakeholders, benchmarking our ESG data, and evaluating potential and emerging ESG drivers. We note, however, that our governance structurt e may not be able to adequately identify or manage ESG-related risks and opportunities, which may include failing to achieve our GHG emissions targets or other ESG-related aspirational goals, including but not limited to as a result of unforff eseen costs or technical difficulties associated with achieving such goals. Moreover, given the evolving nature of GHG emissions accounting methodologies and climate science, it is possible that facff tors outside of our control could give rise to the need to restate or revise our emissions intensity reducd tion goals, cause us to miss them altogether, or limit the impact of success of achieving our goals. Additionally, to the extent we meet such targets, they may be achieved through various contractuat l arrangements, including the purchase of various credits or offsff ets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand from numerous businesses implementing net zero goals, or that the offsff ets we do purchase will successfulff ly achieve the emissions reductions they represent. evaluating companies on their appr In addition, organizations that provide information to investors on corpor ate governance and related matters have developed ublish ratings processes forff their investment sustainabia lity reports that are made available to investors. Such ratings and reports are used by some investors to informff and voting decisions. Unfavff orable 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 forff potential growth projeo cts. To the extent ESG matters negatively impact our reputation, we may also be unabla e to compete as effeff ctively to recruit or retain employees, which may adversely affect our operations. oach to ESG matters. We and other companies in our industry prr a rr to identify a Furthermore, public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny fromff public and governmental authorities related to the risk of potential “greenwashing,” (i.e., misleading inforff mation or falff se claims overstating potential ESG benefits). For example, in March 2021, the SEC establa ished the Climate and ESG Task Force in the Division of Enforcement including greenwashing. Certain non-governmental organizations and other private actors have also fileff d lawsuits under various securities and consumer protection laws alleging that certain ESG statements, emission reduction claims, appr oaches to accounting forff GHG emissions reductions, or other ESG-related goals or increased litigation risk froff m private parties and standards were misleading, false, or otherwise deceptive. As a result, we may face governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industryrr may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to ther regulatory ESG-related focff us and scrutr comply with and navigate furff nd address potential ESG-related misconduct, iny. a ff ff ff ii hett A change in t changeg in polp icll y byc y tyb hott operating expe ee jurisdii icdd tional characterizaii tion of oo ur FERCEE -jCC urisdictiott nal pipelinll es, ts se ageg ncies mayy result in increased reggulatll iott n of sfo uch asset, w,tt i ritt bal hich may cya or local regulatll ortt ause our revenues to dtt gea ncies or a inll e and y ar ecldd nses to increase or delay oa r incii rease thett cost of expanxx sion projects. One of our subsu idiaries owns an oil pipeline that extends from South Pass Block 89 in federal waters, offsff hore Louisiana, to the West Delta Receiving Station in Venice, Louisiana. This subsu idiary has previously been granted a waiver of certain portions of the ICA and related regulations by the FERC. However, if the pipeline’s circumstances change, the FERC could, either at the request of other a waiver. In the event that the FERC determines the entities or on its own initiative, assert that such pipeline no longer qualifieff s forff pipeline no longer qualifieff d forff the ith the FERC, provide a cost justificff ation forff transportation charge and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional statust of transportation on this pipeline could adversely affeff ct our results of operations. Please also see Part I, Items 1 and 2 Business and Properties — Environmental and Occupau tional Safetff y and Health Regulations — Federal Regulation of Sales and Transportation rr of Crude a waiver, we would likely be required to filff e a tariff wff Oil forff more information. We are upgru cultiett s with the migration, we may be unable to timeii adindd g our accountintt g syss tem to a mtt i diffi ly or accurately prepare finff ancial repor ee ts. ore recent versirr on and, if this upgrpp aded versirr on proves ineffeff ctivtt e or we expe ee rience u We are in the process of upgr ading our accounting systems. Any problems or delays associated with the implementation of our accounting platforff m or the failure to complete such implementation on a timely basis could adversely affect our ability to report finff ancial information as our company grows, including the filff ing of our quarterly or annual reports with the SEC on a timely and accurate basis. Afteff r converting froff m prior systems and processes, we may discover data integrity problems or other issues that, if not corrected, could impact our business or finff ancial results. 49 Risks Related to our Capital Structure and Ownership of our Common Stock Our debdd t level ll and thett indentures governingii covenants i tt n oii our NewNN ss prospes cts.tt Our faiff luii re to comply withii ur current or future agreements gtt ll mpii Senior Notes, could nll esult ill n t these covenants could rll our debdd t, includindd g our Bank Creditdd Facilitll y,tt overningii act our finaii ncial conditioii n, results of operations and ii hett accelerll atiott n of oo ur outstandindd g indii ebdd tedness. egativtt ely i and thett busineii 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; selling assets; guaranteeing other indebtedness; entering into agreements that restrict dividends from our subsu idiaries to us; merging, consolidating or transferring all or substantially all of our assets; hedging future production; and entering into transactions with affiff liates. Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the Bank Credit Facility, the indenturt es for each of Talos Production Inc.’s (the “Issuer”) 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) and 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes,” and together, with the 9.000% Notes, our “New Senior Notes”), have important consequences on our operations, including: • • • • • • requiring that we dedicate a subsu tantial portion of our cash floff w froff m operating activities to required payments on debt, thereby reducd ing the availabia lity of cash floff w forff working capital, capital expenditures, and other general business activities; limiting our ability to obtain additional finff ancing in the futff urt e forff 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 i rr n which we operate; detracting froff m our ability to successfulff ly withstand a downturt n in our business or the economy generally; placing us at a competitive disadvantage against other less leveraged competitors; and making us vulnerabla e to increases in interest rates because debt under our Bank Credit Facility is at variable rates. See Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Developments — Debt Offering for additional inforff mation on the issuance of the New Senior Notes. 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 defauff lt 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 finff ancial conditions. Sustained low oil and naturt al gas prices have a material and adverse effeff ct on our liquidity position. Our cash floff w is highly dependent on the prices we receive forff oil and natural gas. 50 We depend on our Bank Credit Facility for a portion of our future capia tal 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 l gas redetermined semi-annually, is based on an amount establa ished by the lenders afteff reserve values. Such borrowing base determines the amount which is availabla e under our Bank Credit Facility. 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 afteff iency; (ii) add additional oil and gas properties acceptabla e 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 afteff equal monthly installments with the first installment due within 30 days afteff iency or (iv) any combination of the above. We are required to elect one of the forff egoing options within 10 days afteff r their evaluation of our proved oil and naturat r the existence of such deficff r the existence of such deficff r the existence of such deficff r the existence of such deficff iency; (iii) pay the deficff iency in four iency. ff ff 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 restructurt e or refinff ance such debt, reducd e or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds ring. We cannot assure you that we will be able to generate sufficient cash floff ws from operating activities to pay the from an equity offeff interest on our debt or that future borrowings, equity financings or proceeds froff m the sale of assets are availabla e 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, ther restrict business operations. The terms of our debt, including our Bank Credit Facility and the respective indenturt es which could furff for our New Senior Notes, may also prohibit us froff m taking such actions. Factors that affeff ct our ability to raise cash through offeff rings 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, refinff ancing or sale of assets. We cannot assure you that any such offerings, restrucr turing, refinancing or sale of assets would be successfully completed. A finff ancial crisis may ia mpii our Bank CreCC dit Fii acFF ilitll y ott act our busineii capia taii ii hett r in t l markerr ts. ss and finff ancial conditdd iott n and may aa dverserr ly impact our abilityii to obtaitt n f unff ii dingii underdd We use our cash floff ws from operating activities and borrowings under our Bank Credit Facility to fund our capia tal expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital forff 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 redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterpar ng obligations. rties to meet their fundi ff l ff it l counterpar We may also face limited ld liiq iuididitty d, d fefauff ltlts, non-pe frformance or rties or other companies in the financial services industry orr nvol iving li is i ions, transactional counterparr rty credit risk on our derivatives contracts and requirements by our contractuat limitations on our ability to access the debt and equity capia tal markets and complete asset sales, increased rties to post collateral guaranteeing counterpar tct fifinanciiall pe frformance E. Eve tnt institutt enerally, or concerns or rumors about any events of these kinds or other similar risks, have in the past and may in the future lead to market-wide liquidity problems. Most recently, on May 1, 2023, First Republic was closed by the Califorff nia Department of Financial Protection and Innovation (“DFPI”), which appa ointed the FDIC as receiver. The FDIC sold First Republic’s deposits and most of its assets to JPMorgan Chase Bank, N.A. On March 10, 2023, Silicon Valley Bank (“SVB”) was closed by the DFPI, which appointed the FDIC as receiver. Similarly, on March 12, 2023, Signature Bank and Silvergate Capia tal Corp.r were each swept into receivership. Although a statement by the Fed and the FDIC indicated that all depositors of SVB would have access to all of their money after the Department of the Treasury,rr only one business day of closure, including funds held in uninsured deposit accounts, borrowers under credit agreements, letters of credit and certain other finff ancial instruments with SVB, Signature Bank or any other financial institution that is placed into receivership by the FDIC may be unabla e to access undrawn amounts thereunder. Access to funding sources and other credit arrangements could be significantly impaired by facff tors that affeff ct the finff ancial services industry orr tothher addvers de dev lelopmentts thth tat r the financial services industry grr r economy in general. fafffefff In addition, from time to time, we could be required to, or we or our affiff liates may seek to, retire or purchase our outstanding debt through cash purchases and/or exchanges forff 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 l restrictions and other factors. The amounts and will depend on prevailing market conditions, our liquidity requirements, contractuat involved may be material. Such transactions may give rise to taxable cancellation of indebtedness income (to the extent the faiff r market value of the property exchanged, or the amount of cash paid to acquire the outstanding debt, is less than the adjud sted issue price of the outstanding debt) and adversely impact our ability to deducd t interest expenses in respect of our debt against our taxabla e income in the future. This could result in a current or future tax liabia lity, which could adversely affect our financial condition and cash flows. 51 We require substantt tial capia taii finaii ncing on satistt l expe ee fas ctortt nditudd rr ertt ms y tr obtaitt n nii eededdd res to ctt ott onduct our opeo rations and replace our productiott n, and we may be unable t ll necessary to fund our planned capia taii ee l expe nditdd ures. ff We spend a subsu tantial amount of capital for the acquisition, exploration, exploitation, development, and production of oil and our capital expenditures primarily through operating cash floff ws, cash on hand and borrowings under our our l drilling results, the availabia lity of drilling rigs and other technological and competitive developments. A further reducd tion in commodity prices may natural gas reserves. We fund Bank Credit Facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially fromff estimates as a result of, aff mong other things, oil and naturt al gas prices, actuat services and equipment and regulatory,rr result in a furff l capital expenditures, which would negatively impact our ability to grow production. ther decrease in our actuat Our cash floff w froff m operations and access to capital is subject to a number of variabla es, including: • • • • • our proved reserves; the level of hydrocarbons r we are abla e to produce froff m 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. If low oil and naturt al gas prices, operating difficulties, declines in reserves or other fact ors, many of which are beyond our control, cause our revenues, cash floff ws 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 availabla e sources of such capital expenditures. We cannot be sure that financing, we may be forff ced to raise additional debt or equity proceeds to fund additional debt or equity financing will be available, and we cannot be sure that cash flows provided by operations will be sufficff ient 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. ff ff We are a holdindd g companm y tn hatt t has no material assets othett r thatt n our ownership of the equity interests ott f To Accordindd gly,ll we are depdd endent upon distii ritt bui expexx nses and pay dividends,dd if any,n on our common stock.kk tions froff m TalTT osll Productiott n IncII . tcc o ptt ay taxeaa s, cover our corporate att alTT osll Productiott n IncII .cc ad r overherr nd othett 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 availabla e 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 anticippate that anyy availabla e cash,, other than the cash distributed to us to pap y ty axes 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 forff eseeable 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 Producd tion 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. icable law or regulation To the extent that we need funds and Talos Production Inc. is restricted froff m making such distributions under appl t our or under the terms of our financing agreements, or is otherwise unabla e to provide such funds, it could materially adversely affecff liquidity and finff ancial condition. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 8 — Debt — Limitation on Restricted Payma ents Including Dividends for additional inforff mation. a 52 Our estimtt atestt decommissioning costs could mll of future asset retirtt ement obligll atiott ns may v dverserr ially all atertt a ly affeff ct our current and futff ure finff ancial position and results of operations. r ary s ignigg fii cantlytt from period to period and unantictt ipatedtt rr crutrr We are required to record a liabia lity for the discounted present value of our asset retirement obligations to plug and abaa ndon 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 forff offsff hore operations as compared to most land-based operations due to increased regulatory s iny 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 r equirements are subju ect to change or more restrictive interprrr etation, 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 tion as a result of hurricanes and other adverse U.S. Gulf of Mexico, platforff ms, facff weather conditions. The estimated costs to plug and abaa ndon a well or dismantle a platforff m can change dramatically if the host platforff m from which the work was anticipated to be performed is damaged or toppled rather than structurt ally intact. Accordingly, our estimates of future asset retirement obligations could diffeff r dramatically from what we may ultimately incur as a result of damage from a hurricane or other naturt al disaster. Also, a sustained lower commodity price environment may cause our non-operator partners to be unabla e to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs. ilities and equipment are subju ect to damage or destrucr rr We have divested, as assignor, various leases, wells and facff ilities located in the U.S. Gulf of Mexico where the purchasers, as rties in these divestiture transactions or assignees, typically assume all abaa ndonment obligations acquired. Certain of these counterpar cy protection or undergone associated reorganizations and may not be able to third parties in existing leases have filed forff perform required abaa ndonment obligations. Under certain circumstances, regulations or federal laws such as the OCSLA could impose joint and several strict liabia lity and require predecessor assignors, such as us, to assume such obligations. As of December 31, 2023, we have accrued $3.3 million and $12.3 million in obligations reflected as “Other current liabia lities” and “Other long-term liabilities”, respectively, on the Consolidated Balance Sheets. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 2 — fii cant Accounting Policies and Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 14 — Summary of Signi Commitments and Contingencies for more inforff mation. r bankrupt i We may na ot realizll e thett ii anticipat edtt benefie tsii from our current and futff ure acquisiii tioii ns, as integre ate f tt utff ure acquisiii tiii ons. nd we may ba tt e unable t ll o s uccessfus llyll Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effeff ctively to achieve revenue growth and maintain profitabia lity in our evolving market. We expect to grow in the futff urt e 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 tothhe dr dififfififff cultltiies, iinexpe irience lities, iinaccur tate reserve estitimattes a dnd fluctuations in market prices. In particular, this risk arises in the context of the pending QuarterNorth Acquisition, which is expected to close in the first quarter of 2024. iwithth operatiting iin new geographihic regiions, u knknow ln liiabibia liti In addition, integrating acquired businesses and properties involves a number of special risks and unforff eseen difficff ulties 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 facff ilities; integrating corpor r ate, technological and administrative funff ctions; diverting management’s attention froff m regular business concerns; diverting finff ancial resources away from existing operations; increasing our indebtedness; and incurring potential environmental or regulatory l rr iabia lities and title problems. Any of these or other similar risks could lead to potential adverse short-term or long-term effeff cts on our operating results. The process of integrating our operations could cause an interruptu ion of, or loss of momentumt 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 effeff ctively manage the integration process, or if any business activities are interruptu ed as a result of the integration process, our business could suffeff r. 53 Our current and futff ure acquisiii ee tioii ns could ell xpos e us to ptt otentt tiallyll signi ificff ant liall biliii tieii s, includindd g P&A liabiliti ii es. We expect that future acquisitions will contribute to our growth. In connection with potential future acquisitions, we may only be able to perform limited dued diligence. Successfulff acquisitions of oil and natural gas properties require an assessment of a number of fact ors, including estimates of recoverabla e reserves, the timing of recovering reserves, exploration potential, futff urt e oil and naturt al gas prices, operating costs and potential environmental, regulatory and other liabilities, including P&A liabia lities. Such assessments are inexact and may not disclose all material issues or liabia lities. 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 famff iliar with the properties to fulff iencies and capabilities. ly assess their deficff ff tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affecff There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, t our production, regulatory,rr revenues and results of operations. We may be successful in obtaining contractuat preclosing liabia lities, including environmental liabia lities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies the sellers, these for breaches of representations and warranties. In addition, even if we are abla e to obtain such indemnificff ation fromff indemnificff ation obligations usually expire over time and could potentially expose us to unindemnifieff d liabia lities, which could materially adversely affect our production, revenues and results of operations. l indemnificff ation forff Resolution of lo itll igtt atiott n could materiallyll affeff ct our finff ancial position and results ott f oo peo rations. Resolution of litigation could materially affecff t our financial position and results of operations. To the extent that potential exposure to liabia lity 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 corpor o ate ott rr roff m corpor benefie t fii tunityii ppor o ate ott ppor rr provisions in our SecSS ond Amendeddd tunitieii s thatt t mightgg not otherwiseii and Restated CerCC tificff ate ott s. ll o utt be availaii ble t f Io ncII rr orpor atiott n could enable oll thers trr ott Subju ect to the limitations of applicable law, our Second Amended and Restated Certificff ate of Incorpor r ation, among other things: • • • permits us to enter into transactions with entities in which one or more of our offiff cers or directors are financially or otherwise interested; permits our offiff cers or directors who are also offiff cers, directors, employees, managing directors, or other affilff iate of a Principal Stockholder (as defined in the Second Amended and Restated Certificff ate of Incorpor ation) to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and r provides that if any of our offiff cers or directors who is also an offiff cer, director, employee, managing director or other affilff iate of the Principal Stockholders becomes aware of a potential business opportunity, transaction or other matter (other than one city as an director or offiff cer of us), that director expressly offered to that director or officer in writing solely in his or her capaa r or offiff cer will have no dutd y to communicate or offer that opportunity to us, and will be permitted to communicate or offeff that opportunity to any other entity or individual and that director or offiff cer will not be deemed to have acted in a manner inconsistent with his or her fiduciary duty to us or our stockholders. Any of our directors may vote upon u any contract or any other transaction between us and any affiff liated corpor r ation without regard to the facff t that such person is also a director or offiff cer of such affiff liated corporation. These provisions create the possibility that a corpor r ate opportunity that would otherwise be availabla e to us may be used for the benefit of others. 54 nd Amended and Restattt edtt Certiftt the fedff t enforff Our SecoSS to the extee entt of actions and proceedindd gs that may ba judicial forum forff dispii utestt withii us or our dirdd ectortt ceable,ll e iniii tiaii icff ate ott f Io ncII rr orpor atiott n desdd ignagg tes thett Court of Co haCC ncery or erdd al distii ritt ct courts of the UniUU teii d StaSS tes of Ao merica as the sole all ted by ob ur stoctt kholdell s,rr offiff cers,rr emplm oyll rs, which could limit ees or agents.tt ii our stockhokk f to hett are and,dd Stattt e ott nd exclusive forff um for certain typeyy s favorablell lderdd s’rr abiliii tyii to obtaitt n aii elawll f Do r Our Second Amended and Restated Certificff ate of Incorpor , the sole and exclusive forum forff ation provides that, unless we consent in writing to the selection of an alternative forff umr (i) any derivative action or proceeding brought on our or our stockholders’ behalf, (ii) any action asserting a claim of breach of a fidff ucd iary duty owed by any of our current or former directors, offiff cers, employees, agents and stockholders to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our Second ation or our Second Amended and Restated Bylaws, (iv) any action as to which the DGCL Amended and Restated Certificff ate of Incorpor f the State of Delaware, or (v) any other action asserting a claim that is governed by the conferff s jurisdiction to the Court of Chancery orr f the State of Delaware. Our Second Amended and Restated Certificff ate of internal affaff Incorporation also provides that, to the fulff eral district courts of the U.S. are the exclusive resolving any complaint asserting a cause of action arising under the Securities Act, subject to and contingent upon a finff al forum forff adjud dication in the State of Delaware of the enforceability of such exclusive forff umrr provision. Section 22 of the Securities Act creates federal and state courts with respect to suits brought to enforce a dutd y or liabia lity created by the Securities concurrent jurisdiction forff Act or the rules and regulations thereunder. Accordingly, both state and fedff eral courts have jurisdiction to entertain claims under the Securities Act. irs doctrine shall be the Court of Chancery orr lest extent permitted by appl icable law, the fedff a r Notwithstanding the forff egoing, the exclusive forum provision does not apply to suits brought to enforce any liabia lity or duty eral courts have exclusive jurisdiction. Section 27 of the Exchange Act created by the Exchange Act or any other claim for which the fedff creates exclusive fedff eral jurisdiction over all suits brought to enforce any duty or liabia lity created by the Exchange Act or the rules and regulations thereunder. Any person or entity purchasing or otherwise acquiring an interest in any shares of our capital stock shall be deemed to have notice of and to have consented to the forum provisions in our Second Amended and Restated Certificff ate of Incorporation. These choice-of-foff rum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that he, she or it believes to be favorable for disputes with us or our directors, offiff cers or other employees, which may discourage such lawsuits. Alternatively, if a court were to finff d these provisions of our Second Amended and Restated Certificff ate of Incorpor icable or unenforff ceable with respect to 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 materially adversely affect our business, financial condition and results of operations and result in a diversion of the time and resources of our management and board of directors. ation inappl a rr While the Delaware courts have determined that choice of forum provisions of this type are facff ially valid, uncertainty exists as to whether a court would enforce such provision, and as such, a stockholder may nevertheless seek to bring a claim in a venue other than those designated in our exclusive forff umr icable, we would expect to vigorously assert the validliditity a dnd enfforc beabililitity fof our ex lclusiiv fe forff umrr proviisiion. ThThiis may req iuire daddidititionall costts asso ici tat ded iwithth resollviing suchh a tctiio in in other jurisdictions and there can be no assurance that the provisions will be enforced by a court in those other jurisdictions. provision. In such instance, to the extent appl a Future sales, or the perception of fo utff ure salesll , bs y ub s or our existing stockhokk lderdd s irr n t ii hett publicll market could cll ause the markerr t price forff our common stock to declinll e. The sale of substantial amounts of shares of our common stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. Certain holders of our common stock, including certain forff mer stockholders of EnVen, are entitled to rights with respect to oximately 11.3% of the outstanding shares of registration of approximately 17.9 million shares of our common stock (representing appr our common stock as of Februar ry 21, 2024) under the Securities Act pursuant to certain registration rights agreements. In addition, we intend to enter into a registration rights agreement in connection with the QuarterNorth Acquisition, which will become effeff ctive at the closing, which will grant registration rights to appr oximately 13.5% of the outstanding shares of our common stock immediately folff lowing the closing of the acquisition. If these holders of our common stock, by exercising their registration rights, sell a large number of shares, the market price for our common stock could be adversely affected. oximately 24.8 million shares of our common stock (representing appr a a a The intii ertt ests of the SliSS m Fii amFF ily all nd its att ffia liaii tes may diffei r froff m thett interests ott f oo ur othett r stockhokk lderdd s.rr As of Februar ry 21, 2024, an entity controlled by the Carlos Slim Helu and his family members (collectively, the “Slim Family”) beneficially owned and possessed voting power approximately 21.9% of our common stock. The Slim Family has significant influff ence over matters submu structurt e, transactions requiring stockholder appr different interests than other holders of our common stock and may make decisions adverse to your interests. a oval, including changes in capital oval under Delaware law, and corporate governance. The Slim Family may have itted to stockholders for appr a 55 Among other things, the Slim Family’s concentration of voting power could delay or defer a sale of us that many of our other t. This concentration of voting power could discourage a potential investor from seeking to acquire our common stockholders suppor stock and, as a result, might harm the market price of our common stock. u Risks Related to the QuarterNorth Acquisition and our Integration of QuarterNorth Into our Business The markerr from those thatt t price for our common stoctt k folff t historically hll loll wingii or currently all ave affea ctedtt ffa ecff t our common stock.kk the closingii of the Quartertt Norr rth Att cquisiii tioii n may be affeff ctedtt by factortt s drr ifdd feff rent Our finff ancial position may differ froff m our financial position beforff e the completion of the QuarterNor rth Acquisition, and the results of operations of the combined company may be affected by some factors that are different from those currently affeff cting our results of operations. Accordingly, the market price and performance of our common stock is likely to be diffeff rent from the performance tions in stock markets could have a of our common stock in the absa l operating performance. material adverse effect rth Acquisition. In addition, general fluff ctuat ur common stock, regardless of our actuat ence of the QuarterNor , or liquidity of, off on the market forff ff Our stockhokk lderdd s,rr as of immediadd tely prior to t tt hett QuarterNorNN th Acquisitiott n, willii have reduced ownership in the combineii d companm yn afteff r closingii of the tratt nsaction. Based on the number of shares of common stock outstanding immediately following the closing of the QuarterNorth Acquisition, our existing stockholders would own approximately 86.5% of the outstanding shares of the combined company and QuarterNor rth’s existing members would own approximately 13.5% of the outstanding shares of the combined company. As a result, our current stockholders will have less influence on the policies of the combined company than they currently have following the closing of the QuarterNorth Acquisition. We may na ot consummate the Quartertt Norr rth Att cquisiii tiii on on the tertt ms rr currently cll ontemplated or at all. We may not consummate the QuarterNor rth Acquisition, which is subject to the satisfaction of customary closing conditions. Many of the conditions to completion of the QuarterNorth Acquisition are not within either our or QuarterNorth’s control, and neither we nor QuarterNorth can predict when, or if, tff hese conditions will be satisfied. If any of these conditions are not satisfieff d or waived prior to the outside date, it is possible that the QuarterNorth Acquisition may be terminated. Although we have agreed with QuarterNorth to use reasonabla e best efforts, subju ect to certain limitations, to promptly complete the QuarterNor rth Acquisition, these and other conditions to the completion of the QuarterNorth Acquisition may fail to be satisfied. In addition, satisfying the conditions to and completion of the QuarterNorth Acquisition may take longer, and could cost more, and require additional borrowings, than we currently expect. There can be no assurance that such conditions will be satisfieff d or that the QuarterNorth Acquisition will be consummated on the terms currently contemplated or at all. If additional borrowings are required to consummate the QuarterNor rth Acquisition, our total debt and leverage will be greater than currently anticipated, and our availabia lity under our Bank Credit Facility will be reduced by a corresponding amount. rth Acquisition, our management will have broad discretion in the use of proceeds froff m the January If we fail to complete the QuarterNor EqEquiuityty OfOffefeffff riringng (a(as ds defefininffff eded heherereinin),), anand md mayay ususe se sucuch ph proroceeceedsds inin wawaysys inin whwhicich yh youou dodo notnot apapprproveove.. Failure to complete the Quartertt Norr rth Att cquisiii tiii on could nll our resultsll of operations, cs ash floff ws and finff ancial positiott n. egativtt ely i ll mpii act our stoctt k price and have a material adverserr effeff ct on If the QuarterNor rth Acquisition is not completed forff any reason, including as a result of faiff approvals, we may be materially adversely affect would be subject to a number of risks, including the folff ff lowing: ed and, without realizing any of the benefitsff lure to obtain all requisite regulatoryrr of having completed the acquisition, we • • • • • we may experience negative reactions from the financial markets, including negative impacts on our stock price; we may experience negative reactions from our customers, distributors, suppl and other business partners; u iers, vendors, landlords, joint venturt e partners we will still be required to pay certain significant costs relating to the acquisition, such as legal, accounting, financial advisor ; and printing fees ff QuarterNorth may be entitled to receive the fulff as of January 13, 2024, by and among the Company, QuarterNorth, Compass Star Merger Sub Iu Representatives named therein (the “QuarterNor l amount of the deposit pursuant to the Agreement and Plan of Merger, dated nc. and the Equityholder rth Merger Agreement”); rth Merger Agreement places certain restrictions on our conduct pursuant to the terms thereof, wff the QuarterNor delay or prevent us from undertaking business opportunities that, absent the QuarterNor been pursued; hich may rth Merger Agreement, may have 56 • • matters relating to the acquisition (including integration planning) require subsu tantial commitments of time and resources by our management, which may have resulted in the distraction of our management from ongoing business operations and pursuing other opportunities that could have been beneficial to us; and litigation related to any faiff to perform our obligations pursuant to the QuarterNorth Merger Agreement. lure to complete the acquisition or related to any enforcement proceeding commenced against us If the QuarterNor rth Acquisition is not completed, the risks described above effeff ct on our results of operations, cash floff ws, finff ancial position and stock price. a may materialize and they may have a material adverse Future sales or issuii ances of oo ur common stoctt k could have a negativtt e impii act on our common stock price. If holders of our common stock, by exercising registration rights or otherwise, sell a large number of shares, the market price for our common stock could be adversely affeff cted. It is possible that some QuarterNor rth shareholders will decide to sell some or all of the shares of our common stock that they received as consideration in the QuarterNorth Acquisition. Shortly after the closing of the QuarterNorth Acquisition, we are obligated to file a registration statement covering the resale of potentially all of the shares issued to the QuarterNor rth shareholders. In addition, in connection with the closing of the QuarterNorth Acquisition, we will enter into a registration rights agreement with certain QuarterNorth shareholders, pursuant to which we will grant such holders certain demand, “piggy-back” registration rights with respect to shares of our common stock received by such holders in the acquisition, subju ect to a lock-up pu eriod of 60 days folff lowing the closing. Following the closing of the QuarterNor rth Acquisition, the QuarterNor of our common stock, representing appr acquisition. We expect that at least a majoa rity of those shares will be subju ect to the lock-up period. oximately 13.5% of the outstanding shares of our common stock afteff a rth shareholders will collectively own 24.8 million shares r the closing of that Any disposition by a significant stockholder of our common stock, including by one of the RRA Holders, or the perception in the market that such dispositions could occur, may cause the price of our common stock to fall. Any such decline could impair the combined company’s abia lity to raise capital through future sales of our common stock. Further, our common stock may not qualify f investment lure may discourage new investors froff m investing in our common stock. indices and any such faiff orff ff Our and QuarterNorNN th’s busineii ss relationshipsii may ba e subjeb ct to disruii ptu iott n due to uncertainty associatedtt withii the Quartertt Norr Acquisition, which could hll and folff the closingii loll wingii ave a material adverserr rth Att of the Quartertt Norr cquisiii tiii on. effeff ct on the resultsll of operations, cs ash floff ws and finff ancial position of uo rthtt s pendingii Parties with which we or QuarterNor rth do business may experience uncertainty associated with the QuarterNor rth Acquisition, including with respect to current or future business relationships with us following the closing of the QuarterNorth Acquisition. Our and iers, vendors, landlords, joint venturt e QuarterNorth’s business relationship may be subju ect to disruptu ion as customers, distributors, suppl partners and other business partners may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than us or QuarterNorth following the QuarterNorth Acquisition. These disruptu ions could have a material and adverse effect on the results of operations, cash floff ws and financial position of us, regardless of whether the QuarterNorth Acquisition is completed, as well as a material and adverse effect on rth Acquisition. our ability to realize the expected benefits of the QuarterNor u The Quartertt Norr rth Mtt erMM ger r Agreement subjects utt s to rtt estrictions on our business activtt ities prior to the EffE ecff tive TimTT e. The QuarterNor rth Merger Agreement subju ects us to restrictions on our business activities prior to the closing of the QuarterNor rth rth to generally conduct Acquisition (the “Effeff ctive Time”). The QuarterNor our businesses in the ordinary course until the Effective Time and to use commercially reasonabla e efforts to preserve intact our present business organizations. Additionally, the QuarterNorth Merger Agreement restricts us and QuarterNor rth froff m certain other actions prior to the Effective Time, including, among other things, (i) amending our respective organizational documents, (ii) issuing, selling, pledging, disposing of or encumbering any of our respective securities and (iii) merging, consolidating, combining or amalgamating with any person or acquiring any assets or incurring indebtedness in excess of certain monetary thresholds. rth Merger Agreement obligates each of us and QuarterNor These restrictions could prevent us from pursuing certain business opportunities that arise prior to the Effeff ctive Time. 57 The faiff luii . affeff ct our futff ure resultsll re to successfulff lyll integre ate ott ur busineii ss and opeo rations with Qtt uartertt Norr ii rth i tt n t hett expexx ctedtt time frame may adverserr ly The integration process of our business with those of QuarterNor rth could result in the loss of key employees, customers, providers, vendors or business partners, the disruptu ion of each company’s or all companies’ ongoing businesses, inconsistencies in standards, controls, procedurd es and policies, potential unknown liabia lities and unforff eseen expenses, delays, or regulatory crr onditions or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. Specifically, lowing issues, among others, must be addressed in integrating the operations in order to realize the anticipated benefitff s of the the folff QuarterNorth Acquisition: • • • • • • • combining the companies’ operations and corpor larger, more complex, integrated business; r ate funff ctions and the resulting diffiff culties associated with managing a combining our business with QuarterNorth in a manner that permits the combined company to achieve any cost savings or operating synergies anticipated to result from the QuarterNorth Acquisition; reducing the additional and unforff eseen expenses such that integration costs are not more than anticipated; minimizing the loss of key employees; identifying and eliminating redunda d nt functions and assets; maintaining existing agreements with customers, providers and vendors or business partners and avoiding delays in entering into new agreements with prospective customers, providers and vendors or business partners; and consolidating the companies’ operating, administrative and information technology infrastructurt e. In addition, at times the attention of certain members of our management and resources may be focff used on the integration of the businesses of the companies and diverted from day-to-day business operations or other opportunities that may have been beneficial to us, which may disruptu our ongoing business. Item 1B. Unresolved Staff Comments None. Item 1C. Cybersecurity Assessingii , Igg deII ntiftt yiff ngii and ManMM agingii Cybersecurity Rtt isks — We strive to align our cybersecurity operating model with the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework to enhance our ability to protect, detect, respond, and recover from potential cybersecurity threats. Our cybersecurity team actively works to assess, identify aff nd manage risks in our information system is in o drder to protect hthe c fonfididfff en itialility, iintegriity a dnd av iaillabibia lility fof our didi igital il i fnfraff structurt e. hThe c bybersecu irity team meets regularly to evaluate potential threats, discuss best practices and identify nff ew solutions to help mitigate cyber risks. We engage third-party service providers to conduct evaluations of our cybersecurity controls through penetration testing, independent audits and consulting on best practices to address existing and new challenges. These evaluations include testing the design and operational effectiveness of our cybersecurity controls. To furff ther enhance the capabilities of our internal systems, we utilize third- party vendors to provide extended coverage of our information technology and operational technology environments. We also share and receive threat intelligence with companies in the energy sector, government agencies, inforff mation sharing and analysis centers and cybersecurity associations in order to monitor and address developments in the cybersecurity environment. t To serve as an additional protection froff m outside threats, we also seek to prepare our employees and contractors abou cybersecurity risks through training, simulated phishing exercises and awareness campaigns. We have implemented software and nd evaluate risks froff m cybersecurity threats associated with third-party service vendors. In the event of a processes to help identify aff cybersecurity incident deemed to have a moderate or higher business impact, we have an incident response plan to notify s enior leadership and to address how to contain the incident, mitigate the impact, and restore normal operations effiff ciently. a ff Cybersecurityii Riskii Assessment — We have integrated cybersecurity risk management into our broader Enterprr ise Risk Management (“ERM”) fraff mework to promote a company-wide culturt e of cybersecurity risk management. Our ERM fraff mework is designed to identifyff and prioritize company-wide risks, including cybersecurity threats, and integrate mitigation measures into our business, operational and e of the ERM fraff mework is to enable the Board and executive leadership to (1) align capital structurt e planning activities. The purpos risk management with strategic objectives, (2) identify r isks, including cybersecurity risks, throughout the organization, (3) assess and prioritize risks that could impact the Company’s operational and strategic objectives, (4) develop and monitor risk mitigation initiatives, and (5) report and assess material risks, mitigation strategies and progress to the Board and/or its applicable committees. Cybersecurity risk is reviewed by a cross-functional, management-level ERM Steering Committee as part of the Company’s overall enterprise risk management program. r ff 58 t of Ro Board of Do irectors’ Oversirr ghi isks from Cybersecurity Ttt hrTT eats — The Board of Directors is aware of the importance of managing risks associated with cybersecurity threats. The Audit Committee has been delegated responsibility by the Board for overseeing the Company’s overall enterprise risk management program, including cybersecurity risk. The Audit Committee receives reports at least quarterly from the Director of Information Technology regarding cybersecurity matters, which may include, among other things, the results of cybersecurity audits, cybersecurity maturity assessments, other inforff mation technology matters, risk mitigation strategies, data protection and progress on initiatives. The Audit Committee Chair is responsible for reporting key cybersecurity issues regarding current and potential material cybersecurity threats and our risk mitigation response strategies to the Board. To further inforff m our Board and management on emerging cybersecurity issues, we periodically engage third-party cybersecurity experts to report to the Audit Committee, other directors, and management, as appl icable, on topics that may include, among other things, the latest cybersecurity trends, new technologies, evolving threats in the marketplace, proposed initiatives, legislation, and reporting standards. a rts to comply with appa Managea ment’s Role in Assessingii and ManMM aging CybCC erserr curityii Threats —tt Our inforff mation technology team is responsible for assessing, identifyiff ng and managing cybersecurity risks. Top cybersecurity risks are also integrated into our overall ERM fraff mework and overseen at the management level by the ERM Steering Committee. Our Director of Information Technology, who reports directly to the Chief Financial Officer (“CFO”) and Senior Vice President and is a member of the ERM Steering Committee, is responsible for licable cybersecurity standards, establa ish cybersecurity protocols and protect the integrity, confidff entiality our effoff and availability of our information technology infrastructurt e. Technology and cybersecurity policy decisions are made by our Director of Information Technology in consultation with our CFO and Senior Vice President. In addition, our Director of Information Technology has a direct line of communication with our President and CEO and Executive Vice President and General Counsel as needed. Our Director of Information Technology has over 20 years of experience in cybersecurity, holds a Master of Science in Cybersecurity from sional and a Boardroom Certifieff d Qualified Technology the University of Houston and is a Certifieff d Inforff mation Systems Security Profesff Expert. Impacm t of Ro isks from Cybersecurityii Threats —tt As of the date of this Annual Report, we are not aware of previous cybersecurity incidents that have materially affected or are reasonabla y likely to materially affeff ct the Company, although the Company regularly experiences cybersecurity incidents that are not deemed material to our operations. Examples of cybersecurity threats we facff e include incidents common to most companies in the energy industry,rr such as phishing, business email compromise, ransomware and denial-of-ff service, as well as attacks froff m more advanced sources, including nation state actors, that target companies in the energy industry.rr Our customers, suppl iers, subcontractors and joint venture partners face similar cybersecurity threats, and a cybersecurity incident impacting us or any of these entities could materially adversely disruptu our operations, including our drilling operations, and affeff ct our performance and results of operations. We acknowledge that cybersecurity threats are continually evolving, and the possibility of futurt e cybersecurity incidents remains. Please see Part I, Item 1A. “Risk Factors — Risks Related to our Business and the Oil and Natural Gas Indusd try —rr Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other disruptu ions.” u Item 3. Legal Proceedings WWe are nam ded as a partty iin ce trt iai ln lawsuitits a dnd re lgul tatory prr roce dediings ariisiin ig i tn thhe ordidinary course fof bbusiiness. WWe ddo tnot expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition. In June 2019, David M. Dunwoody, Jr., former President of EnVen, fileff d a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favff or of Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filff ed a Notice of Appeal in December 2021. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supru eme Court on August 2, 2023, which was denied on January 26, 2024. As of December 31, 2023, the Company has recorded $14.3 million as “Other current liabia lities” on the Condensed Consolidated Balance Sheets related to the litigation. 59 rr the Parish of Jeffeff rson (“Jefferson Parish”), on behalf of Jeffeff On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone Energy Corporation (“Stone”) and other named co-defendants, by the Parish of Jeffeff rson Parish and rson, State of Louisiana, alleging violations of the State the State of Louisiana, in the 24th Judicial District Court forff and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rulr es, orders and ordinances thereunder (collectively, the “CRMA”), relating to certain of the defenff dants’ 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 elief, restoration of the Jefferff son Parish Coastal Zone and related costs and attorney’s fees. In March and April damages and declaratory r 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 bankrupt cy in December 2016, Jefferson Parish dismissed its claims against Stone in these three lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources the Eastern were not similarly dismissed. In 2018, the Jeffeff itted to the District of Louisiana. The plaintiffs moved to remand the lawsuit to the state courts. Plaintiffsff filed motions to remand, which the District Court granted, state court forff remanding the lawsuits back to the 24th Judicial District Court forff rson. Defendants who removed the Jefferson Parish lawsuits have filed notices of appeal providing notice that they intend to appe ’ motion to remand. rson Parish lawsuits were removed to the United States District Court forff al the District Court’s orders granting Plaintiffsff decision in two of the lawsuits on Februarr the Parish of Jeffeff a ’ motions to remand were submu ry 15, 2023. Plaintiffsff r rr On November 8, 2013, a lawsuit was filff ed 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 forff the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defenff dants’ 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 r elief, 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 bankrupt cy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiliff ng; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. In state court, the Plaquemines Parish lawsuit was stayed pending the conclusion of trials in five other cases, also filff ed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. However, in the Eastern District of Louisiana. The plaintiffsff 2018, the Plaquemines Parish lawsuit was removed to the United States District Court forff al of have moved to remand the lawsuit to the state courts, but the case was administratively closed in fedff a al was resolved another case, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. That appe filed a motion by the United States Court of Appeals forff the Fifthff Circuit on December 15, 2022, and on December, 22, 2022, plaintiffsff in federal court to re-open the lawsuit. The United States Court of Appeals forff ’ motion filed motions to remand, which the District Court granted. However, the District Court also granted Defendants’ to re-open. Plaintiffsff the Fifthff motion to stay the remand order pending appeal. That appe Circuit. al is currently pending before the United States Court of Appeals forff eral court pending the appe a the Fifthff Circuit has not yet rulr ed on the plaintiffsff a rr Legal proceedings are subject to subsu tantial uncertainties concerning the outcome of material factuat l 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 unabla e to estimate a range of possible losses or any minimum loss froff m such matters. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 14 — Commitmett nd Contingencies for more inforff mation. nts att Item 4. Mine Safety Disclosures a Not appl icable. 60 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 transferff common stock. Dividends agent, as of Februar ry 21, 2024, there were appr a oximately 180 holders of record of our ff We have never declared or paid any cash dividends on our common stock, and we anticipate that any availabla e 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 i ts 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. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 8 — Debt — Limitation on Restricted Payma ents Including Dividends for additional inforff mation. Securities Authorized for Issuance Under Equity Compensation Plans See Part III, Item 12. Security Ownership of Certain Beneficff ial Owners and Management and Related Stockholder Matters for information regarding securities authorized for issuance under equity compensation plans. Purchases of Equity Securities by the Issuer and Affiliated Purchasers Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. Repurchases may be made froff m time to time in the open market, in a privately negotiated transaction, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractuat l limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares. There were no shares of common stock repurchased during the three months ended December 31, 2023. As of December 31, 2023, there is $52.5 million remaining under the authorized program. 61 Stockholder Return Perforff mance Presentation The folff lowing graph is included in accordance with the SEC’s executive compensation disclosure rulr es. This historic stock price performance is not necessarily indicative of futff urt e stock performance. The grapha 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 forff December 31, 2018 through December 31, 2023. The grapha assumes that $100 was invested in our common stock and each index on December 31, 2018 and that dividends were reinvested. Comparison of Cumulative Five Year Total Return $250 $200 $150 $100 $50 $0 12/31/18 12/31/19 12/31/20 12/31/21 12/31/22 12/31/23 Talos Energy Inc. S&P 500 Index Dow Jones U.S. Select Oil Exploration & Production Index Talos Energy Inc. S&P 500 Index Dow Jones U.S. Exploration & Production Index $ $ $ 2018 2019 2020 2021 2022 2023 100 $ 100 $ 185 $ 131 $ 50 $ 156 $ 60 $ 200 $ 116 $ 164 $ 100 $ 110 $ 74 $ 131 $ 208 $ 87 207 216 The performance graph and the inforff mation contained in this section is not “soliciting material,” is being “furnished” not “filff ed” 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 afteff r the date hereof and irrespective of any general incorpor ation language contained in such filinff g. rr Item 6. [Reserved] 62 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The folff lowing 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 Scheduld es; 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. Actuat r materially froff m those anticipated in these forff ward-looking statements. l results may diffeff This section of this Annual Report generally discusses 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 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 forff the year ended December 31, 2022 filed with the SEC. Our Business We are a technically driven independent exploration and production company focff used on safely and efficiently maximizing long- term value through our operations, currently in the U.S. and offsff hore Mexico both through Upstream and the development of low carbon solutions opportunities. We leverage decades of technical and offsff hore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. We are also utilizing our expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico. We have historically focused our operations in the U.S. Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favff orable geologic and economic conditions, including multiple reservoir forff mations, comprehensive geologic and geophysical databaa ses, extensive infraff structurt e and an attractive and robust asset acquisition market. Additionally, we have access to state-of-tff he-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have s to not been previously applied to our current acreage position. We use our broad regional seismic databaa f high-quality prospects, which we believe greatly improves our development and exploration generate a large and expanding inventory orr success. The appl se, 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 collabor ative arrangement opportunities, among others. ication of our extensive seismic databaa se and our reprocessing effort a a ff Outlook We operate within an industry srr new investments in low-carbonr expanding global economy. ector directly impacted by the energy transition. The energy transition will require both significant to meet the expected energy demand of an energies and continued use of traditional hydrocarbons r Our historical focff us in the Gulf of Mexico results in an asset profile that differentiates us froff m the typical shale-driven onshore exploration and production companies. We are continuing to build operational scale. We expect that the QuarterNor rth Acquisition, discussed below, will add scale to our business both in terms of production and operated infraff structurt e, while also diversifyiff ng our production across a broader asset base. While we are currently a pure play Gulf of Mexico company, diversificff ation outside of our existing operational areas is always a possibility. Oil and gas prices are expected to remain relatively stable in 2024. However, geopolitical tensions may contribute to hydrocarbon tion will return to normal without a recession. Future changes to the benchmark interest rate price volatility. For now, it looks like inflaff remain uncertain. However, a modest reduction to the benchmark interest rate is the most likely scenario for 2024. We expect to scale back planned capital expenditures in 2024 compared to 2023. We remain exposed to increasing regulatory s iny and potential operational disruptu ions from weather-related events in the Gulf of Mexico. The limited scope of BOEM's 2024-2029 offsff hore oil and hrough gas leasing program is disappoi exchanges and mergers and acquisitions. nting to offshore producers. However, we have the abia lity to increase our acreage inventory t crutr a r rr rr Significff ant Developments The folff December 31, 2022: lowing encompasses significant developments since the filing of our Annual Report on Form 10-K forff the year ended QuarterNorNN th Acquisition — On January 13, 2024, we executed the QuarterNor privately-held U.S Gulf of Mexico exploration and production company. The QuarterNor first quarter of 2024. Consideration forff of net unrestricted cash of QuarterNor a rth as of December 31, 2023 and (iii) 24.8 million shares of the Company’s common stock. rth Acquisition consists of (i) appr rth Merger Agreement to acquire QuarterNorth, a rth Acquisition is expected to close durd ing the oximately $964.9 million in cash, (ii) the amount the QuarterNor 63 ring”) of 34,500,000 shares of our common stock, resulting in net proceeds to us of appr Equityii Offeff ringii — On January 22, 2024, we closed an upsized firm commitment underwritten public offeff ring (the “January Equity r deducd ting Offeff the January underwriting discounts and commissions and beforff e estimated offeff rth Acquisition Equity Offeff remains subject to certain conditions to closing. Pending the use of the proceeds of the January Equity Offeff , we may temporarily use all or a portion of such proceeds to reducd e the borrowings outstanding under our Bank Credit Facility. In the event ring will be used for general corporate that the QuarterNor rr purpos oximately $388.5 million, afteff ring expenses. We intend to use the net proceeds fromff ring to fund a portion of the cash consideration for the QuarterNorth Acquisition. However, the QuarterNor rth Acquisition is not completed, the proceeds froff m the January Equity Offeff ring as described above es. a a Debt Offeff ringii — On Februarr ry 7, 2024, Talos Production, Inc. issued in an upsized offeff ring (the “Debt Offering”) $1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $625.0 million aggregate principal amount of 9.000% second-priority senior secured notes due 2029 (the “9.000% Notes”) and $625.0 million aggregate principal amount of 9.375% second-priority senior secured notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “New Senior Notes”), in a private offeff ring to eligible purchasers that is exempt froff m registration under the Securities Act. The New Senior Notes were issued pursuant to an indenturt e governing the 9.000% Notes (the “9.000% Notes Indenturt e”) and an indenturt e governing the 9.375% Notes ry 7, 2024 and (the “9.375% Notes Indenturt e” and, together with the 9.000% Notes Indenturt e, the “Indenturt es”), each dated as of Februar by and among the Company, Talos Production Inc., the subsu idiary guarantors party thereto and Wilmington Trusr t, National Association, tee and collateral agent. The New Senior Notes rank equally in right of payment with all existing and future senior obligations of as trusr , 2024, resulted in $1,250.0 million gross the issuer and the guarantors thereto. The issuance of the New Senior Notes on February 7rr proceeds. The net proceeds froff m the Debt Offeff the pending ve, (ii) funded the redemption (the “Redemptions”) of all of the outstanding 11.75% Notes QuarterNorth Acquisition as discussed aboa and expenses related to the (definff ed below) and 12.00% Notes (defined below) (the “Senior Notes”), and (iii) paid premiums, fees Redemptions and the issuance of the New Senior Notes. We intend to use any remaining net proceeds forff es, general corpor which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility. ring (i) are expected to fund a portion of the cash consideration forff ate purpos r r ff An aggregate of $340 million principal amount of the New Senior Notes will be subju ect to a “special mandatory redemption” in rth Merger Agreement are not consummated on or beforff e May 31, 2024 ertain requirements under the Hart-Scott- t Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notifyff the event that the transactions contemplated by the QuarterNor (or up tu Rodino Antitrusr the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition. o September 30, 2024 solely in the event the parties require additional time to satisfy cff Mexiee co Divestiture — On September 27, 2023, we sold a 49.9% interest in Talos Energy Mexico 7, S. de R.L. de C.V., a wholly Carso (the “Mexico Divestiture”). tions and Divestitures for additional information. owned subsidiary of the Company, to Zamajaa l, S.A. de C.V., a wholly owned subsidiary of Grupo See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 3 — Acquisiii r Common StoSS ck Repuee common stto kck repur hchase program A. As of Df Decembbe 3r 311, 2023 imillillion shhare fs forff resulting in $52.5 million remaining under the authorized program. All repurchased shares are held in treasury.rr 2023, we hhave repur hchas ded 3 43.4 rchase Program — On March 20, 2023, we announced that our Board of Directors approved a $100.0 million illimillion $47.5 fof $47 5 ta t tot lal Factors Affecting the Comparability of our Financial Condition and Results of Operations The folff lowing items affect the comparabia lity of our financial condition and results of operations for periods presented herein and could potentially continue to affeff ct our future financial condition and results of operations. EnVen Acquisiii ry 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 3 — Acquisiii tions and Divestitures for additional inforff mation. tioii n — On Februarr Planll ned Downtime tt — We are vulnerabla e to 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 everyrr two to three years forff inspection as required by the U.S. Coast Guard, durd ing which time we are unabla e to produce the Phoenix Field. During the year ended December 31, 2022, Helix dry-docked the HP-I. Afteff r conducting sea trials, production resumed in mid- September, resulting in a total shut-in period of 41 days. The shut-in resulted in an estimated deferred production of approximately 1.6 MBoepd for the year ended December 31, 2022, based on production rates prior to the shut-in. The next dry-dock is scheduld ed for the first half of 2024 with a projeo cted shut-in period of appr oximately 55 days. a During the year ended December 31, 2022, we experienced appr oximately 26 days of planned third-party downtime due to maintenance of the Shell Odyssey Pipeline, which carries our production primarily from our Ram Powell Field, Main Pass 288 Field red production of and non-operated Delta House facff approximately 0.7 MBoepd for the year ended December 31, 2022, based on production rates prior to the shut-in. ility. Production resumed in October 2022. We estimate the shut-in resulted in deferff a 64 Eugeu ne Island Pipeii line SysSS tem — During the first quarter of 2022, we experienced approximately 40 days of unplanned third-party downtime due to maintenance of the Eugene Island Pipeline System, which carries our production froff m the Phoenix Field and Green oximately Canyon 18 Field. For the year ended December 31, 2022, we estimate the shut-in has resulted in deferred production of appr 1.2 MBoepd based on production rates prior to the shut-in. a Known Trends and Uncertainties Volatilityii in Oil,ii Natural GasGG and NGLNN gas and NGL prices are subju ect to wide fluctuations in suppl of growth depends upon the price we receive for our sales of oil, natural gas and NGL production. Prices — Historically, the markets forff oil and natural gas have been volatile. Oil, natural y and demand. Our revenue, profitabia lity, access to capital and futurt e rate u During January 1, 2023 through December 31, 2023, the daily spot prices for NYMEX WTI crude oil ranged froff m a high of ub natural gas ranged froff m a high of $3.78 per $93.67 per Bbl to a low of $66.61 per Bbl and the daily spot prices for NYMEX Henry Hrr MMBtu to a low of $1.74 per MMBtu. Although we cannot predict the occurrence of events that may affeff ct future commodity prices or the degree to which these prices will be affecff 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 truments for volatility on our business. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 6 — Financial InsII more additional inforff mation regarding our commodity derivative positions as of December 31, 2023. ted, the prices forff ry 2024 Short-Term Energy Outlook on Februar The U.S. Energy Inforff mation Administration (“EIA”) published its Februar ry 6, 2024. The EIA expects naturt al gas prices to average $2.65 per MMBtu in 2024, and rise to an average of $2.94 per MMBtu in 2025, up from an average of $2.54 per MMBtu in 2023. Prices are expected to increase because of slowing growth in natural gas production and increasing U.S. liquefied natural gas exports, particularly in 2025 following the addition of new export capacity in late 2024. However, t consumption of naturt al gas in the electric power sector and the EIA expects upwu persistently high inventories. The EIA also expects the NYMEX WTI spot price will average $77.68 per Bbl in 2024 and then falff l to ce demand growth, allowing inventories to build modestly $74.98 per Bbl in 2025 when it expects production growth will slightly outpat and place some downward pressure on crude oil prices. Recent developments in the Middle East increase the risk for supply disruptu ions over the EIA forff ecast, which could result in higher and more volatile prices than the EIA currently forecast. Heightened tensions around the critical Red Sea shipping channel and other developments in the Middle East have added upwu ard price pressure since early December 2023 and have the potential to disruptu global oil trade floff ws and drive up global oil prices further should they escalate or persist. ard price pressures to be limited by relatively flaff , Ss oods Infln atll iott n of Co G osCC t of Go t as oil prices do. In addition, the U.S. inflaff erSS vices and PerPP sorr nnel — Due to the cyclical nature of the oil and gas industry,rr ld goods and services can put pressure on the pricing structurt e within our industry.rr As commodity prices rise, the cost of oilfieff fluctuating demand forff oilfieff ld goods and services generally also increase, while durd ing periods of commodity price declines, oilfield costs typically lag and do not tion rate began increasing in 2021, peaked in the middle of 2022 and adjud st downward as fasff ld began to gradually decline in the second half of 2022. These inflaff goods , s, ervices and pep rsonnel,, which would in turt n cause our capipa tal expep nditures and opep ratingg costs to rise. Sustained levels of higgh g inflation could likely cause the Fed and other central banks to further increase interest rates, which could have the effeff cts of raising the cost of capital and depressing economic growth, either or both of which could hurt our business. In 2022 and 2023, the Fed raised its eral funds rate to a range of 5.25%-5.50%, benchmark interest rate 11 times. The latest interest rate hike in July 2023 increased the fedff its highest level since 2001. The Fed wants inflaff tion to returt n to its 2% goal over time, and even though inflation is declining, it is still high in absolute terms. Future changes to the benchmark interest rate remain uncertain. tionary pressures may also result in increases to the costs of our oilfieff ent of Oo Impaim rmii il and NatNN ural Gas ProPP peo rtiett s — Under the full cost method of accounting, the “ceiling test” under SEC rules and red regulations specififf es that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferff 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 2023, 2022 and 2021 our ceiling test computations for our U.S. oil and gas properties did not result in a write down. At December 31, 2023, the Company’s ceiling test computation was based on SEC pricing of $78.56 per Bbl of oil, $2.75 per Mcf of natural gas and $18.77 per Bbl of NGLs. If the unweighted average firff st-day-of-the-month commodity price forff the period beginning January 1, 2023 and ending December 1, 2023 used in the determination of the SEC pricing was 10% lower, resulting in $70.73 per Bbl of oil, $2.48 per Mcf of natural gas and $16.89 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $321.9 million. oil or naturt al gas forff r crude There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash floff ws from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referff red to in Part I, Item 1A. “Risk Factors.” The discounted present value of our proved reserves is a majoa r component of the Ceiling calculation. Any decrease in pricing, rentials, or increase in capital or operating costs could negatively impact the estimated future discounted negative change in price diffeff net cash floff ws related to our proved oil and naturt al gas properties. 65 BOEMOO Bondindd g Requirei ments —tt In 2016, BOEM issued the 2016 NTL, which bolstered suppl emental bonding requirements forff offsff hore oil and gas lessees. The 2016 NTL was first paused under the Trumr p Administration, and then in 2020, rescinded by BOEM. nd provide greater transparency In October 2020, BOEM pursued a proposed rule published jointly with the BSEE that sought to clarify aff to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublu essees (operating rights owners) and RUERR eral OCS. The DOI under the Biden and ROW grant holders conducting operations on the fedff Administration elected to separate BOEM and BSEE portions of the supplemental bonding requirements. u In April 2023, BSEE published its Final RulRR e entitled, “Risk Management, Financial Assurance, and Loss Prevention – Decommissioning Activities and Obligations,” wherein BSEE clarified decommissioning responsibilities forff RUE grant holders and formalized BSEE’s policies regarding performance by predecessors ordered to decommission OCS facff ilities. The finff al rule withdraws the proposal in the October 2020 proposed rule to amend BSEE’s regulations requiring the agency to proceed in reverse chronological order against predecessor lessees, owners of operating rights and grant holders when requiring such entities to perform their accruerr d decommissioning obligations upon failure to perform by current lessees, owners, or holders. Under the final rulr e, BSEE may issue an order to predecessors to perform accruer d decommissioning obligations, including beginning maintenance and monitoring within thirty days, designating an operator forff itting a decommissioning plan within one hundred fifty days. decommissioning within ninety days, and submu a u On June 29, 2023, BOEM published a proposed rule that, if adopted as initially proposed, would substantially revise the icable to offsff hore oil and gas operations. The proposed rule would change the current emental finff ancial assurance requirements appl suppl u criteria used to determine whether OCS lease and grant holders are required to secure suppl emental finff ancial assurance. The proposed rule would no longer use the current 5-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead proposes a simplified test: (1) the credit rating of the lessee and, where appl icable, (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. Under the the finff ancial strength of predecessors in determining whether, or how proposed rule, BOEM would no longer consider or rely upon much, supplemental finff ancial assurance should be provided by current lessees and grant holders. BOEM would not require suppl emental ve the base bond requirements in three cases: (1) where a lessee has an investment grade credit rating (i.e., a financial assurance aboa credit rating froff m a Nationally Recognized Statistical Ratings Organizations, or NRSRO, that is greater than or equal to either BBB- from S&P or Baa3 from Moody’s, or its equivalent, or a proxy credit rating greater than or equal to either BBB- or Baa3, as determined by the Regional Director and based upon a company’s audited finff ancial information with an accompanying auditor’s certificate); (2) where there are multiple co-lessees on a lease and any one of those lessees meets the credit rating threshold; and (3) for any lease on which all lessees are rated below investment grade, where the value of the lease’s proved oil and gas reserves is at least three times that of the estimated decommissioning cost estimate. BOEM proposes to phase in compliance with the new requirements over a three-year period. The extended public comment period closed on September 7, 2023, and BOEM is reviewing the comments received. At this any finff al decision, or whether time, we cannot predict whether BOEM will adopt the finff al rule in its current form or at all, the timing forff any changes will result froff m the public notice and comment process, but will continue to monitor this rulr emaking. u u u a Moreover, BOEM has the right to issue liabia lity orders in the futff urt e, including if it determines there is a subsu tantial risk of nonperformance of the current interest holder’s decommissioning obligations. In August 2021, BOEM published a Note to Stakeholders lemental financial assurance requirements to certain high-risk, non-sole liability properties; namely, detailing an expansion of its suppu those properties that are inactive, where production end-of-lff ife i er than five years, or with damaged infraff structurt e irrespective of the remaining property life off f the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable requirements related to financial strength and has no co-owners or predecessors that are finff ancially strong, as determined by BOEM. We may be unabla e to provide the finff ancial assurances in the amounts and under the time periods required by BOEM if it submits futff urt e demands to cover our decommissioning obligations. If in the future BOEM issues orders to provide additional finff ancial assurances and we faiff l to comply with such future orders, BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our production and other operations or cancel our applicable federal offshore leases. Our abia lity to obtain adequate suppl emental finff ancial assurance (pursuant to a final BOEM rulr e that is substantially consistent with the June 2023 proposed rule or otherwise), including the futff urt e cost of compliance with respect to supplemental bonding, could materially and adversely affect our liquidity, finff ancial condition, cash floff ws, business, properties and results of operations. s fewff u ff Deepwater OpeOO rations — We have interests in Deepwater fields in the U.S. Gulf of Mexico. Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabia lities forff inff es 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. environmental losses, personal injury arr nd significant regulatory f nd loss of life aff rr Oil Sii piSS llii Response Planll — We maintain a Regional Oil Spill Response Plan that definff es our response requirements, procedurd es 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 forff approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels. 66 Hurricanes, Tropical StoSS rms and Loop Currents —tt Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerabla e to the effeff cts of hurricanes, tropical storms and loop currents on production and capital projects. Significant impacts could include reductions and/or deferrals of futff urt e oil and naturt al gas production and revenues and increased lease operating expenses for evacuations and repairs. ting court rulr Program Update —tt Five-Year Offsff hore Oil aii nd Gas Leasingii Under the OCSLA, as amended, BOEM within the DOI must prepare and maintain forff ward-looking five-year plans—referff red to by BOEM as national programs or fivff e-year programs—to schedule proposed n May 11, 2022, the DOI cancelled two lease auctions in the Gulf of oil and gas lease sales on the U.S. Outer Continental Shelf. Off Mexico, Lease Sales 259 and 261 included in the 2017-2022 national program that was developed under the Obama Administration, which expired on June 30, 2022. The DOI cited “conflicff ings” as the primary reason for not holding the two Gulf of Mexico lease sales. The IRA,RR which President Biden signed into law on August 16, 2022, reinstated Lease Sale 257 held in November 2021, and required the DOI to both accept all valid high bids received in Lease Sale 257 and issue leases to the high bidders. We were one of the most active bidders in Lease Sale 257 and we were the high bidder on ten (10) blocks and awarded leases on nine (9) blocks. In January 2023, BOEM released its final environmental impact statement forff Lease Sales 259 and 261 and, in March 2023, announced the results of Lease Sale 259, in which we were the high bidder on four r blocks. Lease Sale 261 was scheduld ed to be held on November 8, 2023, pursuant to a September 21, 2023 court order from the United States the Western District of Louisiana, as amended by a September 25, 2023 court order from the United States Court of District Court forff Appeals forff the Fifthff Circuit stayed its and the ing, scheduling oral arguments for November 13, 2023. On November 2, 2023, BOEM announced the postponement District Court’s rulr of Lease Sale 261 as a result of the United States Court of Appeals forff the Fifthff Circuit’s October 26, 2023 order. Pursuant to the United the Fifthff Circuit’s November 14, 2023 order, BOEM held Lease Sale 261 on December 20, 2023, in which States Court of Appeals forff we were the high bidder on thirteen offshore blocks and were awarded four ry 16, 2024. As BOEM is still in its bid evaluation, we are awaiting BOEM’s award decisions on our remaining high bids. the Fifthff Circuit. However, on October 26, 2023, the United States Court of Appeals forff offsff hore blocks, and were awarded leases on all fouff leases as of Februarr ff ff BOEM’s development of a new fivff e-year national program typically takes place over several years, during which successive draftsff it the Proposed oved by review and comment. At the end of the process, the Secretary orr r which the program may be appr a period of at least 60 days, afteff f the Interior must submu of the program are published forff Final Program (“PFP”) to the President and to Congress forff the Secretary orr f the Interior and may take effeff ct with no further regulatory orr r legislative action. a BOEM took the firff st formal step in pursuit of a new five-year national program in January 2018 by releasing a Draft Pff roposed , a Proposed Program (“PP”), which is open forff Program. The OCSLA and its implementing regulations call forff itted to Congress and the President for 60 days before public comment for a period of at least 90 days, and then a PFP, which is submu nd final Programmatic Environmental implementation. These later program stages also are accompanied by publication of a draft aff Impact Statement (“PEIS”), with a period forff the 2023-2028 five-year period were published in the Federal Register on July 8, 2022, with a 90-day comment period. The PP included no more than ten potential lease sales in the Gulf of Mexico. On Septp ember 29,, 2023,, the PFP for 2024-2029 was ppublished and includes a maximum of three potential oil and gas lease sales in the Gulf of Mexico scheduld ed to be held in years 2025, 2027 and 2029. On December 14, 2023, the Secretary orr f the Interior approved the final program in a combined decision memo and Record of Decision and the final program is set to become effeff ctive on July 1, 2024. public comment on the draft PEIS. The PP and a draft Pff EIS forff two subsequent draftsff 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 Adjud sted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below. 67 Basis of Presentation Sources of Revenues Our revenues are derived froff m 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, naturt al 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 2023 Year Ended December 31, 2022 2021 93 % 5 % 2 % 83 % 14 % 4 % 86 % 10 % 4 % Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Realizll ed Prices on the SalSS e oll il, Natural GasGG and NGLNN s — The NYMEX WTI prompt month oil settlement price is a widely r froff m the used benchmark in the pricing of domestic oil in the United States. The actuat quoted NYMEX WTI price as a result of quality and location diffeff rentials. For example, the prices we realize on the oil we produce are affeff cted by the Gulf of Mexico Basin’s proximity to U.S. Gulf Coast refinff eries and the quality of the oil production sold in Eugene Island Crude l prices we realize froff m the sale of oil diffeff and Heavy Louisiana Sweet Crude , Louisiana Light Sweet Crude markets. f Oo r rr rr The NYMEX Henry Hrr l prices we realize froff m the sale of natural gas differ froff m the quoted NYMEX Henry Hrr ub price of naturt al gas is a widely used benchmark forff actuat differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub wu minimal differential in the prices we receive for our production versus average Henry Hrr the pricing of natural gas in the United States. The ub price as a result of quality and location hich creates a ub prices. In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the ub monthly contract prices as tabla e below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hrr 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: ub high per MMBtu ub low per MMBtu NYMEX Henry Hrr NYMEX Henry Hrr Average NYMEX Henry Hrr Average naturt al gas sales price per Mcf (including commodity derivatives) Average naturt al gas sales price per Mcf (excluding commodity derivatives) ub per MMBtu 2023 Year Ended December 31, 2022 2021 $ $ $ $ $ $ $ $ $ $ 89.43 70.25 77.63 73.59 75.17 3.27 2.14 2.54 3.32 2.60 $ $ $ $ $ $ $ $ $ $ 114.84 76.44 94.79 68.40 93.75 8.81 4.38 6.42 5.30 7.06 $ $ $ $ $ $ $ $ $ $ 81.48 52.01 67.99 49.67 65.86 5.51 2.62 3.91 3.11 3.98 NGLs: NGL realized price as a % of average NYMEX WTI 23 % 35 % 39 % To achieve more predictable cash floff w, and to reducd e exposure to adverse fluff ctuat tions in commodity prices, we enter into commodity derivative arrangements forff 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 reducd tions in oil and natural gas prices on our cash floff w froff m operations for those periods. However, our price risk management activity may also reduce our ability to benefit froff m 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 instrumrr ents to manage commodity price risk in the future. Our hedging strategy and futff urt e 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. 68 Expexx nses a Lease OpeOO rating ExpeEE , insurance, a portion of the HP-I lease, materials and suppl nse — 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 ies, rental and third party costs comprise the most significant portion of our lease operating expense. It further consists of costs associated with majoa r 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 feeff s related to certain reimbursements forff costs froff m certain third parties. u Productiott n TaxTT es — 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. Depree eciatiott n, Deplee etll iott n and Amortizaii capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the fulff and naturt al gas activities. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 2 — Summary of Signi Accounting Policies for furff tion expexx nse — Depreciation, depletion and amortization expense is the expensing of the oil ant l cost method of accounting forff fici ther discussion. i Accretiott n ExpeEE nse — We have obligations associated with the retirement of our oil and natural gas wells and related infrastructurt e. 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 accruer a liabia lity 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 liabia lity is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life off f the related assets as the discounted liabilities are accreted to their expected settlement values. General and Admidd niii stii ratt including payroll and benefits for our corporate staff, cff operations, bad debt expense, equity-based compensation expense, audit and other fees overhead, osts of maintaining our headquarters, costs of managing our producd tion for professional services and legal compliance. tive Expexx nse — General and administrative expense generally consists of costs incurred forff ff Interest Expexx nse — We finance a portion of our working capital requirements, capital expenditures and acquisitions with tions red ), commitment fees, imputed interest on our capital lease, performance bond . Interest expense is net of capitalized interest on expenditures made in connection with exploratoryrr borrowings under our Bank Credit Facility and term-based debt. As a result, we incur interest expense that is affected by both fluff ctuat in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferff financing costs (including origination and amendment fees premiums and annual agency fees projects that are not subju ect to current amortization. ff ff Price Risk ManMM agement Activitieii s — We utilize commodity derivative instrumr tions in the prpricice oe of of oilil anand nd natatururtt alal gagass. WeWe rerecocognignizeze gagainins as andnd lolossesses as assssocociaiateted wd withith ourour opeopen cn comommomodidityty dederirivavativtive ce contontraractcts as as cs comommomodidityty 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 forff es. 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 floff w is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterpar ents to reduce our exposure to fluff ctuat accounting purpos rty. r 69 Results of Operations Revenues The inforff mation below provides a discussion of, aff nd an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands, except per unit data): Revenues: Oil Natural gas NGL Total revenues 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) 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) Year Ended December 31, 2023 2022 Change 1,357,732 $ 68,034 32,120 1,457,886 $ 1,365,148 $ 227,306 59,526 1,651,980 $ (7,416) (159,272) (27,406) (194,094) 18,062 26,194 1,767 24,195 49.5 71.8 4.8 66.3 75.17 $ 2.60 $ 18.18 $ 60.26 $ 59.86 $ 14,561 32,215 1,793 21,723 39.9 88.3 4.9 59.5 93.75 $ 7.06 $ 33.20 $ 76.05 $ 56.46 $ 3,501 (6,021) (26) 2,472 9.6 (16.5) (0.1) 6.8 (18.58) (4.46) (15.02) (15.79) 3.40 $ $ $ $ $ $ $ The inforff mation below provides an analysis of the change in our oil, natural gas and NGL revenues in our Upstream Segment, due to changes in sales prices and production volumes (in thousands): Revenues: Oil Natural gas NGL Total revenues Price Volume Total $ $ (335,635) $ (116,764) (26,543) (478,942) $ 328,219 $ (42,508) (863) 284,848 $ (7,416) (159,272) (27,406) (194,094) Volumetric Analysll is — Production volumes increased by 6.8 MBoepd to 66.3 MBoepd for the year ended December 31, 2023. The increase was primarily due to 17.6 MBoepd in producd tion froff m the oil and natural gas assets acquired in the EnVen Acquisition. Additionally, production volumes increased due to the third party downtime for the HP-I dry-rr dock in our Phoenix Field, the Eugene Island Pipeline System shut-in primarily impacting HP-I and Green Canyon 18 Field and the Shell Odyssey Pipeline shut-in primarily lity, which resulted in 3.5 MBoepd of deferred impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House faci production durd ing 2022. These increases were partially offsff et by a decrease of 13.4 MBoepd due to well performance and naturt al production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field. ff 70 Operatintt g ExpeEE nses Lease OpeOO rating ExpeEE nse The folff lowing tabla e highlights lease operating expense items in total and on a cost per Boe production basis to our Upstream Segment. The inforff mation 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, 2023 2022 $ $ 389,621 $ 16.10 $ 308,092 14.18 Total lease operating expenses for the year ended December 31, 2023 increased by approximately $81.5 million, or 26%. The increase is primarily related to lease operating expenses of $86.8 million incurred in connection with assets acquired froff m the EnVen Acquisition. Additionally, there was a $11.3 million decrease in production handling feeff costs froff m certain third parties related to our historical operations. This increase was partially offsff et by a $17.1 million decrease in facility and workover expense related to repairs and maintenance at the Phoenix Field compared to the same period in 2022. s related to reimbursements forff Depree eciatiott n, Deplee etll iott n and Amortizatiott n The folff lowing tabla e highlights depreciation, depletion and amortization items. The information below provides the financial results and an analysis of significant variances in these results (in thousands): Depreciation, depletion and amortization $ 663,534 $ 414,630 Year Ended December 31, 2023 2022 Depreciation, depletion and amortization expense for the year ended December 31, 2023 increased by appr oximately $248.9 million, or 60%. This increase was primarily due to an increase of $8.28 per Boe, or 44% in the depletion rate on our proved oil and natural gas properties dued to an increase in our proved properties and related production primarily related to the assets acquired as part of the EnVen Acquisition, which resulted in $176.3 million of additional depletion. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 3 — Acquisiii further discussion on the EnVen Acquisition. Additionally, the depletion rate increased due to the extension of the HP-I lease during the fourth quarter of 2022. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 5 — Leases for additional inforff mation on the HP-I lease extension. tions and Divestitures” forff a General and Admindd istrativtt e ExpEE ense The folff lowingg tabla e higghligghts ggeneral and administrative expep nse items in total and on a cost pper Boe pproduction basis forff the Upstream Segment. The inforff mation below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data): Upstream Segment CCS Segment Unallocated corporr rate Total general and administrative expense Upstream general and administrative expense per Boe Year Ended December 31, 2023 2022 $ $ $ 139,026 $ 11,922 7,545 158,493 $ 5.75 $ 82,979 10,240 6,535 99,754 3.82 General and administrative expense forff the year ended December 31, 2023, increased by approximately $58.7 million, or 59%. This increase was primarily related to higher Upstream Segment transaction costs for the closing and continued integration of the EnVen Acquisition of $31.4 million or $1.26 per Boe. The Upstream Segment also had an increase in legal fees of $5.1 million or $0.21 per Boe dued to the Dunwoody litigation assumed as part of the EnVen Acquisition. See Part IV, Item 15. Exhibits and Financial Statement ther discussion. Additionally, there was an increase in payroll expense Schedules — Note 14 — Commitmett due to additional employee headcount primarily related to the EnVen Acquisition. These increases were partially offsff et by a decrease in non-cash equity-based compensation of $3.0 million, primarily due to a forff feiture during the third quarter of 2023. nd Contingencies for furff nts att 71 Miscii ellall neous The folff lowing tabla e highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands): Accretion expense Other operating (income) expense Interest expense Price risk management activities (income) expense Equity method investment (income) expense Other (income) expense Income tax (benefit) expense Year Ended December 31, 2023 2022 $ $ $ $ $ $ $ 86,152 $ (52,155) $ 173,145 $ (80,928) $ (3,209) $ (12,371) $ (60,597) $ 55,995 33,902 125,498 272,191 (14,222) (31,800) 2,537 Accretiott n ExpeEE nse — During the year ended December 31, 2023, we recorded $86.2 million of accretion expense compared to $56.0 million during the year ended December 31, 2022. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of the EnVen Acquisition. See Part IV, Item 15. Exhibits and Financial Statement ther discussion. Schedules — Note 3 — Acquisiii tions and Divestitures for furff Othett xpeEE come) Ee r OpeOO rating (In(( nse — During the year ended December 31, 2023, we recognized a gain of $66.2 million on the Mexico Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 3 — Acquisiii tions and Divestitures for further discussion. This gain was partially offsff et by $11.9 million of estimated decommissioning obligations primarily as a result of unrelated parties or counterpar cy or insolvency. During the year ended December 31, 2022, we recorded $31.6 million of estimated decommissioning obligations. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 14 — Commitments and Contingencies. rties that were unabla e to perform the required abaa ndonment obligations due to bankrupt r Interest Expexx nse — During the year ended December 31, 2023, we recorded $173.1 million of interest expense compared to $125.5 million during the year ended December 31, 2022. The change is primarily a result of the increase in interest associated with the 11.75% Notes assumed as part of the EnVen Acquisition. Additionally, there was an increase in interest associated with the Bank Credit ther discussion in Facility due to increased interest rates and average borrowings when compared to the same period in 2022. See furff Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 8 — Debt. Price Risk ManMM agement Activitieii year ended December 31, 2023 resulted in a decrease of approximately $353.1 million, or 130%. The income of $80.9 million for the year ended December 31, 2023 consisted of $90.4 r value of our open derivative contracts offset by $9.5 million in cash settlement million in non-cash gains froff m the increase in the faiff lolossessess. ThThe ee expexpensnse oe of $f $272 2 425.6 milmilliolion in in cn casash sh setettletlemementnt lolosssseses anandd $153.4 million in non-cash gains from the increase in the fair value of our open derivative contracts. s — Price risk management activities forff ththe ye yearear enendeded Dd Decemecembeber 3r 311, 2022 2022 coconsnsisisteted od of $f $425 6 272.2 mimilliollion fn fororffff These unrealized gains and losses on open derivative contracts relate to production forff 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 2025, we expect these activities to continue to impact net income (loss) based on fluff ctuat tions in market prices for oil and naturt al gas. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 6 — Financial InsII truments for additional inforff mation. Equityii Method Investment IncII ome — During the year ended December 31, 2023, we recorded $12.1 million of equity losses offsff et by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron. During the year ended December 31, 2022, we recorded a $13.9 million gain on the partial sale and $1.4 million gain on the fundi ng of the capital carry of our equity method investment in Bayou Bend offsff et by equity losses of $1.1 million. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investmett ntstt for additional inforff mation. ff Othett r (In(( xpeEE come) Ee nse — During the year ended December 31, 2022, we recorded a $27.5 million gain as a result of the settlement agreement to resolve a previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 14 — Commitments and Contingencies. This was partially offset by a $1.6 million loss on extinguishment of debt as a result of the redemption of the 12.00% Notes furff ther discussed in Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 8 — Debt. 72 enefitff (ExpeEE Income Tax Baa nse) — During the year ended December 31, 2023, we recorded $60.6 million of income tax benefit compared to $2.5 million of income tax expense durd ing the year ended December 31, 2022, primarily due to a non-cash tax benefit of our deferred tax assets partially offsff et with an income tax expense $106.8 million related to the release of the valuation allowance forff of $31.1 million related to current year activity inclusive of permanent differences for the year ended December 31, 2023. The realization of our deferred tax asset depends on recognition of sufficff ient future taxabla e income in specific tax jurisdictions in which temporaryrr differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not red tax assets will not be realized. See additional inforff mation on the valuation allowance as described in that some portion of the deferff Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 11 — Income Taxeaa s. Commitments and Contingencies For a further discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 14 — Commitmett nd 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. nts att 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 floff ws or results of operations. See Part I, Item 3. Legal Proceedings for additional information. Supplemental Non-GAAP Measure EBITDA aDD nd Adjudd stedtt EBITDADD “EBITDA” and “Adjud sted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional inforff mation to evaluate, with certain adjud stments, items required or permitted in calculating covenant compliance under our emental indicators of the operational performance of our business, (iii) additional criteria forff debt agreements, (ii) important suppl evaluating our performance relative to our peers and (iv) suppl certain material non-cash and/or other items that may not continue at the same level in the futff urt e. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes forff analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of finff ancial performance presented in accordance with GAAP. emental inforff mation to investors about u u a We define these as the following: • • EBITDADD — Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense. Adjudd stedtt EBITDA —DD EBITDA plus non-cash write-down of oil and naturt al gas properties, transaction and other (income) r value of derivatives (mark to market effeff ct, net of cash expenses, decommissioning obligations, the net change in the faiff settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense. 73 The folff lowing tabla e presents a reconciliation of the GAAP financial measure of net income (loss) to Adjud sted EBITDA for each of the periods indicated (in thousands): Net income (loss) Interest expense Income tax expense (benefit) Depreciation, depletion and amortization Accretion expense EBITDA Write-down of oil and naturt al gas properties Transaction and other (income) expense(1) Decommissioning obligations(2) Derivative fair value (gain) loss(3) Net cash received (paid) on settled derivative instrumr (Gain) loss on debt extinguishment Non-cash write-down of other well equipment Non-cash equity-based compensation expense ents(3) Adjud sted EBITDA 2023 Year Ended December 31, 2022 2021 $ $ 187,332 $ 173,145 (60,597) 663,534 86,152 1,049,566 — (33,295) 11,879 (80,928) (9,457) — — 12,953 950,718 $ 381,915 $ 125,498 2,537 414,630 55,995 980,575 — (34,513) 31,558 272,191 (425,559) 1,569 — 15,953 841,774 $ (182,952) 133,138 (1,635) 395,994 58,129 402,674 18,123 5,886 21,055 419,077 (290,164) 13,225 5,606 10,992 606,474 (1) (2) (3) tions and Divestitures. The amount includes a gain on the fundi tions and Divestitures and Note 10 — Emplm oyee Benefite Plans and Share-Based ComCC pem nsation. Other income (expense) includes restrucrr Transaction expenses include $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expenses ther discussion in Part IV, Item 15. Exhibits and Financial Statement Scheduldd es — Note 3 for the years ended December 31, 2023 and 2022, respectively. See furff — Acquisiii turing expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningfulff indicator of our operating performance. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 3 — Acquisiii ng of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the the year ended December 31, 2022. See furff partial sale of our investment in Bayou Bend to Chevron forff ther discussion in Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 7 — Equity Method Investmett ntstt . For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15. Exhibits and Financial Statement Scheduldd es — Note 14 — Commitments and Contingencies. Estimated decommissioning obligations were a result of working interest partners or counterparr required abaa ndonment obligations due to bankrupt and Contingencies for additional inforff mation on decommissioning obligations. The adjud stments forff adjud sting net loss for changes in the fair value of derivative instrumrr commodity derivative instrumrr unr ents have the effect of ents, which are recognized at the end of each accounting period because we do not designate ents as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjud sted EBITDA on an rties of divestiturt e transactions that were unabla e to perform the cy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 14 — Commitments r value (gains) losses and net cash receipts (payments) on settled commodity derivative instrumrr lealiiz ded bba isi ds durd iing thhe pe iri dod hth de deriivatiives se lttledd. the derivative faiff rr ff Liquidity and Capital Resources capia tal expenditures, working capital, debt service, share repurchases and forff Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary es. The cost uses of cash are forff of borrowing under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed is making it more expensive to borrow money. Our working capital deficit has decreased since December 31, 2022 primarily due to a decrease of $61.1 million in liabia lities froff m price risk management activities and an increase of $11.1 million in assets from price risk management activities. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 6 — Financial InsII truments for additional information. As of December 31, 2023, our availabla e liquidity (cash plus availabla e capacity under the Bank Credit Facility) was $787.9 million. general corpor ate purpos ff rr r We fund drilling, completions and development activities primarily through operating cash floff ws, cash on hand and through d significant acquisitions with the issuance of senior borrowings under the Bank Credit Facility, if necessary. Historically, we have funde notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjud st our capia tal budget in response to changing operating cash floff w forff ecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities. We are continuing to explore a capital raise to finff ance the accelerated growth of our CCS segment. ff 74 Capia taii l ExpeEE nditdd ures — The folff lowing is a table of our capital expenditures, excluding acquisitions, forff the year ended December 31, 2023 (in thousands): U.S. drilling & completions Mexico appraisal & exploration Asset management(1) Seismic and G&G, land, capia talized G&A and other Total Upstream capital expenditures Plugging & abaa ndonment Decommissioning obligations settled(2) Total Upstream Investment in CCS Total $ $ 447,254 291 83,970 64,955 596,470 86,615 50,584 733,669 40,961 774,630 (1) (2) Asset management consists of capia tal expenditures forff activities primarily associated with recompletions and improvements to our facilities and infrastructurt e. Settlement of decommissioning obligations as a result of working interest partners or counterparr required abaa ndonment obligations due to bankrupt and Contingencies for additional inforff mation on decommissioning obligations. development-related rr rties of divestiture transactions that were unabla e to perform the cy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 14 — Commitments Based on our current level of operations and availabla e cash, we believe our cash floff ws from operations, combined with availabia lity under the Bank Credit Facility, provide sufficient liquidity to fund our board approved 2024 Upstream capital spending program of $565.0 million to $595.0 million and plugging & abaa ndonment and decommissioning obligations of $90.0 million to $100.0 million. However, our ability to (i) generate suffiff cient cash floff ws from operations or obtain futff urt e borrowings under the Bank Credit Facility, and (ii) repay or refinff ance any of our indebtedness on commercially reasonabla e terms or at all forff any potential futff urt e acquisitions, joint venturt es 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 producd tion), but we could be required to, or we or our affiliates may from time to time, take additional futff urt e actions on an opportunistic basis. To address further changes in the financial and/odd r commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinff ance our outstanding indebtedness. Common StoSS ck Repuee approved limit of $100.0 million and no set term limits. In March and June of 2023, we repurchased 1.9 million shares forff and 1.5 million shares forff program. All repurchased shares are held in treasury.rr rchase Program — Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an $26.6 million $20.9 million, respectively. As of December 31, 2023, there is $52.5 million remaining under the authorized RRepur hchases ma by be m dad fe froff m tiime to itime iin hthe open markket, iin priivat lely negotiiatedd transactiions, o br by suchh o hther means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will l limitations and other considerations. The program may be extended, modified, suspended or depend on market conditions, contractuat discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares. The IRA 2022 provides forff , among other things, the imposition of a new 1% U.S. fedff eral excise tax on certain repurchases of r December 31, 2022. Accordingly, the excise tax applies to our share stock by publicly traded U.S. corporations such as us afteff es. Subject to certain exceptions and adjustments, repurchase program. The excise tax payment is non-deductible for income tax purpos ation durd ing the applicable tax year. The repurchase the excise tax equals 1% of the faiff ation durd ing a taxabla e year, amount subju ect to the excise tax is generally reducd ed by the faiff including the faiff ation or employees of certain of its subsu idiaries. The current federal administration has proposed increasing the excise tax amount from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any change can take effect. We do not anticipate paying any excise tax in 2023 based on the fair market value of the stock issuance in connection to the EnVen Acquisition. r market value of any stock issued or provided to employees of a corpor r market value of the stock repurchased by a corpor r market value of any stock issued by a corpor r r r r Overview of Cash Flowll Activities — The folff lowing tabla e summarizes cash floff ws provided by (used in) by type of activity, forff the following periods (in thousands): Operating activities Investing activities Financing activities Year Ended December 31, 2023 2022 $ $ $ 519,069 $ (512,626) $ 85,411 $ 709,739 (311,977) (423,469) Operatintt g Activtt itiett s — Net cash provided by operating activities decreased $190.7 million in 2023 compared to 2022 primarily attributable to a decrease in revenues combined with an increase in lease operating expense of $275.6 million. 75 Investing Activtt ities — Net Cash used in investing activities increased $200.6 million in 2023 compared to 2022 primarily due to an increase in capital expenditures of $238.3 million. The capital expenditure budget forff 2023 included projeo cts related to the EnVen Acquisition. Additionally, we had an increase in contributions to equity method investees of $27.2 million and investment in intangibles of $12.4 million. This was offset by cash proceeds of $74.9 million froff m the Mexico Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisiii tions and Divestitures for additional inforff mation. Finaii ncing Activtt ities — Net cash used in finff ancing activities increased $508.9 million in 2023 compared to 2022. We had net ng of the EnVen borrowings from the Bank Credit Facility of $200.0 million forff Acquisition, working capital needs and capital expenditures. We had net repayments of $375.0 million durd ing the same period in 2022 due to a management goal to reducd e our leverage ratio coupled with a commodity price environment that supported debt repayments to achieve such goal. See Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 3 — Acquisiii tions and Divestitures for additional inforff mation on the EnVen Acquisition. We repurchased $47.5 million of our common stock through our share repurchase program during the year ended December 31, 2023. See the subsu ection entitled “— Common Stock Repurchase Program” forff additional information. Additionally, there was an increase in redemption of senior notes of $11.8 million and deferred finff ancing costs of $11.6 million in each case when compared to the same period in 2022. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt. the year ended December 31, 2023 due to the fundi ff Overview of Debt Instrutt mentstt Finaii ncing Arrangements —tt oximately $1,025.7 million, comprised of our $866.0 million aggregate principal amount of the 12.00% Notes and 11.75% Notes (as defined herein) and $200.0 million outstanding under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2023. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 8 — Debt. As of December 31, 2023, total debt, net of discount and deferff red finff ancing costs, was appr a – matures March 2027 — We maintain a Bank Credit Facility with a syndicate of finff ancial institutions. The Bank Creditdd Facilityii determination of the borrowing base based on our proved producing reserves and a portion of our Bank Credit Facility provides forff 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 8 — Debt. 12.00% Second-Pdd riPP ority Senior Secured NotNN estt —due January 2026 — The 12.00% Notes were issued pursuant to an indenturt e dated January 4, 2021 and the first supplemental indenturt e dated January 14, 2021 between Talos Energy Inc. (the “Parent Guarantor”); tee Talos Production Inc. (the “Issuer”); the Subsu idiary Guarantors (definff ed below); and Wilmington Trusr and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities forff es under the indenturt es. The 12.00% Notes were secured on a second-priority senior secured basis by liens on subsu tantially the same collateral as the collateral securing the Issuer’s existing firff st-priority obligations under its Bank Credit Facility. The 12.00% Notes were scheduled to mature on Januaryy 15,, 2026 and had interest pap yay bla e semi-annuallyy each Januaryy 15 and July 1y 5. We made an interest payment of $38.3 million on January 16, 2024. For additional details on the 12.00% Notes, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 8 — Debt. t, National Association, as trusrr r all purpos On January 23, 2024, we issued a conditional notice to redeem in full the 12.00% Notes at a redemption price of 103.000% of the principal amount thereof, plus accruerr d and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes ring. indenturt e. The 12.00% Notes were redeemed on Februar ry 7, 2024 for $662.4 million utilizing the net proceeds froff m the Debt Offeff 11.75% Senior Secured SecoSS nd Lien Notes—due AprA il 2026 — On February 1rr 3, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes dued 2026 (the “11.75% Notes”) with a principal amount of $257.5 million. The 11.75% Notes were scheduld ed to mature on April 15, 2026 and interest accruer d and was paid semi-annually in cash in arrears on April 15th and October 15th of each year. The 11.75% Notes were secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The indenturt e governing the 11.75% Notes required the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year. For additional details on the 11.75% Notes, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 8 — Debt. On January 26, 2024, we issued a conditional notice to redeem in full the 11.75% Notes at a redemption price of 102.938% of the principal amount thereof, plus accruerr d and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes with the trustee sufficient to satisfy and discharge the 11.75% Notes indenturt e and the 11.75% indenturt e. We irrevocably deposited funds Notes until redeemed on April 15, 2024 with the funds deposited with the trustee and elected to satisfy and discharge the 11.75% Notes indenturt e in accordance with its terms and the 11.75% Notes trustee acknowledged such discharge and satisfaction. We deposited $247.5 million with the trustee on Februarr ry 7, 2024 utilizing the net proceeds froff m the Debt Offeff ring. ff ff 76 9.000% Second-Pdd riPP ority Senior Secured NotNN estt —due FebFF ruary 2r 029 — The 9.000% Notes were issued pursuant to the 9.000% Notes indenturt e. The 9.000% Notes rank pari passu in right of payment and constitutt e a single class of securities for all purpos es under the indenturt e. The 9.000% Notes are secured on a second-priority senior secured basis by liens on subsu tantially the same collateral as the collateral securing the Issuer’s existing firff st-priority obligations under its Bank Credit Facility. The 9.000% Notes maturt e on Februar ry 1, 2029 and have interest payable semi-annually each Februar ry 1 and August 1. r 9.375% Second-Pdd riPP ority Senior Secured NotNN estt —due FebFF ruary 2r 031 — The 9.375% Notes were issued pursuant to the 9.375% es under Notes indenturt e. The 9.375% Notes rank pari passu in right of payment and constitutt e a single class of securities for all purpos the indenturt e. The 9.375% Notes are secured on a second-priority senior secured basis by liens on subsu tantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes maturt e on Februar ry 1, 2031 and have interest payable semi-annually each Februar ry 1 and August 1. r Guarantor FinFF ancial Infon rmatiott n — We own no operating assets and have no operations independent of our subsu idiaries. 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 futff urt e direct or indirect wholly owned material restricted subsu idiaries that guarantees the Issuer’s Bank Credit Facility (collectively, the “Subsu idiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”). Our non-domestic subsu idiaries (other than Talos International Holdings SCS) and our unrestricted CCS domestic subsu idiaries (the “Non-Guarantors”) are 100% owned by us but do not guarantee the 12.00% Notes. In lieu of providing separate financial statements forff emental summarized combined balance sheet and statement of operations information forff the Issuer and the Guarantors, we have presented the accompanying suppl the Issuer and the Guarantors on a u combined basis after elimination of intercompany transactions and amounts related to investment in any subsidiary that is a Non- Guarantor.rr The folff lowing tabla e presents the balance sheet information forff the respective periods (in thousands): Current assets Non-current assets Total assets Current liabilities Non-current liabilities Talos Energy Inc. stockholdersʼ equity Total liabia lities and stockholdersʼ equity The folff lowing tabla e presents the income statement inforff mation (in thousands): Revenues Costs and expenses Net income (loss) Year Ended December 31, 2023 2022 $ $ $ $ 409,112 $ 4,352,102 4,761,214 $ 577,587 $ 2,082,543 2,101,084 4,761,214 $ 344,525 2,571,254 2,915,779 599,669 1,285,992 1,030,118 2,915,779 Year Ended December 31, 2023 $ $ 1,457,886 (1,258,327) 199,559 Material Cash Requirements — We are party to various contractuat l obligations. Some of these obligations may be refleff cted 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. 77 The folff lowing tabla e and discussion summarizes our material cash requirements froff m known contractuat l obligations as of December 31, 2023 (in thousands): Long-term financing obligations: Debt principal Debt interest Vessel commitments(1) Derivative liabia lities Operating lease obligations Finance lease(2) Purchase obligations(3) Other commitments(4) Total contractuat l obligations(5) 2024 2025 2026 2027 2028 Thereafter Total(5) $ 30,000 $ 123,084 13,216 7,305 4,748 19,336 3,083 3,991 30,000 $ 806,041 $ 200,000 $ 119,559 — 795 4,716 — — 327 68,975 — — 4,803 — — — 5,152 — — 4,708 — — — $ 204,763 $ 155,397 $ 879,819 $ 209,860 $ — $ — — — 4,610 — — — 4,610 $ — $ 1,066,041 — 316,770 13,216 — 8,100 — 28,169 4,584 19,336 — 3,083 — 4,318 — 4,584 $ 1,459,033 (1) (2) (3) (4) (5) the HP-I floff ating production faci l obligations and accordingly, other joint owners in the properties operated by us will be billed forff Includes vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments their working interest share of such represent gross contractuat costs. Lease agreement forff Includes committed purchase orders to execute planned futff urt e drilling activities. Includes commitments associated with our CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement. dismantlement, abandonment and restoration costs of oil and natural gas properties of $897.2 This table does not include our estimated discounted liability forff million as of December 31, 2023. For additional inforff mation regarding these liabia lities, please see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 9 — Asset Retirement Obligations. Additionally, this table does not include liabia lities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 14 — Commitment and Contingencies. lity in the Phoenix Field. ff Debt principal of $638.5 million associated with the 12.00% Notes refleff cted in the table above was redeemed on February 7rr , 2024 from proceeds froff m the Debt Offeff ring. There was $191.8 million of interest refleff cted in the table above associated with the 12.00% Notes. Debt principal of $227.5 million associated with the 11.75% Notes refleff cted in the table above will be redeemed on April 15, ring. There was $58.0 million of interest refleff cted in the table above associated with the 11.75% 2024 from proceeds froff m the Debt Offeff f Notes. The New Senior Notes have an aggregate principal amount of $1,250.0 million with interest of $688.9 million over the life off the New Senior Notes. Perforff marr nce Obligll atiott ns — As of December 31, 2023, we had secured performance bonds totaling $1.4 billion primarily related to plugging and abaa ndonment of wells and removal of facff ilities in the U.S. Gulf of Mexico and certain obligations under the PSCs with Mexico from third party sureties. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the availabla e revolving credit commitments. See the subsu ection entitled “— KnowK n Trends and Uncertainties — BOEM Bonding Requirements” for additional inforff mation on the future cost of compliance with respect to BOEM suppl emental bonding requirements that could have a material adverse effect on our business, properties, results of operations and finff ancial condition. u For additional inforff mation about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 14 — Commitmett nts att nd Contingencies. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affeff ct the reported amount of assets, liabia lities, revenue and expense, and the disclosures of contingent assets and liabia lities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the s and accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in fact circumstances may result in revised estimates and actuat r materially from those estimates. Our management has lowing critical accounting estimates. Our significant accounting policies are described in Part IV, Item 15. Exhibits and identified the folff fici ant Accounting Policies. Financial Statement Schedules — Note 2 — Summary of Signi l results may diffeff ff i tt Proved Reserve EstEE ima l cost method of accounting, tes — We account for our oil and natural gas producing activities using the fulff which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the value of our evaluated oil and naturt al gas properties is permanently impaired based on the quarterly full cost ceiling impairment test. We estimate our proved oil, natural gas and NGL reserves in accordance with the guidelines establa ished 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 reasonabla e 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. 78 Our estimates of proved reserves are made using availabla e 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 dued to reaching economic limits at an earlier projeo cted 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. The depletion of our proved oil and naturt al gas properties is calculated using the unit-of-pff roduction method based on proved oil and gas reserves. If the proved reserves used had been a 10 percent lower, depreciation, depletion and amortization in the three months ended December 31, 2023 would have increased by an estimated $19.4 million. Furthermore, the Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues froff m proved reserves, computed using a discount factor of 10%, plus the r value of unproved oil and naturt al gas properties not being amortized less the related tax effects. Downward lower of cost or estimated faiff revisions of previous reserve quantity estimates accounted for appr oximately $484.4 million of the standardized measure of our total reserves from December 31, 2022 to December 31, 2023. The Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties durd ing the years ended December 31, 2023, 2022 and 2021. a Asset Retirtt ement Obligll atiott ns — The Company has obligations associated with the retirement of its oil and natural gas wells and related infraff structurt e. 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 abaa ndons them. The Company accruer s a liabia lity 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 liabia lity 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 tion rate. Changes in estimate in the table below represent changes to the expected amount and timing of payments and a projected inflaff to settle its asset retirement obligations. Typically, these changes result froff m obtaining new inforff mation about the timing of its r initial recording, the liabia lity is increased for the obligations to plug and abaa ndon oil and natural gas wells and the costs to do so. Afteff 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 accruer d forff asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties. a income taxes under GAAP which results in the recognition of deferff Income Taxeaa s — Our provision for income taxes includes U.S. state and fedff eral and forff eign taxes. We record our federal income red tax assets and liabia lities taxes in accordance with accounting forff for the expected future tax consequences of temporary drr rences between the book carrying amounts and the tax basis of assets and liabia lities. Deferred tax assets and liabia lities are measured using enacted tax rates expected to apply to taxable income in the years in rences and carryforwards are expected to be recovered or settled. The effeff ct on deferred tax assets and which those temporary drr liabia lities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is tnot bbe re laliiz ded A. As of Df Decembbe 3r 311, esttablbla iishhed td to r deducd 2023, we believe it is more likely than not that some or all of the benefits from our state deferff red tax assets will not be realized and reduced the state deferred tax assets by a valuation allowance. ty thhan n tot thth tat ththe r lel tat ded tta bx ben fefititffff s willill red td tax assetts ifif itit iis more liklik lel de d feferff iffeff iffeff We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary l outcome r significantly from our estimates, which could impact our financial position, results of course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actuat of these futff urt e tax consequences could diffeff operations and cash floff ws. We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a tax position taken or expected to be taken in a tax returt n. Authoritative guidance a recognition threshold and measurement attribute forff uncertainty in income taxes requires that we recognize the finff ancial statement benefitff of a tax position only after for accounting forff lowing an audit. For tax positions meeting determining that the relevant tax authority would more likely than not sustain the position folff the more likely than not threshold, the amount recognized in the finff ancial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. aiFF r Vi Determinatiott n of Fo ss Combinatiott ns — We account for business combinations under the acquisition method of identifiaff bla e assets acquired and liabia lities assumed equal to their estimated accounting. Accordingly, we recognize amounts forff acquisition date fair values. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the acquisition date amounts of the identifiaff bla e net assets acquired. alVV ue in Busineii We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market- based measurement, it is determined based on the assumptions that market participants would use. The most significff ant assumptions relate to the estimated fair values of proved and unproved oil and naturt al gas properties. 79 The faiff r value of proved and oil naturt al gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash floff ws. Significant inputs to the valuation include estimates of futff urt e producd tion volumes, futff urt e operating and development costs, futff urt e commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments are appl ied to proved developed non-producing, proved undeveloped, probabla e and possible reserves to refleff ct the relative uncertainty of each reserve class. a The estimates used in determining faiff r values are based on assumptions believed to be reasonabla e but which are inherently r value. Historically there has been uncertain. Accordingly, actuat significant volatility in oil, natural gas and NGL prices and estimates of such futff urt e prices are inherently imprecise. Additionally, the actuat rent than the projeo ction. Cash flows realized later in the projection period are less valuable than those realized earlier dued to the time value of money. A higher discount rate decreases the net present value of cash floff ws. r froff m the projected results used to determine faiff l timing of the production could be diffeff l results may diffeff Recently Adopted Accounting Standards None. Recently Issued Accounting Standards Information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part IV, Item 15. Exhibit and Financial Statement Schedules — Note 1 — Organi tion, Nature of Business and Basis oii resentation. f Po zaii r 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 ents to mitigate the impact of market price risk exposures primarily management activities involve the use of derivative financial instrumrr 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 fisff cal quarter rolling basis. For any quarter occurring during the first fouff r forff ward fiscal quarters, we are required to hedge a minimum of 50% of our reasonabla y anticipated projected production from proved developed producing reserves froff m the semi-annual reserves report delivered to the administrative agent of our Bank Credit Facility, adjusted to 45% in July and November and 25% in August, September and October. For the fifth and sixth forff ward fiscal quarters, if the Consolidated Total Debt to EBITDAX Ratio (as definff ed in the Bank Credit Facility) is greater than or equal to 1.00 to 1.00, then we are required to hedge a minimum of 25%, adjusted to 20% in August, September and October. All derivatives are recorded on the Consolidated Balance Sheets at faiff r 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 inin eaeachch pepeririod.od. Commodity Price Risks Oil and natural gas prices can fluff ctuat year ended December 31, 2023, our average oil price realizations afteff $68.40 per Bbl in the comparabla e 2022 period. Our average natural gas price realizations afteff during the year ended December 31, 2023 to $3.32 per Mcf from $5.30 per Mcf in the comparabla e 2022 period. te significantly and have a direct impact on our revenues, earnings and cash floff w. During r the effeff ct of derivatives increased 8% to $73.59 per Bbl from r the effeff ct of derivatives decreased 37% Price Risk Management Activities We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and naturt al gas production through the use of oil and natural gas swaps. These contracts will impact our earnings as the faiff r 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 subju ect to commodity price risks on our remaining forff ecasted production. 80 We had commodity derivative instruments in place to reduce the price risk associated with future production of 9,833 MBbls of crude f naturt al gas at December 31, 2023, with a net derivative asset position of $45.6 million. For additional oil and 15,515 MMBtu ot r information regarding our commodity derivative instruments, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note truments, included elsewhere in this Annual Report. The table below presents the hypothetical sensitivity of our 6 — Financial InsII commodity price risk management activities to changes in faiff r values arising from immediate selected potential changes in oil and natural gas prices at December 31, 2023 (in thousands): Price impact(1) Oil and Natural Gas Derivatives Ten Percent Increase Ten Percent Decrease Fair Value Fair Value Change Fair Value Change $ 45,603 $ (21,481) $ (67,084) $ 113,601 $ 67,998 (1) Presents the hypothetical sensitivity of our commodity price risk management activities to changes in faiff r values arising from changes in oil and naturt al gas prices. Variable Interest Rate Risks We had total debt outstanding of $1,066.0 million at December 31, 2023, before unamortized original issue discount and deferff red finff ancing costs. Of this, $866.0 million aggregate principal was from our 12.00% Notes and 11.75% Notes, which bears interest at a fixed rate. The remaining $200.0 million is froff m 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 availabla e 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. As of December 31, 2023, our interest rate risk exposure is mitigated as a result of fixff ed interest rates on 81% of our debt. The all-in interest rate on our variable rate debt at December 31, 2023 was 8.26%, which includes a spread of 2.85% based on the utilization rate of our Bank Credit Facility, and a secured overnight financing rate (”SOFR”) of 5.41%. A 10% change in the SOFR rate on this variabla e rate the year ended December 31, 2023 by approximately $1.1 million. debt balance at December 31, 2023 would change interest expense forff For additional inforff mation regarding the borrowing base utilization percentage associated with our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Scheduld es — Note 8 — Debt, included elsewhere in this Annual Report. Item 8. Financial Statements and Supplementary Data See the Consolidated Financial Statements and Report of Independent Registered Publu ic Accounting Firm as of December 31, the years ended December 31, 2023, 2022 and 2021, included in Part IV, Item 15. Exhibits and Financial 2023 and 2022 and forff Statements Schedules. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. 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 effeff ctiveness of our disclosure controls and procedurd es (as definff ed 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. Based on such evaluation, our chief executive offiff cer and chief finff ancial offiff cer have concluded that as of December 31, 2023, our disclosure controls and procedures are designed at a reasonabla e assurance level and are effective to provide reasonabla e assurance that inforff mation we are required to disclose in reports that we file or submu it under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rulrr es and forff ms of SEC, and that such information is accumulated and communicated to our management, including our chief executive officer and chief finff ancial offiff cer, as appr opriate, to allow timely decisions regarding required disclosures. a Management’s Annual Report on Internal Control over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over finff ancial reporting as definff ed in Rule 13a-15(f) under the Exchange Act. Management conducted an assessment of the effeff ctiveness of our internal control over finff ancial 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 finff ancial reporting was effeff ctive as of December 31, 2023 to provide reasonabla e assurance regarding the reliabia lity of financial reporting and the preparation of finff ancial 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 finff ancial reporting, which is included in this Annual Report. 81 Changes in Internal Control over Financial Reporting There were no changes in our internal controls over finff ancial reporting identified in management's evaluation pursuant to RulRR es 13a-15(d) or 15d-15(d) of the Exchange Act durd ing the fourth quarter of 2023 that materially affeff cted, or are reasonabla y likely to materially affeff ct, our internal control over finff ancial reporting. Item 9B. Other Information During the three months ended December 31, 2023, no director or offiff cer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K. Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection a Not appl icable. 82 Item 10. Directors, Executive Officers and Corporate Governance PART III The inforff mation required by this item is incorpor rr ated by reference to our Proxy Statement forff the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fisff cal year ended December 31, 2023. Our Board of Directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors and employees, which is availabla e on our website (www.talosenergy.gg com) under “Corporate Governance” within the “Investors” tab.a 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 inforff mation on the website address and location specified above. Item 11. Executive Compensation The inforff mation required by this item is incorpor rr ated by reference to our Proxy Statement forff the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fisff cal year ended December 31, 2023. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The inforff mation required by this item is incorpor rr ated by reference to our Proxy Statement forff the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fisff cal year ended December 31, 2023. Item 13. Certain Relationships and Related Transactions, and Director Independence The inforff mation required by this item is incorpor rr ated by reference to our Proxy Statement forff the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fisff cal year ended December 31, 2023. Item 14. Principal Accounting Fees and Services The inforff mation required by this item is incorpor rr ated by reference to our Proxy Statement forff the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fisff cal year ended December 31, 2023. 83 Item 15. Exhibits and Financial Statement Schedules (a) The following documents are filff ed 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 finff ancial statements filed as part of this Annual Report on Form 10-K. (2) Financial Statement Schedules: Other than as stated on the Index to Consolidated Financial Statements on page F-1 with respect to Schedule I, finff ancial statement scheduld es have been omitted because they are either not material, not required, not applicable or the informff ation required to be presented is included in our Consolidated Financial Statements and related notes. (3) Exhibits: Exhibit Number 2.1# 2.2# 3.1 3.2 4.1 4.2 4.3 4.4 4.5 4.6 4.7 Agreement and Plan of Merger, dated as of September 21, 2022, by and among Talos Energy Inc., Talos Production Inc., Tide Merger Sub Iu II LLC, BCC Enven Investments, L.P. and EnVen Energy Corporation (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022). Inc., Tide Merger Sub II LLC, Tide Merger Sub Iu Description Agreement and Plan of Merger, dated as of January 13, 2024, by and among Talos Energy Inc., QuarterNorth Energy ated by reference to Inc., Compass Star Merger Sub Iu Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024). nc. and the Equityholder Representatives named therein (incorpor r rr Second Amended and Restated Certificff ate of Incorpor ry 14, 2023). 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on Februarr ation of Talos Energy Inc. (incorpor rr ated by reference to Exhibit Second Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 1rr 4, 2023). Indenturt e, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and ated by reference to Exhibit 4.1 to Wilmington Trusrr Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021). tee and as collateral agent (incorpor t, National Association, as trusrr r Form of Stock Certificate forff 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 Februar ry 9, 2018). First Supplemental Indenturt e, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trusr ated 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). tee and as collateral agent (incorpor t, National Association, as trusr rr Indenturt e, dated as of February 7rr Wilmington Trusr reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7rr , 2024, and by and among Talos Production Inc., the Guarantors named therein and tee, pursuant to which the 2029 Notes were issued. (incorporated by , 2024). t, National Association, as trusr Indenturt e, dated as of February 7rr Wilmington Trusr reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7rr , 2024, and by and among Talos Production Inc., the Guarantors named therein and tee, pursuant to which the 2031 Notes were issued. (incorporated by , 2024). t, National Association, as trusr Form of 12.00% Second-Priority Senior Secured Note dued r (incorpor January 8, 2021). 2026 (included as Exhibit A to Exhibit 4.6 hereto) ated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on Form of 9.000% Second-Priority Senior Secured Note dued (incorpor r Februar 2029 (included as Exhibit A to Exhibit 4.4 hereto) ated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on ry 7, 2024). 84 4.8 4.9 4.10 4.11 4.12 4.13 4.14 4.15 4.16 10.1 10.2 10.3† 10.4† 10.5† 10.6† 10.7† Form of 9.375% Second-Priority Senior Secured Note dued (incorpor r Februar 2031 (included as Exhibit A in Exhibit 4.5 hereto) ated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on ry 7, 2024). 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). Registration Rights Agreement, dated September 21, 2022, by and among Talos Energy Inc. and the Persons listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022). Description of Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorpor ated by reference to Exhibit 4.10 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on r March 1, 2023). u Second Suppl therein and Wilmington Trusr Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 28, 2022). emental Indenturt e, dated as of October 27, 2022, among Talos Production Inc., the Guarantors named ated by reference to tee and as collateral agent (incorpor t National Association, as trusrr rr Indenturt e, dated as of April 15, 2021, by and among Energy Venturt es GoM LLC, EnVen Finance Corporr ration, Talos Production Inc. (as successor in interest to EnVen Energy Corporation), the other guarantors party thereto and ated by reference to Exhibit 4.1 to r Wilmington Trusrr Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on Februar tee and as collateral agent (incorpor t, National Association, as trusrr ry 14, 2023). u emental Indenturt e, dated as of February 1rr Second Suppl rr party thereto and Wilmington Trusrr ry 14, 2023). Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on Februarr 3, 2023, among Talos Production Inc., each of the other guarantors ated by reference to tee and collateral agent (incorpor t, National Association, as trusr 3, 2023, among Talos Production Inc., Energy Venturt es GoM LLC, t, National Association, as tee and collateral agent (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001- Third Supplemental Indenturt e, dated as of February 1rr EnVen Finance Corporation, each of the other guarantors party thereto and Wilmington Trusr trusr 38497) filed with the SEC on February 1rr 4, 2023). 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 (incorpor ated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K12B/A filed with the SEC on July 18, 2018). rr Intercreditor Agreement, dated as of May 10, 2018, between JPMorgan Chase Bank, N.A., as First Lien Agent, and Wilmington Trusr t, 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). r Letter between Talos Energy Inc. and Shannon Young, dated as of April 13, 2019 (incorpor Offeff Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on April 24, 2019). rr ated by reference to r Letter between Talos Energy Inc. and Robert D. Abendschein, dated as of December 26, 2019 (incorpor Offeff ated 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). r Employment Agreement, dated as of February 3rr Timothy S. Duncan (incorpor Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018). , 2012, by and between Talos Energy Operating Company LLC and ated by reference to Exhibit 10.10 to Talos Energy Inc.’s Amendment No. 3 to the r Employment Agreement, dated as of February 3rr A. Parker (incorpor Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018). , 2012, by and between Talos Energy Operating Company LLC and John ated by reference to Exhibit 10.12 to Talos Energy Inc.’s Amendment No. 3 to the Registration rr Employment Agreement, dated as of August 30, 2013, by and between Talos Energy Operating Company LLC and William S. Moss III (incorpor ated 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). rr 85 10.8† 10.9† 10.10† 10.11 Separation and Release Agreement by and between the Company and Robert D. Abendschein, effeff ctive December 26, 2023 (incorpor ated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 29, 2023). rr 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 (incorpor Q (File No. 001-38497) filed with the SEC on May 6, 2021). rr ated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10- under Production Sharing Modality (Contract Area 7), dated Contract for the Exploration and Extraction of Hydrocarbons as of September 4, 2015, by and among the National Hydrocarbons Commission, Sierra O&G Exploración y Producd ción, r S. de R.L. de C.V., Talos Energy Offsff hore 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). r 10.12†* Form of Indemnificff ation Agreement (Directors and Offiff cers). 10.13† 10.14† 10.15† 10.16† 10.17† 10.18† 10.19† 10.20† 10.21† 10.22† 10.23† 10.24† Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors) (incorpor Exhibit 10.20 to Talos Energy Inc.’s Form 10-Q filff ed with the SEC on August 9, 2018). r ated by reference to Form of Talos Energy Inc. Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit ated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) Agreement (Directors) (incorpor filed with the SEC on May 6, 2021). rr 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 Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorpor rated by referff ence 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). Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit AgAgrereememenent (t (DiDirerectctorors)s) (i(incncororporpor 38497) atateded byby rerefefererencnce te to Eo Exhixhibibit 1t 10 10.1 toto TaTalolos Es Enenergrgy Iy Incnc ’. s Fs Fororm 1m 100-Q (Q (FiFilele NoNo 0. 00101-38497) filed with the SEC on November 3, 2021). rrr Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorpor rated by referff ence to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001- 38497) filed with the SEC on May 5, 2022). 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 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001- 38497) filed with the SEC on May 5, 2022). Form of Performance Share Unit Cancellation and Release Agreement (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 5, 2022). 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). Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorpor 38497) filed with the SEC on May 9, 2023). ated by reference to Exhibit 10.5 to Talos Energy Inc.’s Form 10-Q (File No. 001- r 86 10.25 10.26 10.27 10.28 10.29 10.30 10.31 10.32 10.33* 10.34# 21.1* 22.1* 23.1* 23.2* 24.1* Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffiff rmation 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 (incorpor ated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on July 10, 2019). r 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 (incorpor ated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on r 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 (incorpor ated 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). r 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 (incorpor ated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on r 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. ated by reference to Exhibit 10.45 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC (incorpor r ry 25, 2022). on Februar Borrowing Base Redetermination Agreement and Eighth Amendment to Credit Agreement, dated as of May 4, 2022, 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. (incorpor ated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on r August 05, 2022). Incremental Agrg eement of Increasing Lg enders, d, ated as of May 4y , 2, 022,, byy and amongg DNB Cappital LLC and Mizuho Bank, Ltd, as increasing lender, Talos Production Inc., as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, swingline lender and issuing bank and Natixis, New York Branch, as issuing bank.(incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on August 05, 2022). Incremental Agreement and Ninth Amendment to Credit Agreement, dated as of December 23, 2022, among Talos Energy Inc., Talos Production Inc., each other Credit Party, JPMorgan Chase Bank, N.A., as Administrative Agent, each ated by reference to Exhibit 10.1 to Talos Energy Issuing Bank, the Swingline Lender and each of the Lenders (incorpor Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 27, 2022). r Tenth Amendment to Credit Agreement, dated January 13, 2024, by and among Talos Energy Inc., as Holdings and a Guarantor, Talos Production Inc., as the Borrower, the other Guarantors party thereto, JPMorgan Chase, N.A., as the Administrative Agent, and the Lenders party thereto. Form of QuarterNorth Suppor parties thereto (incorpor with the SEC on January 1rr r 6, 2024). u t Agreement, by and among QuarterNorth Energy Inc., Talos Energy Inc. and the other ated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed List of Subsu idiaries of Talos Energy Inc. List of Subsu idiary Guarantors and Issuers of Guaranteed Securities. Consent of Ernst & Young LLP. Consent of Netherland, Sewell & Associates, Inc. Powers of Attorney (included on signature pages of this Part IV). 87 31.1* 31.2* 32.1** 97.1* 99.1* Certificff ation of Chief Executive Officer of Talos Energy Inc. pursuant to RulRR e 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbar nes-Oxley Act of 2002. Certificff ation of Chief Financial Officer of Talos Energy Inc. pursuant to RulRR e 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbar nes-Oxley Act of 2002. Certificff ation 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. Talos Energy Inc. Executive Compensation Clawback Policy, effeff ctive November 15, 2023. Netherland, Sewell & Associates, Inc. reserve report forff Talos Energy Inc. as of December 31, 2023. 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 Labea l. 101.PRE* Inline XBRL Taxonomy Extension Presentation. 104* Cover Page Interactive Data File – The cover page interactive data fileff its XBRL tags are embedded within the Inline XBRL document. does not appear in the Interactive Data File because * ** † # Filed herewith. Furnished herewith. Identifieff s 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 NoNonene. 88 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 duld y authorized. SIGNATURES Date: February 2rr 8, 2024 By: TALOS ENERGY INC. /s/ Sergio L. Maiworm, Jr. Sergio L. Maiworm, Jr. Chief Financial Offiff cer and Senior Vice President POWER OF ATTORNEY KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Timothy S. Duncan and Sergio L. Maiworm, Jr., and each of them, as his or her true and lawfulff attorneys-in-fact and agents, with full power of subsu titution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and the same, with all exhibits thereto, and other documents in connection therewith, with the all amendments to this report, and to fileff l power and authority to do Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, fulff and perform each and every act and thing requisite and necessary to be done in connection therewith, as fulff es as he or she might or could do in person, hereby ratifying and confirff ming that all said attorneys-in-fact and agents, or any of them or their or his or her substitute or subsu titutes, may lawfully do or cause to be done by virtuet ly to all intents and purpos hereof.ff rr Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the folff lowing persons on behalf of the Registrant and in the capacities and on the dates indicated. Date February 2rr 8, 2024 Februar ry 28, 2024 Februar ry 28, 2024 February 28, 2024 Februar ry 28, 2024 FFebbruar 2024 ry 2828, 2024 February 28, 2024 Februar ry 28, 2024 February 28, 2024 Februar ry 28, 2024 Signature /s/ Timothy S. Duncan Timothy S. Duncan /s/ Sergio L. Maiworm, Jr. Sergio L. Maiworm, Jr. abcock /s/ Gregory Brr abcock Gregory Brr /s/ Paula R. Glover Paula R. Glover /s/ Neal P. Goldman Neal P. Goldman //s/ J/ J hohn “B“Brad”d” JJuneau John “Brad” Juneau /s/ Donald R. Kendall, Jr. Donald R. Kendall, Jr. /s/ Richard Sherrill Richard Sherrill /s/ Charles M. Sledge Charles M. Sledge /s/ Shandell Szabo Shandell Szabo Title Chief Executive Officer (Principal Executive Officff er, Director) Chief Financial Offiff cer (Principal Financial Offiff cer, Authorized Signatory) Chief Accounting Officer (Principal Accounting Officer, Authorized Signatory) Director Director DiDirector Director Director Director Director 89 Index to Consolidated Financial Statements Reports of Independent Registered Publu ic Accounting Firm (PCAOB ID 42) ............................................................................. Consolidated Balance Sheets as of December 31, 2023 and 2022................................................................................................. Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021................................................ Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2023, 2022 and 2021 ........... Consolidated Statements of Cash Flows forff the years ended December 31, 2023, 2022 and 2021 .............................................. Notes to Consolidated Financial Statements .................................................................................................................................. Note 1 — Organization, Nature of Business and Basis of Presentation ................................................................................... Note 2 — Summary of Significant Accounting Policies........................................................................................................... Note 3 — Acquisitions and Divestitures ................................................................................................................................... Note 4 — Property, Plant and Equipment ................................................................................................................................. Note 5 — Leases ....................................................................................................................................................................... Note 6 — Financial Instruments................................................................................................................................................ Note 7 — Equity Method Investments...................................................................................................................................... Note 8 — Debt........................................................................................................................................................................... Note 9 — Asset Retirement Obligations ................................................................................................................................... Note 10 — Employee Benefitff Plans and Share-Based Compensation...................................................................................... Note 11 — Income Taxes.......................................................................................................................................................... Note 12 — Income (Loss) Per Share......................................................................................................................................... Note 13 — Related Party Transactions ..................................................................................................................................... Note 14 — Commitments and Contingencies ........................................................................................................................... Note 15 — Segment Information .............................................................................................................................................. Note 16 — Supplpp emental Oil and Gas Disclosures ((Unaudited)) ............................................................................................. Note 17 — Subsequent Events .................................................................................................................................................. Schedule to Consolidated Financial Statements............................................................................................................................. Schedule I — Condensed Financial Inforff mation of Registrant................................................................................................. F-2 F-6 F-7 F-8 F-9 F-10 F-10 F-10 F-16 F-18 F-19 F-21 F-23 F-24 F-28 F-28 F-31 F-33 F-34 F-35 F-37 F-39 F-42 F-43 F-43 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, 2023 and 2022, the related consolidated statements of operations, changes in stockholders' equity and cash floff ws for each of the three years in the period red to as the ended December 31, 2023, and the related notes and the financial statement schedule listed in Item 15(a) (collectively referff “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, 2023 and 2022, and the results of its operations and its cash flows forff each of the three years in the period ended December 31, 2023, in conforff mity 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 finff ancial reporting as of December 31, 2023, 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 Februarr ry 28, 2024 expressed an unqualified opinion thereon. Basis forff Opinion These finff ancial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s finff ancial statements based on our audits. We are a public accounting firff m registered with the PCAOB and are required to eral securities laws and the applicable rules and regulations be independent with respect to the Company in accordance with the U.S. fedff 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 reasonabla e assurance aboa to error or fraud. to error Our audits included performing procedurd es to assess the risks of material misstatement of the financial statements, whether dued or fraud, and performing procedurd es that respond to 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 reasonabla e basis for our opinion. ut whether the financial statements are free of material misstatement, whether dued Critical Audit Matter The critical audit matters communicated below are matters arising froff m the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the finff ancial statements and (2) involved our especially challenging, subju ective, or complex judgments. The communication of the crcritiiticalcal auaudidit mt matattetersrs doedoes ns notot alalteter ir in an anyny waway oy ourur opiopininionon onon ththe ce consonsololididatateded fifinanancnciaial sl statatetemementnts,s, tatakeken an as as a whwholole,e, anand wd we ae arere notnot,, by communicating the critical audit matter below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which it relates. Depree eciatiott n, deplee etll iott n and amortizatiott n of po roved oil and gas propertiett s. Descripti ion of to hett Matter As described in Note 2 to the consolidated financial statements, the Company follows the fulff of accounting forff of proved oil and gas properties is calculated using the unit-of-pff gas reserves, as estimated by the Company’s internal reservoir engineers. l cost method its oil and gas properties. Depreciation, depletion and amortization (“DD&A”) of the cost roduction method based on proved oil and ased on evaluations of estimated in-place hydrocarbon Proved oil and gas reserves are prepared using standard geological and engineering methods generally recognized in the petroleum industry brr volumes using financial and non-financial inputs. 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 and evaluation of inputs, including historical production, future oil and gas price assumptions, futff urt e 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 forff all properties as of December 31, 2023. r Auditing the Company’s DD&A expense 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. F-2 How We AWW ddressed the Matter in Our Audit We obtained an understanding, evaluated the design, and tested the operating effeff ctiveness of the Company’s controls that address the risks of material misstatement relating to the DD&A expense calculation, including management’s controls over the completeness and accuracy of the finff ancial data provided to the engineers for use in estimating oil and gas reserves. Our audit procedurd es included, among others, evaluating the profesff sional qualificff ations and objectivity of the Company’s internal reservoir engineers responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineers used to audit the proved oil and gas reserve estimates. On a sample basis, we tested the completeness and accuracy of the finff ancial data used in the estimation of proved oil and gas reserves by agreeing significant inputs to source documentation, where availabla e, and assessing the inputs for reasonabla eness based on review of corroborative evidence and consideration of any contrary evidence. Additionally, we performed analytic and lookback procedurd es on select inputs into the oil and gas reserve estimate. Finally, we tested that the DD&A expense calculations are based on the appr opriate proved oil and gas reserve balances from the Company’s reserve report. a Evaluation of the faiff Corporatiott n business combinaii r vi tion alue measurement of oo il and gas propertiett s acquirei d in t ii hett EnVen Energygg Descripti ion of to hett Matter As described in Note 3 to the consolidated financial statements, the Company executed a merger agreement oximately $1.0 billion. The transaction net consideration of appr a to acquire EnVen Energy Corporr was accounted for as a business combination. ration forff The Company applied a discounted cash flow method to estimate the faiff r value of the proved and unproved oil and gas properties acquired. Significant judgment is required by the Company’s internal reservoir engineers in evaluating geological and engineering data when estimating oil and gas reserves. Significant inputs to the valuation of proved and unproved oil and gas properties include estimates of futff urt e oil and gas price assumption and production profiles of reserve estimates, reserve category r ors and discount rate using a market-based weighted average cost of capital. isk adjustment fact ff rr Auditing the Company’s determination of the fair value of the proved and unproved oil and gas properties to the significant estimation required by management of reserves associated with acquired was complex dued the acquired assets and the sensitivity of the significant assumptions used in determining the fair value. In evaluating the reasonabla eness of management’s estimates and assumptions used, the audit testing procedurd es performed required a high degree of auditor judgment and additional effort, including involving internal specialists. HoHow Ww We Ae AWWWW ddrddresessesed td thehe Matter in Our Audit WeWe obtobtaiainened ad an un undendersrstatandindingng, evevalaluauateted td thehe dedesisigngn anand td tesesteted td thehe opeoperaratitingng efeffefeffff ctctivivenenesess os of tf thehe CoCompmpanany’y ss internal controls over its process to estimate the faiff r value of the acquired proved and unproved oil and gas properties, including management’s review of the significant assumptions used as inputs to the fair value calculations. To test the estimated faiff r value of the acquired proved and unproved oil and gas properties, our audit procedurd es included, among others, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data suppor ting the significant assumptions. For example, we compared and assessed certain significant assumptions to current industry orr r third-party data for reasonabla eness. u We also performed sensitivity analyses of significant assumptions, to evaluate the extent of their impact to the faiff r value calculation. In addition, we involved our valuation specialists to assist with certain significant assumptions included in the fair value estimate. Furthermore, we evaluated the professional qualificff ations r value of and objectivity of the third-party valuation specialist engaged by the Company to prepare the faiff the acquired proved and unproved oil and gas properties. Asset Retirtt ement Obligll atiott ns Descripti ion of to hett Matter As described in Note 2 and 9 of the consolidated financial statements, the Company records a liabia lity for the Asset Retirement Obligation at faiff r value in the period in which it is incurred. The retirement obligations are periodically adjud sted to reflect changes in the expected cash floff ws resulting from revisions to the estimates of either the timing or amount of the retirement costs. Due to the complexity involved in estimating the the expected cash outflows, management used a specialist to estimate the expected cash outflows forff Company’s asset retirement obligation as of December 31, 2023. F-3 Auditing management’s accounting forff retirement obligations was especially challenging, as significant judgment is required by the Company in determining the obligation. The significant judgment was primarily related to the inherent estimation uncertainty relating to the expected cash outflows extent of futff urt e asset retirement activities and the ultimate productive life off f the properties. How We AWW ddressed the Matter in Our Audit We obtained an understanding, evaluated the design, and tested the operating effeff ctiveness of the controls asset retirement obligation, including the controls over management’s over the Company’s accounting forff review of the significant assumptions described above a . a To test the asset retirement obligation, among other procedurd es, we evaluated the methodology, tested the significant assumptions described above and tested the completeness and accuracy of the underlying data used by the Company in estimating the expected cashfloff ws. To assess the estimates of asset retirement activities and cash flows, we evaluated significant changes froff m the prior estimate, verifieff d consistency between the timing of asset retirement activities and projected productive life off f the properties, verified cost rates against third-party inforff mation or internal cost records and recalculated management’s estimate. We asset involved our asset retirement specialists to assist in our evaluation of the expected cash outflows forff retirement obligation. /s/ Ernst & Young LLP We have served as the Company’s auditor since 2010. Houston, Texas Februar ry 28, 2024 F-4 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 finff ancial reporting as of December 31, 2023, 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, effeff ctive internal control over finff ancial reporting as of December 31, 2023, 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, 2023 and 2022, the related consolidated statements of operations, changes in stockholders’ equity, and cash floff ws for each of the three years in the period ended December 31, 2023, and the related notes and the financial statement schedule listed in Item 15(a) (collectively referff red to as the consolidated financial statements”) and our report dated February 2rr 8, 2024 expressed an unqualifieff d opinion thereon. Basis forff Opinion The Company’s management is responsible for maintaining effeff ctive internal control over finff ancial reporting and forff its assessment of the effectiveness of internal control over finff ancial 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 finff ancial reporting based on our audit. We are a public accounting firff m registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. fedff eral 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 reasonabla e assurance about whether effect ive internal control over finff ancial reporting was maintained in all material respects. ff Our audit included obtaining an understanding of internal control over finff ancial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effeff ctiveness of internal control based on the assessed risk, and performing such other procedurd es as we considered necessary in the circumstances. We believe that our audit provides a reasonabla e basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over finff ancial reporting is a process designed to provide reasonabla e assurance regarding the reliabia lity of financial reporting and the preparation of finff ancial statements for external purpos es in accordance with generally accepted accounting principles. A company’s internal control over finff ancial reporting includes those policies and procedurd es that (1) pertain to the maintenance of records that, in reasonabla e detail, accurately and faiff rly refleff ct the transactions and dispositions of the assets of the company; ((2)) pro ividde reasonablbla e assurance thhat transac itions are reco drd ded as necessary to permiit preparatiion of ff fiinfff an ici lal statements iin 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 reasonabla e assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effeff ct on the financial statements. r Because of its inherent limitations, internal control over finff ancial reporting may not prevent or detect misstatements. Also, projeo ctions of any evaluation of effectiveness to futff urt e 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 procedurd es may deteriorate. /s/ Ernst & Young LLP Houston, Texas Februar ry 28, 2024 F-5 TALOS ENERGY INC. CONSOLIDATED BALANCE SHEETS (In thousands, except share amounts) Year Ended December 31, 2023 2022 $ 33,637 $ 178,977 79,337 19,296 36,152 64,387 10,389 422,175 7,906,295 268,315 34,027 8,208,637 (4,168,328) 4,040,309 102,362 17,551 146,049 54,277 16,207 11,418 5,961 4,816,309 $ 84,193 $ 227,690 55,051 33,060 77,581 7,305 42,300 2,666 48,769 578,615 992,614 819,645 795 18,211 251,278 2,661,158 — 1,275 2,549,097 (347,717) (47,504) 2,155,151 4,816,309 $ $ $ $ 44,145 150,598 54,697 6,684 25,029 84,759 1,917 367,829 5,964,340 154,783 30,691 6,149,814 (3,506,539) 2,643,275 — 7,854 1,745 25,541 — 5,903 6,479 3,058,626 128,174 219,769 52,215 — 39,888 68,370 36,340 1,943 60,359 607,058 585,340 501,773 7,872 14,855 176,152 1,893,050 — 826 1,699,799 (535,049) — 1,165,576 3,058,626 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 subju ect to amortization Other property and equipment Total property and equipment Accumulated depreciation, depletion and amortization Total property and equipment, net Other long-term assets: Restricted cash Assets from price risk management activities Equity method investments Other well equipment Notes receivabla e, net Operating lease assets Other assets Total assets Current liabilities: LIABILITIES AND STOCKHOLDERSʼ EQUITY Accounts payable Accruerr d liabia lities Accruerr d royalties Current portion of long-term debt Current portion of asset retirement obligations Liabilities froff m price risk management activities Accruerr d interest payable Current portion of operating lease liabia lities Other current liabia lities Total current liabia lities Long-term liabia lities: Long-term debt Asset retirement obligations Liabilities froff m price risk management activities Operating lease liabia lities Other long-term liabia lities Total liabia lities Commitments and contingencies (Note 14) Stockholdersʼ equity: red stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding Preferff as of December 31, 2023 and 2022, respectively Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively Additional paid-in capital Accumulated deficff Treasury srr tock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively it Total stockholdersʼ equity Total liabilities and stockholdersʼ equity See accompanying notes. F-6 TALOS ENERGY INC. CONSOLIDATED STATEMENTS OF OPERATRR IONS (In thousands, except share amounts) 2023 Year Ended December 31, 2022 2021 Revenues: Oil Natural gas NGL Total revenues Operating expenses: Lease operating expense Production taxes Depreciation, depletion and amortization Write-down of oil and naturt al 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) Equity method investment income (expense) Other income (expense) Net income (loss) before income taxes Income tax benefitff Net income (loss) (expense) NNet income (loss) per common share: Basic Diluted Weighted average common shares outstanding: Basic Diluted $ $ $ $ 1,357,732 $ 68,034 32,120 1,457,886 389,621 2,451 663,534 — 86,152 158,493 (52,155) 1,248,096 209,790 (173,145) 80,928 (3,209) 12,371 126,735 60,597 187,332 $ 1.56 $ 1.55 $ 119,894 120,752 1,365,148 $ 227,306 59,526 1,651,980 308,092 3,488 414,630 — 55,995 99,754 33,902 915,861 736,119 (125,498) (272,191) 14,222 31,800 384,452 (2,537) 381,915 $ 4.63 $ 4.56 $ 82,454 83,683 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 See accompanying notes. F-7 TALOS ENERGY INC. CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (In thousands, except share amounts) Common Stock Shares Issued Par Value Additional Paid-In Capital Accumulated Deficit Treasury Stock Shares Amount Total Stockholdersʼ Equity Balance at December 31, 2020 Equity-based compensation Equity-based compensation tax withholdings Equity-based compensation stock issuances Net income (loss) Balance at December 31, 2021 Equity-based compensation Equity-based compensation tax withholdings Equity-based compensation stock issuances Net income (loss) Balance at December 31, 2022 Equity-based compensation Equity-based compensation tax withholdings Equity-based compensation stock issuances Issuance of common stock forff acquisition (Note 3) Purchase of treasury stock Net income (loss) 81,279,989 $ — — 601,488 — 81,881,477 — — 688,851 — 82,570,328 — — 1,110,143 43,799,890 — — Balance at December 31, 2023 127,480,361 $ 813 $ — 1,659,800 $ 20,165 (734,012) — — $ — — $ — — 6 — 819 — — 7 — 826 — — 11 (3,161) — (6) — 1,676,798 27,611 — (182,952) (916,964) — (4,603) — (7) — 1,699,799 25,008 (7,459) (11) — 381,915 (535,049) — — — — — — — — — — — — — — — — — — — — — — — — — — — 926,601 20,165 (3,161) — (182,952) 760,653 27,611 (4,603) — 381,915 1,165,576 25,008 (7,459) — 438 — — 1,275 $ 831,760 — — 2,549,097 $ — — 187,332 (347,717) — 3,400,000 — 3,400,000 $ — (47,504) — (47,504) $ 832,198 (47,504) 187,332 2,155,151 See accompanying notes. F-8 TALOS ENERGY INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) 2023 Year Ended December 31, 2022 2021 $ 187,332 $ 381,915 $ (182,952) 749,686 — 15,039 12,953 (80,928) (9,457) 3,209 — (86,615) (66,115) 20,352 7,066 (60,401) (96,960) (76,092) 519,069 (561,434) 17,617 73,004 (29,447) (12,366) — (512,626) — (30,000) 825,000 (625,000) (11,775) (1,545) (16,306) (47,504) (7,459) 85,411 91,854 44,145 135,999 $ 114,972 $ 130,313 $ 470,625 — 14,379 15,953 272,191 (425,559) (14,222) 1,569 (69,596) 303 14,927 (36,545) 24,258 73,531 (13,990) 709,739 (323,164) (3,500) 1,937 (2,250) — 15,000 (311,977) — (18,184) 85,000 (460,000) (189) — (25,493) — (4,603) (423,469) (25,707) 69,852 44,145 $ 105,773 $ 91,809 $ 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 Cash flows froff m operating activities: Net income (loss) Adjud stments to reconcile net income (loss) to net cash provided by (used in) operating activities Depreciation, depletion, amortization and accretion expense Write-down of oil and naturt al gas properties and other well equipment Amortization of discount, premium and deferred finff ancing costs Equity-based compensation expense Price risk management activities (income) expense Net cash received (paid) on settled derivative instruments Equity method investment (income) expense Loss (gain) on extinguishment of debt Settlement of asset retirement obligations Gain (loss) on sale of assets Changes in operating assets and liabia lities: Accounts receivable Other current assets Accounts payable Other current liabia lities Other non-current assets and liabia lities, net Net cash provided by (used in) operating activities Cash flows froff m investing activities: Exploration, development and other capital expenditures Proceeds froff m (cash paid for) acquisitions, net of cash acquired Proceeds froff m (cash paid for) sale of property and equipment, net Contributions to equity method investees Investment in intangible assets Proceeds froff m sale of equity method investment Net cash provided by (used in) investing activities Cash flows froff m finff ancing activities: Issuance of senior notes Redemption of senior notes Proceeds froff m Bank Credit Facility Repayment of Bank Credit Facility Deferred finff ancing costs Other deferff red payments Payments of finance lease Purchase of treasury stock Employee stock awards tax withholdings Net cash provided by (used in) finff ancing activities Net increase (decrease) in cash, cash equivalents and restricted cash Cash, cash equivalents and restricted cash: Balance, beginning of period Balance, end of period u Suppl emental non-cash transactions: Capia tal expenditures included in accounts payable and accruerr d liabia lities u Suppl emental cash floff w inforff mation: Interest paid, net of amounts capitalized $ $ $ See accompanying notes. F-9 TALOS ENERGY INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2023 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. The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash floff ws or liabia lities independent of its subsu idiaries. 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 safelff y and effiff ciently maximizing long-term value through its operations, currently in the United States (“U.S.”) and offsff hore Mexico both through upstream oil and gas exploration and production and the development of low carbon solutions 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 offsff hore basins around the world. The Company is also utilizing its expertise to develop CCS projects to help reducd e industrial emissions along the coast of the U.S. Gulf of Mexico. r Basis of Presentation and Consolidation The Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest. Both majoa rity-owned subsu idiaries and any variable interest entity in which the Parent Company is the primary brr iary are consolidated. All intercompany transactions have been eliminated. All adjud stments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash floff ws for the periods refleff cted herein. eneficff The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affeff ct the reported amounts of assets and liabia lities and disclosure of contingent assets and liabia lities as of the date of the finff ancial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actuat r froff m those estimates. l results could diffeff Segments The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportabla e segment. The legal entities included in the es of the Bank Credit Facility CCS Segment have been designated as unrestricted, non-guarantor subsu idiaries of the Company for purpos (a(as ds defefininffff eded inin NoNotete 2 —2 antant AcAccocountuntining Pg Pololicicieiess) a) andnd inindedentntururtt e ge goveovernrnining tg thehe seseninioror notnoteses. S. Seeee adaddiditiotionanall information in Note 15 — Segme ficficii ent InfII orff mation. SumSummamaryry ofof SiSignigni r ii Recently Issued Accounting Standards Segme segment reporting. The upda ent Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required te is intended to improve reportabla e segment disclosures, primarily through enhanced significant segment expenses. The update will require public entities to disclose significant segment expenses that are fiscal r December 15, 2024 on a retrospective disclosures forff disclosures about regularly provided to the chief operating decision maker and included within segment profit and loss. The update is effeff ctive forff years beginning afteff basis. Early adoption is permitted. The Company is currently evaluating the effeff ct of this update on the Company’s disclosures. r December 15, 2023, and interim periods within fiscal years beginning afteff u a Tax Daa isclosll ures — In December 2023, the FASB issued an update which expands disclosures in an entity’s income tax rate annual periods ication in all periods presented is permitted. The reconciliation table and regarding cash taxes paid both in the U.S. and foreign jurisdictions. The update is effeff ctive forff beginning afteff r December 15, 2024 on a prospective basis. However, retrospective appl Company is currently evaluating the effeff ct of this update on the Company’s disclosures. a Note 2 — Summary of Significff ant Accounting Policies Overview of Significant Accounting Policies Cash and CasCC h Equivalenll Sheets. The Company considers all cash, money market funds or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates faiff ts — The Company presents cash as “Cash and cash equivalents” on the Company’s Consolidated Balance and highly liquid investments with an original maturity of three months r value. ff F-10 eceivable all Accounts Rtt nd Alloll wance forff Expexx ctedtt Creditdd Losses — Accounts receivabla e are stated at the historical carrying amount expected credit losses. At each reporting period, the recoverabia lity of material receivabla es is assessed using net of an allowance forff ted forff ecasts of future economic conditions to determine their historical data, current market conditions and reasonabla e and suppor expected collectability. A loss-rate methodology is used to estimate the allowance forff expected credit losses to be accruerr d on material receivabla es to reflect the net amount to be collected. As of December 31, 2023 and 2022, the Company had allowances of $8.8 million and $10.7 million, respectively, presented net in accounts receivabla e on the Consolidated Balance Sheets. u Price Risk ManMM agement Activtt ities — The Company uses commodity price derivatives to manage fluctuating oil and naturt al gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts froff m) counterpar rential between a fixff ed price and a variabla e price for a fixed quantity of oil or natural gas without the rties based on the diffeff exchange of underlying volumes. Commodity derivatives are recorded on the Consolidated Balance Sheets at faiff r 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 classifieff s cash floff ws related to derivative contracts based on the naturt e and e of the derivative. As the derivative cash floff ws are considered an integral part of the Company’s oil and naturt al gas operations, rr purpos they are classifieff d as cash floff ws from operating activities. The Company does not enter into derivative agreements for trading or other speculative purpos es. r The commodity derivative’s faiff exchange or over-the-counter rences or terms that extend beyond the period forff which to location diffeff quotations. Quoted valuations may not be availabla e dued quotations are available. Where quotes are not availabla e, 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 actuat r froff m its estimates, and these differences can be favff orable or unfavff orable. r value reflects the Company’s best estimate with priority based upon l results may diffeff u Prepaid Assets —tt Prepaid assets primarily represent prepaid subsu criptions, insurance, progress payments forff well equipment and deposits with the Office of Natural Resources Revenue (“ONRR”). The progress payments made forff well equipment relate to long lead time items which the Company has not taken title to as of period end. 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 actuat l royalty payments remitted to the ONRR. Accountintt g forff Oil aii nd Natural GasGG Activitieii oil and natural gas exploration and development activities. Under the full cost method, subsu tantially all costs incurred in connection with the acquisition, development and exploration of oil and naturt al 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 hyrr l cost ppool, w, hich is subjju ect to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below. s — The Company follows the full cost method of accounting forff p y ical costs are cappitalized into the fulff ole costs and ggeologig cal and geg ophys Capia talized 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, capia talized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded froff m 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 abaa ndonment 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 froff m proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and naturt al gas properties not being amortized less the related tax effect s. 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, naturt al 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 off f the reserves, even though actual prices and costs of oil and natural gas are ofteff n volatile and may change from period to period. ff F-11 Under the full cost method of accounting forff 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 forff which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifyiff ng for capitalization of interest costs. When the Company sells or conveys interests in oil and naturt al gas properties, the Company reduces its oil and naturt al gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reducd tions to the cost of the Company’s oil and naturt al 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. Othett r ProPP peo rty att ent — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, offiff ce furniturt e and fixturt es 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. nd Equipmii Restritt ctedtt Cash — Any cash that is legally restricted from use is classifieff d as restricted cash. If the purpos e of restricted cash relates to acquiring a long-term asset, liquidating a long-term liability, or is otherwise unavailabla e forff a period longer than one year from the balance sheet date, the restricted cash is included in other long-term assets. Otherwise, restricted cash is included in other current assets ds held in escrow to be used for futff urt e plugging and abaa ndonment in the Consolidated Balance Sheets. The Company acquired funff tions and Divestitures). These escrow (“P&A”) obligations assumed through the EnVen Acquisition (as definff ed in Note 3 — Acquisiii accounts required deposits of appa tions and Divestitures) prior to the consummation of the acquisition. This is reflected as “Restricted Cash” within “Other long-term assets” on the Consolidated Balance Sheets. roximately $100.0 million, which was fully funded by EnVen (as definff ed in Note 3 — Acquisiii r nts —tt Equityii Method Investmett The Company generally accounts forff investments under the equity method of accounting when it exercises significant influff ence over the entity’s operating and finff ancial policies but does not hold a controlling finff ancial interest in the entity. The voting percentage that is presumed to provide an investor with the required level of influence necessary to apply the equity method of accounting varies depending on the naturt e of the investee. For investments in common stock, in-subsu tance common stock, a each investor, a voting percentage of limited liabia lity company or partnership that does not maintain specific ownership accounts forff 20% or more is generally presumed to demonstrate significant influff ence. For investments in a limited partnership or unincorpor ated joint venture and a limited liabia lity company or partnership that maintains a specific ownership account for each investor, a voting interests in limited percentage of 3-5% or more is generally presumed to demonstrate significant influff ence. Equity method accounting forff partnerships is generally appropriate unless the interest is so minor that the investor has virtually no influence (less than 3%). rr a In appl ying the equity method of accounting, the investments are initially recognized at cost and subsequently adjud sted for the Company’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method are refleff cted as “Equity method investments” on the Consolidated Balance Sheets. The equity in earnings of an investee is reflected in “Equiq tyy method investment income (e( xpep nse))” on the Consolidated Statement of Opep rations. The gag in or loss from the full or ppartial sale of an equity method investment is presented in the same line item in which the Company reports the equity in earnings of the investee. The Company assesses equity method investments forff impairment whenever changes in the facts and circumstances indicate a the loss in value has occurred if the loss is deemed to be other-than-temporary.rr When the loss is deemed to be other-than-temporary,rr carrying value of the equity method investment is written down to faiff r value. The impairment charge is included as a component of the Company’s share of the earning or losses of the investee. No impairment charges have been recorded during the years ended December 31, 2023, 2022 and 2021. Othett r WelWW l Ell quipment — Other well equipment primarily represents the cost of equipment to be used in the Company’s oil and ars and certain wellhead equipment. When well equipment is u ied to wells, the cost is capia talized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be natural gas drilling and development activities such as drilling pipe, tubul suppl u reimbursed by third party participants. Notes Receivable,ll net — The Company holds two notes receivabla e with an aggregate facff e value of $66.2 million acquired by the Company as part of the EnVen Acquisition (as defined herein), which consist of commitments froff m the sellers of oil and naturt al gas properties related to the costs associated with P&A obligations (the “P&A Notes Receivabla e”). The P&A Notes Receivable are recorded at a discounted value, being accreted to their principal amounts and presented as such, net of related cumulative estimated credit losses, on the accompanying Consolidated Balance Sheets. The Company estimates the current expected credit losses related to its P&A Notes Receivabla e using the probabia lity of default method based on the long-term credit ratings of the counterparr rties of the notes, which are currently considered “investment grade.” F-12 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 refleff cted as “Operating lease assets,” “Current portion of operating lease liabia lities” and “Operating lease liabia lities” on the Consolidated Balance Sheets. Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabia lities” on the Consolidated Balance Sheets. A right-of-use (“ROU”) asset representing our right to use an underlying asset forff the lease term and a lease liabia lity representing all leases, regardless our obligation to make lease payments arising from the lease are recognized on the Consolidated Balance Sheets forff of classification. The ROU asset is initially measured as the present value of the lease liabia lity adjusted forff any payments made prior to lease commencement, including any initial direct costs incurred and incentives received. Lease liabia lities 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 forff 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 except forff our leased floating production vessel class. Our lease terms may include options to extend or terminate the lease when it is reasonabla y 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. Debt Issuance CosCC ts — The Company presents debt issuance costs associated with revolving line-of-credit arrangements as a reduction of the carrying value of long-term debt. Asset Retirtt ement Obligll atiott ns — The Company has obligations associated with the retirement of its oil and natural gas wells and related infraff structurt e. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no s a liabia lity with respect to these obligations based longer plans to use them or when the Company abaa ndons them. The Company accruer on its estimate of the timing and amount to replace, remove or retire the associated assets. In estimating the liabia lity 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 tion rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset and a projected inflaff the timing of its obligations to plug and retirement obligations. Typically, these changes result froff m obtaining new inforff mation about abandon oil and natural gas wells and the costs to do so. After initial recording, the liabia lity is increased forff 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 diffeff rence as an adjustment to proved properties. a i immissii r iio iningii ObObliligat iiott ns — CCe trt iain cou tnterpar trtiie is i dn diivestittiture ttransa tctiions or ththiirdd partitie is in e ixi tstiin lg leases thth tat hhave fifilledd DDeco for bankrupt cy protection or undergone associated reorganizations may not be able to perform required abaa ndonment 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 probabla e and reasonabla y estimabla e. When there is a range of possible outcomes, the amount accruerr d 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 accruer d. These accruar ation becomes availabla e. In addition, when decommissioning obligations are reasonabla y possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonabla y made). See Note 14 — Commitments & ContCC ingencies for additional inforff mation. ls may be adjusted as additional informff 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 faiff r value on the date awards are granted to its employees. The faiff r value of the stock-based awards is determined at the date of grant and is not remeasured for awards classifieff d as equity unless the award is modified. Liabia lity classified awards are remeasured at each reporting period. The Company records share-based compensation, net of actuat the restricted stock units (“RSUs”) and performance share units (“PSUs”) in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 10 — Emplm oyee Benefite s Ptt lans and Share-Based ComCC pem nsation for additional inforff mation. feiturt es, forff l forff 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. F-13 PSUs withii Markerr t Based Conditidd ons — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model forff awards with a market condition 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 subju ective. The number of shares of common stock issuable upon vesting ranges froff m zero to 200% of the number of PSUs granted based on the Company’s total shareholder returt n (“TSR”). Share-based compensation related to PSUs with a market condition are recognized as the requisite service period is fulff filled, even if the market condition is not achieved. nce Based Conditiodd PSUs withii Perforff marr ns — 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 for awards with a performance condition. The Company recognizes compensation cost forff awards with performance conditions if and when the Company concludes that it is probabla e that the performance condition will be achieved. The Company reassesses the probabia lity of vesting at each reporting period for awards with performance conditions and adjusts compensation cost based on its probabia lity assessment. The Company recognizes a cumulative catch-up au djustment for such changes in its probabia lity assessment in subsu equent reporting periods, using the grant date faiff r value of the award whose terms reflect the updated probabla e performance condition (which could be either a reversal or increase in expense). The number of shares of common stock issuable upon vesting ranges froff m zero to 200% of the number of PSUs granted based on a metric associated with the Company’s own operations or activities. Revenue Recogno ition — Revenues are recorded based froff m the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues froff m 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 transferff red, prices are fixed and determinable and collection is reasonabla y assured. This occurs when production has been delivered to a pipeline or when a barge liftinff g 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, thereforff e, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Productiott n HanHH dlinll g FeeFF s — The Company presents certain reimbursements forff costs froff m certain third parties as a reducd tion of “Lease operating expense” on the Consolidated Statements of Operations. ONRR FRR edFF erdd al Royao lty Refue nd — Included within “Other operating (income) expense” on the Consolidated Statements of claim froff m the ONRR. The Company records income when ff Operations is income from the Company’s multi-year federal royalty refund ff a refund is filed and its collection is reasonabla y assured. Income Taxeaa s — The Company records current income taxes based on estimates of current taxabla e income and provides forff deferred income taxes to refleff ct estimated futff urt e income tax payments and receipts. The impact to changes in tax laws are recorded in the period red taxes represent the tax impacts of differences between the finff ancial statement and tax bases of assets the change is enacted. Deferff red tax assets and liabia lities, along with any related rs at each year end. The Company classifies all deferff and liabia lities and carryove valuation allowance,, as long-g term on the Consolidated Balance Sheets. rr iffeff The realization of deferff red tax assets depends on recognition of suffiff cient futff urt e taxable income during periods in which those rences are deductible. The Company reducd es deferred tax assets by a valuation allowance when, based on estimates, it temporary drr is more likely than not that a portion of those assets will not be realized in a futff urt e period. The deferff red 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 drr rences, the existence of taxable income in carryback years, tax planning strategies and future taxabla e income forff each of its taxabla e 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. iffeff The Company’s policy is to classify i ff nterest 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 ShaSS re — 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 RSUs, PSUs and outstanding warrants. See Note 12 — Income (Loss) Per Shar e for additional inforff mation. SS Fair Value MeaMM sure of Finaii ncial InsII ents generally consist of cash and cash equivalents, accounts receivabla e, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, accounts receivabla e r value due to the highly liquid naturt e of these instruments. and accounts payabla e appr truments — Financial instrumr oximates faiff a F-14 Current fair value accounting standards define fair value, establa ish a consistent framework for measuring fair value and stipulate the related disclosure requirements forff r 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 transferff lows a three-level hierarchy, prioritizing and defining the types of inputs used to measure faiff a liabia lity, in an orderly transaction between market participants. The Company folff r value depending on the degree to which they are observabla e as folff each majoa r asset and liabia lity category mrr easured at faiff lows: • • • Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabia lities in active markets. Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabia lities in active markets, and inputs that are observabla e forff l term of the financial statement. the asset or liabia lity, either directly or indirectly, forff subsu tantially the fulff Level 3 – Inputs to the valuation methodology are unobservabla e (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 liabia lities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows: • • • Market Apprpp oach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabia lities. Cost Apprpp oach – Amount that would be required to replace the service capacity of an asset (replacement cost). Income Apprpp oach – Techniques to convert expected future cash floff ws to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models). r value Authoritative guidance on finff ancial instruments requires certain fair value disclosures to be presented. The estimated faiff amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of faiff rent assumptions or valuation methodologies may have a r value. The use of diffeff material effeff ct on the estimated faiff r value amounts. Variable Ill ntII ertt est EntE ittt iett s — Upon inception of a contractuat l agreement, the Parent Company performs an assessment to determine whether the arrangement contains a variabla e interest in a legal entity and whether that legal entity is a variabla e interest Entity (“VIE”). The Parent Company assesses all aspects of its interests in an entity and uses judgment when determining if it is the primary brr iary. as both the power to direct the activities of the VIE that most significantly impact the entity’s economic The primary beneficiary hrr from the VIE that could potentially be significant to the performance and the obligation to absa orb l VIE. Other qualitative fact ture, risk and rewards hshariing, co tntra tctuat tothher partities. AA reassessmentt of tf thhe priimaryrr beneficiary crr onclusion is conducted when there are changes in the facts and circumstances related to a VIE. See Note 7 — Equity Method Investments for additional inforff mation. ors that are considered include decision-making responsibilities, the VIE capia tal strucr iwithth thth Ve VIEIE, v totiing riighthts a dnd llevell of if i osses or the right to receive benefitsff ll agreementts nvolveme tnt eneficff fof r ff l Concentration of Credit Risk Consisting principally of cash and cash equivalents, accounts receivabla e and commodity derivatives, the Company is subju ect to concentrated financial instrumr ents credit risk. Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed fedff erally insured limits. The Company monitors the finff ancial 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 finff ancial condition of these institutions and has not experienced losses dued lt on these instrumr to counterpar rty defauff ents. The Company markets the majoa rity 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 majoa r oil and naturt al gas companies, well-establa ished oil and pipeline companies and independent oil and gas producers and suppl iers. The Company performs ongoing credit evaluations of its customers and provide allowances for probabla e credit losses when necessary. u F-15 The percent of consolidated revenue of majoa r customers, those whose total represented 10% or more of the Company’s oil, naturt al gas and NGL revenues, was as folff lows: Shell Trading (US) Company Valero Energy Corporation Chevron Products Company ** Less than 10% 2023 Year Ended December 31, 2022 2021 54% 21% ** 44% 23% 11% 45% ** 29% The loss of a majoa r customer could have material adverse effecff t on the Company in the short term. However, the Company believes it would be abla e to obtain other customers to market its oil, natural gas and NGL production. Cash, Cash Equivalents and Restricted Cash The folff lowing tabla e provides a reconciliation of the amount of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the total of the same such amounts shown in the Consolidated Statement of Cash Flows (in thousands): Cash and cash equivalents Restricted cash included in Other long-term assets Total cash, cash equivalent and restricted cash Note 3 — Acquisitions and Divestitures Business Combinations Year Ended December 31, 2023 2022 $ $ 33,637 $ 102,362 135,999 $ 44,145 — 44,145 Acquisitions qualifyiff ng as business combinations are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabia lities assumed be recognized on the Consolidated Balance Sheets at their fair values as of the acquisition date. EnVen Acquisiii tiii on — On September 21, 2022, the Company executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). On Februar consideration consisting of (i) $207.3 million in cash, (ii) 43.8 million shares of the Company’s common stock valued at $832.2 million and (iii) the effective settlement of an accounts receivabla e balance of $8.4 million. No gain or loss was recognized on settlement as the payable was effectively settled at the recorded amamount ount T. Thehe cascash ph payaymementnt wawas ps parartitialallyly fufundended wd witith bh bororrorowiwingsngs unde ry 13, 2023, the Company completed the EnVen Acquisition forff under tr thehe BaBanknk CrCrededitit FaFacicilitylity. The folff lowing tabla e summarizes the purchase price (in thousands except share and per share data): Talos common stock Talos common stock price per share(1) Common stock value Cash consideration Settlement of preexisting relationship Total purchase price $ $ $ $ $ 43,799,890 19.00 832,198 207,313 8,388 1,047,899 (1) Represents the closing price of the Company’s common stock on Februarr ry 13, 2023, the date of the closing of the EnVen Acquisition. F-16 The folff fair values on Februarr ry 13, 2023 (in thousands): lowing tabla e presents the final allocation of the purchase price to the assets acquired and liabia lities assumed based on their Current assets Property and equipment Other long-term assets: Restricted cash Notes receivabla e, net Other long-term assets Current liabilities: Current portion of long-term debt Current portion of asset retirement obligations Other current liabia lities Long-term liabia lities: Long-term debt Asset retirement obligations Deferred tax liabia lities Other long-term liabia lities Allocated purchase price $ $ 243,571 1,455,347 100,753 14,844 48,899 (33,234) (7,079) (124,347) (233,836) (251,779) (150,264) (14,976) 1,047,899 The faiff r values determined for accounts receivabla e, accounts payable and other current assets and most current liabilities were equivalent to the carrying value due to their short-term nature. Assumed debt was valued based on observabla e market prices. The faiff r value of proved oil and naturt al gas properties as of the acquisition date is based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash floff ws incorporating market participant assumptions. Significant inputs to the valuation include estimates of futff urt e production volumes, futff urt e operating and development costs, futff urt e commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjud stments were appl ied to proved developed non-producing, proved undeveloped, probabla e and possible reserves to refleff ct the relative uncertainty of each reserve class. These inputs are classified as Level 3 unobservabla e inputs, including the underlying commodity price price assumptions which are based on the five-year NYMEX forward strip prices, escalated for inflaff differentials. r, and adjusted forff tion thereafteff a The faiff r value of asset retirement obligations is determined by calculating the present value of estimated futff urt e cash floff ws related to the liabia lities. The Company utilizes several assumptions, including a credit-adjud sted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflaff tion rate. aa oxioximamatetelyly $21 8 ThThe Ce Comompapanyny inincucurrerred ad apprppr $21.8 millimillionon ofof acqacquiuisisitition-on-rerelalateted cd cosoststs inin coconnennectctioion wn withith ththe Ee EnVnVenen AcAcquiquisisitiotionn exclusive of severance expense, of which $12.8 million was recognized during the year ended December 31, 2023 and $9.0 million was recognized durd ing the year ended December 31, 2022 and refleff cted in general and administrative expense on the Consolidated Statements of Operations. Additionally, the Company incurred $25.3 million in severance expense in connection with the EnVen Acquisition forff Plans and Share-Based ComCC pem nsation for additional discussion. the year ended December 31, 2023. See Note 10 — Emplm oyee Benefite The folff lowing tabla e presents revenue and net income (loss) attributable to the EnVen Acquisition for the period from Februaryrr 13, 2023 to December 31, 2023 (in thousands): Revenue Net income (loss) Year Ended December 31, 2023 $ $ 423,624 85,622 F-17 u tion (Un(( Pro ForFF marr lowing suppl Finaii ncial InfII orff marr auditeii d) — The folff emental pro forma finff ancial information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2023 and 2022 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma inforff mation was derived from historical statements of operations of the Company and EnVen adjud sted to include (i) depletion expense appl ied to the adjud sted basis of the oil and natural gas properties acquired, (ii) interest expense to refleff ct borrowings under the Bank Credit Facility and to adjust the amortization of the transaction related premium of the 11.75% Notes (as defined in Note 8 — Debt), (iii) general and administrative expense adjusted forff costs incurred (including severance), (iv) other income (expense) to adjud st the accretion of the discount on the P&A Notes Receivabla e and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for the year ended December 31, 2022 were adjud sted to include $65.1 million of emental pro general and administrative expenses, of which $16.3 million were incurred durd ing the year ended December 31, 2022. Suppl forma earnings for the year ended December 31, 2023 were adjud sted to exclude $65.1 million of general and administrative expenses. rt to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred This information does not purpor on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except forff the per share data). u a Revenue Net income (loss) Basic net income (loss) per common share Diluted net income (loss) per common share Subsequent Event Year Ended December 31, 2023 2022 1,509,929 $ 217,537 $ 1.74 $ 1.73 $ 2,355,215 425,995 3.37 3.34 $ $ $ $ QuarterNorNN th Acquisition — On January 13, 2024, the Company executed a merger agreement to acquire QuarterNorth Energy Inc. (“QuarterNorth,” and such acquisition, the “QuarterNorth Acquisition”), a privately-held U.S. Gulf of Mexico exploration and production company. The QuarterNorth Acquisition is expected to close durd ing the first quarter of 2024. Consideration forff the QuarterNorth Acquisition primarily consists of (i) appr oximately $964.9 million in cash, (ii) the amount of net unrestricted cash of QuarterNorth as of December 31, 2023 and (iii) 24.8 million shares of the Company’s common stock. a Divestiture Mexiee co Divestitutt re — On September 27, 2023, the Company closed the sale of a 49.9% equity interest in its subsidiary, Talos Energy Carso, for $74.9 million Mexico 7, S. de R.L. de C.V. (“Talos Mexico”) to Zamajal, S.A. de C.V., a wholly owned subsidiary of Grupo in cash consideration with an additional $49.9 million contingent on first oil production froff m the Zama Field (the “Mexico Divestiture”). The contingent consideration will be recognized when regular commercial production froff m the Zama Field becomes probable. Talos Mexico, through its wholly owned subsidiary, holds a 17.4% unitized interest in the Zama Field. r As a result of the Mexico Divestiture, Talos Mexico was deconsolidated on September 27, 2023 and is now accounted for as an equity method investment. Total assets derecognized included $112.3 million of unproved properties associated with exploration and r value of the Company’s appraisal activities in Block 7 located in the shallow waters off tff he coast of Mexico’s Tabasco state. The faiff retained equity method investment in Talos Mexico was $107.6 million. The determination of faiff r r value was based on the implied faiff r value of Talos Mexico was based on the transaction price of the Mexico Divestiture, which was value of Talos Mexico. The implied faiff an orderly transaction between market participants. A gain of $66.2 million was recognized on the Mexico Divestiture during the year ended December 31, 2023 which is included in “Other operating (income) expense” on the Consolidated Statements of Operations. Note 4 — Property, Plant and Equipment Proved Properties The Company’s interests in oil and naturt al gas proved properties are located in the United States, primarily in the Gulf of Mexico deep and shallow waters. During 2023, 2022 and 2021, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At December 31, 2023, its ceiling test computation was based on SEC pricing of $78.56 per Bbl of oil, $2.75 per Mcf of natural gas and $18.77 per Bbl of NGLs. Unproved Properties Unproved capitalized costs of oil and naturt al gas properties excluded froff m amortization relate to unevaluated properties associated eral lease sales, certain geological and geophysical costs, expenditures with acquisitions, leases awarded in the U.S. Gulf of Mexico fedff associated with certain exploratory wrr ells in progress and capitalized interest. F-18 During the year ended December 31, 2023, the Company derecognized $112.3 million of unproved properties associated with the exploration and appraisal activities in Block 7 located in the shallow waters off tff he coast of Mexico’s Tabasco state. See Note 3 — Acquisiii tions and Divestitures for additional discussion. During the year ended December 31, 2021, the Company’s evaluation of unproved property located offsff hore Mexico resulted in a non-cash impairment of $18.1 million presented as “Write-down of oil and naturt al gas properties” on the Consolidated Statements of Operations. The non-cash impairment was primarily attributable to the Company’s operations in offsff hore Mexico in Block 31 associated with the Company’s non-consent of the proposed appraisal plan durd ing the fourth quarter of 2021. The folff lowing tabla e sets forff th a summary of the Company’s oil and naturt al gas property costs not being amortized at December 31, 2023, by the year in which such costs were incurred (in thousands): Acquisition United States Exploration United States Total unproved properties, not subju ect to amortization Total 249,799 $ 18,516 268,315 $ 2023 229,216 $ 10,108 239,324 $ $ $ Year Ended December 31, 2022 2021 2020 and Prior — $ 1,299 1,299 $ — $ 2,295 2,295 $ 20,583 4,814 25,397 The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are establa ished or impairment is determined. The unproved costs will be excluded froff m the amortization base until the Company has made a determination red to the amortization base over as to the existence of proved reserves. The Company currently estimates these costs will be transferff eight years. Note 5 — Leases t The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to suppor 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 floff ating production facff ility 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 ROU 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-ff production method, computed quarterly. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized. u In November 2022, the Company exercised its option to extend the lease of the HP-I through June 1, 2024. The extension resulted in a remeasurement of the lease liabia lity to $166.3 million and corresponding adjud stment to proved property. ThTh le lease cost ds describib ded bbellow are presentedd on a gros bs basiis and dd do not represent thhe CCompan ’y’s net propor itionate hshare off 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): 2023 Year Ended December 31, 2022 2021 Finance lease cost - interest on lease liabia lities Operating lease cost, excluding short-term leases(1) Short-term lease cost(2) Variable lease cost(3) Variable and fixff ed sublu ease income Total lease cost $ $ 14,476 $ 4,883 117,132 2,888 (482) 138,897 $ 7,558 $ 2,281 55,072 1,450 — 66,361 $ 11,453 2,706 38,472 1,356 — 53,987 (1) (2) (3) Operating lease cost refleff ct 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 forff as a ROU asset and lease liabia lity on the Consolidated Balance Sheets. Variabla e lease costs primarily represent diffeff long-term leases. rences between minimum payment obligations and actuat drilling rigs, most of which are short-term contracts not recognized l operating charges incurred by the Company related to its F-19 The present value of the fixed lease payments recorded as the Company’s ROU asset and liabia lity, adjusted forff initial direct costs and incentives were as follows (in thousands): Operating leases: Operating lease assets Current portion of operating lease liabia lities Operating lease liabia lities Total operating lease liabia lities Finance leases: Proved properties Other current liabia lities Other long-term liabia lities Total finff ance lease liabia lities Year Ended December 31, 2023 2022 11,418 $ 2,666 $ 18,211 20,877 $ 166,261 $ 17,834 $ 131,230 149,064 $ 5,903 1,943 14,855 16,798 166,261 16,306 149,064 165,370 $ $ $ $ $ $ The table below presents the lease maturt ity by year as of December 31, 2023 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the Consolidated Balance Sheets. 2024 2025 2026 2027 2028 Thereafter Total lease payments Imputed interest Total lease liabia lities Operating Leases Finance Leases 4,748 $ 4,716 4,803 4,708 4,610 4,584 28,169 $ (7,292) 20,877 $ 30,782 30,782 30,782 30,782 30,782 43,608 197,518 (48,454) 149,064 $ $ $ 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 2023 Year Ended December 31, 2022 2021 5.9 years 6.4 years 6.4 years 7.4 years 7.4 years 1.4 years 10.8% 9.2% 11.8% 9.2% 11.9% 21.9% The table below presents the suppl u emental cash floff w inforff mation related to leases (in thousands): Operating cash outflow from finff ance leases Operating cash outflow from operating leases ROU assets obtained in exchange for new finance lease liabia lities ROU assets obtained in exchange for new operating lease liabia lities(1) Remeasurement of lease liabia lity arising froff m modification of ROU asset(2) 2023 Year Ended December 31, 2022 2021 $ $ $ $ $ 14,476 $ 6,318 $ — $ 12,971 $ (5,124) $ 7,181 $ 3,722 $ 166,261 $ 474 $ — $ 11,453 3,864 — 1,020 — (1) (2) See EnVen Acquisition in Note 3 — Acquisiii Lease termination accounted for as a lease modification based on the modified lease term. The termination did not take effeff ct contemporaneously with the effective date of the modification. tions and Divestitures. F-20 Note 6 — Financial Instruments As of December 31, 2023 and 2022, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivabla e and accounts payable approximate their faiff r values because they are highly liquid or dued to the short-term nature of these instrumrr ents. Debt Instruments The folff lowing tabla e presents the carrying amounts, net of discount and deferff red finff ancing costs, and estimated faiff r values of the Company’s debt instrumr ents (in thousands): 12.00% Second-Priority Senior Secured Notes – dued 2026 11.75% Senior Secured Second Lien Notes – due April 2026 Bank Credit Facility – matures March 2027 January $ $ $ 601,353 $ 234,221 $ 190,100 $ 655,130 $ 233,410 $ 200,000 $ 590,132 $ — $ (4,792) $ 674,542 — — December 31, 2023 December 31, 2022 Carrying Amount Fair Value Carrying Amount Fair Value The carrying value of the senior notes are adjusted forff (representing a Level 1 faiff other observabla e (Level 2) inputs are used such as quoted prices for similar liabia lities in the active markets. red finff ancing costs. Fair value is estimated r value measurement) using quoted secondary market trading prices and, where such prices are not availabla e, discount, premium and deferff The carrying amount of the Company’s bank credit facility, as amended and restated (the “Bank Credit Facility”), is presented net of deferred finff ancing costs. The faiff r 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 refleff ctive of market rates (representing a Level 2 faiff r value measurement). Oil and Natural Gas Derivatives The Company attempts to mitigate a portion of its commodity price risk and stabilize cash floff ws associated with sales of oil and natural gas production. The Company is currently utilizing oil and naturt al gas swapsa are contracts where the Company either receives or pays depending on whether the oil or naturt al gas floff ating 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 froff m counterpar the ceiling rties. Typical collar contracts require payments by the Company if the NYMEX average closing price is above price or payments to the Company if the NYMEX average closing price is below the floff or price. and costless collars. Swapsa a In connection with the EnVen Acquisition, the Company assumed oil and naturt al gas collar contracts that combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these contracts, when the NYMEX average closing price is below the floff or price, the Company receives the diffeff rence between the NYMEX average closing price and the flfloor priice, cappedd at thhe didifffferenc be between hth fe fllofff or priice a dnd hthe shhort put priice. The folff lowing tabla e 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 instrumrr Unrealized gain (loss)(1) Price risk management activities income (expense) ents 2023 Year Ended December 31, 2022 (9,457) $ 90,385 80,928 $ (425,559) $ 153,368 (272,191) $ $ $ 2021 (290,164) (128,913) (419,077) (1) Includes $1.4 million gain from the unrealized derivative instrumrr ents acquired froff m the EnVen Acquisition for the year ended December 31, 2023. The folff lowing tabla es reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2023: Production Period Settlement Index Swap Contracts rr Crude oil: January 2024 – December 2024 January 2025 – December 2025 NYMEX WTI CMA NYMEX WTI CMA Natural gas: January 2024 – December 2024 January 2025 – December 2025 NYMEX Henry Hrr NYMEX Henry Hrr ub ub Volumes (Bbls)ll (MMBtu)u 16,859 $ 7,734 $ 18,716 $ 13,712 $ Swap Price (per Bbl) (per MMBtu)u 74.30 73.80 3.41 3.92 F-21 Two-Way Collar Contracts Production Period Settlement Index rr Crude oil: Volumes (Bbls)ll Floor Price (per Bbl) Ceiling Price (per Bbl) January 2024 – December 2024 NYMEX WTI CMA 1,497 $ 70.00 $ 79.32 Natural gas: (MMBtu)u (per MMBtu)u (per MMBtu)u January 2024 – December 2024 NYMEX Henry Hrr ub 10,000 $ 4.00 $ 6.90 Production Period rr Crude oil: Settlement Index Three-Way Collar Contracts Volumes (Bbls)ll Short Put Price (per Bbl) Floor Price (per Bbl) Ceiling Price (per Bbl) January 2024 – March 2024 NYMEX WTI CMA 3,200 $ 57.27 $ 70.00 $ 98.01 The folff lowing tabla es provide additional inforff mation related to financial instrumr ents measured at fair value on a recurring basis (in thousands): Assets: Oil and natural gas derivatives Liabilities: Oil and natural gas derivatives Total net asset (liabia lity) Assets: Oil and natural gas derivatives Liabilities: Oil and natural gas derivatives Total net asset (liabia lity) Financial Statement Presentation Level 1 Level 2 Level 3 Total December 31, 2023 — $ — — $ 53,703 $ (8,100) 45,603 $ — $ — — $ 53,703 (8,100) 45,603 Level 1 Level 2 Level 3 Total December 31, 2022 — $ — — $ 32,883 $ (76,242) (43,359) $ — $ — — $ 32,883 (76,242) (43,359) $ $ $ $ Derivatives are classified as either current or non-current assets or liabia lities based on their anticipated settlement dates. Although rties, the Company presents its derivative financial instrumrr ents on a lowing tabla e presents the fair value of derivative finff ancial instruments as well as the Company has master netting arrangements with its counterpar gross basis in its Consolidated Balance Sheets. The folff the ppotential effect of nettingg arrangeg ments on the Comppany'y s recognig zed derivative asset and liabia lityy amounts ((in thousands):) Oil and natural gas derivatives: Current Non-current Total gross amounts presented on balance sheet Less: Gross amounts not offsff et on the balance sheet Net amounts Credit Risk December 31, 2023 December 31, 2022 Assets Liabilities Assets Liabilities $ $ 36,152 $ 17,551 53,703 8,100 45,603 $ 7,305 $ 795 8,100 8,100 — $ 25,029 $ 7,854 32,883 32,883 — $ 68,370 7,872 76,242 32,883 43,359 pportunities to mitigate exposure risk; and (iv) potentially requiring counterpar The Company is subju ect to the risk of loss on its finff ancial instruments as a result of nonperformance by counterparr l obligations. The Company has entered into International Swapsa rties to mitigate this risk. The Company also maintains credit policies with regard to its counterparr rties pursuant and Derivative Association agreements to the terms of their contractuat rties to minimize overall with counterpar rties’ financial condition to determine their credit worthiness; credit risk. These policies require (i) the evaluation of potential counterpar rds the Company netting or set (ii) the regular monitoring of counterpar off off rties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabia lities froff m commodity price risk management activities at December 31, 2023 represent derivative instrumr ealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and eight of which are parties under the rties and, subju ect to the terms of the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterpar Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities. Had the Company’s counterpar led to perform under existing commodity derivative contracts the maximum loss at December 31, rties faiff 2023 would have been $45.6 million. rties’ credit exposures; (iii) the use of contract language that affoff rties; all of which are registered swap da ents from nine counterpar F-22 Note 7 — Equity Method Investments The folff lowing tabla e presents the Company’s investments in unconsolidated affiff liates by segment for the periods indicated below. The Company accounts forff these investments using the equity method of accounting. Upstream: Talos Energy Mexico 7, S. de R.L. de C.V SP 49 Pipeline LLC CCS: Bayou Bend CCS LLC Harvest Bend CCS LLC Coastal Bend CCS LLC Total Equity Method Investments Talos Energy Mexico 7, S. de R.L. de C.V. Ownership Interest at December 31, 2023 Year Ended December 31, 2022 2023 50.1% $ 33.3% 25.0% 65.0% 50.0% 107,259 $ 861 28,183 9,746 — $ 146,049 $ — 374 1,371 — — 1,745 See Note 3 – Acquisiii million positive basis diffeff commercial production from the Zama Field commences. tions and Divestitures for additional inforff mation on the deconsolidation of Talos Mexico. There is $66.0 rence related to this investment, which will be amortized on a units of production method once regular Bayou Bend CCS LLC On March 8, 2022, the Company made a $2.3 million cash contribution forff a 50% membership interest in Bayou Bend CCS LLC (“Bayou Bend”). Bayou Bend has a CCS site that is in the early stages of development located offsff hore Jeffeff rson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. In May 2022, the Company sold a 25% membership interest to Chevron U.S.A. Inc. (“Chevron”) forff upfroff nt cash consideration of $15.0 million. The Company recognized a $13.9 million gain on the partial sale of its investment in Bayou Bend during the year ended December 31, 2022, which is included in “Equity method investment income (expense)” on the Consolidated Statement of Operations. Chevron also agreed to fund up to $10.0 million of contributions to Bayou Bend on the Company’s behalf, which was fully funded by the first quarter of 2023. The Bayou Bend investment was increased with an d by Chevron. The Company recognized an $8.6 million and $1.4 million gain durd ing the offsff etting gain as the capital carry was funde years ended December 31, 2023 and 2022, respectively, on the funff ding of the capital carry of its investment in Bayou Bend. This gain is included in “Equity method investment income (expense)” on the Consolidated Statements of Operations. ff Effeff ctive March 1, 2023, Chevron became the operator of Bayou Bend. During March 2023, Bayou Bend expanded its storage int through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located within the Houston Ship footprt ChChannell, BBeaumo tnt and Pd Port At A trthhur re igion. VIE Disclosures VIE aII etertt minrr nd Primary Benefie ciary Dr atiott n — Talos Mexico, Bayou Bend, Harvest Bend CCS LLC (“Harvest Bend”), and Coastal Bend CCS LLC (“Coastal Bend”) were each determined to be a VIE. Neither Talos Mexico, Bayou Bend, Harvest Bend, nor Coastal Bend had suffiff cient equity at risk to finance their respective activities without additional subordinated finff ancial suppor t. The Company is not the primary beneficiary orr to the governance structurt e of these entities. The most significant activities of these entities are jointly controlled by the owners. The level of the Company’s economic interest in Harvest Bend is not indicative of the amount of power held. f these VIE’s dued u Finaii ncings — All of the Company’s VIE’s have historically been funded through equity contributions from owners. Maxiaa muii m Expos EE ure — The Company’s maximum exposure to loss as result of its involvement with VIE’s is the carrying amount of each investment. s —kk Nature of Riskii Talos Mexico holds a working interest in the unitized Zama Field. In March 2023, Petróleos Mexicanos submu itted the Zama Unit Development Plan (“UDP”) to Mexico’s governmental agency for appr oved in June 2023. An Integrated Project Team (“IPT”) was forff med in March 2023 to pool the talents and competencies of all companies participating in the development of the Zama Field. The IPT reports to the Zama Unit Operating Committee, which includes representatives from each of the participating companies. Final Investment Decision (“FID”) is expected following completion and final review of the front- ial stage and marks the beginning end engineering and design (“FEED”), projeo ct financing and final appr a tion. of the engineering and construcr Availabia lity of equipment and unexpected construcr tion hurdles could delay the start of oil and gas production. Even though an IPT exists, teamwork could remain a challenge. There is also a risk that the project will not be completed within the budget and timeline, which ultimately could have an adverse impact on the net present value of the projeo ct. tion stage, where projeo ct contractors proceed with procuring material and beginning the construcr oval and the UDP received appr ovals. Achieving FID is a crucr a a F-23 ff rr development of our CCS projects is dependent on various economic, regulatory,rr operational and technical facff The successfulff lure to satisfy, wholly or in a significant measure, any of such fact tors. The faiff ors could have a material adverse impact on the Company’s business, results of operations and finff ancial condition. For example, successful development of CCS projects in the United States requires compliance with stringent and varied regulatory s chemes including obtaining Class VI well permits that are applicable to subsu urface injen ction of CO2 for geologic sequestration. Locating a suitabla e source of anthropogenic CO2 and reaching suitabla e agreements to capture that CO2 is crucrr ial. Infrastructurt e to transport CO2 between the source and CCS project sites is also required. In project areas with existing CO2 transportation pipelines, reaching an agreement on CO2 transportation with operators of such pipelines will be necessary. Inabia lity to reach a suitabla e agreement may render a project uneconomic or impracticable. Separately, if no CO2 pipelines exist in proposed project areas, or if existing pipelines do not extend to one or more of the Company’s projeo ct sites, conversion of existing pipelines or construcrr tion of new pipelines or lateral connections will be required, which may render one or more projects uneconomic. Given the capital-intensive naturt e of CCS projects, project finff ance plays a critical role in accelerating the development of the Company’s projects. If the Company is unabla e to obtain acceptabla e finff ancing for its CCS projects, then it could result in significant delays in the development and construcrr tion of such projects. Lastly, the development of CCS projects is incentivized by tax credits provided under Section 45Q of the Internal Revenue Code of 1986, as amended. The Company’s inabia lity to benefit froff m such tax credits could prevent the development of the Company’s projeo cts. Note 8 — 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): 12.00% Second-Priority Senior Secured Notes – dued 11.75% Senior Secured Second Lien Notes – due April 2026 Bank Credit Facility – matures March 2027 January 2026 Total debt, before discount, premium and deferred finff ancing cost Unamortized discount, premium and deferff red finff ancing cost, net Total debt Less: Current portion of long-term debt Long-term debt 12.00% Second-Priority Senior Secured Notes $ $ Year Ended December 31, 2023 2022 638,541 $ 227,500 200,000 1,066,041 (40,367) 1,025,674 33,060 992,614 $ 638,541 — — 638,541 (53,201) 585,340 — 585,340 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 indenturt e dated January 14, 2021 between the Parent Company (the “Parent Guarantor”), TTallo Ps Prodductitio In Inc (. (thth “e “IIssuer”)”), a dnd certtaiin fof thth Ie Issue 'r's s bubsididiia iries (t(thhe “S“S bubsididiiary GGuaranttors”” a dnd, ttogethther iwithth thth Pe Parentt tee and collateral agent. The 12.00% Notes rank pari Guarantor, the “Guarantors”) and Wilmington Trusr t, National Association, as trusr es under the indenturt es. The 12.00% Notes are fully passu in right of payment and constitutt e a single class of securities for all purpos 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 Grr uarantors and will be unconditionally guaranteed on the same basis by certain of the Issuer’s future subsu idiaries. The 12.00% Notes are secured on a second-priority basis by liens on subsu tantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes maturt e January 15, 2026 and have interest payable semi-annually each January 15 and July 15. r 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 accruerr d and unpaid interest if redeemed during the period commencing on January 15 of the years set forff th below: Period 2023 2024 r 2025 and thereafteff Redemption Price 106.000% 103.000% 100.000% a The indenturt e governing the 12.00% Notes appl ies certain limitations on the Company’s abia lity and the ability of its subsu idiaries to, among other things, (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from Talos Production Inc.’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of Talos Production Inc.’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiff liates. The 12.00% Notes contain customary qrr uarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2023. F-24 The Issuer initiated a notes consent solicitation on October 21, 2022, to obtain the requisite holders’ consent to certain amendments to the indenturt e governing the Issuer’s 12.00% Notes to permit the incurrence of indebtedness in respect of the 11.75% Senior Secured 2026 of EnVen (the “Notes Consent Solicitation”). The Notes Consent Solicitation expired on October 27, 2022, Second Lien Notes dued with holders of 95.8% of the aggregate principal amount of the 12.00% Notes outstanding consenting. As a result, the Issuer entered into a second suppl its execution. The Issuer red holders of the 12.00% Notes consideration equal to 50 basis points times the principal amount of the 12.00% Notes held by such offeff 3, 2023, the Issuer paid the Consent Fee of approximately $3.1 million in the aggregate consenting holder (“Consent Fee”). On February 1rr in connection with the EnVen Acquisition. emental indenturt e to the base indenturt e on October 27, 2022, which became effeff ctive upon u u During the year ended December 31, 2022, the Company repurchased $11.5 million of the 12.00% Notes. The debt repurchases resulted in a loss on extinguishment of debt for the year ended December 31, 2022 of $1.6 million, which is presented as “Other income (expense)” on the Consolidated Statements of Operations. Subsequent Event — On January 23, 2024, the Company issued a conditional notice to redeem in full the 12.00% Notes at a redemption price of 103.00% of the principal amount thereof, plus accruer d and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes indenturt e. The 12.00% Notes were redeemed on February 7rr , 2024 for $662.4 million utilizing the net proceeds froff m the Debt Offeff ring (as definff ed below). 11.75% Senior Secured Second Lien Notes On Februarr ry 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior 2026 (the “11.75% Notes”) with a principal amount of $257.5 million. The 11.75% Notes maturt e on Secured Second Lien Notes dued April 15, 2026 and interest accruer s and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The indenturt e governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year. The Company may redeem all or a portion of the 11.75% 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 accruerr d and unpaid interest if redeemed during the period commencing on February 1rr 5 of the years set forth below: Period 2023 2024 r 2025 and thereafteff Redemption Price 105.875% 102.938% 100.000% The 11.75% Notes are governed by an indenturt e by and among Energy Venturt es GoM LLC, EnVen Finance Corpor ration as co- t, National Association as trustee and collateral agent, dated as of April 15, issuers, the guarantors party thereto and Wilmington Trusr emental indenturt e to the 2021 (“( 11.75% Notes Indenturt e”).) Talos Production Inc. and certain of its subsidiaries entered into a supplppu 11.75% Notes Indenturt e which, inter alia, provides forff the assumption of the indebtedness in respect of the 11.75% Notes by Talos Production Inc., as well as guarantees of such indebtedness by certain subsu idiaries of Talos Production Inc., as contemplated by the terms of the 11.75% Notes Indenturt e. The 11.75% Notes Indenturt e contains certain covenants, which are customary wrr ith respect to non-investment grade debt securities, including limitations on the Company’s abia lity to incur and guarantee additional indebtedness, repay, redeem, or repurchase certain debt and capital stock, issue certain preferred stock or similar equity securities, pay dividends or make other distributions on capital stock, enter into certain types of transactions with affiff liates, make loans or investments, and make other restricted payments. Additionally, certain covenants restrict Talos Production Inc. subsu idiaries’ abia lity to pay dividends, create liens, and sell certain assets. Subsequent Event — On January 26, 2024, the Company issued a conditional notice to redeem in full the 11.75% Notes at a redemption price of 102.938% of the principal amount thereof, plus accruer d and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes Indenturt e. The Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes Indenturt e and the 11.75% Notes until redeemed on April 15, 2024 with the funds tee nd discharge the 11.75% Notes Indenturt e in accordance with its terms and the 11.75% Notes trustee acknowledged and elected to satisfy aff such discharge and satisfacff ry 7, 2024 utilizing the net proceeds from the Debt Offeff tion. The Company deposited $247.5 million with the trustee on Februar deposited with the trusr ring. ff 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 accruerr d and unpaid interest using the proceeds froff m the issuance of the 12.00% Notes. The debt redemption resulted in a loss on extinguishment of debt of $13.2 million forff the year ended December 31, 2021, which is included in “Other income (expense)” on the Consolidated Statements of Operations. F-25 7.50% Senior Notes The 7.50% Senior Notes dued 2022 matured on May 31, 2022 and were redeemed at an aggregate principal of $6.1 million plus accruer d and unpaid interest. Bank Credit Facility The Company maintains a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and four th quarter of each year. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027, (ii) increased the borrowing base from $1.1 billion to $1.5 billion and (iii) increased commitments froff m $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. On June 9, 2023, the borrowing base decreased froff m $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million as part of the biannual determination. ff The Bank Credit Facility no longer bears interest at the applicable London InterBank Offered Rate plus the applicable margin. Interest under the Bank Credit Facility accruer s at the Company’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the appl icable margin (“RFR Loans”). The ABR is based on the greater of (a) the prime eral funds rate plus 0.5% or (c) the adjud sted term SOFR for a one-month interest period plus 1.00%. The adjud sted term rate, (b) a fedff SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months, six-months, and twelve-months) calculated and published by the CME Group Inc. plus 0.10%. The adjud sted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York plus 0.10%. 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 Term Benchmark Loans, RFR Loans and ABR Loans as well as the commitment fee rate, in each case based upon the appl icable borrowing base utilization percentage: a a Borrowing Base Utilization Percentage Level 1 Level 2 Level 3 Level 4 Level 5 Utilization < 25% ≥ 25% < 50% ≥ 50% < 75% ≥ 75% < 90% ≥ 90% Term Benchmark Loans and RFR Loans 2.75% 3.00% 3.25% 3.50% 3.75% ABR Loans 1.75% 2.00% 2.25% 2.50% 2.75% Commitment Fee Rate 0.38% 0.38% 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 CoConsnsololididatateded ToTotatal Dl Debebt tt to Eo EBIBITDTDAXAX RaRatiotio (a(as ds defefininffff eded inin ththe Be Banank Ck Creredidit Ft Facacilityility) o) of nf no go grereataterer ththanan 3 003.00 toto 1 001.00 calcalcuculalateted ed eachach 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. Under the Bank Credit Facility, unutilized commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by, among other things, mortgages covering at least 85.0% of the oil and naturt al gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly- owned subsidiaries. As of December 31, 2023, the Company's borrowing base was $1,075.0 million with total commitments of $965.0 million. Additionally, no more than $250.0 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 subju ect 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, 2023. As of December 31, 2023, the Company had outstanding borrowings at a weighted average interest rate of 8.26%. nd Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of See Note 14 — Commitmett December 31, 2023. nts att Subsequent Event — On January 13, 2024, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”). The Tenth Amendment, among other things, (i) permits the incurrence of additional indebtedness in order to fundff the QuarterNorth Acquisition, with such indebtedness excluded froff m any reduction of the borrowing base that would otherwise result from such incurrence, and (ii) reaffiff rms the borrowing base at $1.1 billion effective upon closing of the QuarterNorth Acquisition. u F-26 Limitation on Restricted Payments Including Dividends The Company has not historically declared or paid any cash dividends on its capital stock. However, to the extent the Company determines in the futff urt e that it may be appropriate to pay a special dividend or initiate a quarterly dividend program, the Company’s ability to pay any such dividends to its stockholders may be limited to the extent its consolidated subsu idiaries are limited in their ability to make distributions to the Parent Company, including the significant restrictions that the agreements governing the Company’s debt impose on the ability of its consolidated subsu idiaries to make distributions and other payments to the Parent Company. With respect to entities accounted for under the equity method, the Company’s primary equity method investee as of December 31, 2023 did not have any undistributed earnings. The Bank Credit Facility contains restrictions on the abia lity of Talos Production Inc. to transfer funds to the Parent Company in the forff m of cash dividends, loans or advances. The Bank Credit Facility restricts distributions and other payments to the Parent Company, subju ect to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as afteff r giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) availabla e commitments exceed 25% of the then effeff ctive loan limit; (iii) the pro forff ma current ratio of 1.0 to 1.0 is satisfieff d; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as definff ed in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Availabla e Free Cash Flow Amount (as definff ed in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00. ff In addition, the indenturt e governing the 12.00% Notes restricts the Company’s consolidated subsu idiaries from, directly or indirectly, among other things, declaring or paying any dividend on account of their equity securities, subject to certain limited exceptions described in the indenturt e. Such exceptions include, among other things, if (i) no default has occurred or would occur as a result thereof, (ii) immediately after giving effeff ct to such transaction on a pro forff ma basis, the issuer could incur $1.00 of additional indebtedness in compliance with a fixed charge coverage ratio of 2.25 to 1.00, (iii) the ratio of the issuer’s total debt to EBITDA ratio is not greater than 3.00 to 1.00, and (iii) if payments pursuant to such transaction, together with the aggregate amount of certain other restricted payments, is less than the cumulative credit permitted under the indenturt e. The indenturt e governing the 11.75% Notes contains a similar restriction on the Company and its consolidated subsu idiaries’ abia lity to declare or pay dividends, subject to exceptions which include, among other things, (i) subju ect to no default or event of default having occurred or continuing, dividends in an aggregate amount not to exceed the greater of $25 million and 2.5% of Adjud sted Consolidated Net Tangible Assets, (ii) dividends or distributions to any parent company to make payments, in lieu of issuing fraff ctional shares in connection with share dividends, share splits, reverse share splits, mergers, consolidations, amalgamations or other business combinations and in connection with the exercise of warrants, options or other securities convertible into or exchangeable for equity interests of the Company. At December 31, 2023, restricted net assets of the Company’s consolidated subsu idiaries exceeded 25%. Subsequent Event — Debt Offeff ring On Februar ring (the “Debt Offering”) forff ry 7, 2024, the Company closed an upsized offeff the sale of $1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $625.0 million aggregate principal amount of second-priority senior secured notes due 2029 and $625.0 million aggregate principal amount of second-priority senior secured notes due 2031 ing to eligible purchasers that is exempt froff m registration under the Securities (collectively, the “New Senior Notes”), in a private offerff Act. The net proceeds from the Debt Offeff the pending QuarterNorth Acquisition, (ii) funded the redemption of all of the outstanding 12.00% Notes and all of the outstanding 11.75% Notes discussed above s and expenses related to the Redemptions and the issuance of the New Senior Notes. (the “Redemptions”), and (iii) paid premiums, feeff The Company intends to use any remaining net proceeds forff es, which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility. ring (i) are expected to fund a portion of the cash consideration forff general corpor ate purpos a rr r An aggregate of $340.0 million principal amount of the New Senior Notes will be subject to a “special mandatory redemption” in rth Merger Agreement are not consummated on or beforff e May 31, 2024 ertain requirements under the Hart-Scott- t Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notifyff the event that the transactions contemplated by the QuarterNor (or up tu Rodino Antitrusr the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition. o September 30, 2024 solely in the event the parties require additional time to satisfy cff F-27 Note 9 — Asset Retirement Obligations The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabia lities, and the changes in that liabia lity were as follows (in thousands): Balance, beginning of period Obligations assumed(1) Obligations incurred Obligations settled Obligations divested Accretion expense Changes in estimate(2) Balance, end of period Less: Current portion Long-term portion Year Ended December 31, 2023 2022 $ $ $ 541,661 $ 258,858 14,199 (86,615) (19,448) 86,152 102,419 897,226 $ 77,581 819,645 $ 434,006 — 1,140 (69,596) (1,572) 55,995 121,688 541,661 39,888 501,773 (1) (2) Assumed in connection with the EnVen Acquisition. See furff Changes in estimate were primarily due to an increase in estimated service costs. Additionally, increases for the year ended December 31, 2023 due to the acceleration of estimated settlement date. tions and Divestitures. ther discussion in Note 3 — Acquisiii At December 31, 2023, the Company has (1) restricted cash of $102.4 million inclusive of interest earned to date, held in escrow and (2) the P&A Notes Receivabla e with an aggregate facff e value of $66.2 million to settle future asset retirement obligations. These assets are discussed in Note 2 — Summary of Signi ant Accounting Policies. fici i Note 10 — Employee Benefitff s Plans and Share-Based Compensation EnVen Acquisition Severance The folff lowing tabla e summarizes severance accruar l activity in connection with the EnVen Acquisition included in “Other current liabia lities” and “Other long-term liabia lities” on the Consolidated Balance Sheets as of December 31, 2023 (in thousands): Severance accruar l at December 31, 2022 Accruar l additions Benefit payments Severance accruar l at December 31, 2023 Less: Current portion at December 31, 2023 Long-term portion at December 31, 2023 $ $ — 25,348 (19,054) 6,294 6,190 104 rr a The above ermination benefitsff tabla e includes involuntary t that are being provided pursuant to a one-time benefit arrangement that ermination benefitff s are also being provided is being spread over the future service period through the termination date. Involuntary t l termination benefitsff required by the terms of existing employee agreements. Pursuant to the EnVen Merger pursuant to contractuat t was establa ished and funded with $14.5 million at closing to pay a portion of future severance benefitff s associated Agreement, a rabbi trusr with the contractuat t held $3.7 million in assets of which $3.3 million and $0.4 million are included in “Other current assets” and “Other assets,” respectively, on the Consolidated Balance Sheets and both of which are included in the severance accruar t are availabla e to satisfy the claims of our creditors in the event of bankrupt cy or insolvency. Severance costs are reflected in “General and administrative expense” on the Consolidated Statement of Operations. l at December 31, 2023 listed above r . As of December 31, 2023, the rabbi trusrr . The assets of the rabbi trusrr l termination benefitsff a rr 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 forff potential grants of: (i) incentive stock options qualifieff d as such under U.S. fedff eral income tax laws (“ISOs”), (ii) stock options that do not qualify aff eciation rights, (iv) restricted stock awards, (v) RSUs, (vi) awards of vested stock, (vii) dividend equivalents, (viii) other share-based or cash awards and (ix) subsu titute awards. Employees, non-employee directors and consultants of the Company and its affiff liates are eligible to receive awards under the 2021 LTIP. The 2021 LTIP authorizes the Company to grant awards of up tu o 8,639,415 shares of the Company’s common stock, subject to the share counting and share recycling provisions of the 2021 LTIP. s ISOs (together with ISOs, “Options”), (iii) stock appr a F-28 Restritt ctedtt Stoctt k UniUU tsii – EmpEE loyeo es — RSUs granted to employees under the LTIP Plans primarily vest ratabla y over an appr oximate three year period subju ect 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 oximately $19.0 million, which is expected to be recognized over a weighted average period of 1.7 years. at December 31, 2023 was appr a a Restritt ctedtt Stoctt k UniUU tsii – NonNN -employeo e Directortt srr — 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. 60%, and cash for the Upon vesting, these RSUs represent a contingent right to receive one share of common stock for each RSU forff remaining 40%. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2023 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 liabia lity awards and will be subsu equently remeasured at each reporting period. The folff lowing tabla e summarizes RSU activity: Restricted Stock Units Weighted Average Grant Date Fair Value Unvested RSUs at December 31, 2020 Granted Vested Forfeited Unvested RSUs at December 31, 2021 Granted Vested Forfeited Unvested RSUs at December 31, 2022(1) Granted Vested Forfeited Unvested RSUs at December 31, 2023(1) 1,652,988 $ 1,102,038 $ (669,832) $ (101,995) $ 1,983,199 $ 2,297,465 $ (967,269) $ (97,891) $ 3,215,504 $ 1,154,541 $ (1,730,959) $ (332,725) $ 2,306,361 $ 13.73 13.11 15.01 12.46 13.02 13.23 14.14 14.34 12.79 16.24 11.97 14.52 14.89 (1) As of December 31, 2023 and 2022, 26,975 and 25,257, respectively, of the unvested RSUs were accounted for as liabia lity awards in “Accruerr d liabia lities” on the Consolidated Balance Sheet. The Company considers its intent and abia lity to settle awards in cash or shares in determining whether to classify the awards as equity or as a liabia lity. Certain awards granted durd ing the year ended December 31, 2021 were originally classified as liability awards; oval of the 2021 LTIP. The aggregate amount of however, these awards became equity-classified awards upon stockholder appr compensation cost related to these awards is determined by the faiff r value of the award on the modification date. a Perforff marr nce ShaSS re Units –tt Emplm oyll ees — 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 froff m zero to 200% of the target number of PSUs granted. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2023 a was appr oximately $8.7 million, which is expected to be recognized over a weighted average period of 1.7 years. F-29 The folff lowing tabla e summarizes PSU activity: Perforff mance Share Units Weighted Average Grant Date Fair Value Unvested PSUs at December 31, 2020 Granted Vested Forfeited Unvested PSUs at December 31, 2021 Granted(1) Vested(2) Forfeited Cancelled Unvested PSUs at December 31, 2022 Granted(3) Forfeited Unvested PSUs at December 31, 2023 834,172 $ 586,995 $ (391,308) $ (14,400) $ 1,015,459 $ 629,666 $ (14,474) $ (16,486) $ (975,564) $ 638,601 $ 595,394 $ (217,346) $ 1,016,649 $ 25.46 18.96 39.43 18.48 16.41 23.73 13.05 17.48 16.42 23.66 18.76 21.28 21.30 (1) (2) (3) There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder returt n (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s returt n on the wells included in the 2022 drill program over a three-year performance period. The performance period for the relative TSR awards ended on December 31, 2022. The payout on these awards was 0% based on actuat performance period as certifieff d by the Compensation Committee of the Company’s Board of Directors in early 2023. Since these awards were legally forff they will again be availabla e forff There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s returt n on the wells included in the 2023 drill program over a three-year performance period. new awards under the recycling provisions of the 2021 LTIP. l performance over the feited Certain awards granted during the year ended December 31, 2021 were originally classified as liabia lity awards; however, these oval of the 2021 LTIP. The following tabla e summarizes the assumptions r value of the relative or absa olute TSR PSUs granted and modified at the date awards became equity-classified awards upon stockholder appr used in the Monte Carlo simulations to calculate the faiff indicated: a Expected term (in years) Expected volatility Risk-free interest rate Dividend yield Fair value (in thousands) $ Grant December 1 2.1 61.9 % 4.4 % — % 12 2023 Grant July 1 2.5 66.2 % 4.6 % — % 173 $ Grant March 5 2.8 73.1 % 4.5 % — % $ 6,165 2022 Grant September 20 2.3 74.3 % 3.9 % — % 621 $ 2021 Grant March 5 Modification May 11 Grant March 8 2.8 82.2 % 1.6 % — % 2.6 80.9 % 0.3 % — % 2.8 78.3 % 0.3 % — % $ 8,668 $ 9,715 $ 11,129 Modifii cation — During March 2022, the outstanding PSUs held by certain executive officers that were awarded in 2020 and 2021 were cancelled and, in connection with this cancellation, 1,147,352 of RSUs were granted (the “Retention RSUs”). The Retention RSUs will vest ratabla y each year over two years, generally contingent upon continued employment through each such date. The cancellation of the PSUs along with the concurrent grant of the Retention RSUs are accounted for as a modification. The incremental cost of $9.7 million will be recognized prospectively over the modified requisite service period. Additionally, the remaining unrecognized grant or modification date faiff r value of the original PSUs will be recognized over the original remaining requisite service period. 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 naturt e 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 folff lowing tabla e presents the amount of costs expensed and capitalized (in thousands): Share-based compensation costs Less: Amounts capitalized to oil and gas properties Total share-based compensation expense 2023 Year Ended December 31, 2022 2021 $ $ 25,236 $ 12,283 12,953 $ 28,280 $ 12,327 15,953 $ 20,560 9,568 10,992 F-30 Note 11 — Income Taxes Income Tax Expense (Benefitff ) 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 deferff red income tax expense (benefit) Total income tax expense (benefit) 2023 Year Ended December 31, 2022 2021 $ $ $ $ $ 76 $ 31 107 $ (60,704) $ — (60,704) $ 1,375 $ 432 1,807 $ 659 $ 71 730 $ (60,597) $ 2,537 $ (5) (993) (998) (1,067) 430 (637) (1,635) A reconciliation of income tax expense (benefit) computed at the U.S. fedff eral statutt ory t rr ax rate to the Company’s income tax expense (benefit) is as follows (in thousands, except percentages): Income tax expense (benefit) at the fedff eral statutt ory t rr ax rate State income taxes Impact of foreign operations Effeff ct of change in state rate Prior year taxes Change in valuation allowance Other permanent differences Total income tax expense (benefit) Effeff ctive tax rate 2023 Year Ended December 31, 2022 2021 $ $ 26,614 1,748 13,539 — 1,184 (106,815) 3,133 (60,597) (47.81)% $ $ 80,735 1,591 15,657 — (2,920) (96,537) 4,011 2,537 0.66 % $ $ (38,763) (674) (11,920) 2,008 486 45,547 1,681 (1,635) 0.89 % The Company’s effective tax rate for the year ended December 31, 2023 differed froff m the federal statutory rate of 21.0% primarily iwithth $106.8 millimillionon rerelalateted td to to thehe rereleleasase oe of tf thehe avalluatatioion an allollo awancnce fe fororfff rered td taax asassesetsts ofoffsfsfff etet itits ds defefererfff d edue toto a na nonon-cacashsh tata bx benenefefititffff ofof $106 8 permanent diffeff rences and state income tax expense. The Company’s effective tax rate for the years ended December 31, 2022 and 2021 differed froff m the federal statutory rate of 21.0% primarily due to recording a full valuation allowance against its fedff eral, state and forff eign deferred tax assets. F-31 Deferred Tax Assets and Liabilities Net deferff red tax assets (liabia lities) refleff ct the net tax effects of temporary drr liabia lities forff and liabia lities were as follows (in thousands): financial reporting purpos r es and the amounts used forff income tax purpos iffeff rr rences between the carrying amounts of assets and red tax assets es. Significant components of deferff Deferred tax assets: Federal net operating loss Foreign tax loss carryforward State net operating loss Tax credits Interest expense carryforward Asset retirement obligations Derivatives Other well equipment Accruer d bonus Share-based compensation Operating lease liabia lities Finance lease liabia lities Other Total deferff red tax assets Valuation allowance Total deferff red tax assets, net Deferred tax liabia lities: Oil and gas properties Operating lease assets Derivatives Prepaid Total deferff Net deferff red tax liabia lity red tax liabilities Year Ended December 31, 2023 2022 147,252 $ 509 24,840 107 46,414 190,248 — 1,317 5,050 5,172 4,427 31,607 3,383 460,326 (23,697) 436,629 $ 512,918 $ 2,421 9,670 3,847 528,856 (92,227) $ 159,257 44,462 24,787 107 23,262 115,848 9,273 1,891 5,863 5,296 3,669 32,559 7,142 433,416 (129,105) 304,311 302,602 1,323 — 2,530 306,455 (2,144) $ $ $ $ Net Operating Loss The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2023 (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 452,393 248,807 1,696 125,958 277,930 2035 - 2037 Unlimited 2025 - 2032 2025 - 2037 Unlimited $ $ $ $ $ As of December 31, 2023, the Company had U.S. fedff oximately $701.2 million, all of which are subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect ation to utilize its tax attributes, against future U.S. taxabla e income in the event of a change in ownership. If not to the abia lity of a corpor utilized, such carryforwards would begin to expire at the end of 2035. eral net operating loss carryforwards (“NOLs”) of appr a r Valuation Allowance The Company recorded a valuation allowance of $23.7 million and $129.1 million as of December 31, 2023 and 2022, respectively. Deferred income tax assets and liabia lities are recorded related to NOLs and temporary drr rences between the book and tax basis of assets and liabia lities expected to produce tax deductions and income in the future. The realization of these assets depends on recognition of sufficient futff urt e taxable income in specific tax jurisdictions in which those temporary drr rences or NOLs relate. iffeff iffeff 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 deferff red tax assets will not be realized using availabla e positive and negative evidence, including future reversals of temporaryrr differences, tax-planning strategies and futff urt e taxable income, to estimate whether suffiff cient futff urt e taxable income will be generated to permit use of deferff red tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits the Company’s abia lity to consider other subjective positive evidence. F-32 At December 31, 2022, the Company maintained a valuation allowance related to federal, state and foreign deferff red tax assets, as there was insufficient positive evidence to overcome the subsu tantial negative evidence of being in a cumulative loss position. At December 31, 2023, the Company is no longer in a cumulative loss position and reached the conclusion that it is appropriate to release the valuation allowance against its federal deferff red tax assets due to the sustained positive operating performance and the availabia lity of expected future taxabla e income. The Company’s remaining valuation allowance primarily relates to various state operating loss carryforwards. Uncertain Tax Positions The table below sets forff th the beginning and ending balance of the total amount of unrecognized tax benefitff s. None of the unrecognized benefitsff 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 finff ancial statements. Balances in the uncertain tax positions are as folff lows (in thousands): Total unrecognized tax benefitsff Increases in unrecognized tax benefitsff , beginning balance as a result of: Tax positions taken durd ing a prior period Tax positions taken durd ing the current period , ending balance Total unrecognized tax benefitsff 2023 Year Ended December 31, 2022 2021 $ $ 835 $ 154 — 989 $ 696 $ 100 39 835 $ 648 21 27 696 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 2020 through 2023 tax years remain open to examination by the tax jurisdictions in which the Company is subject to tax. The eral income tax returt ns of the Company for years ending on or before December 31, statutt e of limitations with respect to the U.S. fedff 2019 are closed, except to the extent of any NOL carryover balance. EnVen Acquisition On Februar ry 13, 2023, the Company completed the EnVen Acquisition, which is furff Divestitures. The Company recognized a net deferff date to reflect diffeff babalalancnce ie is bs basaseded onon prprelelimimininarary cy crrr rences between tax basis and the fair value of EnVen’s assets acquired and liabilities assumed. The deferff alalcuculalatiotionsns anand od on in infnfororffff mamatiotion an avavaililabablele toto mamananagegemementnt atat ththe te timime se sucuch eh eststimaimatetes ws werere me madade.e. tions and red tax liability of $150.3 million in its purchase price allocation as of the acquisition red tax ther discussed in Note 3 —Ac— quisiii Note 12 — 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 Februar ry 28, 2021. The folff thousands, except forff the per share amounts): lowing tabla e presents the computation of the Company’s basic and diluted income (loss) per share were as folff lows (in Net income (loss) 2023 Year Ended December 31, 2022 2021 $ 187,332 $ 381,915 $ (182,952) Weighted average common shares outstanding — basic Dilutive effeff ct of securities Weighted average common shares outstanding — diluted 119,894 858 120,752 82,454 1,229 83,683 NNet income (loss) per common share: Basic Diluted Anti-dilutive potentially issuable securities excluded froff m diluted common shares $ $ 1.56 $ 1.55 $ 1,353 4.63 $ 4.56 $ 865 81,769 — 81,769 (2.24) (2.24) 1,709 F-33 Note 13 — Related Party Transactions Apollo Funds and Riverstone Funds On Februar ry 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 affiff liated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”) and members of management pursuant to which the Talos Energy LLC received a private equity capital commitment. On January 3, 2022, the Apollo Funds ceased being a beneficial owner of more than fivff e percent of the Company’s common stock. On July 5, 2023, the Riverstone Funds ceased being a beneficial owner of more than fivff e percent of the Company’s common stock. Whistler Acquisition Settlement On August 31, 2018, the Company acquired Whistler Energy II, LLC from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds. A settlement agreement related to a dispute regarding the decommissioning obligation of a Deepwater well was executed in September 2021. For the year ended December 31, 2021, the Company recognized a $4.4 million gain resulting fromff the settlement which is refleff cted in “Other income (expense)” on the Company’s Consolidated Statements of Operations. Registration Rights Agreements tion Rightgg s Att 2018 Regie stii ratt greement — On May 10, 2018, the Company entered into a registration rights agreement (the “2018 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 on such date. Subsequently, the 2018 Registration Rights Agreement was amended to add additional affilff iates of the Riverstone Funds as parties to the agreement and provide such parties with customary r egistration rights with respect to the Company’s Series A Convertible Preferff red Stock issued to these parties at the closing of an acquisition on Februar ry 28, 2020. rr The 2018 Registration Rights Agreement provided that registration rights would terminate with respect to Franklin and MacKay Shields in the event that either Franklin or MacKay Shields ceased to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. Additionally, the 2018 Registration Rights Agreement provided that registration rights would otherwise terminate at such time as there were no registrabla e securities outstanding. The 2018 Registration Rights Agreement terminated on July 5, 2023 as there were no registrable securities outstanding. The Company agreed to bear all of the expenses incurred in connection with any offer and sale, while the selling stockholders will of nil, nil, and $0.7 million s, discounts and selling commissions. The Company incurred fees ff be responsible for paying underwriting feeff for the fiscal years ended December 31, 2023, 2022 and 2021, respectively. tstiii ratt tition RiRi hghii 2022 RRe igie 2022 tts AAgreementt — IIn conne tctiion withith thth Ce Compa ’ny’s e tntry iintto thth Ee E VnVen MMerger AAgreementt o Sn Septte bmber 21, 2022 to acquire EnVen, the Company entered into a registration rights agreement (the “2022 Registration Rights Agreement”) with Adage Capital Partners, L.P. (“Adage”) and affiff liated entities of Bain Capia tal, LP (“Bain”). Pursuant to the 2022 Registration Rights Agreement, the Company grants to Adage and Bain certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock to be received by such entities in the EnVen Acquisition, subju ect to certain customary t hresholds and conditions. Adage and Bain held appr oximately 2.3% and 12.2%, respectively, of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by each of Adage and Bain. a rr Additionally, the Company agreed to pay certain expenses of the parties incurred in connection with the exercise of their rights certain securities law matters in connection with any registration statement filed under such agreement and to indemnify t pursuant thereto. The Company did not incur any fees for the fiscal year ended December 31, 2023. hem forff ff Amended and Restated Stockholders’ Agreement and Related Agreements 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 2rr 4, 2020, the Company and the other parties thereto amended the Stockholders’ Agreement to, among other things, add additional affiliates of the Riverstone Funds (or one or more of its designated affiliates) as parties to the Stockholders’ Agreement and provided ownership of the Series A Convertible Preferff red Stock would, prior to the conversion thereof on March 20, 2020, count towards certain stock ownership requirements on an as converted basis to retain the Riverstone Funds rights to nominate directors to the board of directors. On March 29, 2022, the Company and other parties thereto, entered into the Amended and Restated Stockholders’ Agreement, in connection with the termination of the Apollo Funds’ rights thereunder and the resignation of certain members of the Company's Board of Directors (the “Amended and Restated Stockholders’ Agreement”). The Amended and Restated Stockholders’ Agreement, among other things, (i) terminated the rights of the Apollo Funds under the Stockholders’ Agreement and (ii) eliminated the requirement that the board of directors consist of ten members. F-34 t agreement dated as of September 21, 2022 requiring the Riverstone Funds to, among other things, appr In connection with the closing of the EnVen Acquisition, the Company and the Riverstone Funds terminated the Amended and Restated Stockholders’ Agreement and Mr. Robert M. Tichio resigned froff m the Company’s Board of Directors pursuant to a shareholder ove the EnVen Merger u suppor Agreement and the proposed business combination. In connection with the termination of the Amended and Restated Stockholders’ Agreement, the Company and the Riverstone Funds entered into a letter agreement, dated February 1rr 3, 2023, pursuant to which the parties thereto agreed to execute and deliver such additional documents and take all such further action as may be reasonabla y necessary to cause the Amended and Restated Stockholders’ Agreement to be terminated without any furff ther force and effeff ct. a Legal Fees The Company has engaged the law firff m Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An immediate famff ily 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, 2023, 2022 and 2021, the Company incurred fees of approximately $3.3 million, $4.8 million, and $3.1 million, respectively, of which $0.8 million, $1.3 million, and $0.2 million were payable at each respective balance sheet date for legal services performed by V&E. ff Slim Family Carlos Slim Helú, Carlos Slim Domit, Marco Antonio Slim Domit, Patrick Slim Domit, María Soumaya Slim Domit, Vanessa Paola Slim Domit and Johanna Monique Slim Domit (collectively, the “Slim Family”) are beneficff t which in turn owns all of the outstanding voting securities of Control Empresarial de Capia tales S.A. de C.V. (“Control Empresarial” together with the Slim Family, the “Slim Family Offiff ce”). Control Empresarial, a sociedad anónima de capia tal variable organized under the laws of the United Mexican States, is a holding company with portfolff io investments in various companies. Control Empresarial and the Slim Family became related parties on November 7, 2023 when they accumulated greater than ten percent of the Company’s outstanding shares of common stock. Control Empresarial held approximately 12.2% of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by Control Empresarial. The Slim Family own a majoa rity stake in Grupo tions and Divestitures for additional r information. The Company had no related party receivabla e froff m affiliates of the Slim Family as of December 31, 2023. Carso, which indirectly has an ownership interest in Talos Mexico. See Note 3 – Acquisiii iaries of a Mexican trusr Subsequent Event — In connection with the January Equity Offeff to approximately 21.9% of the Company’s outstanding shares of common stock as of the closing of the January Equity Offeff on SEC beneficff ial ownership reports filed by Control Empresarial. See Note 17 – Subsequent Events for additional inforff mation. ring (definff ed below), Control Empresarial increased their holding ring based ring in Februarr In connection with the Debt Offeff ring consisting ring to eligible purchasers that of $1,250.0 million in aggregate principal amount of second-priority senior secured notes in a private offeff ring, and after expressing a non-binding was exempt froff m registration under the Securities Act. In connection with the Debt Offeff indication of interest after commencement of the offeff ring, entities and/or persons related to the Slim Family Offiff ce purchased an aggregate principal amount of $$312.5 million of such notes from the initial purchasers of such offering. In connection with such transaction, the Company expects to pay Inbursa, a banking institution controlled by the Slim Family Offiff ce an advisory fee of approximately $2.7 million. See Note 8 – Debt for additional inforff mation regarding the Debt Offering. ry 2024, the Company consummated a firm commitment debt offeff Equity Method Investments The Company had a $5.5 million related party receivabla e froff m various equity method investments as of December 31, 2023. This is reflected as “Other, net” within “Accounts Receivabla e” on the Consolidated Balance Sheets. See Note 7 – Equity Method Investments for additional inforff mation on the Company’s equity method investments. Note 14 — Commitments and Contingencies Legal Proceedings and Other Contingencies From time to time, the Company is involved in litigation, regulatory err xaminations and administrative proceedings primarily arising in the ordinary crr ourse 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 finff ancial position; however, an unfavff orable outcome could have a material adverse effect interim period or year. on the Company’s results from operations for a specificff On March 23, 2022, the Company entered into a settlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its claims in the litigation. The settlement is reflected as “Other income (expense)” on the Consolidated Statements of Operations. F-35 In June 2019, David M. Dunwoody, Jr., former President of EnVen, filff ed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favff or or Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filff ed a Notice of Appeal in December 2021. The litigation was assumed as part of the EnVen Acquisition. In April 2023, the appe llate court affirmed the trial court’s judgment. The Company filed a petition forff review with the Texas Supru eme Court on August 2, 2023, which was denied on January 26, 2024. As Of December 31, 2023, the Company has recorded $14.3 million as “Other current liabia lities” on the Consolidated Balance Sheets related to the litigation. a Perforff mance Obligations Regulations with respect to the Company's operations govern, among other things, engineering and construcrr production faci obligations under the production sharing contracts with Mexico. lities, safety procedurd es, plugging and abaa ndonment of wells, removal of faci ff ff tion specificff ations for lities in the U.S. Gulf of Mexico and certain As of December 31, 2023, the Company had secured performance bonds from third party sureties totaling $1.4 billion. The cost of securing these bonds is refleff cted as “Interest expense” on the Consolidated Statements of Operations. Additionally, as of December 31, 2023, the Company had secured letters of credit issued under its Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the availabla e revolving credit commitments. See Note 8 — Debt for furff ther information on the Bank Credit Facility. The table below summarizes the Company’s total minimum commitments associated with vessel commitments, purchase obligations and other miscellaneous commitments as of December 31, 2023 (in thousands): Vessel Commitments(1) Committed purchase orders(2) Other commitments(3) Total $ $ 13,216 $ 3,083 3,991 20,290 $ — $ — 327 327 $ — $ — — — $ — $ — — — $ — $ — — — $ 13,216 3,083 4,318 20,617 2024 2025 2026 2027 Thereafter Total (1) (2) (3) certain Deepwater well intervention, drilling operations and decommissioning activities. These l obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working Includes vessel commitments the Company will utilize forff commitments represent gross contractuat interest share of such costs. Includes committed purchase orders to execute planned futff urt e drilling activities. These commitments represent gross contractuat other joint owners in the properties operated by the Company will be billed forff Includes commitments associated with the Company’s CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement. their working interest share of such costs. l obligations and accordingly, Decommissioning Obligations The Company, as a co-lessee or predecessor-in-interest in oil and natural gas leases located in the U.S. Gulf of Mexico, is in the of divestiturt e of certain oil and natural gas assets previously owned chain of title with unrelated third parties either directly or by virtuet rties in these divestiture transactions or third parties in existing leases have filed forff and assigned by our subsu idiaries. Certain counterpar bankrupt cy protection or undergone associated reorganizations and may not be able to perform required abaa ndonment obligations. r Regulations or federal laws could require the Company to assume such obligations. The Company refleff cts such costs as “Other operating (income) expense” on the Consolidated Statements of Operations. The decommissioning obligations included are in the Consolidated Balance Sheets as “Other current liabia lities” and “Other long- lows (in thousands): term liabilities”, and the changes in that liabia lity were as folff Balance, beginning of period Additions Changes in estimate Reimbursements dued Settlements Balance, end of period Less: Current portion Long-term portion from third parties 2023 Year Ended December 31, 2022 2021 $ $ $ 54,269 $ 266 11,613 — (50,584) 15,564 $ 3,280 12,284 $ 24,336 $ 8,900 22,658 — (1,625) 54,269 $ 42,069 12,200 $ — 21,056 — 3,280 — 24,336 3,756 20,580 F-36 Although it is reasonabla y possible that the Company could receive state or fedff eral decommissioning orders in the futff urt e or be notifieff d of defauff lting 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 froff m such orders. However, the Company could incur judgments, enter into settlements or revise its opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effecff t on its results of operations in the period in which the amounts are accruerr d and its cash floff ws in the period in which the amounts are paid. Note 15 — Segment Information The Company’s operations are managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The Upstream Segment is the Company’s only reportabla e segment. The Company’s chief operating decision-maker (“CODM”) is the President and Chief Executive Officer, who reviews operating results to make decisions about allocating resources and assessing performance for the entire company. A reportabla e segment is an operating segment that meets materiality thresholds. The 10% test, as prescribed by the segment reporting accounting guidance, are based on the reported measures of revenue, profit, and assets that are used by the CODM to assess performance and allocate resources. The CCS Segment currently does not meet any of the reportabla e segment quantitative thresholds. The profit or loss metric used to evaluate segment performance is Adjud sted EBITDA, which is definff ed by the Company as net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion, and amortization; accretion expense; non-cash write-down of oil and naturt al gas properties; transaction and other (income) expenses; decommissioning obligations; the net change in the faiff r value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives); (gain) loss on debt extinguishment; non-cash write-down of other well equipment; and non-cash equity-based compensation expense. Corporate general and administrative expense include certain shared costs such as finff ance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each of operating segment. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment. The remaining expenses are included in the reconciliation of reportabla e segment Adjud sted EBITDA to consolidated pre-tax net income (loss) as an unallocated corporate general and administrative expense. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company’s CODM does not review assets by segment as part of the financial inforff mation provided and thereforff e, no asset information is provided in the tabla e below. The folff lowing tabla e presents selected segment information forff the periods indicated (in thousands): Revenues froff m External Customers: Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method: Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Adjud sted EBITDA: Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Segment Expenditures: Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 $ $ $ $ $ Upstream All Other(1) Total 1,457,886 $ 1,651,980 1,244,540 — $ — — 1,457,886 1,651,980 1,244,540 120 $ 101 — 979,729 $ 859,840 $ 615,798 733,669 $ 452,674 338,822 (12,228) $ (1,166) — (22,883) $ (12,786) (4,782) 40,961 $ 2,778 — (12,108) (1,065) — 956,846 847,054 611,016 774,630 455,452 338,822 (1) The CCS Segment is included in the “All Other” category.rr The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments artners. Equity method investments is a business strategy that enabla es us to achieve favorable economies of scale relative to the level of investment with industry prr and business risk assumed. F-37 Reconciliations The folff lowing tabla e presents the reconciliations of Adjud sted EBITDA to the Company’s consolidated totals (in thousands): Adjud sted EBITDA: ate general and administrative expense reportabla e segments Total forff All other Unallocated corpor r Interest expense Depreciation, depletion and amortization Accretion expense Write-down of oil and naturt al gas properties Transaction and other (income) expenses(1) Decommissioning obligations(2) Derivative fair value gain (loss) (3) Net cash (received) paid on settled derivative instrumr Gain (loss) on extinguishment of debt Non-cash write-down of other well equipment Non-cash equity-based compensation expense ents (3) Income (loss) before income taxes 2023 Year Ended December 31, 2022 2021 979,729 $ (22,883) (6,128) (173,145) (663,534) (86,152) — 33,295 (11,879) 80,928 9,457 — — (12,953) 126,735 $ 859,840 $ (12,786) (5,280) (125,498) (414,630) (55,995) — 34,513 (31,558) (272,191) 425,559 (1,569) — (15,953) 384,452 $ 615,798 (4,782) (4,542) (133,138) (395,994) (58,129) (18,123) (5,886) (21,055) (419,077) 290,164 (13,225) (5,606) (10,992) (184,587) $ $ (1) Transaction expenses includes $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expense forff the years ended December 31, 2023 and 2022, respectively. See furff tion and Divestitures and Note 10 — Emplm oyee Benefitse Plans and Share-Based ComCC pem nsation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningfulff indicator of its operating performance. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Note 3 — Acquisiii ng of the capital carry of the Company’s investment in Bayou Bend the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the by Chevron of $8.6 million and $1.4 million forff partial sale of its investment in Bayou Bend to Chevron forff ther discussion in Note 7 — Equity Method Investments. For the year ended December 31, 2022. See furff the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 14 — Commitments and Contingencies. (2) Estimated decommissioning obligations were a result of working interest partners or counterparr rr rties of divestiture transactions that were unabla e to perform the cy or insolvency. See Note 14 — Commitments and Contingencies for additional inforff mation on decommissioning tions and Divestitures. The amount includes a gain on the fundi ther discussion in Note 3 — Acquisiii ff required abaa ndonment obligations due to bankrupt obligations. (3) The adjud stments forff the derivative faiff r value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effeff ct of adjud sting ents, which are recognized at the end of each accounting period because the Company does not designate net loss forff commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjud sted EBITDA on an unrealized babasisis ds d rurdd ining tg thehe pepeririodod ththe de dereriivatatiiveses sesettttleledd. changes in the fair value of derivative instrumrr The folff lowing tabla e presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands): Segment Expenditures: Total reportabla e segments All other Change in capital expenditures included in accounts payable and accrued liabia lities Plugging & abaa ndonment Decommissioning obligations settled Investment in CCS intangibles and equity method investees Other deferff Insurance recovery proceeds Non-cash well equipment transfers Other red payments Exploration, development and other capital expenditures $ $ 2023 Year Ended December 31, 2022 2021 733,669 $ 40,961 (9,199) (86,615) (50,584) (40,946) (1,545) 2,802 (27,731) 622 561,434 $ 452,674 $ 2,778 (60,011) (69,596) (1,625) (2,778) — — (6) 1,728 323,164 $ 338,822 — 28,258 (67,988) — — (7,921) — 1,086 1,074 293,331 F-38 Note 16 — 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): Consolidll atdd edtt Entitieii Proved properties Unproved oil and gas properties, not subju ect to amortization(1) s: Total oil and gas properties Less: Accumulated depletion Net capitalized costs Depletion and amortization rate (Per Boe) Company'n s S' Investees: Unproved oil and gas properties, not subju ect to amortization haSS re of Equityii 2023 Year Ended December 31, 2022 2021 7,906,295 $ 268,315 8,174,610 4,143,491 4,031,119 $ 27.23 $ 5,964,340 $ 154,783 6,119,123 3,484,590 2,634,533 $ 18.95 $ 5,232,480 219,055 5,451,535 3,072,907 2,378,628 16.71 56,579 $ — $ — $ $ $ $ (1) Amount includes $111.4 million and $110.3 million of unproved properties, not subju ect to amortization, related to the Company’s operations in offsff hore Mexico forff the years ended December 31, 2022 and 2021, respectively. 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 refleff cted as “Asset retirement obligations” on the accompanying Consolidated Balance Sheets. See Note 9 — Asset Retirement Obligations for additional inforff mation. Costs Incurred forff Property Acquisition, Exploration and Development Activities The folff lowing tabla e refleff cts the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities durd ing the years indicated (in thousands). Costs incurred also include new asset retirement obligations establa ished in the current year, as well as increases or decreases to the asset retirement obligations resulting froff m changes to estimates during the year. Consolidll atdd edtt Entitieii Property acquisition costs: s: Proved properties Unproved properties, not subju ect to amortization Total property acquisition costs Exploration costs(1) Development costs Total costs incurred Company'n s S' Exploration costs haSS re of Equityii Investees: 2023 Year Ended December 31, 2022 2021 $ $ $ 951,703 $ 249,688 1,201,391 161,296 805,148 2,167,835 $ — $ 2,221 2,221 125,889 541,512 669,622 $ 210 — 210 23,844 245,058 269,112 290 $ — $ — (1) Amount includes nil, $1.2 million and $6.6 million of exploration costs related to the Company’s operations in offsff hore Mexico forff 2023, 2022 and 2021, respectively. the years ended December 31, 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 futff urt e rates of production and timing of development expenditures. The reserve data in the folff lowing tabla es only represent estimates and should not be construer d as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and subsurface information obtained froff m 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, naturt al gas and NGL reserves are located in the U.S. Gulf of Mexico. At December 31, 2023, 2022 and 2021, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil es by the Company’s reservoir engineers and audited by reporting purpos and naturt al gas properties were estimated and compiled forff Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. r F-39 The folff lowing tabla e presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf)ff NGL (MBbls) Oil Equivalent (MBoe) Consolidll atdd edtt Entitieii Total proved reserves at December 31, 2020 s: Revision of previous estimates Production Extensions and discoveries Total proved reserves at December 31, 2021 Revision of previous estimates Production Sales of reserves Extensions and discoveries Total proved reserves at December 31, 2022 Revision of previous estimates Production Purchases of reserves Extensions and discoveries Total proved reserves at December 31, 2023 Total Proved Developed Reserves as of: December 31, 2021 December 31, 2022 December 31, 2023 Total Proved Undeveloped Reserves as of: December 31, 2021 December 31, 2022 December 31, 2023 109,307 13,619 (16,159) 997 107,764 (5,625) (14,561) (158) 3,639 91,059 (6,308) (18,062) 41,871 2,255 110,815 93,420 80,285 98,225 14,344 10,774 12,590 257,208 8,979 (32,795) 2,961 236,353 (8,302) (32,215) (7,625) 31,340 219,551 (62,946) (26,194) 36,690 12,770 179,871 186,442 161,727 141,823 49,911 57,824 38,048 10,858 5,137 (1,875) 315 14,435 (2,002) (1,793) — 2,288 12,928 (1,283) (1,767) 1,116 979 11,973 11,792 9,315 9,957 2,643 3,613 2,016 163,033 20,252 (23,500) 1,806 161,591 (9,010) (21,723) (1,429) 11,150 140,579 (18,082) (24,195) 49,102 5,362 152,766 136,286 116,555 131,819 25,305 24,024 20,947 During 2023, proved reserves increased by 12.2 MMBoe primarily dued to a purchases of reserves of 49.1 MMBoe in connection with the EnVen Acquisition and 5.4 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Brutus Field in the Green Canyon core area. This increase was partially offsff et by a decrease of 24.2 MMBoe of producd tion and a decrease of 18.1 MMBoe from revisions of previous estimates. The revisions were primarily due to a 13.5 MMBoe decrease in reserve volumes due to the decrease in SEC Pricing of $17.47 per Bbl of oil and $4.05 per Mcf of natural gas and an additional decrease in the Phoenix Field in the Green Canyon core area due to well performance. During 2022, proved reserves decreased by 21.0 MMBoe primarily due to a decrease of 21.7 MMBoe of production. Additionally, there was a decrease of 9.0 MMBoe primarily due to timing of development of certain PUD locations to move beyond five years at the Phoenix Field in the Green Canyon core area and sales of reserves of 1.4 MMBoe primarily related to the Brusr hy Creek Field in the Shelf and Gulf Coast area. The decrease was partially offsff et by 11.2 MMBoe of estimated proved reserves fromff extensions and discoveries primarily from evaluations of the Pompano Field and the Ram Powell Field located in the Mississippi Canyon core area. During 2021, proved reserves decreased by 1.4 MMBoe primarily due to a decrease of 23.5 MMBoe of production. The decrease was partially offsff et 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 froff m extensions and discoveries primarily from an evaluation of Crown and Anchor Field located in the Mississippi Canyon core area. F-40 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves The folff lowing tabla e refleff cts the standardized measure of discounted future net cash floff ws relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands): s: Consolidll atdd edtt Entitieii Future cash inflows Future costs: Production Development and abandonment Future net cash floff ws before income taxes Future income tax expense Future net cash floff ws afteff Discount at 10% annual rate Standardized measure of discounted future net cash floff ws r income taxes 2023 Year Ended December 31, 2022 2021 $ 9,425,055 $ 10,674,896 $ 8,496,005 (3,090,491) (2,358,368) 3,976,196 (589,413) 3,386,783 (343,295) 3,043,488 $ (1,906,752) (1,873,453) 6,894,691 (1,114,409) 5,780,282 (1,411,834) 4,368,448 $ (1,868,818) (1,422,507) 5,204,680 (676,778) 4,527,902 (1,087,291) 3,440,611 $ Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash SEC Pricing used in determining the ents. See the folff lowing tabla e forff flow estimates do not include the effects of derivative instrumrr standardized measure: Oil price per Bbl Natural gas price per Mcf NGL price per Bbl 2023 Year Ended December 31, 2022 2021 $ $ $ 78.56 $ 2.75 $ 18.77 $ 96.03 $ 6.80 $ 33.89 $ 67.14 3.71 26.62 Future net cash floff ws are discounted at the prescribed rate of 10%. Actuat onsiderably from these estimates. Although the Company’s estimates of total proved reserves, development and abandonment 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. All estimated costs to settle asset retirement obligations associated with the Company’s proved reserves have been included in their calculation of development and abandonment of the standardized measure of discounted future net cash floff ws for each period presented. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Thereforff e, such estimated futff urt e net cash floff w computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves. l futff urt e net cash floff ws may vary crr Changes in Standardized Measure of Discounted Future Net Cash Flows Principal changes in the standardized measure of discounted future net cash floff ws attributable to the Company’s proved oil, natural gas and NGL reserves are as folff lows (in thousands): s: Consolidll atdd edtt Entitieii Standardized measure, beginning of year Sales and transferff s of oil, net gas and NGLs produced during the period Net change in prices and production costs Changes in estimated futff urt e development and abandonment costs Previously estimated development and abandonment costs incurred Accretion of discount Net change in income taxes Purchases of reserves Sales 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 $ $ 2023 Year Ended December 31, 2022 2021 4,368,448 $ (1,065,814) (2,835,125) (19,877) 202,503 518,110 357,321 2,033,852 — 90,244 (484,423) (121,751) 3,043,488 $ 3,440,611 $ (1,340,400) 2,388,442 (84,391) 20,107 392,600 (327,265) — (5,218) 202,239 (255,743) (62,534) 4,368,448 $ 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 F-41 Note 17 — Subsequent Events QuarterNorth Acquisition For additional Inforff mation, see the following: • • • Note 3 — Acquisiii tions and Divestitures Note 8 — Debt Note 13 — Related Party Transactions Equity Offeff ring On January 22, 2024, the Company closed an upsized underwritten public offeff ring”) of 34.5 million shares of the Company’s common stock, resulting in net proceeds to the Company of approximately $388.5 million, afteff r deducd ting underwriting discounts and commissions and beforff e estimated offering expenses. The Company intends to use the net proceeds froff m the January Equity Offeff rth ring as described Acquisition remains subju ect to certain conditions to closing. Pending the use of the proceeds of the January Equity Offeff above, the Company may temporarily use all or a portion of such proceeds to reducd e the borrowings outstanding under the Company’s Bank Credit Facility. In the event that the QuarterNorth Acquisition is not completed, the proceeds froff m the January Equity Offeff ring will be used for general corporate purpos ring to fund a portion of the cash consideration forff rth Acquisition. However, the QuarterNor ring (the “January Equity Offeff the QuarterNor es. rr F-42 Year Ended December 31, 2023 2022 100 $ 221 19 340 — 169 36 205 2,246,908 2,247,248 $ 1,168,053 1,168,258 316 $ 705 124 1,145 90,952 92,097 — 1,275 2,549,097 (347,717) (47,504) 2,155,151 2,247,248 $ 249 728 62 1,039 1,643 2,682 — 826 1,699,799 (535,049) — 1,165,576 1,168,258 Schedule I. Condensed Financial Inforff mation of Registrant TALOS ENERGY INC. (PARENT ONLY) BALANCE SHEETS (In thousands, except share amounts) ASSETS $ $ $ $ Current assets: Accounts receivable: Other, net Prepaid assets Other current assets Total current assets Other long-term assets: Investments in subsidiaries Total assets LIABILITIES AND STOCKHOLDERSʼ EQUITY Current liabilities: Accounts payable Accruerr d liabia lities Other current liabia lities Total current liabia lities Long-term liabia lities: Other long-term liabia lities Total liabia lities Commitments and contingencies Stockholdersʼ equity: red stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of Preferff December 31, 2023 and 2022, respectively Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively Additional paid-in capital Accumulated deficff Treasury srr tock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively it Total stockholdersʼ equity Total liabilities and stockholdersʼ equity See accompanying notes. F-43 TALOS ENERGY INC. (PARENT ONLY) STATEMENTS OF OPERATRR IONS (In thousands) Revenues: Oil Natural gas NGL Total revenues Operating expenses: Lease operating expense Production taxes Depreciation, depletion and amortization Accretion expense General and administrative expense Other operating (income) expense Total operating expenses Operating income (expense) Interest expense Price risk management activities income (expense) Equity method investment income (expense) Other income (expense) Equity earnings (loss) from subsidiaries Net income (loss) before income taxes Income tax benefitff Net income (loss) (expense) 2023 Year Ended December 31, 2022 2021 $ $ $ — $ — — — — — — — 2,708 $ — 2,708 (2,708) — — — (1) 128,888 126,179 61,153 187,332 $ — $ — — — — — — — 2,145 $ — 2,145 (2,145) — — — (1) 385,968 383,822 (1,907) 381,915 $ — — — — — — — — 1,322 — 1,322 (1,322) (5) — — (2) (180,548) (181,877) (1,075) (182,952) See accompanying notes. F-44 TALOS ENERGY INC. (PARENT ONLY) STATEMENTS OF CASH FLOWS (In thousands) Cash flows froff m operating activities: Net cash provided by (used in) operating activities Cash flows froff m investing activities: Distributions from subsidiaries Contributions to subsu idiaries Net cash provided by (used in) investing activities Cash flows froff m finff ancing activities: Purchase of treasury stock Net cash provided (used in) by finff ancing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents: Balance, beginning of period Balance, end of period 2023 Year Ended December 31, 2022 2021 $ (1,836) $ (809) $ 49,340 — 49,340 (47,504) (47,504) — — — $ $ 809 — 809 — — — — — $ (876) 879 (3) 876 — — — — — See accompanying notes. F-45 TALOS ENERGY INC. (PARENT ONLY) NOTES TO CONDENSED FINANCIAL STATEMENTS December 31, 2023 Note 1 — Basis of Presentation Pursuant to the rulr es and regulations of the SEC, the parent only condensed financial inforff mation of Talos Energy, Inc. do not reflect all of the inforff mation and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included under Part IV, Item 15. Exhibits and Financial Statement Scheduld es in this Annual Report. F- 46 (cid:37)(cid:68)(cid:70)(cid:78)(cid:29)(cid:3)(cid:48)(cid:72)(cid:74)(cid:68)(cid:81)(cid:3)(cid:39)(cid:76)(cid:70)(cid:78)(cid:15)(cid:3)(cid:38)(cid:17)(cid:3)(cid:42)(cid:82)(cid:85)(cid:71)(cid:82)(cid:81)(cid:3)(cid:47)(cid:72)(cid:81)(cid:71)(cid:86)(cid:72)(cid:92)(cid:15)(cid:3)(cid:39)(cid:72)(cid:69)(cid:82)(cid:85)(cid:68)(cid:75)(cid:3)(cid:43)(cid:88)(cid:86)(cid:87)(cid:82)(cid:81)(cid:15)(cid:3)(cid:42)(cid:85)(cid:72)(cid:74)(cid:3)(cid:37)(cid:68)(cid:69)(cid:70)(cid:82)(cid:70)(cid:78)(cid:15)(cid:3)(cid:45)(cid:82)(cid:72)(cid:3)(cid:54)(cid:68)(cid:88)(cid:89)(cid:68)(cid:74)(cid:72)(cid:68)(cid:88)(cid:15)(cid:3)(cid:45)(cid:82)(cid:72)(cid:79)(cid:3)(cid:51)(cid:79)(cid:68)(cid:88)(cid:70)(cid:75)(cid:72) (cid:41)(cid:85)(cid:82)(cid:81)(cid:87)(cid:29)(cid:3)(cid:54)(cid:72)(cid:85)(cid:74)(cid:76)(cid:82)(cid:3)(cid:48)(cid:68)(cid:76)(cid:90)(cid:82)(cid:85)(cid:80)(cid:15)(cid:3)(cid:58)(cid:76)(cid:79)(cid:79)(cid:76)(cid:68)(cid:80)(cid:3)(cid:54)(cid:17)(cid:3)(cid:48)(cid:82)(cid:86)(cid:86)(cid:3)(cid:44)(cid:44)(cid:44)(cid:15)(cid:3)(cid:45)(cid:82)(cid:75)(cid:81)(cid:3)(cid:36)(cid:17)(cid:3)(cid:51)(cid:68)(cid:85)(cid:78)(cid:72)(cid:85)(cid:15)(cid:3)(cid:55)(cid:76)(cid:80)(cid:82)(cid:87)(cid:75)(cid:92)(cid:3)(cid:54)(cid:17)(cid:3)(cid:39)(cid:88)(cid:81)(cid:70)(cid:68)(cid:81)(cid:15)(cid:3)(cid:45)(cid:82)(cid:75)(cid:81)(cid:3)(cid:37)(cid:17)(cid:3)(cid:54)(cid:83)(cid:68)(cid:87)(cid:75) MANAGEMENT TEAM BOARD OF DIRECTORS STOCKHOLDER INFORMATION 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 (cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(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:15)(cid:3)(cid:49)(cid:72)(cid:90)(cid:3)(cid:57)(cid:72)(cid:81)(cid:87)(cid:88)(cid:85)(cid:72)(cid:86) NEAL P. GOLDMAN (cid:38)(cid:75)(cid:68)(cid:76)(cid:85)(cid:80)(cid:68)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:37)(cid:82)(cid:68)(cid:85)(cid:71)(cid:3) (cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:76)(cid:81)(cid:74)(cid:3)(cid:48)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:15)(cid:3)(cid:54)(cid:36)(cid:42)(cid:40)(cid:3)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3) (cid:44)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:15)(cid:3)(cid:47)(cid:47)(cid:38) WILLIAM S. MOSS III (cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(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:15)(cid:3)(cid:42)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:79)(cid:3) (cid:38)(cid:82)(cid:88)(cid:81)(cid:86)(cid:72)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:72)(cid:70)(cid:85)(cid:72)(cid:87)(cid:68)(cid:85)(cid:92) JOHN B. SPATH (cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(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:43)(cid:72)(cid:68)(cid:71)(cid:3)(cid:82)(cid:73)(cid:3) (cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86) SERGIO L. MAIWORM JR. (cid:54)(cid:72)(cid:81)(cid:76)(cid:82)(cid:85)(cid:3)(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: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) GREG BABCOCK (cid:3)(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 (cid:3)(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:15)(cid:3)(cid:43)(cid:88)(cid:80)(cid:68)(cid:81)(cid:3)(cid:53)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86) DEBORAH HUSTON (cid:3)(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:39)(cid:72)(cid:83)(cid:88)(cid:87)(cid:92)(cid:3)(cid:42)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:79)(cid:3) (cid:38)(cid:82)(cid:88)(cid:81)(cid:86)(cid:72)(cid:79) C. GORDON LINDSEY (cid:3)(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:15)(cid:3)(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:39)(cid:72)(cid:89)(cid:72)(cid:79)(cid:82)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87) JOE SAUVAGEAU (cid:3)(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:15)(cid:3)(cid:36)(cid:86)(cid:86)(cid:72)(cid:87)(cid:3)(cid:39)(cid:72)(cid:89)(cid:72)(cid:79)(cid:82)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87) JOEL PLAUCHE (cid:3)(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:15)(cid:3)(cid:43)(cid:54)(cid:40)(cid:15)(cid:3)(cid:53)(cid:72)(cid:74)(cid:88)(cid:79)(cid:68)(cid:87)(cid:82)(cid:85)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3) (cid:38)(cid:82)(cid:80)(cid:83)(cid:79)(cid:76)(cid:68)(cid:81)(cid:70)(cid:72) 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)(cid:3) (cid:55)(cid:68)(cid:79)(cid:82)(cid:86)(cid:3)(cid:40)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:3)(cid:44)(cid:81)(cid:70)(cid:17) PAULA R. GLOVER (cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:15)(cid:3)(cid:36)(cid:79)(cid:79)(cid:76)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:54)(cid:68)(cid:89)(cid:72)(cid:3)(cid:40)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92) JOHN “BRAD” JUNEAU (cid:54)(cid:82)(cid:79)(cid:72)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:85)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:42)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:79)(cid:3)(cid:51)(cid:68)(cid:85)(cid:87)(cid:81)(cid:72)(cid:85)(cid:15)(cid:3) (cid:45)(cid:88)(cid:81)(cid:72)(cid:68)(cid:88)(cid:3)(cid:40)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:47)(cid:17)(cid:51)(cid:17) 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)(cid:3) (cid:46)(cid:72)(cid:81)(cid:80)(cid:82)(cid:81)(cid:87)(cid:3)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:51)(cid:68)(cid:85)(cid:87)(cid:81)(cid:72)(cid:85)(cid:86) JOSEPH A. MILLS (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)(cid:3)(cid:54)(cid:68)(cid:80)(cid:86)(cid:82)(cid:81)(cid:3) (cid:53)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:44)(cid:44)(cid:15)(cid:3)(cid:47)(cid:47)(cid:38)(cid:3)(cid:9)(cid:3) (cid:41)(cid:82)(cid:88)(cid:81)(cid:71)(cid:72)(cid:85)(cid:18)(cid:50)(cid:90)(cid:81)(cid:72)(cid:85)(cid:15)(cid:3)(cid:58)(cid:68)(cid:87)(cid:72)(cid:85)(cid:73)(cid:82)(cid:85)(cid:71)(cid:3)(cid:40)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:15)(cid:3)(cid:47)(cid:47)(cid:38) RICHARD SHERRILL (cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:15)(cid:3)(cid:38)(cid:79)(cid:72)(cid:68)(cid:81)(cid:3)(cid:36)(cid:76)(cid:85)(cid:72)(cid:3)(cid:51)(cid:68)(cid:85)(cid:87)(cid:81)(cid:72)(cid:85)(cid:86) 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)(cid:3)(cid:38)(cid:68)(cid:80)(cid:72)(cid:85)(cid:82)(cid:81)(cid:3) (cid:44)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79) SHANDELL SZABO (cid:3)(cid:53)(cid:72)(cid:87)(cid:76)(cid:85)(cid:72)(cid:71)(cid:3)(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:82)(cid:73)(cid:3)(cid:56)(cid:17)(cid:54)(cid:17)(cid:3) (cid:40)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:36)(cid:81)(cid:68)(cid:71)(cid:68)(cid:85)(cid:78)(cid:82)(cid:3)(cid:51)(cid:72)(cid:87)(cid:85)(cid:82)(cid:79)(cid:72)(cid:88)(cid:80)(cid:3) (cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81) CORPORATE OFFICE (cid:22)(cid:22)(cid:22)(cid:3)(cid:38)(cid:79)(cid:68)(cid:92)(cid:3)(cid:54)(cid:87)(cid:17)(cid:15)(cid:3)(cid:54)(cid:88)(cid:76)(cid:87)(cid:72)(cid:3)(cid:22)(cid:22)(cid:19)(cid:19)(cid:3) (cid:43)(cid:82)(cid:88)(cid:86)(cid:87)(cid:82)(cid:81)(cid:15)(cid:3)(cid:55)(cid:59)(cid:3)(cid:26)(cid:26)(cid:19)(cid:19)(cid:21)(cid:3) (cid:51)(cid:75)(cid:82)(cid:81)(cid:72)(cid:29)(cid:3)(cid:26)(cid:20)(cid:22)(cid:17)(cid:22)(cid:21)(cid:27)(cid:17)(cid:22)(cid:19)(cid:19)(cid:19) WEBSITE (cid:90)(cid:90)(cid:90)(cid:17)(cid:87)(cid:68)(cid:79)(cid:82)(cid:86)(cid:72)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:17)(cid:70)(cid:82)(cid:80) STOCK EXCHANGE LISTING (cid:49)(cid:72)(cid:90)(cid:3)(cid:60)(cid:82)(cid:85)(cid:78)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:3) (cid:54)(cid:92)(cid:80)(cid:69)(cid:82)(cid:79)(cid:29)(cid:3)(cid:55)(cid:36)(cid:47)(cid:50) ANNUAL MEETING (cid:3)(cid:48)(cid:68)(cid:92)(cid:3)(cid:21)(cid:22)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:23)(cid:3)(cid:68)(cid:87)(cid:3)(cid:20)(cid:19)(cid:29)(cid:19)(cid:19)(cid:3)(cid:36)(cid:48)(cid:3)(cid:38)(cid:55) (cid:55)(cid:75)(cid:85)(cid:72)(cid:72)(cid:3)(cid:36)(cid:79)(cid:79)(cid:72)(cid:81)(cid:3)(cid:38)(cid:72)(cid:81)(cid:87)(cid:72)(cid:85) (cid:3)(cid:22)(cid:22)(cid:22)(cid:3)(cid:38)(cid:79)(cid:68)(cid:92)(cid:3)(cid:54)(cid:87)(cid:17)(cid:15)(cid:3)(cid:54)(cid:88)(cid:76)(cid:87)(cid:72)(cid:3)(cid:22)(cid:22)(cid:19)(cid:19)(cid:3) (cid:43)(cid:82)(cid:88)(cid:86)(cid:87)(cid:82)(cid:81)(cid:15)(cid:3)(cid:55)(cid:59)(cid:3)(cid:26)(cid:26)(cid:19)(cid:19)(cid:21) FORM 10-K (cid:3)(cid:38)(cid:82)(cid:83)(cid:76)(cid:72)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:183)(cid:86)(cid:3)(cid:20)(cid:19)(cid:16)(cid:46)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3) (cid:68)(cid:89)(cid:68)(cid:76)(cid:79)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:90)(cid:72)(cid:69)(cid:86)(cid:76)(cid:87)(cid:72)(cid:3)(cid:68)(cid:87) (cid:90)(cid:90)(cid:90)(cid:17)(cid:87)(cid:68)(cid:79)(cid:82)(cid:86)(cid:72)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:17)(cid:70)(cid:82)(cid:80) AUDITORS (cid:3)(cid:40)(cid:85)(cid:81)(cid:86)(cid:87)(cid:3)(cid:9)(cid:3)(cid:60)(cid:82)(cid:88)(cid:81)(cid:74)(cid:3) (cid:43)(cid:82)(cid:88)(cid:86)(cid:87)(cid:82)(cid:81)(cid:15)(cid:3)(cid:55)(cid:59) SHAREHOLDER SERVICES (cid:38)(cid:82)(cid:80)(cid:83)(cid:88)(cid:87)(cid:72)(cid:85)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:3) (cid:51)(cid:17)(cid:50)(cid:17)(cid:3)(cid:37)(cid:82)(cid:91)(cid:3)(cid:24)(cid:19)(cid:24)(cid:19)(cid:19)(cid:19)(cid:3) (cid:47)(cid:82)(cid:88)(cid:76)(cid:86)(cid:89)(cid:76)(cid:79)(cid:79)(cid:72)(cid:15)(cid:3)(cid:46)(cid:60)(cid:3)(cid:23)(cid:19)(cid:21)(cid:22)(cid:22)(cid:3) (cid:55)(cid:82)(cid:79)(cid:79)(cid:16)(cid:41)(cid:85)(cid:72)(cid:72)(cid:29)(cid:3)(cid:20)(cid:17)(cid:27)(cid:19)(cid:19)(cid:17)(cid:28)(cid:25)(cid:21)(cid:17)(cid:23)(cid:21)(cid:27)(cid:23)(cid:3) (cid:44)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:29)(cid:3)(cid:20)(cid:17)(cid:26)(cid:27)(cid:20)(cid:17)(cid:24)(cid:26)(cid:24)(cid:17)(cid:22)(cid:20)(cid:21)(cid:19) OVERNIGHT MAIL (cid:23)(cid:25)(cid:21)(cid:3)(cid:54)(cid:82)(cid:88)(cid:87)(cid:75)(cid:3)(cid:23)(cid:87)(cid:75)(cid:3)(cid:54)(cid:87)(cid:85)(cid:72)(cid:72)(cid:87)(cid:15)(cid:3)(cid:54)(cid:88)(cid:76)(cid:87)(cid:72)(cid:3) (cid:20)(cid:25)(cid:19)(cid:19)(cid:3)(cid:47)(cid:82)(cid:88)(cid:76)(cid:86)(cid:89)(cid:76)(cid:79)(cid:79)(cid:72)(cid:15)(cid:3)(cid:46)(cid:60)(cid:3)(cid:23)(cid:19)(cid:21)(cid:19)(cid:21) INVESTOR RELATIONS (cid:3)(cid:38)(cid:82)(cid:81)(cid:87)(cid:68)(cid:70)(cid:87)(cid:3)(cid:88)(cid:86)(cid:3)(cid:68)(cid:87)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:82)(cid:85)(cid:35)(cid:87)(cid:68)(cid:79)(cid:82)(cid:86)(cid:72)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:17)(cid:70)(cid:82)(cid:80) TALOS ENERGY 2023 ANNUAL REPORT THINK AS AN OWNER EMBODY INTEGRITY AND SAFETY MAINTAIN OPTIONALITY EMPOWER EACH OTHER EMBRACE DIVERSITY AND INCLUSION 333 Clay St., Suite 3300 Houston, Texas 77002 713.328.3000 www.talosenergy.com 

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