Matador Resources Company Annual Report 2022

FY2022 Annual Report · Matador Resources Company
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2 0 2 2 A N N UA L R E P O R T

Gaining Strength.  
Growing Stronger Together.

Matador Resources Company

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Matador Resources Company(cid:3)(cid:76)(cid:86)(cid:3)(cid:68)(cid:81)(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: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:72)(cid:81)(cid:74)(cid:68)(cid:74)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(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:15)(cid:3)(cid:71)(cid:72)(cid:89)(cid:72)(cid:79)(cid:82)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87)(cid:15)(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:68)(cid:81)(cid:71)(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:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:85)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(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:15)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:81)(cid:3)(cid:72)(cid:80)(cid:83)(cid:75)(cid:68)(cid:86)(cid:76)(cid:86)(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:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:86)(cid:75)(cid:68)(cid:79)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)
(cid:88)(cid:81)(cid:70)(cid:82)(cid:81)(cid:89)(cid:72)(cid:81)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:83)(cid:79)(cid:68)(cid:92)(cid:86)(cid:17)(cid:3)(cid:50)(cid:88)(cid:85)(cid:3)(cid:70)(cid:88)(cid:85)(cid:85)(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:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:73)(cid:82)(cid:70)(cid:88)(cid:86)(cid:72)(cid:71)(cid:3)(cid:83)(cid:85)(cid:76)(cid:80)(cid:68)(cid:85)(cid:76)(cid:79)(cid:92)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:79)(cid:76)(cid:84)(cid:88)(cid:76)(cid:71)(cid:86)(cid:16)(cid:85)(cid:76)(cid:70)(cid:75)(cid:3)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:58)(cid:82)(cid:79)(cid:73)(cid:70)(cid:68)(cid:80)(cid:83)(cid:3)(cid:68)(cid:81)(cid:71)
(cid:37)(cid:82)(cid:81)(cid:72)(cid:3)(cid:54)(cid:83)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:83)(cid:79)(cid:68)(cid:92)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:39)(cid:72)(cid:79)(cid:68)(cid:90)(cid:68)(cid:85)(cid:72)(cid:3)(cid:37)(cid:68)(cid:86)(cid:76)(cid:81)(cid:3)(cid:76)(cid:81)(cid:3)(cid:54)(cid:82)(cid:88)(cid:87)(cid:75)(cid:72)(cid:68)(cid:86)(cid:87)(cid:3)(cid:49)(cid:72)(cid:90)(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:58)(cid:72)(cid:86)(cid:87)(cid:3)(cid:55)(cid:72)(cid:91)(cid:68)(cid:86)(cid:17)(cid:3)(cid:58)(cid:72)(cid:3)(cid:68)(cid:79)(cid:86)(cid:82)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:40)(cid:68)(cid:74)(cid:79)(cid:72)(cid:3)(cid:41)(cid:82)(cid:85)(cid:71)(cid:3)(cid:86)(cid:75)(cid:68)(cid:79)(cid:72)
(cid:83)(cid:79)(cid:68)(cid:92)(cid:3)(cid:76)(cid:81)(cid:3)(cid:54)(cid:82)(cid:88)(cid:87)(cid:75)(cid:3)(cid:55)(cid:72)(cid:91)(cid:68)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:43)(cid:68)(cid:92)(cid:81)(cid:72)(cid:86)(cid:89)(cid:76)(cid:79)(cid:79)(cid:72)(cid:3)(cid:86)(cid:75)(cid:68)(cid:79)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:82)(cid:87)(cid:87)(cid:82)(cid:81)(cid:3)(cid:57)(cid:68)(cid:79)(cid:79)(cid:72)(cid:92)(cid:3)(cid:83)(cid:79)(cid:68)(cid:92)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:49)(cid:82)(cid:85)(cid:87)(cid:75)(cid:90)(cid:72)(cid:86)(cid:87)(cid:3)(cid:47)(cid:82)(cid:88)(cid:76)(cid:86)(cid:76)(cid:68)(cid:81)(cid:68)(cid:17)

(cid:36)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:79)(cid:92)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:71)(cid:88)(cid:70)(cid:87)(cid:3)(cid:80)(cid:76)(cid:71)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:86)(cid:88)(cid:83)(cid:83)(cid:82)(cid:85)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(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:15)(cid:3)(cid:71)(cid:72)(cid:89)(cid:72)(cid:79)(cid:82)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87)(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:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)
(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72)(cid:86)(cid:3)(cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:86)(cid:86)(cid:76)(cid:81)(cid:74)(cid:15)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:87)(cid:85)(cid:68)(cid:81)(cid:86)(cid:83)(cid:82)(cid:85)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:86)(cid:72)(cid:85)(cid:89)(cid:76)(cid:70)(cid:72)(cid:86)(cid:15)(cid:3)(cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:74)(cid:68)(cid:86)(cid:15)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:72)(cid:71)(cid:3)(cid:90)(cid:68)(cid:87)(cid:72)(cid:85)(cid:3)(cid:74)(cid:68)(cid:87)(cid:75)(cid:72)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:72)(cid:85)(cid:89)(cid:76)(cid:70)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)
(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:72)(cid:71)(cid:3)(cid:90)(cid:68)(cid:87)(cid:72)(cid:85)(cid:3)(cid:71)(cid:76)(cid:86)(cid:83)(cid:82)(cid:86)(cid:68)(cid:79)(cid:3)(cid:86)(cid:72)(cid:85)(cid:89)(cid:76)(cid:70)(cid:72)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:76)(cid:85)(cid:71)(cid:3)(cid:83)(cid:68)(cid:85)(cid:87)(cid:76)(cid:72)(cid:86)(cid:17)

FINANCIAL & OPERATING HIGHLIGHTS

($ in millions, unless otherwise noted)

2020

2021

2022

Balance Sheet Data
(cid:38)(cid:68)(cid:86)(cid:75)
(cid:49)(cid:72)(cid:87)(cid:3)(cid:51)(cid:85)(cid:82)(cid:83)(cid:72)(cid:85)(cid:87)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87)
(cid:55)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:36)(cid:86)(cid:86)(cid:72)(cid:87)(cid:86)
(cid:38)(cid:88)(cid:85)(cid:85)(cid:72)(cid:81)(cid:87)(cid:3)(cid:47)(cid:76)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)
(cid:47)(cid:82)(cid:81)(cid:74)(cid:16)(cid:55)(cid:72)(cid:85)(cid:80)(cid:3)(cid:47)(cid:76)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)
(cid:55)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:54)(cid:75)(cid:68)(cid:85)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:333)(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)

Net Production Volumes (Annual)
(cid:50)(cid:76)(cid:79)(cid:3)(cid:11)(cid:48)(cid:37)(cid:69)(cid:79)(cid:12)
Natural Gas (Bcf)
(cid:55)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:50)(cid:76)(cid:79)(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:89)(cid:68)(cid:79)(cid:72)(cid:81)(cid:87)(cid:3)(cid:11)(cid:48)(cid:37)(cid:50)(cid:40)(cid:12) (1)(2)

(cid:8)(cid:3)(cid:50)(cid:76)(cid:79)(cid:3)(cid:76)(cid:81)(cid:3)(cid:51)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:57)(cid:82)(cid:79)(cid:88)(cid:80)(cid:72)(cid:86)(2)

Average Daily Production (BOE/d)(2)

Reserves Information
(cid:55)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:51)(cid:85)(cid:82)(cid:89)(cid:72)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:11)(cid:48)(cid:48)(cid:37)(cid:50)(cid:40)(cid:12) (2)(3)

(cid:8)(cid:3)(cid:39)(cid:72)(cid:89)(cid:72)(cid:79)(cid:82)(cid:83)(cid:72)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(2)

(cid:54)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:48)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)
PV-10 (4)

Operating Data
(cid:50)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:49)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:42)(cid:68)(cid:86)(cid:3)(cid:53)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:86)

(cid:8)(cid:3)(cid:50)(cid:76)(cid:79)(cid:3)(cid:76)(cid:81)(cid:3)(cid:53)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:86)
(cid:49)(cid:72)(cid:87)(cid:3)(cid:44)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:11)(cid:47)(cid:82)(cid:86)(cid:86)(cid:12) (5)
Adjusted EBITDA(7)

Realized Pricing
(cid:50)(cid:76)(cid:79)(cid:15)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:53)(cid:72)(cid:68)(cid:79)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:39)(cid:72)(cid:85)(cid:76)(cid:89)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:86)(cid:3)(cid:11)(cid:83)(cid:72)(cid:85)(cid:3)(cid:37)(cid:69)(cid:79)(cid:12)
(cid:49)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:42)(cid:68)(cid:86)(cid:15)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:53)(cid:72)(cid:68)(cid:79)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:39)(cid:72)(cid:85)(cid:76)(cid:89)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:86)(cid:3)(cid:11)(cid:83)(cid:72)(cid:85)(cid:3)(cid:48)(cid:70)(cid:73)(cid:12)

$
57.9
(cid:7)(cid:3) (cid:22)(cid:15)(cid:22)(cid:25)(cid:26)(cid:17)(cid:27)
(cid:7) (cid:22)(cid:15)(cid:25)(cid:27)(cid:26)(cid:17)(cid:22)
(cid:7)
(cid:21)(cid:28)(cid:19)(cid:17)(cid:28)
(cid:7) (cid:3)(cid:3)(cid:20)(cid:15)(cid:27)(cid:27)(cid:22)(cid:17)(cid:22)
(cid:7) (cid:20)(cid:15)(cid:24)(cid:20)(cid:22)(cid:17)(cid:19)

(cid:20)(cid:24)(cid:15)(cid:28)(cid:22)(cid:20)
69.5
(cid:21)(cid:26)(cid:15)(cid:24)(cid:20)(cid:23)

58%

75,175

270.3

46% 

(cid:7) (cid:20)(cid:15)(cid:24)(cid:27)(cid:23)(cid:17)(cid:23)
(cid:7) (cid:20)(cid:15)(cid:25)(cid:24)(cid:27)(cid:17)(cid:19)

(cid:7)

$
(cid:7)

(cid:7)
(cid:7)

(cid:26)(cid:23)(cid:23)(cid:17)(cid:24)

(cid:27)(cid:19)(cid:8)
(593.2) (6)
(cid:24)(cid:20)(cid:28)(cid:17)(cid:22)

(cid:22)(cid:28)(cid:17)(cid:27)(cid:22)
(cid:21)(cid:17)(cid:20)(cid:23)

$
48.1
(cid:7)(cid:3) (cid:22)(cid:15)(cid:27)(cid:24)(cid:25)(cid:17)(cid:26)(cid:3)
(cid:7) (cid:23)(cid:15)(cid:21)(cid:25)(cid:21)(cid:17)(cid:21)
(cid:7)
(cid:23)(cid:25)(cid:23)(cid:17)(cid:27)
(cid:7) (cid:3)(cid:3)(cid:20)(cid:15)(cid:25)(cid:25)(cid:28)(cid:17)(cid:28)
(cid:7) (cid:21)(cid:15)(cid:20)(cid:21)(cid:26)(cid:17)(cid:23)

(cid:20)(cid:26)(cid:15)(cid:27)(cid:23)(cid:19)
81.7
(cid:22)(cid:20)(cid:15)(cid:23)(cid:24)(cid:23)

57%

86,176

323.4

60% 

(cid:7) (cid:23)(cid:15)(cid:22)(cid:26)(cid:24)(cid:17)(cid:23)(cid:3)
(cid:7) (cid:24)(cid:15)(cid:22)(cid:23)(cid:26)(cid:17)(cid:25)(cid:3)

(cid:7) (cid:20)(cid:15)(cid:26)(cid:19)(cid:19)(cid:17)(cid:24)

(cid:26)(cid:20)(cid:8)(cid:3)

$
585.0
(cid:7) (cid:20)(cid:15)(cid:19)(cid:24)(cid:21)(cid:17)(cid:19)

$
505.2
(cid:7) (cid:23)(cid:15)(cid:23)(cid:20)(cid:27)(cid:17)(cid:21)
(cid:7) (cid:24)(cid:15)(cid:24)(cid:24)(cid:23)(cid:17)(cid:24)
(cid:7)
(cid:24)(cid:26)(cid:24)(cid:17)(cid:28)
(cid:7) (cid:20)(cid:15)(cid:25)(cid:25)(cid:20)(cid:17)(cid:24)
(cid:7) (cid:22)(cid:15)(cid:22)(cid:20)(cid:26)(cid:17)(cid:20)

(cid:21)(cid:20)(cid:15)(cid:28)(cid:23)(cid:22)
99.3
(cid:22)(cid:27)(cid:15)(cid:23)(cid:28)(cid:24)

57%

105,465

356.7

62%

(cid:7) (cid:25)(cid:15)(cid:28)(cid:27)(cid:22)(cid:17)(cid:21)
(cid:7) (cid:28)(cid:15)(cid:20)(cid:22)(cid:21)(cid:17)(cid:21)

(cid:7) (cid:21)(cid:15)(cid:28)(cid:19)(cid:24)(cid:17)(cid:26)

(cid:26)(cid:22)(cid:8)

(cid:7) (cid:20)(cid:15)(cid:21)(cid:20)(cid:23)(cid:17)(cid:21)
(cid:3)(cid:7) (cid:21)(cid:15)(cid:20)(cid:21)(cid:26)(cid:17)(cid:21)

(cid:7)
(cid:7)

(cid:24)(cid:25)(cid:17)(cid:26)(cid:19)
(cid:24)(cid:17)(cid:26)(cid:23)

(cid:7)
(cid:7)

(cid:28)(cid:21)(cid:17)(cid:27)(cid:26)
(cid:26)(cid:17)(cid:20)(cid:24)

(1) Thousands of barrels of oil equivalent. 

(2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(3) Millions of barrels of oil equivalent.
(cid:11)(cid:23)(cid:12)(cid:3)(cid:51)(cid:57)(cid:16)(cid:20)(cid:19)(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:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:17)(cid:3)(cid:41)(cid:82)(cid:85)(cid:3)(cid:68)(cid:3)(cid:71)(cid:72)(cid:403)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:51)(cid:57)(cid:16)(cid:20)(cid:19)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:3)(cid:85)(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:87)(cid:82)(cid:3)(cid:54)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:48)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:15)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:335)(cid:37)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:331)(cid:3)(cid:40)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:51)(cid:85)(cid:82)(cid:89)(cid:72)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:336)

(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(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:3)(cid:82)(cid:81)(cid:3)(cid:41)(cid:82)(cid:85)(cid:80)(cid:3)(cid:20)(cid:19)(cid:16)(cid:46)(cid:3)(cid:72)(cid:81)(cid:70)(cid:79)(cid:82)(cid:86)(cid:72)(cid:71)(cid:3)(cid:75)(cid:72)(cid:85)(cid:72)(cid:76)(cid:81)(cid:17)(cid:3)

(cid:11)(cid:24)(cid:12) (cid:36)(cid:87)(cid:87)(cid:85)(cid:76)(cid:69)(cid:88)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:3)(cid:53)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:38)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:3)(cid:68)(cid:73)(cid:87)(cid:72)(cid:85)(cid:3)(cid:74)(cid:76)(cid:89)(cid:76)(cid:81)(cid:74)(cid:3)(cid:72)(cid:73)(cid:73)(cid:72)(cid:70)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:68)(cid:80)(cid:82)(cid:88)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:87)(cid:87)(cid:85)(cid:76)(cid:69)(cid:88)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:76)(cid:85)(cid:71)(cid:16)(cid:83)(cid:68)(cid:85)(cid:87)(cid:92)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:79)(cid:76)(cid:81)(cid:74)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:86)(cid:17)

(cid:11)(cid:25)(cid:12) (cid:44)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:86)(cid:3)(cid:68)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:73)(cid:88)(cid:79)(cid:79)(cid:16)(cid:70)(cid:82)(cid:86)(cid:87)(cid:3)(cid:70)(cid:72)(cid:76)(cid:79)(cid:76)(cid:81)(cid:74)(cid:3)(cid:76)(cid:80)(cid:83)(cid:68)(cid:76)(cid:85)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:7)(cid:25)(cid:27)(cid:23)(cid:17)(cid:26)(cid:3)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:88)(cid:81)(cid:85)(cid:72)(cid:68)(cid:79)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:79)(cid:82)(cid:86)(cid:86)(cid:3)(cid:82)(cid:81)(cid:3)(cid:71)(cid:72)(cid:85)(cid:76)(cid:89)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:7)(cid:22)(cid:21)(cid:17)(cid:19)(cid:3)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:17)

(cid:11)(cid:26)(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:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:17)(cid:3)(cid:41)(cid:82)(cid:85)(cid:3)(cid:68)(cid:3)(cid:71)(cid:72)(cid:403)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(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:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:3)(cid:85)(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:87)(cid:82)(cid:3)(cid:81)(cid:72)(cid:87)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:11)(cid:79)(cid:82)(cid:86)(cid:86)(cid:12)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:81)(cid:72)(cid:87)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)
(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:70)(cid:87)(cid:76)(cid:89)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:15)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:335)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:333)(cid:86)(cid:3)(cid:39)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:81)(cid:68)(cid:79)(cid:92)(cid:86)(cid:76)(cid:86)(cid:3)(cid:82)(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:38)(cid:82)(cid:81)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(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)(cid:3)(cid:331)(cid:3)(cid:47)(cid:76)(cid:84)(cid:88)(cid:76)(cid:71)(cid:76)(cid:87)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:331)
(cid:49)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:48)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:336)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(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:3)(cid:82)(cid:81)(cid:3)(cid:41)(cid:82)(cid:85)(cid:80)(cid:3)(cid:20)(cid:19)(cid:16)(cid:46)(cid:3)(cid:72)(cid:81)(cid:70)(cid:79)(cid:82)(cid:86)(cid:72)(cid:71)(cid:3)(cid:75)(cid:72)(cid:85)(cid:72)(cid:76)(cid:81)(cid:17)

 
 
 
 
 
 
 
 
Areas of Operation

CHAVES

TWIN LAKES 
~47,000 gross/
~25,800 net acres

ARROWHEAD 
~59,500 gross/ 
~22,500 net acres

2

Matador Resources Company Totals
Production: 111,700 BOE/d
Proved Reserves: 356.7 MMBOE
Acreage: 271,000 gross / 159,800 net
Locations: 4,821 gross / 1,615 net

Southeast New Mexico & West Texas
Production: 106,100 BOE/d
Proved Reserves: 346.8 MMBOE
Acreage: 237,100 gross / 129,400 net
Locations: 4,382 gross / 1,468 net

South Texas
Production: 1,100 BOE/d
Proved Reserves: 3.8 MMBOE
Acreage: 15,400 gross / 13,100 net
Locations: 124 gross / 98 net

Northwest Louisiana
Production: 4,500 BOE/d
Proved Reserves: 6.1 MMBOE
Acreage: 18,500 gross / 17,300 net
Locations: 315 gross / 49 net

RUSTLER  
BREAKS (1) 
~45,500 gross/
~26,400 net acres

RANGER (1) 
~40,700 gross/ 
~22,600 net acres

ANTELOPE 
RIDGE (1)
~26,500 gross/ 
~17,900 net acres

NEW MEXICO

TEX AS

In 2022, Matador was the #8 oil 
producer and the #8 natural gas 
producer in New Mexico.(2)

Y
D
D
E

A
E
L

STATELINE 
~2,900 gross/ 
ro
ro s/ 
~2,900 net acres

WOLF/JACKSON 
TRUST (LOVING) (1)
~14,400 gross/ 
~10,800 net acres

LOVING

Note: All proved reserves acreage and locations as of 
December 31, 2022. Some tracts not shown on map.

(1) Acreage totals do not include Advance acreage

(2) Source: Enverus

 ~500 miles of three-stream pipelines

Matador Acreage (129,400 net)

Advance Acreage (18,500 net)

= Combined Acreage (147,900 net)

AVERAGE DAILY TOTAL DELAWARE BASIN PRODUCTION BOE/d 
Q4 2022 BOE; up 29% YoY

110,000

100,000

90,000

80,000

70,000

60,000

50,000

40,000

30,000

20,000

10,000

0

Oil 

Natural Gas

0
0
3
9
4

,

0
0
6

,

2
5

0
0
8

,

1
5

0
0
5

,

1
6

0
0
3

,

0
6

0
0
4

,

6
5

0
0
5
7
8

,

0
0
0

,

4
8

0
0
4

,

2
8

0
0
4
9
8

,

0
0
4
7
7

,

0
0
0

,

8
6

0
0
0

,

6
6

0
0
4

,

6
6

0
0
2

,

5
0
1

0
0
7
9
9

,

,

0
0
1
6
0
1

4Q18

1Q19

2Q19

3Q19

4Q19

1Q20

2Q20

3Q20

4Q20

1Q21

2Q21

3Q21

4Q21 1Q22

2Q22

3Q22

4Q22

Dear Shareholders and Friends

M atador’s Board of Directors, Executive Committee, staff 

and I are all pleased to celebrate with you another record 
year for Matador in 2022. Once again, we achieved 
(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:85)(cid:71)(cid:86)(cid:3)(cid:68)(cid:70)(cid:85)(cid:82)(cid:86)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:69)(cid:82)(cid:68)(cid:85)(cid:71)(cid:15)(cid:3)
including record production, net income, Adjusted

EBITDA, net cash provided by operating activities and adjusted 
“Free Cash Flow.”  These record results could not have been
achieved at Matador without a great team, which is committed
(cid:87)(cid:82)(cid:3)(cid:403)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:74)(cid:85)(cid:72)(cid:68)(cid:87)(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:68)(cid:86)(cid:86)(cid:72)(cid:87)(cid:86)(cid:15)(cid:3)(cid:71)(cid:72)(cid:89)(cid:72)(cid:79)(cid:82)(cid:83)(cid:76)(cid:81)(cid:74)(cid:3)(cid:69)(cid:72)(cid:87)(cid:87)(cid:72)(cid:85)(cid:3)(cid:90)(cid:68)(cid:92)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)
generate value from those assets and looking for many different
ways to continue improving and adding value to both our 
exploration and production business and our midstream business.

(cid:55)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:85)(cid:71)(cid:3)(cid:85)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:21)(cid:19)(cid:21)(cid:21)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72)(cid:71)(cid:3)(cid:88)(cid:86)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:85)(cid:72)(cid:81)(cid:74)(cid:87)(cid:75)(cid:3)
(cid:87)(cid:82)(cid:3)(cid:68)(cid:81)(cid:81)(cid:82)(cid:88)(cid:81)(cid:70)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:21)(cid:19)(cid:21)(cid:22)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:90)(cid:72)(cid:3)(cid:75)(cid:68)(cid:71)(cid:3)(cid:72)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:87)(cid:82)(cid:3)(cid:68)(cid:3)(cid:71)(cid:72)(cid:403)(cid:81)(cid:76)(cid:87)(cid:76)(cid:89)(cid:72)
agreement to acquire Advance Energy Partners Holdings, LLC 
(“Advance”) for an initial cash payment of $1.6 billion, subject to
customary closing adjustments, and possible additional cash
consideration based on the price of oil during 2023. This is a very
attractive opportunity for Matador because these properties offer
strong existing production and proved undeveloped reserves 
in our main areas of interest. This acquisition further adds to our 
current inventory of high quality rock and undrilled A+ locations in 
already developed zones in the area. Advance also offers existing 
midstream assets that provide upside value and synergies with
our newly acquired Pronto midstream systems in Lea County,
New Mexico. Overall, we were pleased to successfully close the 
Advance transaction in April 2023. We expect these properties
to start immediately delivering strong returns in 2023 while
(cid:75)(cid:72)(cid:79)(cid:83)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:72)(cid:87)(cid:3)(cid:88)(cid:83)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:3)(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:68)(cid:81)(cid:3)
even better 2024.

RECORD 2022 RESULTS
Last year in 2022, Matador was able to accomplish many of the
goals it set for itself.  During the year, Matador reported record 
average daily total production of 105,500 barrels of oil and natural 
(cid:74)(cid:68)(cid:86)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:89)(cid:68)(cid:79)(cid:72)(cid:81)(cid:87)(cid:3)(cid:11)(cid:335)(cid:37)(cid:50)(cid:40)(cid:336)(cid:12)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:71)(cid:68)(cid:92)(cid:15)(cid:3)(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:76)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:403)(cid:85)(cid:86)(cid:87)(cid:3)(cid:87)(cid:76)(cid:80)(cid:72)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:3)(cid:75)(cid:68)(cid:86)
exceeded average production of 100,000 BOE per day for an entir
year. Matador also reported record annual net income (GA
me (GAAP) of 
$1.21 billion and record annual Adjusted EBITDA (nDA (non-GAAP) of 
$2.13 billion in 2022, both over 100% increase
reported record annual net cash providovided by operating activities 
(GAAP) of $1.98 billion and record ord annual adjusted Free Cash 
Flow (non-GAAP) of $1.22 billibillion in 2022, again, both above 100%
increases from 2021.

reases from 2021. We also 

an entire

Our midstream busbusinesses also had a record year in 2022,
including recordord annual net income (GAAP) of $147 million and 
record annuanual Adjusted EBITDA (non-GAAP) of $198 million for San 
(cid:48)(cid:68)(cid:87)(cid:72)(cid:82)(cid:3)(cid:48)(cid:76)(cid:71)(cid:48)(cid:76)(cid:71)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:15)(cid:3)(cid:47)(cid:47)(cid:38)(cid:3)(cid:11)(cid:335)(cid:54)(cid:68)(cid:81)(cid:3)(cid:48)(cid:68)(cid:87)(cid:72)(cid:82)(cid:336)(cid:12)(cid:15)(cid:3)(cid:69)(cid:82)(cid:87)(cid:75)(cid:3)(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:403)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:76)(cid:81)(cid:70)(cid:85)(cid:72)(cid:68)(cid:86)(cid:72)(cid:86)(cid:3)
over 202021. San Mateo also had all-time high revenue attributable 
to thithird-party customers of $58.9 million, which was $18.8 million
momore than we had anticipated for 2022.

In June of 2022, we were also pleased to announce the acquisition
of Pronto Midstream, LLC (“Pronto”), which provides us with
strategic and operational advantages by giving us additional 
(cid:70)(cid:68)(cid:83)(cid:68)(cid:70)(cid:76)(cid:87)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:86)(cid:86)(cid:88)(cid:85)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:90)(cid:76)(cid:79)(cid:79)(cid:3)(cid:372)(cid:82)(cid:90)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
wells will be produced with minimal disruption in Lea County,
New Mexico.  Pronto’s assets include approximately 45 miles 
of gas gathering pipelines, three compressor stations and a
cryogenic natural gas processing plant with a designed capacity 
of 60 million cubic feet per day that we named the “Marlan Plant” 

in honor of our longtime shareholder, friend and director, Marlan
Downey.  We look forward to expanding Pronto’s assets to support 
our growing exploration and production business as well as to 
provide natural gas gathering and processing services for other
producers in the Delaware Basin.

CONTINUED REPAYING DEBT
(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:3)(cid:403)(cid:81)(cid:76)(cid:86)(cid:75)(cid:72)(cid:71)(cid:3)(cid:21)(cid:19)(cid:21)(cid:21)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:69)(cid:72)(cid:86)(cid:87)(cid:3)(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:75)(cid:76)(cid:86)(cid:87)(cid:82)(cid:85)(cid:92)(cid:17)(cid:3)
We repaid over $825 million of debt, including over $350 million of 
our bonds, in a little more than two years.  In fact, Matador ended
2022 with no borrowings under our commercial credit facility. As a
result of our record earnings and our disciplined debt repayment, 
Matador achieved a leverage ratio of 0.1x at December 31, 2022,
which is the lowest ratio Matador has had since we became a 
public company in 2012. Notably, each of the corporate credit 
ratings agencies (S&P, Moody’s and Fitch) took note of Matador’s 
(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:85)(cid:72)(cid:81)(cid:74)(cid:87)(cid:75)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:72)(cid:68)(cid:70)(cid:75)(cid:3)(cid:88)(cid:83)(cid:74)(cid:85)(cid:68)(cid:71)(cid:72)(cid:71)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:333)(cid:86)(cid:3)(cid:70)(cid:85)(cid:72)(cid:71)(cid:76)(cid:87)(cid:3)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)
notch or two in 2022.

INCREASED THE DIVIDEND
(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:3)(cid:69)(cid:72)(cid:79)(cid:76)(cid:72)(cid:89)(cid:72)(cid:86)(cid:3)(cid:74)(cid:85)(cid:82)(cid:90)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:68)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:3)(cid:403)(cid:91)(cid:72)(cid:71)(cid:3)(cid:71)(cid:76)(cid:89)(cid:76)(cid:71)(cid:72)(cid:81)(cid:71)(cid:3)(cid:76)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)
fairest way to return cash to shareholders. We were pleased that
Matador’s Board of Directors (the “Board”) approved multiple 
increases to our quarterly dividend in 2022. We began 2022
(cid:69)(cid:92)(cid:3)(cid:83)(cid:68)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:3)(cid:84)(cid:88)(cid:68)(cid:85)(cid:87)(cid:72)(cid:85)(cid:79)(cid:92)(cid:3)(cid:71)(cid:76)(cid:89)(cid:76)(cid:71)(cid:72)(cid:81)(cid:71)(cid:3)(cid:82)(cid:73)(cid:3)(cid:7)(cid:19)(cid:17)(cid:19)(cid:24)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:403)(cid:85)(cid:86)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:86)(cid:72)(cid:70)(cid:82)(cid:81)(cid:71)
quarters. In June 2022, we announced at the annual meeting of 
shareholders that the Board had doubled the quarterly dividend
to $0.10 per share, which was paid to shareholders in the third and
fourth quarters. In December 2022, we announced that the Board
had again amended the Company’s dividend policy, increasing the 
quarterly dividend by 50% to $0.15 per share per quarter. We are
pleased to report that this increased dividend was paid on March 
bruary 27, 2023.
9, 2023, to shareholders of record as of February 27, 2023.

ADVANCE ENERGY ACQUISITION — 
INCREASING OUR STRENGTH IN OUR  
CORE AREAS
The strength of our balance sheet and the approximate $500 million
of cash we had on our balance sheet at the end of the year allowed
us to take advantage of a unique and strategic bolt-on acquisition
opportunity by entering into an agreement to acquire Advance in 
January 2023. We are extremely excited about this opportunity for 
Matador and all its shareholders. The acquisition closed early in 
the second quarter of 2023 and has an effective date of January 1,
2023. Our production estimates for 2023 only include production 
from the Advance properties after the closing of the acquisition. 
Production revenues from the Advance assets from January 1,
2023, to the closing date in April 2023 were included as part of the 
purchase price adjustment and were used to credit and reduce the
(cid:403)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:79)(cid:82)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:83)(cid:85)(cid:76)(cid:70)(cid:72)(cid:17)(cid:3)

The Advance acquisition includes approximately 18,500 net acres
in the core of the northern Delaware Basin with approximately 99% 
of such acreage held by production. Most of the Advance acreage
is adjacent to or very close to some of our best acreage where we
have regularly drilled wells with an estimated ultimate recovery 
of over one million barrels of oil and natural gas equivalent. The 
(cid:36)(cid:71)(cid:89)(cid:68)(cid:81)(cid:70)(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:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72)(cid:86)(cid:3)(cid:68)(cid:3)(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:403)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:76)(cid:81)(cid:70)(cid:85)(cid:72)(cid:68)(cid:86)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:81)(cid:87)(cid:82)(cid:85)(cid:92)
of comparable recoveries in primary development zones with 206
gross (174 net) operated locations in our core target formations a
an additional 38 gross (35 net) upside locations in the Wolfca

olfcamp D

ns and

formation. We expect an average lateral length of approximately
9,400 feet for operated wells drilled on the Advance properties,
(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:76)(cid:80)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:86)(cid:3)(cid:70)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:72)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:70)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:70)(cid:85)(cid:72)(cid:68)(cid:86)(cid:72)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)
returns for the wells that we drill on this acreage. This new acreage
also provides further expansion opportunities for Pronto, our 
wholly-owned midstream subsidiary serving that area in Lea 
County, New Mexico. 

(cid:82)(cid:81)(cid:3)(cid:87)
BOE p
wells o

(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:3)(cid:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:403)(cid:85)(cid:86)(cid:87)(cid:3)(cid:84)(cid:88)(cid:68)(cid:85)(cid:87)(cid:72)(cid:85)(cid:3)(cid:21)(cid:19)(cid:21)(cid:22)(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:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:36)(cid:71)(cid:89)(cid:68)(cid:81)(cid:70)(cid:72)
properties would be between 24,500 and 25,500 BOE per
day. We expect to turn to sales 21 gross (20.4 net) wells on the 
will be a
Advance acreage in the second half of 2023, which will be another 
(cid:22)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)
(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:403)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:76)(cid:81)(cid:70)(cid:85)(cid:72)(cid:68)(cid:86)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:88)(cid:85)(cid:85)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:85)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:70)(cid:87)(cid:72)(cid:71)(cid:3)(cid:21)(cid:19)(cid:21)(cid:22)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:17)
Advance was operating one drilling rig on these assets, and we
ssets, and w
 rig program
expect to add this drilling rig to our existing seven rig program in 
losed. Matado
the Delaware Basin now that the acquisition has closed. Matador’s 
existing seven rigs are expected to operate throuughout our 
acreage position in the Delaware Basin as set forrth in more
detail below.

The Advance acquisition was funded with a cocombination of 
(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:82)(cid:81)(cid:3)(cid:75)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:73)(cid:85)(cid:72)(cid:72)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:372)(cid:82)(cid:90)(cid:3)(cid:85)(cid:72)(cid:70)(cid:72)(cid:76)(cid:89)(cid:72)(cid:71)(cid:3)(cid:83)(cid:85)(cid:83)(cid:85)(cid:76)(cid:82)(cid:85)(cid:3)(cid:87)(cid:82)(cid:3)(cid:70)(cid:79)(cid:82)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)
borrowings under our credit agreement. O. On March 31, 2023, we 
successfully increased the elected commmmitment under our credit
agreement from $775 million to $1.2525 billion and issued $500
million in bonds to the market in an an offering that was six times
(cid:82)(cid:89)(cid:72)(cid:85)(cid:86)(cid:88)(cid:69)(cid:86)(cid:70)(cid:85)(cid:76)(cid:69)(cid:72)(cid:71)(cid:17)(cid:3)(cid:44)(cid:80)(cid:83)(cid:82)(cid:85)(cid:87)(cid:68)(cid:81)(cid:87)(cid:79)(cid:92)(cid:15)(cid:3)(cid:87)(cid:75)(cid:15)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(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:3)(cid:71)(cid:82)(cid:72)(cid:86)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:403)(cid:70)(cid:68)(cid:81)(cid:87)(cid:79)(cid:92)
(cid:76)(cid:80)(cid:83)(cid:68)(cid:70)(cid:87)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:333)(cid:86)(cid:3)(cid:79)(cid:72)(cid:89)(cid:72)(cid:85)(cid:68)(cid:74)(cid:72)(cid:3)(cid:83)(cid:74)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:403)(cid:79)(cid:72)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:90)(cid:72)(cid:3)(cid:85)(cid:72)(cid:80)(cid:68)(cid:76)(cid:81)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)
maintaining a strong bag balance sheet and paying down our debt with
(cid:73)(cid:85)(cid:72)(cid:72)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:372)(cid:82)(cid:90)(cid:3)(cid:74)(cid:82)(cid:76)(cid:81)(cid:74)
(cid:74)(cid:82)(cid:76)(cid:81)(cid:74)(cid:3)(cid:73)(cid:82)(cid:85)(cid:90)(cid:68)(cid:85)(cid:71)(cid:3)(cid:68)(cid:86)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:68)(cid:86)(cid:3)(cid:76)(cid:81)(cid:70)(cid:85)(cid:72)(cid:68)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:3)
returns over t

ver time.

2023 OPERATING PLAN —  
GROWING STRONGER TOGETHER
While we celebrate the success of 2022, we look forward to
achieving even better results in 2023 and especially into 2024. 

Our 2023 drilling program is expected to focus on opportuniti
throughout our acreage position in the northern Delaware Ba
(cid:49)(cid:82)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:80)(cid:76)(cid:79)(cid:72)(cid:86)(cid:87)(cid:82)(cid:81)(cid:72)(cid:86)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:15)(cid:3)(cid:71)(cid:88)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:403)(cid:85)(cid:86)(cid:87)(cid:3)(cid:75)(cid:68)(cid:79)(cid:73)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:92)(cid:72)(cid:68)(cid:85)
plan to turn to sales eight gross (7.7 net) wells in the Rodn
dney
Robinson leasehold and eight gross (8.0 net) Boros and
nd Voni 
wells in the Stateline asset area, adding to the 54 Bor
Boros and Voni
wells that were already drilled and producing.

ties 
Basin.

(cid:68)(cid:85)(cid:15)(cid:3)(cid:82)(cid:88)(cid:85)

Bureau of Land Management

he Boros and Voni 
federal leaseholds that

ease Sale in September 2018 (the 
me analysts and investors questioned 

Both the Rodney Robinson leasehold and the 
leaseholds in the Stateline asset area are fe
were acquired by Matador from the Bur
in the New Mexico Oil and Gas Lease
“BLM Acquisition”). While some a
the BLM Acquisition at the tim
them, have turned out to 
that Matador has ever
already paid for it
us in moving 
(cid:28)(cid:27)(cid:8)(cid:3)(cid:87)(cid:90)(cid:82)(cid:16)
(cid:87)(cid:90)(cid:82)(cid:16)(cid:80)(cid:76)(cid:79)(cid:72)(cid:3)(cid:79)(cid:68)(cid:87)(cid:72)(cid:85)(cid:68)(cid:79)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:86)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:69)(cid:72)(cid:87)(cid:87)(cid:72)(cid:85)(cid:3)(cid:70)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:72)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:70)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)
production histories. We believe the Advance acreage is of similar 
prod
high quality.  

ever developed. The BLM Acquisition has
or itself several times over. This acreage assisted 
ing from drilling 98% one-mile lateral wells to drilling 

e time, these assets, and the wells on 
t to be among the best acreage and wells

expect to achieve record production again in 2023 (and again in
2024) with total production in 2023 expected to be approximately
45.3 million BOE, which is an 18% increase over our record 2022 
production. As in prior years, we expect to continue to focus on
(cid:71)(cid:85)(cid:76)(cid:79)(cid:79)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:79)(cid:72)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:70)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:72)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:70)(cid:76)(cid:72)(cid:86)(cid:15)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:72)(cid:91)(cid:83)(cid:68)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)
the use of existing facilities and dual-fuel pressure pumping and 
Simul-Frac completions. Obviously, we believe our 2023 operating 
plan should provide another rewarding year for Matador and all of 
its stakeholders. 

Notably, Matador anticipates that its 2023 operating plan will set
(cid:88)(cid:83)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:68)(cid:81)(cid:3)(cid:72)(cid:89)(cid:72)(cid:81)(cid:3)(cid:69)(cid:72)(cid:87)(cid:87)(cid:72)(cid:85)(cid:3)(cid:21)(cid:19)(cid:21)(cid:23)(cid:17)(cid:3)(cid:44)(cid:81)(cid:3)(cid:21)(cid:19)(cid:21)(cid:21)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:75)(cid:76)(cid:87)(cid:3)(cid:68)(cid:81)(cid:3)(cid:76)(cid:81)(cid:372)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)
point when we exceeded average production of 100,000 BOE per
day. We now expect that during the fourth quarter of 2023, we will
produce an average of over 140,000 BOE per day (at the midpoint 
of our guidance issued on February 21, 2023), which is a 28% year-
(cid:82)(cid:89)(cid:72)(cid:85)(cid:16)(cid:92)(cid:72)(cid:68)(cid:85)(cid:3)(cid:76)(cid:81)(cid:70)(cid:85)(cid:72)(cid:68)(cid:86)(cid:72)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:73)(cid:82)(cid:88)(cid:85)(cid:87)(cid:75)(cid:3)(cid:84)(cid:88)(cid:68)(cid:85)(cid:87)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:21)(cid:19)(cid:21)(cid:21)(cid:17)(cid:3)(cid:54)(cid:76)(cid:74)(cid:81)(cid:76)(cid:403)(cid:70)(cid:68)(cid:81)(cid:87)(cid:79)(cid:92)(cid:15)
much of this growth will be in oil production as we expect to 
produce 87,500 barrels of oil per day in the fourth quarter of 2023
(at the midpoint of our guidance issued on February 21, 2023), 
which is a 41% increase as compared to the fourth quarter of 2022. 

ANNUAL MEETING 
On behalf of the Matador Board of Directors and Staff, we invite
each of you to attend our annual shareholders’ meeting on Friday,
June 9, 2023, at the Hilton Dallas Lincoln Centre. We sincerely 
hope that you will be able to join us in Dallas or on the broadcast 
as the annual meeting usually draws over 200 shareholders,
friends and employees and provides the opportunity to socialize 
with directors, management and senior staff before and after the 
formal meeting. If you are unable to attend, we encourage you to
please participate via our virtual live webcast the morning of the 
event. We will provide additional full details about the meeting 
and participation arrangements separately. We always enjoy
seeing everyone in person and hope this year’s meeting will be
bigger and better than ever. 

THANK YOU
Naturally, the Board and I are very pleased with Matador’s record
performance in 2022 and the outlook for 2023 and how it sets 
us up nicely for 2024. We remain grateful for all the continued
support and friendship of all our shareholders. Please reach out
to us any time you have questions, concerns, or suggestions. We
recognize that our success starts with our outstanding staff and
a stable group of long-term shareholders, vendors, bankers and 
other friends. As always, we invite you to stop by and see us or call 
us whenever you are in the Dallas area.

Sincerely,

Importantly, with the projects previously mentioned and the
other wells that we plan to turn to sales in our other asset areas,
we anticipate turning to sales over 90 net operated wells for the
(cid:403)(cid:85)(cid:86)(cid:87)(cid:3)(cid:87)(cid:76)(cid:80)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:38)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:333)(cid:86)(cid:3)(cid:75)(cid:76)(cid:86)(cid:87)(cid:82)(cid:85)(cid:92)(cid:3)(cid:71)(cid:88)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:21)(cid:19)(cid:21)(cid:22)(cid:17)(cid:3)(cid:36)(cid:86)(cid:3)(cid:68)(cid:3)(cid:85)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)

Joseph Wm. Foran

Founder, Chairman & CEO
(972) 371-5206

Board of Directors and Special Advisor

Joseph Wm. Foran

Founder, Chairman and Chief Executive
(cid:50)(cid:73)(cid:403)(cid:70)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:3)(cid:53)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:38)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:3)
(Matador II); Founder, Chairman and Chief 
(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:73)(cid:403)(cid:70)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:3)(cid:51)(cid:72)(cid:87)(cid:85)(cid:82)(cid:79)(cid:72)(cid:88)(cid:80)
Corporation (Matador I)

Monika U. Ehrman

Director; Professor of Law, Southern
Methodist University Dedman School of 
Law; BS in Petoleum Engineering; Former 
public Oil and Gas Company In-House
Legal Counsel

Timothy E. Parker

James M. Howard   

Lead Independent Director; Contractor in 
Charge of Research, Brightworks Wealth 
Management, LLC; Former Portfolio Manager 
and Analyst – Natural Resources,
T. Rowe Price & Associates

Director; Retired Trustee, Private Family Trust; 
Former Vice President, Texon L.P.; Former 
Vice President, Tripetrol Oil Trading Inc.;
Former Member, NYMEX Crude Oil
Advisory Committee

R. Gaines Baty

Deputy Lead Independent Director;
(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:73)(cid:403)(cid:70)(cid:72)(cid:85)(cid:15)(cid:3)(cid:53)(cid:17)(cid:3)(cid:42)(cid:68)(cid:76)(cid:81)(cid:72)(cid:86)(cid:3)(cid:37)(cid:68)(cid:87)(cid:92)(cid:3)
Associates, Inc., a leading executive
(cid:86)(cid:72)(cid:68)(cid:85)(cid:70)(cid:75)(cid:3)(cid:403)(cid:85)(cid:80)(cid:30)(cid:3)(cid:51)(cid:88)(cid:69)(cid:79)(cid:76)(cid:86)(cid:75)(cid:72)(cid:71)(cid:3)(cid:36)(cid:88)(cid:87)(cid:75)(cid:82)(cid:85)

Reynald A. Baribault

Director; President, CEO and Co-Founder,
IPR Energy Partners, LLC; Former Executive
Vice President/Engineering and Co-Foun
NP Resources, LLC; Former Vice 
Netherland, Sewell & AssoAssociates, Inc.

Vice President 

o-Founder 

Julia P. Forrester Rogers

Director; Professor of Law, Southern
Methodist University Dedman School of 
Law; Former Associate Provost, Southern 
Methodist University; Former Real Estate
Attorney, Thompson & Knight LLP

Kenneth L. Stewart

Director; Retired Executive Vice President,
Compliance and Legal Affairs, Children’s
Health System of Texas; Retired Partner,
Chair – United States, Norton Rose
Fulbright US LLP

William M. Byerley

Shelley F. Appel

Director; Retired Partner,
PricewaterhouseCoopers (PwC); Practice 
(cid:73)(cid:82)(cid:70)(cid:88)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:72)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:3)(cid:70)(cid:79)(cid:76)(cid:72)(cid:81)(cid:87)(cid:86)(cid:30)(cid:3)(cid:38)(cid:72)(cid:85)(cid:87)(cid:76)(cid:403)(cid:72)(cid:71)(cid:3)
Public Accountant

Special Advisor; ESG Coordinator, Matador 
Resources Company, Former Senior Investor 
(cid:53)(cid:72)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:50)(cid:73)(cid:403)(cid:70)(cid:72)(cid:85)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:48)(cid:72)(cid:85)(cid:74)(cid:72)(cid:85)(cid:86)(cid:3)(cid:9)(cid:3)(cid:36)(cid:70)(cid:84)(cid:88)(cid:76)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)
Manager, Royal Dutch Shell PLC; Former 
Corporate Strategy, NYSE Euronext and
Intercontinental Exchange Group

Environmental, Social and Governance (ESG)(1)

ENVIRONMENTAL

CONTINUED REDUCTION OF 
PER-BARREL EMISSIONS(2)

INCREASED USE OF NON-FRESH 
WATER, INCLUDING RECYCLED WATER

>40%  >60% 

Reduction in 
direct greenhouse 
gas emissions 
intensity from 
2019 to 2022

Reduction 
in methane 
emissions 
intensity from 
2019 to 2022

>9
>95% >70% 

f total
of total water 
onsume
consumed 
in 2022 was 
n 2022 wa
non-fresh water(3)
on-fresh w

of wells completed in 
2022 utilized recycled 
produced water(4)

SOCIAL

ZERO

employee lost time 
incidents during 
approximately 
3.3 million employee 
man-hours from 2017 
to 2022

>50 

hours of 
continuing 
education per 
employee in 2022

NE
INCREASED TRANSPORTATION ON PIPELINE

OPERATED PRODUCED OIL ON PIPE

OPERATED PRODUCE
OPERATED PRODUCED WATER ON PIPE
E

Barrels Transported via Pipeline 
Barrels Transported via Trucks

Barrels Transported via P
Barrels Transported via Pipeline 
P
Barrels Transported via T
Barrels Transported via Trucks
T

d
/
l
b
B

,

d
e
t
r
o
p
s
n
a
r
T

l
i

O
d
e
t
a
r
e
p
O
s
s
o
o
r
r
G
G

80,000

70,000

60,000

50,000

40,000

30,000

20,000

0,000
10,000

0
0

89%
9%

82%
%

65%

48%

14%

12%

2017
2017

2018
2018

2019
2019

2020
2020

2021
2021

2022
2022

d
d
/
/
l
l
b
b
B
B

,
,

d
d
e
e
t
t
r
r
o
o
p
p
s
s
n
n
a
a
r
r
T
T
r
r
e
e
t
t
a
a
W
W
d
d
e
e
t
t
a
a
r
r
e
e
p
p
O
O
s
s
s
s
o
o
r
r
G
G

350,000
350,000

300,000
300,000

250,000
250,000

200,000
200,000

150,000
150,000

100,000
100,000

50,000
50,000

0
0

99%

98%

96%

80%

70%
70%

59%
59%

2017
2017

82018
2018

2019

2020

2021

2022

GOVERNANCE
GOVERNANCE

5.5%
5.5%

of common stock 
of common stock 
held by directors
held by directors 
and executive
and executive 
(cid:82)(cid:73)(cid:403)(cid:70)(cid:72)(cid:85)(cid:86)(5)
(cid:82)(cid:73)(cid:403)(cid:70)(cid:72)(cid:85)(cid:86)(5)

8
8

9
9

Independence
Independence
ce

Eight directors 
Eight director
or
are independent, 
are indepen
pen
including a lead 
including
ing
indep
ep
independent 
director
dirdir

Diversity

One minority 
and two female 
directors

2

9

Refreshment

Less than six years’ 
tenure for more than 
half the directors

5

9

For more information, visit our web
For more information, visit our website at www.matadorresources.com/sustainability
web

(1) These sustainabil
(cid:70)(cid:68)(cid:79)(cid:70)(cid:88)(cid:79)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:88)
factors. A
(cid:85)(cid:72)(cid:372)(cid:72)(cid:70)
co
consolidated basis, except where otherwise noted.

(cid:74)(cid:3)(cid:86)(cid:88)(cid:70)(cid:75)(cid:3)(cid:80)(cid:72)(cid:87)(cid:85)(cid:76)(cid:70)(cid:86)(cid:3)(cid:76)(cid:86)(cid:3)(cid:86)(cid:88)(cid:69)(cid:77)(cid:72)(cid:70)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:70)(cid:72)(cid:85)(cid:87)(cid:68)(cid:76)(cid:81)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:85)(cid:88)(cid:79)(cid:72)(cid:86)(cid:15)(cid:3)(cid:85)(cid:72)(cid:74)(cid:88)(cid:79)(cid:68)(cid:87)(cid:82)(cid:85)(cid:92)(cid:3)(cid:85)(cid:72)(cid:89)(cid:76)(cid:72)(cid:90)(cid:86)(cid:15)(cid:3)(cid:71)(cid:72)(cid:403)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:15)(cid:3)(cid:70)(cid:68)(cid:79)(cid:70)(cid:88)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:80)(cid:72)(cid:87)(cid:75)(cid:82)(cid:71)(cid:82)(cid:79)(cid:82)(cid:74)(cid:76)(cid:72)(cid:86)(cid:15)(cid:3)(cid:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:86)(cid:15)(cid:3)(cid:68)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)

s. As a result, these metrics are subject to change from time to time as updated data or other information becomes available. The metrics provided
(cid:372)(cid:72)(cid:70)(cid:87)(cid:3)(cid:69)(cid:82)(cid:87)(cid:75)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:333)(cid:86)(cid:3)(cid:74)(cid:85)(cid:82)(cid:86)(cid:86)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(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:3)(cid:9)(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:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:68)(cid:81)(cid:3)(cid:48)(cid:68)(cid:87)(cid:72)(cid:82)(cid:3)(cid:48)(cid:76)(cid:71)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:15)(cid:3)(cid:47)(cid:47)(cid:38)(cid:333)(cid:86)(cid:3)(cid:74)(cid:85)(cid:82)(cid:86)(cid:86)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:80)(cid:76)(cid:71)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:82)(cid:81)(cid:3)(cid:68)

(cid:11)(cid:21)(cid:12)(cid:3)(cid:40)(cid:80)(cid:76)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:372)(cid:68)(cid:85)(cid:72)(cid:71)(cid:3)(cid:89)(cid:82)(cid:79)(cid:88)(cid:80)(cid:72)(cid:86)(cid:3)(cid:68)(cid:85)(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:76)(cid:81)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:85)(cid:71)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:40)(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:51)(cid:85)(cid:82)(cid:87)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:36)(cid:74)(cid:72)(cid:81)(cid:70)(cid:92)(cid:3)(cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:372)(cid:72)(cid:70)(cid:87)(cid:3)(cid:82)(cid:81)(cid:79)(cid:92)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:333)(cid:86)(cid:3)(cid:74)(cid:85)(cid:82)(cid:86)(cid:86)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)

exploration & production operations. 

(cid:11)(cid:22)(cid:12)(cid:3)(cid:41)(cid:85)(cid:72)(cid:86)(cid:75)(cid:3)(cid:90)(cid:68)(cid:87)(cid:72)(cid:85)(cid:3)(cid:76)(cid:86)(cid:3)(cid:71)(cid:72)(cid:403)(cid:81)(cid:72)(cid:71)(cid:3)(cid:68)(cid:86)(cid:3)(cid:31)(cid:20)(cid:15)(cid:19)(cid:19)(cid:19)(cid:3)(cid:80)(cid:74)(cid:18)(cid:47)(cid:3)(cid:87)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:71)(cid:76)(cid:86)(cid:86)(cid:82)(cid:79)(cid:89)(cid:72)(cid:71)(cid:3)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:86)(cid:3)(cid:48)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:333)(cid:86)(cid:3)(cid:74)(cid:85)(cid:82)(cid:86)(cid:86)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:89)(cid:82)(cid:79)(cid:88)(cid:80)(cid:72)(cid:86)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:75)(cid:92)(cid:71)(cid:85)(cid:68)(cid:88)(cid:79)(cid:76)(cid:70)(cid:3)(cid:73)(cid:85)(cid:68)(cid:70)(cid:87)(cid:88)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:79)(cid:72)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)

operations, as well as estimates for Matador’s other operations. 

(cid:11)(cid:23)(cid:12)(cid:3)(cid:36)(cid:86)(cid:3)(cid:86)(cid:82)(cid:80)(cid:72)(cid:3)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:87)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:372)(cid:88)(cid:76)(cid:71)(cid:3)(cid:88)(cid:86)(cid:72)(cid:71)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:75)(cid:92)(cid:71)(cid:85)(cid:68)(cid:88)(cid:79)(cid:76)(cid:70)(cid:3)(cid:73)(cid:85)(cid:68)(cid:70)(cid:87)(cid:88)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:3)

(5) As of February 21, 2023. Please see Matador’s most recent Proxy Statement for additional information.

 
 
 
 
 
 
 
 
 
 
 
 
Strategic Bolt-On Acquisition of Advance Energy

The Advance Transaction is a strategic
bolt-on acquisition in the core of the
Northern Delaware Basin including 
18,500 net acres, virtually all held-by-
production. The properties include
(cid:86)(cid:87)(cid:85)(cid:82)(cid:81)(cid:74)(cid:3)(cid:72)(cid:91)(cid:76)(cid:86)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:372)(cid:82)(cid:90)
and proved reserves. Matador will add 
over 200 high-quality net locations 
primarily in development zones, 
with potential for additional upside 
locations. There are existing midstream 
assets, which provide upside value and
synergies with Pronto Midstream.

ADVANCE 
FOCUS 
AREA

ACQUISITION DETAILS
Price: $1.6 billion(1)
Effective Date: 1/1/2023
Closing: Q2 2023

KEY METRICS

Net Acres

18,500

Held by Production (%)

99%

Q1 2023E Production

Forward 1-year Adj. 
EBITDA(2)

24,500 to 25,500
BOE/d (74% oil)

$475 to $525 million

Net Locations

203 (85% operated)

Avg. Operated  
Lateral Length

9,400 feet

2023E “D/C/E” CapEx

$300 to $350 million

YE 2022  
Proved Reserves

106 MMBOE (73% oil)

PV-10 at strip pricing(3)

$1.92 billion

Production Value(4)

$45,600 / BOE per day

TWIN LAKES

ARROWHEAD

RANGER

RUSTLER BREAKS

ANTELOPE RIDGE

STATELINE

WOLF/JACKSON TRUST (LOVING)

  Matador Acreage at December 31, 2022

  Advance Transaction Acreage

Note: All acreage as of December 31, 2022 pro forma for the Advance Transaction. Some 
tracts not shown on map.

(1) Subject to customary closing adjustments and plus additional cash consideration of 

(cid:7)(cid:26)(cid:17)(cid:24)(cid:3)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:72)(cid:68)(cid:70)(cid:75)(cid:3)(cid:80)(cid:82)(cid:81)(cid:87)(cid:75)(cid:3)(cid:71)(cid:88)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:21)(cid:19)(cid:21)(cid:22)(cid:3)(cid:76)(cid:81)(cid:3)(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:68)(cid:89)(cid:72)(cid:85)(cid:68)(cid:74)(cid:72)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:83)(cid:85)(cid:76)(cid:70)(cid:72)(cid:3)(cid:68)(cid:86)(cid:3)(cid:71)(cid:72)(cid:403)(cid:81)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)
securities purchase agreement exceeds $85 per Bbl.

(cid:11)(cid:21)(cid:12)(cid:3)(cid:40)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:88)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:87)(cid:85)(cid:76)(cid:83)(cid:3)(cid:83)(cid:85)(cid:76)(cid:70)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:80)(cid:76)(cid:71)(cid:16)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:21)(cid:19)(cid:21)(cid:22)(cid:17)(cid:3)(cid:36)(cid:71)(cid:77)(cid:17)(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:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)
(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:17)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:38)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:3)(cid:71)(cid:72)(cid:403)(cid:81)(cid:72)(cid:86)(cid:3)(cid:36)(cid:71)(cid:77)(cid:17)(cid:3)(cid:40)(cid:37)(cid:44)(cid:55)(cid:39)(cid:36)(cid:3)(cid:68)(cid:86)(cid:3)(cid:72)(cid:68)(cid:85)(cid:81)(cid:76)(cid:81)(cid:74)(cid:86)(cid:3)(cid:69)(cid:72)(cid:73)(cid:82)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:15)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)
taxes, depletion, depreciation and amortization, accretion of asset retirement obligations,
property impairments, unrealized derivative gains and losses, certain other non-cash
items and non-cash stock-based compensation expense and net gain or loss on asset sales 
and impairment. The most comparable GAAP measures to Adj. EBITDA are net income
or net cash provided by operating activities. The Company has not provided such GAAP
measures or a reconciliation to such GAAP measures because they would be preliminary
and prospective in nature and would not be able to be prepared without estimation of a
number of variables that are unknown at this time.

(3) PV-10 (present value discounted at 10%) at December 31, 2022 utilizing strip pricing as of 
(cid:80)(cid:76)(cid:71)(cid:16)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:21)(cid:19)(cid:21)(cid:22)(cid:17)(cid:3)(cid:51)(cid:57)(cid:16)(cid:20)(cid:19)(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:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:15)(cid:3)(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:71)(cid:76)(cid:73)(cid:73)(cid:72)(cid:85)(cid:86)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:42)(cid:36)(cid:36)(cid:51)
(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:335)(cid:54)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:48)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:336)(cid:3)(cid:69)(cid:72)(cid:70)(cid:68)(cid:88)(cid:86)(cid:72)(cid:3)(cid:51)(cid:57)(cid:16)(cid:20)(cid:19)(cid:3)(cid:71)(cid:82)(cid:72)(cid:86)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:72)(cid:73)(cid:73)(cid:72)(cid:70)(cid:87)(cid:86)
of income taxes on future income. The income taxes related to the acquired properties
is unknown at this time because the Company’s tax basis in such properties will not be 
known until the closing of the transaction and is subject to many variables. As such, the 
Company has not provided the Standardized Measure of the acquired properties or a 
reconciliation of PV-10 to Standardized Measure.

(4) Equals PV-10 of proved developed reserves of $1.14 billion divided by midpoint of Q1 2023 

production estimate of 25,000 BOE per day.

2 0 2 2 F O R M 10 - K

Gaining Strength.  
Growing Stronger Together.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
l3 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the ﬁscal year ended December 31, 2022
or
l TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________

Commission File Number 001-35410

MATADOR RESOURCES COMPANY

(Exact name of registrant as speciﬁed in its charter)

Texas
(State or other jurisdiction of
incorporation or organization)

5400 LBJ Freeway, Suite 1500
Dallas, Texas
(Address of principal executive ofﬁces)

27-4662601
(I.R.S. Employer
Identiﬁcation No.)

75240
(Zip Code)

Registrant’s telephone number, including area code: (972) 371-5200

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

Title of each class

Trading symbol(s)

Name of each exchange on which registered

Common Stock, par value $0.01 per share

MTDR

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 deﬁned in Rule 405 of the Securities Act. Yes l3 No l
Indicate by check mark if the registrant is not required to ﬁle reports pursuant to Section 13 or Section 15(d) of the Act. Yes l No l3

Indicate by check mark whether the registrant (1) has ﬁled all reports required to be ﬁled by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to ﬁle such
reports), and (2) has been subject to such ﬁling requirements for the past 90 days. Yes l3 No l

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit such ﬁles). Yes l3 No l

Indicate by check mark whether the registrant is a large accelerated ﬁler, an accelerated ﬁler, a non-accelerated ﬁler, a smaller
reporting company, or an emerging growth company. See the deﬁnitions of “large accelerated ﬁler,” “accelerated ﬁler,” “smaller
reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated ﬁler l3
Non-accelerated ﬁler l

l
Accelerated ﬁler
Smaller reporting company l
Emerging growth company l

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

Indicate by check mark whether the registrant has ﬁled a report on and attestation to its management’s assessment of the
effectiveness of its internal control over ﬁnancial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by
the registered public accounting ﬁrm that prepared or issued its audit report. l3
Indicate by check mark whether the registrant is a shell company (as deﬁned in Rule 12b-2 of the Exchange Act). Yes l No l3

The aggregate market value of the voting and non-voting common equity of the registrant held by non-afﬁliates, computed by
reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently
completed second ﬁscal quarter was $5,188,536,396.

As of February 21, 2023, there were 119,071,975 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference
to the registrant’s deﬁnitive proxy statement relating to the 2022 Annual Meeting of Shareholders, which will be ﬁled with the Securities
and Exchange Commission within 120 days after the end of the ﬁscal year to which this Annual Report on Form 10-K relates.

Auditor Name: KPMG LLP

Auditor Location: Dallas, TX

Auditor Firm ID: 185

MATADOR RESOURCES COMPANY

Table of Contents

PART I

ITEM 1.

ITEM 1A.

ITEM 1B.

ITEM 2.

ITEM 3.

ITEM 4.

PART II

ITEM 5.

ITEM 6.

ITEM 7.

Page

Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3

Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases

of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Management’s Discussion and Analysis of Financial Condition and Results of Operations. . . . . 97

ITEM 7A.

Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

ITEM 8.

ITEM 9.

ITEM 9A.

ITEM 9B.

PART III

ITEM 10.

ITEM 11.

ITEM 12.

ITEM 13.

ITEM 14.

PART IV

ITEM 15.

ITEM 16.

Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . 125

Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

Directors, Executive Ofﬁcers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

Security Ownership of Certain Beneﬁcial Owners and Management and

Related Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . 129

Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

Exhibits and Financial Statement Schedules. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

Form 10-K Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

FORM 10-K

2022 ANNUAL REPORT

1

Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “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”). Additionally,
forward-looking statements may be made orally or in press releases, conferences, reports, on our website or
otherwise, in the future by us or on our behalf. Such statements are generally identiﬁable by the terminology
used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,”
“intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words,
although not all forward-looking statements contain such identifying words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that

may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and
other factors that may cause actual results, levels of activity and achievements to differ materially from those
expressed or implied by such statements. Such factors include, among others: general economic conditions; our
ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas
and natural gas liquids (“NGL”) prices and the demand for oil, natural gas and NGLs; our ability to replace
reserves and efﬁciently develop current reserves; the operating results of our midstream business’s oil, natural gas
and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and
the drilling of any additional salt water disposal wells; costs of operations; delays and other difﬁculties related to
producing oil, natural gas and natural gas liquids; delays and other difﬁculties related to regulatory and governmental
approvals and restrictions; impact on our operations due to seismic events; availability of sufﬁcient capital to
execute our business plan, including from future cash ﬂows, available borrowing capacity under our revolving credit
facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate
acquisitions; the operating results of and availability of any potential distributions from our joint ventures; weather
and environmental conditions; the ongoing impact of the novel coronavirus (“COVID-19”) and its variants on oil
and natural gas demand, oil and natural gas prices and our business; our ability to consummate the Advance
Acquisition (as deﬁned below) in the anticipated timeframe or at all; risks related to the satisfaction or waiver of the
conditions to closing the Advance Acquisition in the anticipated timeframe or at all; risks related to obtaining the
requisite regulatory approvals for the Advance Acquisition; disruption from the Advance Acquisition making it more
difﬁcult to maintain business and operational relationships; signiﬁcant transaction costs associated with the Advance
Acquisition; the risk of litigation and/or regulatory actions related to the Advance Acquisition; and the other factors
discussed below and elsewhere in this Annual Report and in other documents that we ﬁle with or furnish to the
United States Securities and Exchange Commission (the “SEC”), all of which are difﬁcult to predict. Forward-looking
statements may include statements about:

• our business strategy;

• our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling

impairment could be realized;

• our cash ﬂows and liquidity;

•

the amount, timing and payment of dividends, if any;

• our ﬁnancial strategy, budget, projections and operating results;

•

the supply and demand of oil, natural gas and NGLs;

• oil, natural gas and NGL prices, including our realized prices thereof;

•

•

•

•

the timing and amount of future production of oil and natural gas;

the availability of drilling and production equipment;

the availability of oil storage capacity;

the availability of oil ﬁeld labor;

FORM 10-K

2

MATADOR RESOURCES COMPANY

•

•

the amount, nature and timing of capital expenditures, including future exploration and development costs;

the availability and terms of capital;

• our drilling of wells;

• our ability to negotiate and consummate acquisition and divestiture opportunities;

•

the integration of acquisitions, including the Advance Acquisition, with our business;

• government regulation and taxation of the oil and natural gas industry;

• our marketing of oil and natural gas;

• our exploitation projects or property acquisitions;

• our ability and the ability of our midstream joint venture to construct, maintain and operate midstream

pipelines and facilities, including the operation of cryogenic natural gas processing plants and the drilling
of additional salt water disposal wells;

•

the ability of our midstream business to attract third-party volumes;

• our costs of exploiting and developing our properties and conducting other operations;

• general economic conditions;

• competition in the oil and natural gas industry, including in both the exploration and production and

midstream segments;

•

the effectiveness of our risk management and hedging activities;

• our technology;

• environmental liabilities;

• our initiatives and efforts relating to environmental, social and governance matters;

• counterparty credit risk;

• geopolitical instability and developments in oil-producing and natural gas-producing countries;

•

the impact of COVID-19 and its variants on the oil and natural gas industry and our business;

• our future operating results;

•

•

the Advance Acquisition and the anticipated timing and beneﬁts thereof;

the impact of the Inﬂation Reduction Act of 2022; and

• our plans, objectives, expectations and intentions contained in this Annual Report or in our other ﬁlings with

the SEC that are not historical.

Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are
reasonable based on information available to us on the date hereof, no assurances can be given as to future results,
levels of activity, achievements or ﬁnancial condition.

You should not place undue reliance on any forward-looking statement and should recognize that the statements
are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those
anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described
above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement
is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements
are not exclusive and further information concerning us, including factors that potentially could materially affect our
ﬁnancial results, may emerge from time to time. We undertake no obligation to update forward-looking statements
to reﬂect actual results or changes in factors or assumptions affecting such forward-looking statements, except as
required by law, including the securities laws of the United States and the rules and regulations of the SEC.

FORM 10-K

2022 ANNUAL REPORT

3

Part I

ITEM 1. BUSINESS.

In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company
and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to
Matador Resources Company, (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively
with its subsidiaries and (iv) references to “Pronto” refer to Pronto Midstream, LLC, and the “Pronto Acquisition”
refers to the acquisition of Pronto by a subsidiary of the Company on June 30, 2022. For certain oil and natural gas
terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report.

GENERAL

We are an independent energy company engaged in the exploration, development, production and acquisition

of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other
unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp
and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in
the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
Additionally, we conduct midstream operations in support of our exploration, development and production
operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water
gathering services and produced water disposal services to third parties.

We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Ofﬁcer.

Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company
with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed
to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and
Chief Executive Ofﬁcer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an
all-cash transaction for an enterprise value of approximately $388.5 million.

On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the
symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock.

Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash ﬂows
and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by,
among other items, executing the following business strategies:

•

•

focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp
and Bone Spring plays in the Delaware Basin;

identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced
portfolio of oil and natural gas properties;

• continue to improve operational and cost efﬁciencies;

•

identify and develop midstream opportunities that support and enhance our exploration and development
activities and that generate value for San Mateo and Pronto;

• maintain our ﬁnancial discipline;

•

return capital to shareholders through our dividend policy;

• pursue opportunistic acquisitions, divestitures and joint ventures; and

• provide the energy that society needs and do so in a manner that is safe, protects the environment and is

consistent with the oil and natural gas industry’s best practices.

FORM 10-K PART I

4

MATADOR RESOURCES COMPANY

Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020,

which led to a very challenging oil and natural gas price environment, global oil demand and oil and natural gas
prices improved signiﬁcantly during 2021 and 2022. These factors, along with the successful execution of our
business strategies, led to increases in our oil and natural gas production and proved oil and natural gas reserves in
2022, as well as to increases in our oil and natural gas revenues and cash ﬂows. We also improved the capital
efﬁciency of our drilling and completion operations and achieved several key operational milestones throughout the
year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West
Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year,
including generating free cash ﬂow, paying down borrowings, increasing our quarterly cash dividend and earning
performance incentives from Five Point Energy, LLC, our joint venture partner in San Mateo (“Five Point”). Further,
we concluded several important ﬁnancing transactions in 2022, including increasing the borrowing base under our
Credit Agreement (as deﬁned below) and extending the maturity of and increasing the lender commitments under
the San Mateo Credit Facility (as deﬁned below). San Mateo also achieved important milestones in 2022, including
the addition of produced water disposal capacity and being awarded several new customer contracts. These
achievements and transactions increased our operational ﬂexibility and opportunities while preserving the strength
of our balance sheet and our liquidity position.

2022 HIGHLIGHTS

Increased Oil, Natural Gas and Oil Equivalent Production

For the year ended December 31, 2022, we achieved record oil, natural gas and average daily oil equivalent
production. In 2022, we produced 21.9 million Bbl of oil, an increase of 23%, as compared to 17.8 million Bbl of
oil produced in 2021. We also produced 99.3 Bcf of natural gas, an increase of 22% from 81.7 Bcf of natural gas
produced in 2021. Our average daily oil equivalent production for the year ended December 31, 2022 was
105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, an increase of
22%, as compared to 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas
per day, for the year ended December 31, 2021. The increase in oil and natural gas production was primarily
attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2022,
which offset declining production in the Eagle Ford shale. Oil production comprised 57% of our total production
(using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for each of the years ended December 31, 2022
and 2021.

Increased Oil, Natural Gas and Oil Equivalent Reserves

At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE,

including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, an increase of 10% from 323.4 million BOE, including
181.3 million Bbl of oil and 852.5 Bcf of natural gas, at December 31, 2021. The Standardized Measure of our
total proved oil and natural gas reserves increased 60% from $4.38 billion at December 31, 2021 to $6.98 billion
at December 31, 2022. The PV-10 of our total proved oil and natural gas reserves increased 71% from $5.35 billion
at December 31, 2021 to $9.13 billion at December 31, 2022. The increases in our Standardized Measure and
PV-10 were primarily a result of the signiﬁcantly higher unweighted arithmetic average oil and natural gas prices used
to estimate proved reserves at December 31, 2022, as compared to December 31, 2021, but also due to the
10% increase in our total proved oil and natural gas reserves at December 31, 2022, as compared to December 31,
2021. PV-10 is a non-GAAP ﬁnancial measure. For a reconciliation of PV-10 to Standardized Measure, see
“—Estimated Proved Reserves.”

FORM 10-K PART I

2022 ANNUAL REPORT

5

At December 31, 2022, proved developed reserves included 116.0 million Bbl of oil and 632.9 Bcf of natural gas,

and proved undeveloped reserves included 80.3 million Bbl of oil and 329.7 Bcf of natural gas. Proved developed
reserves and proved oil reserves comprised 62% and 55%, respectively, of our total proved oil and natural gas
reserves at December 31, 2022. Proved developed reserves and proved oil reserves comprised 60% and 56%,
respectively, of our total proved oil and natural gas reserves at December 31, 2021. The improvement in proved
developed reserves as a percentage of our total proved oil and natural gas reserves to 62% at December 31, 2022
from 60% at December 31, 2021 was primarily attributable to the development and conversion of approximately
38.4 million BOE of our proved undeveloped reserves to proved developed reserves and the addition of 24.7 million
BOE in extensions and discoveries primarily in the Delaware Basin in 2022.

Operational Highlights

We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per

well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical
approach to track and monitor the effectiveness of our drilling and completion techniques and service providers.
This allows us to better manage operating costs, the pace of development activities, technical applications, the
gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas,
which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors,
we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin
wells. We expect the Delaware Basin will continue to be our primary area of focus in 2023.

We completed and began producing oil and natural gas from 144 gross (69.8 net) wells in the Delaware Basin in
2022, including 81 gross (64.5 net) operated and 63 gross (5.4 net) non-operated wells. At December 31, 2022, our
total acreage position in the Delaware Basin was approximately 237,100 gross (129,400 net) acres, primarily in Lea
and Eddy Counties, New Mexico and Loving County, Texas. We have focused our Delaware Basin operations on the
following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and
the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the Wolf and Jackson Trust
asset areas in Loving County, Texas. Our Delaware Basin properties are the most signiﬁcant component of our
asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 24% to
100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil
production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022, as compared to
80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil
production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021. We expect our
Delaware Basin production to increase in 2023 as we continue the delineation and development of these asset areas.

During 2022, we achieved all ﬁve signiﬁcant and important operational milestones in the Delaware Basin we set

at the beginning of the year. These ﬁve operational milestones (as further described below in “—Exploration and
Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we
turned to sales:

• 11 Voni wells, all of which were 2.3-mile laterals, in the western portion of the Stateline asset area in a

staggered fashion in early 2022; these 11 Voni wells have produced in aggregate approximately 3.6 million
BOE in 11 months of production;

•

the third group of nine Rodney Robinson wells in the western portion of our Antelope Ridge asset area in
March 2022; these nine Rodney Robinson wells have produced in aggregate approximately 3.1 million BOE
in 10 months of production;

• 11 Rustler Breaks wells in April 2022; these 11 wells have produced in aggregate approximately 2.6 million

BOE in almost nine months of production;

FORM 10-K PART I

6

MATADOR RESOURCES COMPANY

• 16 Antelope Ridge wells in the second half of 2022; these 16 wells have produced in aggregate

approximately 1.6 million BOE in 2022; and

• 12 Ranger wells in the fourth quarter of 2022.

In addition to achieving these ﬁve key operational milestones, further operational highlights in the Delaware Basin

(as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—
Delaware Basin”) in 2022 included:

• continued drilling of longer laterals, whereby 90% of the operated horizontal wells we turned to sales in

2022 had lateral lengths of two miles or greater, as compared to 74% in 2020; and

• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2022 of

$772.5 million, which was at the low end of our revised estimated range for 2022 D/C/E capital expenditures
of $765 to $835 million as provided on July 26, 2022 and afﬁrmed on October 25, 2022, which included the
addition of a seventh operated drilling rig in September 2022.

Capital Resources and Financing Highlights

During 2022, we achieved several signiﬁcant and important capital resources objectives, which included:

•

•

•

•

the generation of free cash ﬂow in all four quarters of 2022;

the repayment of all outstanding borrowings under our revolving credit facility, resulting in no outstanding
borrowings under that facility at December 31, 2022;

the repurchase of $350.8 million of our outstanding senior notes;

the amendments of our dividend policy in the second and fourth quarters of 2022, pursuant to which we
increased the quarterly cash dividend from $0.05 per share of common stock to $0.15 per share of common
stock; and

•

the receipt of $28.3 million in performance incentives directly from Five Point.

In addition, we concluded several important ﬁnancing transactions in 2022 that increased our operational

ﬂexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position.
These transactions included:

•

•

the spring and fall redetermination processes revised our Fourth Amended and Restated Credit Agreement
(the “Credit Agreement”) to collectively (i) increase the borrowing base to $2.25 billion, as compared to
$1.35 billion at December 31, 2021, (ii) increase the elected borrowing commitment to $775.0 million, as
compared to $700.0 million at December 31, 2021, (iii) reafﬁrm the maximum facility amount at $1.5 billion
and (iv) add one new bank to our lending group; and

the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in December 2022
to (i) extend the maturity date by three years from December 2023 to December 2026, (ii) increase the
lender commitments under the San Mateo Credit Facility from $450.0 million to $485.0 million, (iii) refresh
the accordion feature that provides for potential increases in lender commitments to up to $735.0 million,
as compared to $700.0 million previously, and (iv) add one new bank to San Mateo’s lending group.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and

Capital Resources” for additional information regarding these ﬁnancing transactions.

FORM 10-K PART I

2022 ANNUAL REPORT

7

Midstream Highlights

Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49%

by our joint venture partner, Five Point, and through Pronto, which is a wholly-owned subsidiary.

San Mateo achieved strong operating results in 2022, highlighted by (i) free cash ﬂow generation, (ii) increased

midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water
handling volumes and oil gathering and transportation volumes, all as compared to 2021. Volumes for the years
ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been
delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries
were made in both years), but for which San Mateo recognized revenues during the years ended December 31,
2022 and 2021.

During 2022, San Mateo closed seven new midstream transactions with oil and natural gas producers and other

counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and
processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new
opportunities reﬂect additional business awarded to San Mateo by existing customers, which we believe is indicative
of the quality of service San Mateo provides to all of its customers in the Delaware Basin.

At December 31, 2022, San Mateo’s midstream system included:

• Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and

approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County,
Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset
area to the acreage in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”);

• Oil Assets: Three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput

capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico
and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P.
(“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and

• Produced Water Assets: 15 commercial salt water disposal wells and associated facilities with designed
produced water disposal capacity of 445,000 Bbl per day and approximately 165 miles of produced water
gathering pipelines in Eddy County, New Mexico and Loving County, Texas.

On June 30, 2022, we acquired a wholly-owned subsidiary of Summit Midstream Partners, LP that was

subsequently renamed Pronto, which owned a cryogenic gas processing plant with a designed inlet capacity of
60 MMcf of natural gas per day (the “Marlan Processing Plant”), three compressor stations and approximately
45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico.

Environmental, Social and Governance (“ESG”) Initiatives

We are committed to creating long-term value in a responsible manner. Our aim is to reliably and proﬁtably

provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the
industry’s best practices and the highest applicable regulatory and legal standards. More recently, we have begun
formally reporting on our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned
with standards developed by an industry leader, the Sustainability Accounting Standards Board (SASB).

FORM 10-K PART I

8

MATADOR RESOURCES COMPANY

Highlights from our ESG initiatives, which generally relate to our operations in 2021 except as otherwise

noted, include:

• Decreased direct greenhouse gas emissions intensity by 28% in 2021, as compared to 2020;

• Decreased methane emissions intensity by 48% in 2021, as compared to 2020;

• Decreased ﬂaring intensity by 53% in 2021, as compared to 2020;

•

•

Increased use of non-fresh water to 96% of total water consumption in 2021;

Increased number of wells utilizing recycled produced water to 72% of total wells completed in 2021;

• Transported 99% of operated produced water and 89% of operated produced oil by pipeline in 2022;

•

Incurred no employee lost time incidents during approximately 3.3 million employee man-hours from 2017
to 2022; and

• Provided approximately 16,000 hours of employee continuing education, equating to approximately 50 hours

per employee in 2022.

These sustainability metrics have been calculated using the best information available to us. The data utilized in
calculating such metrics is subject to certain reporting rules, regulatory reviews, deﬁnitions, calculation methodologies,
estimates, adjustments and other factors. We expect to complete the review of ﬁscal year 2022 data from our ESG
initiatives in the second half of 2023 in connection with the preparation of our 2022 Sustainability Report.

RECENT DEVELOPMENTS

On January 24, 2023, our wholly-owned subsidiary entered into a deﬁnitive agreement to acquire Advance Energy

Partners Holdings, LLC (“Advance”) from afﬁliates of EnCap Investments L.P., including certain oil and natural gas
producing properties and undeveloped acreage located primarily in Lea County, New Mexico and Ward County,
Texas (the “Advance Acquisition”). The consideration for the Advance Acquisition is expected to consist of $1.6 billion
in cash, subject to customary closing adjustments, including for working capital and for title and environmental
defects, plus additional cash consideration of $7.5 million for each month during 2023 in which the average price of
crude oil (as deﬁned in the securities purchase agreement) exceeds $85 per barrel. The consummation of the
Advance Acquisition is subject to customary closing conditions and is expected to close in the second quarter of
2023 with an effective date of January 1, 2023.

We estimate the total proved oil and natural gas reserves associated with these properties are approximately
106.4 million BOE (73% oil) at December 31, 2022. These reserves estimates were prepared by our engineering
staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Other highlights of the Advance Acquisition include:

• Estimated production in the ﬁrst quarter of 2023 of 24,500 to 25,500 BOE per day (74% oil);

• Approximately 18,500 net acres (99% held by production) in the core of the northern Delaware Basin, most

of which is strategically located in our Ranger asset area in Lea County, New Mexico near our existing
properties;

• 206 gross (174 net) operated locations (84% working interest) and 200 gross (29 net) non-operated

locations (15% working interest);

• 21 gross (20 net) drilled but uncompleted wells expected to be turned to sales in the second half of 2023;

• Acreage conducive to drilling longer laterals with an expected average lateral length for operated locations

of approximately 9,400 feet; and

• Upside related to potential midstream opportunities for Pronto, which operates in Lea County, New Mexico.

FORM 10-K PART I

2022 ANNUAL REPORT

9

EXPLORATION AND PRODUCTION SEGMENT

Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring

plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale
play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2022, we
devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the
Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our
inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing
basins with well-established production histories offering the potential for multiple-zone completions.

The following table presents certain summary data for each of our operating areas as of and for the year ended

December 31, 2022.

Southeast New Mexico/
West Texas:

Producing
Wells

Total Identiﬁed
Drilling Locations(1)

Gross
Acreage

Net
Acreage

Gross

Net

Gross

Net

Estimated Net
Proved Reserves(2)

Avg. Daily
Production
%
MBOE(3) Developed (BOE/d)(3)

Delaware Basin(4)

237,100

129,400

1,087

543.3

4,382

1,468

346,788

61.0

100,135

South Texas:

Eagle Ford(5)

Northwest Louisiana

Haynesville
Cotton Valley(6)
Area Total(7)
Total

15,400

13,100

91

72.3

124

98

3,861

100.0

1,373

16,200
15,800
18,500
271,000

8,900
14,900
17,300
159,800

246
65
311
1,489

19.1
39.8
58.9
674.5

161
154
315
4,821

14
35
49
1,615

5,126
947
6,073
356,722

99.0
100.0
99.2
62.1

3,789
168
3,957
105,465

(1)

Identiﬁed and engineered drilling locations. These locations have been identiﬁed for potential future drilling and were not producing at
December 31, 2022. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating
area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths,
from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current
acreage position. At December 31, 2022, approximately two-thirds of these identiﬁed drilling locations were expected to be horizontal laterals with
lateral lengths of approximately two miles or greater, and approximately 80% are expected to have lateral lengths of approximately 1.5 miles
or greater. At December 31, 2022, these engineered drilling locations included 390 gross (156 net) operated and non-operated locations to which
we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon and Avalon
formations, in the Delaware Basin and only seven gross (less than 0.1 net) locations to which we have assigned proved undeveloped reserves in
the Haynesville shale. At December 31, 2022, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale.

(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas
Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference.

(3) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated

using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the

Delaware Basin at December 31, 2022.

(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.

(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore,

the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we
are producing from or that we believe to be prospective for these formations.

FORM 10-K PART I

10

MATADOR RESOURCES COMPANY

We are active both as an operator and as a non-operating co-working interest owner with various industry

participants. At December 31, 2022, we operated a signiﬁcant majority of our acreage in the Delaware Basin in
Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are
often relatively small. At December 31, 2022, we also were the operator for approximately 87% of our Eagle Ford
acreage and approximately 51% of our Haynesville acreage.

While we do not always have direct access to our operating partners’ drilling plans with respect to future well
locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff
of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and
our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland,
Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with
our estimates of these drilling plans and our approach to booking these reserves.

Southeast New Mexico and West Texas — Delaware Basin

The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production
region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in
many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir
targets, but, in recent years, the combination of advanced formation evaluation, 3-D seismic technology, horizontal
drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in
the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate
reservoirs of the Bone Spring, Brushy Canyon and Avalon formations.

In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone
Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked
layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic
submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas
produced in the basin. Historically, production has come from conventional reservoirs; however, we and other
industry players have realized that the source rocks also have sufﬁcient porosity and permeability to be commercial
reservoirs. In addition, the source rocks are interbedded with reservoir layers that have ﬁlled with hydrocarbons,
both of which can produce signiﬁcant volumes of oil and natural gas when connected by horizontal wellbores with
multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a
given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring
and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identiﬁed and targeted by
companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring
(First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identiﬁed as
Wolfcamp A through D.

At December 31, 2022, our total acreage position in Southeast New Mexico and West Texas was approximately

237,100 gross (129,400 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas.
These acreage totals included approximately 40,700 gross (22,600 net) acres in our Ranger asset area in Lea
County, 59,500 gross (22,500 net) acres in our Arrowhead asset area in Eddy County, 45,500 gross (26,400 net)
acres in our Rustler Breaks asset area in Eddy County, 26,500 gross (17,900 net) acres in our Antelope Ridge asset
area in Lea County, 14,400 gross (10,800 net) acres in our Wolf and Jackson Trust asset areas in Loving County,
2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County and 47,000 gross (25,800 net) acres in our
Twin Lakes asset area in Lea County at December 31, 2022. We consider the vast majority of our Delaware Basin
acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations.
Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well
as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2022, our acreage
position in the Delaware Basin was approximately 77% held by existing production. Excluding the Twin Lakes asset

FORM 10-K PART I

2022 ANNUAL REPORT

11

area and the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease
Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding
provisions, our acreage position in the Delaware Basin was approximately 92% held by existing production at
December 31, 2022.

During the year ended December 31, 2022, we continued the delineation and development of our Delaware

Basin acreage. We completed and began producing oil and natural gas from 144 gross (69.8 net) wells in the
Delaware Basin, including 81 gross (64.5 net) operated horizontal wells and 63 gross (5.4 net) non-operated
horizontal wells, throughout our various asset areas. At December 31, 2022, we had tested a number of different
producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches
of the Avalon, two benches of the First Bone Spring, two benches of the Second Bone Spring, two benches of the
Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower
section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn.

As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production

increased signiﬁcantly in 2022. Our average daily oil equivalent production from the Delaware Basin increased
approximately 24% to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per
day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022,
as compared to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day
(97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021.

At December 31, 2022, approximately 97% of our estimated total proved oil and natural gas reserves, or
346.8 million BOE, was attributable to the Delaware Basin, including approximately 193.5 million Bbl of oil and
919.7 Bcf of natural gas, an 11% increase, as compared to 312.0 million BOE for the year ended December 31, 2021.
Our Delaware Basin proved reserves at December 31, 2022 comprised approximately 99% of our proved oil
reserves and 96% of our proved natural gas reserves, as compared to approximately 98% of our proved oil reserves
and 95% of our proved natural gas reserves at December 31, 2021.

At December 31, 2022, we had identiﬁed 4,382 gross (1,468 net) engineered locations for potential future drilling

on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower
Brushy Canyon and Avalon formations. These locations include 2,198 gross (1,296 net) locations that we anticipate
operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling
locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current
assumptions for a well that could be drilled at speciﬁed locations given our current acreage position. At December 31,
2022, approximately two-thirds of these identiﬁed drilling locations are expected to have horizontal lateral lengths of
approximately two miles or greater and approximately 80% are expected to have horizontal lateral lengths of
approximately 1.5 miles or greater. These engineered locations have been identiﬁed on a property-by-property basis
and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of
return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data,
drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion
costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria.
Our engineered well locations, at December 31, 2022, do not yet include all portions of our acreage position. Our
identiﬁed well locations presume that multiple intervals may be prospective at any one surface location. Although
we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31,
2022, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore
and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future
drilling. At December 31, 2022, these potential future drilling locations included 390 gross (156 net) operated and
non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy
Canyon and Avalon, to which we have assigned proved undeveloped reserves.

FORM 10-K PART I

12

MATADOR RESOURCES COMPANY

We began 2022 operating ﬁve drilling rigs in the Delaware Basin but contracted a sixth drilling rig during the
ﬁrst quarter of 2022 to begin development of certain acquired assets in the western portion of the Ranger asset area
in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated seven drilling rigs
throughout the remainder of 2022. We have built signiﬁcant optionality into our drilling program, which should
generally allow us to decrease or increase the number of rigs we operate as necessary based on changing
commodity prices and other factors.

Antelope Ridge Asset Area - Lea County, New Mexico

In the Antelope Ridge asset area, we turned to sales 26 gross (21.9 net) operated wells and 23 gross (0.6 net)

non-operated wells during 2022.

The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM

Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75%
NRI on most fee leases today. At the end of the ﬁrst quarter of 2022, we achieved one of our ﬁve operational
milestones we set for Matador in 2022 when we turned to sales nine gross (8.1 net) wells on the Rodney Robinson
leasehold. These wells were the third group of wells drilled on the Rodney Robinson leasehold. The nine Rodney
Robinson wells, which included one Third Bone Spring completion, two Second Bone Spring completions, three
First Bone Spring completions and three Avalon completions, have produced in aggregate approximately 3.1 million
BOE in approximately ten months of production.

In the third and fourth quarter of 2022, we achieved another one of our ﬁve operational milestones in 2022 when
we turned to sales 16 gross (12.9 net) operated wells in other portions of the Antelope Ridge asset area. In addition,
we turned to sales one gross (0.9 net) operated well in the ﬁrst quarter of 2022. In total, these 17 Antelope Ridge
wells, which included three Third Bone Spring, eight Second Bone Spring and six First Bone Spring completions
have produced in aggregate approximately 1.8 million BOE in an average of approximately four months of production.

In September 2022, we added a seventh drilling rig, which enabled us to accelerate the timing of the fourth group

of eight Rodney Robinson wells. These eight gross (7.7 net) wells are expected to be turned to sales late in the ﬁrst
quarter of 2023. We plan to turn to sales 12 gross (9.1 net) operated wells in the Antelope Ridge asset area in 2023.

Rustler Breaks Asset Area - Eddy County, New Mexico

In the Rustler Breaks asset area, we turned to sales 21 gross (13.5 net) operated wells and 22 gross (2.3 net)

non-operated wells during 2022.

In the second quarter of 2022, we achieved one of our ﬁve operational milestones in 2022 when we turned to

sales eleven gross (6.5 net) wells in the Rustler Breaks asset area. In addition, we turned to sales an additional
ten gross (7.0 net) operated wells at various times in the third and fourth quarters of 2022. In total, these 21 Rustler
Breaks wells, which included four Wolfcamp B, two Wolfcamp A, two Third Bone Spring, one Third Bone Spring
Carbonate, seven Second Bone Spring, four First Bone Spring and one Brushy Canyon completions, have produced
in aggregate approximately 3.8 million BOE in an average of approximately six months of production.

We plan to turn to sales 21 gross (13.2 net) operated wells in the Rustler Breaks asset area in 2023.

Arrowhead Asset Area - Eddy County, New Mexico

In the Arrowhead asset area, we turned to sales two gross (1.1 net) operated wells and eight gross (1.3 net)
non-operated wells during 2022. This included two Second Bone Spring completions that turned to sales late in the
fourth quarter of 2022.

We plan to turn to sales 18 gross (11.5 net) operated wells in the Arrowhead asset area in 2023.

FORM 10-K PART I

2022 ANNUAL REPORT

13

Ranger and Twin Lakes Asset Areas - Lea County, New Mexico

In the Ranger asset area, we turned to sales 14 gross (10.1 net) operated wells and ten gross (1.2 net) non-

operated wells during 2022. In the Twin Lakes area, we did not turn to sales or participate in any horizontal operated
or non-operated wells during 2022.

In February 2022, we contracted a sixth drilling rig to begin development on certain properties acquired in the
western portion of our Ranger asset area and late in the fourth quarter of 2022, we achieved another one of our ﬁve
operational milestones for 2022 when we turned to sales 12 gross (8.8 net) wells. This included two Wolfcamp A,
four Third Bone Spring, ﬁve Second Bone Spring and one First Bone Spring completions, which have in aggregate
produced 0.3 million BOE in approximately one month of production.

Early in the ﬁrst quarter of 2022, we also turned to sales the second batch of two Uncle Ches wells, which
targeted the Second Bone Spring Sand. We are very pleased with the results of these additional Uncle Ches wells,
which in aggregate, have produced over 0.7 million BOE in 11 months of production and are exhibiting high (90%)
oil cuts and low water cuts (approximately one Bbl of water per Bbl of oil produced).

We plan to turn to sales 21 gross (14.5 net) operated wells in the Ranger asset area in 2023, not including any

wells expected to be turned to sales on Advance’s properties.

Stateline Asset Area - Eddy County, New Mexico

In the Stateline asset area, we turned to sales 15 gross (15.0 net) operated wells during 2022. Early in the ﬁrst

quarter of 2022, we achieved another one of our ﬁve operational milestones in 2022 when we turned to sales
11 gross (11.0 net) wells on the Voni leasehold in the Stateline asset area. The 11 Voni wells, which included four
Wolfcamp B, ﬁve Third Bone Spring Carbonate and two First Bone Spring completions, have produced in
aggregate approximately 3.6 million BOE in approximately 11 months of production. These 11 Voni wells had
average completed lateral lengths of approximately 12,100 feet.

In the second quarter of 2022, we returned to Stateline to drill an additional batch of four Wolfcamp B wells on

the Boros leasehold on the eastern side of the Stateline asset area. These four Wolfcamp B completions were
turned to sales late in the third quarter of 2022 and have produced in aggregate approximately 0.5 million BOE in
approximately three months.

We plan to turn to sales eight gross (8.0 net) operated wells in the Stateline asset area in 2023.

Wolf and Jackson Trust Asset Areas - Loving County, Texas

In the Wolf and Jackson Trust asset areas, we turned to sales three gross (2.7 net) operated wells during
2022. This included three Second Bone Spring completions that have in aggregate produced 0.9 million BOE in
approximately 11 months.

We plan to turn to sales nine gross (8.3 net) operated wells in the Wolf asset area in 2023.

FORM 10-K PART I

14

MATADOR RESOURCES COMPANY

South Texas — Eagle Ford Shale and Other Formations

At December 31, 2022, our properties included approximately 15,400 gross (13,100 net) acres in the Eagle Ford
shale play in South Texas. We believe that approximately 89% of our Eagle Ford acreage is prospective predominantly
for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural
gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2022.

During the year ended December 31, 2022, we converted approximately $46.5 million of non-core assets to
cash, including the sales of approximately 12,000 gross (12,000 net) acres in the Eagle Ford shale for approximately
$46.5 million. We did not conduct any operated or non-operated drilling and completion activities on our leasehold
properties in South Texas during the year ended December 31, 2022. In fact, as of December 31, 2022, we had not
completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result of not
completing any new operated wells since 2019 and our asset sales during the year, our average daily oil equivalent
production from the Eagle Ford shale decreased 35% to 1,373 BOE per day, including 971 Bbl of oil per day and
2.4 MMcf of natural gas per day, during 2022, as compared to 2,126 BOE per day, including 1,528 Bbl of oil per day
and 3.6 MMcf of natural gas per day, during 2021. For the year ended December 31, 2022, 1% of our total daily
oil equivalent production was attributable to the Eagle Ford shale, as compared to 2% for the year ended
December 31, 2021.

At December 31, 2022, approximately 1% of our estimated total proved oil and natural gas reserves, or 3.9 million

BOE, was attributable to the Eagle Ford shale, including approximately 2.8 million Bbl of oil and 6.5 Bcf of natural
gas. Our Eagle Ford total proved reserves comprised approximately 1% of our proved oil reserves and 1% of our
proved natural gas reserves at December 31, 2022, essentially unchanged from December 31, 2021.

Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations

We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest

Louisiana during 2022, although we did participate in the drilling and completion of 11 gross (1.0 net) non-operated
Haynesville shale wells that were turned to sales in 2022. We do not plan to drill any operated Haynesville shale or
Cotton Valley wells in 2023.

At December 31, 2022, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including
16,200 gross (8,900 net) acres in the Haynesville shale play and 15,800 gross (14,900 net) acres in the Cotton Valley
play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in
Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be
the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,700 net) acres that
we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton
Valley plays in Northwest Louisiana was held by existing production at December 31, 2022.

For the year ended December 31, 2022, approximately 4% of our average daily oil equivalent production, or
3,957 BOE per day, including nine Bbl of oil per day and 23.7 MMcf of natural gas per day, was attributable to our
leasehold interests in Northwest Louisiana, while for the year ended December 31, 2021, approximately 4% of
our average daily oil equivalent production, or 3,516 BOE per day, including nine Bbl of oil per day and 21.0 MMcf of
natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31,
2022, approximately 9% of our daily natural gas production, or 23.7 MMcf of natural gas per day, was attributable to
our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2021, approximately 9% of
our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to these properties. At
December 31, 2022, approximately 2% of our estimated total proved reserves, or 6.1 million BOE, was attributable
to our properties in Northwest Louisiana.

FORM 10-K PART I

2022 ANNUAL REPORT

15

Midstream Segment

Our midstream segment conducts midstream operations in support of our exploration, development and

production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced
water gathering services and produced water disposal services to third parties.

Southeast New Mexico and West Texas — Delaware Basin

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The

midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas
processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one
salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area;
(iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and
(iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the
Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million
in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance
incentives over a ﬁve-year period, which in October 2020 was extended by an additional year. At February 21, 2023,
we had earned all of the potential $73.5 million in performance incentives. Through February 21, 2023, Five Point
had paid $14.7 million in performance incentives in each of the ﬁrst quarters of 2018, 2019, 2020 and 2021, and
the remaining $14.7 million in performance incentives is expected to be paid during the ﬁrst quarter of 2023. In
connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold
interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, ﬁxed fee oil, natural gas and produced
water gathering and produced water disposal agreements. In addition, we dedicated current and certain future
leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, ﬁxed fee natural gas
processing agreement.

On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic

joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, speciﬁcally in
Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the ﬁrst $150.0 million of
capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline
asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital
expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest
in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives through
mid-2024, plus additional performance incentives for securing volumes from third-party customers. At February 21,
2023, we had received $62.2 million of the potential $150.0 million in performance incentives. In connection with
the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline
asset area pursuant to 15-year, ﬁxed-fee oil transportation, oil, natural gas and produced water gathering, natural
gas processing and produced water disposal agreements.

Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own
51% and 49% of San Mateo, respectively. San Mateo provides ﬁrm service to us, while also being a midstream
service provider to other customers in and around our Stateline, Wolf and Rustler Breaks asset areas and the
Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream
Assets, the expanded Black River Processing Plant and facilities that have been developed in the Greater Stebbins
Area and the Stateline asset area.

On June 30, 2022, we acquired the Marlan Processing Plant, three compressor stations and approximately

45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition.

FORM 10-K PART I

16

MATADOR RESOURCES COMPANY

Natural Gas Gathering and Processing Assets

The Black River Processing Plant and associated gathering system were originally built to support our ongoing

and future development efforts in the Rustler Breaks asset area and to provide us with ﬁrm takeaway and
processing services for our Rustler Breaks natural gas production. We had previously completed the installation and
testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our
Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our
operated natural gas production at Rustler Breaks.

In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River
Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing
designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf
of natural gas per day. The expanded Black River Processing Plant supports our exploration and development
activities in the Delaware Basin and, at December 31, 2022, was gathering and processing natural gas from the
Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural
gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers
in the area.

At December 31, 2022, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines

between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater
Stebbins Area (approximately 19 miles). At December 31, 2022, San Mateo was gathering or transporting all our
operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler
Breaks asset area and the Wolf asset area.

In addition, at December 31, 2022, San Mateo had an NGL pipeline connection at the Black River Processing

Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several signiﬁcant
beneﬁts to us and other San Mateo customers compared to transporting NGLs by truck. San Mateo’s customers
receive (i) ﬁrm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing
realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s
ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative
to pipe rather than to truck NGLs during severe weather events and otherwise.

In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural
gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas
gathering and processing assets in the Wolf asset area, including a cryogenic natural gas processing plant and
approximately six miles of high-pressure gathering pipelines.

At December 31, 2022, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and

related compression and treating systems. During the year ended December 31, 2022, San Mateo gathered an
average of approximately 287 MMcf of natural gas per day, an increase of 22% as compared to 236 MMcf of natural
gas per day gathered during the year ended December 31, 2021. In addition, during the year ended December 31,
2022, San Mateo processed approximately 289 MMcf of natural gas at the Black River Processing Plant, an increase
of 36%, as compared to 213 MMcf of natural gas per day processed during the year ended December 31, 2021.
Natural gas gathering and processing volumes for the years ended December 31, 2022 and 2021 do not include the
full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to
minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo
recognized revenues.

At December 31, 2022, Pronto owned (i) the Marlan Processing Plant, (ii) three compressor stations and

(iii) approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico.

FORM 10-K PART I

2022 ANNUAL REPORT

17

Crude Oil Gathering and Transportation Assets

San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream

producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and
related transactions to offer producers located within a joint development area crude oil transportation services from
the wellhead to Midland, Texas with access to other end markets.

At December 31, 2022, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins

Area that was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 miles
of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil
gathering and transportation systems (collectively with the crude oil gathering and transportation system in the
Rustler Breaks asset area and the crude oil gathering system in the Wolf asset area, the “San Mateo Oil Pipeline
Systems”) in service, at December 31, 2022, we estimated we had on pipe almost all of our oil production from
the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area.

At December 31, 2022, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation
pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains
and two trucking facilities. During the year ended December 31, 2022, the San Mateo Oil Pipeline Systems had
throughput of approximately 48,300 Bbl of oil per day, an increase of 18%, as compared to throughput of approximately
40,800 Bbl of oil per day during the year ended December 31, 2021.

Produced Water Gathering and Disposal Assets

During 2022, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins

Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to four. In
addition to its four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at
February 21, 2023, San Mateo had eight commercial salt water disposal wells and associated facilities in the Rustler
Breaks asset area, three commercial salt water disposal wells and associated facilities in the Wolf asset area and
produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins
Area. At February 21, 2023, San Mateo had designed disposal capacity of approximately 445,000 Bbl of produced
water per day.

During the year ended December 31, 2022, San Mateo handled approximately 361,000 Bbl of produced water
per day, an increase of 30%, as compared to approximately 278,000 Bbl of produced water per day handled during
the year ended December 31, 2021.

South Texas / Northwest Louisiana

In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our
operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most
of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo
or Pronto.

FORM 10-K PART I

18

MATADOR RESOURCES COMPANY

OPERATING SUMMARY

The following table sets forth certain unaudited production and operating data for the years ended December 31,

2022, 2021 and 2020.

Unaudited Production Data:
Net Production Volumes:

Oil (MBbl)
Natural gas (Bcf)

Total oil equivalent (MBOE)(1)
Average daily production (BOE/d)(1)

Average Sales Prices:

Oil, without realized derivatives (per Bbl)
Oil, with realized derivatives (per Bbl)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)

Operating Expenses (per BOE):

Production taxes, transportation and processing
Lease operating
Plant and other midstream services operating
Depletion, depreciation and amortization
General and administrative

Year Ended December 31,

2022

2021

2020

21,943
99.3
38,495
105,465

$ 96.32
$ 92.87
7.98
$
7.15
$

7.33
$
4.08
$
$
2.48
$ 12.11
3.02
$

17,840
81.7
31,454
86,176

$ 67.58
$ 56.70
$ 6.06
$ 5.74

$ 5.69
$ 3.46
$ 1.95
$ 10.97
$ 3.06

15,931
69.5
27,514
75,175

$ 37.38
$ 39.83
$ 2.14
$ 2.14

$ 3.39
$ 3.81
$ 1.51
$ 13.15
$ 2.27

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

The following table sets forth information regarding our production volumes, sales prices and production costs

for the year ended December 31, 2022 from our operating areas, which we consider to be distinct ﬁelds for
purposes of accounting for production.

Southeast
New Mexico/
West Texas

South Texas

Northwest Louisiana

Delaware Basin Eagle Ford(1)

Haynesville Cotton Valley(2)

Total

Annual Net Production Volumes
Oil (MBbl)
Natural gas (Bcf)
Total oil equivalent (MBOE)(3)
Percentage of total annual net production
Average Net Daily Production Volumes
Oil (Bbl/d)
Natural gas (MMcf/d)
Total oil equivalent (BOE/d)
Average Sales Prices(4)
Oil (per Bbl)
Natural gas (per Mcf)
Total oil equivalent (per BOE)
Production Costs(5)
Lease operating, transportation and processing (per BOE)

21,585
89.8
36,550

94.9%

355
0.9
501
1.3%

—
8.3
1,383

3.6%

59,139
246.0
100,135

$ 96.34
$
8.18
$ 76.98

971
2.4
1,373

$ 95.23
$ 9.04
$ 83.24

—
22.7
3,789

$ —
$ 5.81
$34.87

3
0.3
61
0.2%

9
1.0
168

$91.53
$ 5.71
$37.23

21,943
99.3
38,495

100.0%

60,119
272.1
105,465

$ 96.32
$
7.98
$ 75.48

$

5.10

$ 27.41

$ 5.37

$22.69

$

5.43

(1)

Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.

(2)

Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio

of one Bbl of oil per six Mcf of natural gas.

(4) Excludes impact of derivative settlements.

(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

FORM 10-K PART I

2022 ANNUAL REPORT

19

The following table sets forth information regarding our production volumes, sales prices and production costs

for the year ended December 31, 2021 from our operating areas, which we consider to be distinct ﬁelds for
purposes of accounting for production.

Southeast
New Mexico/
West Texas

South Texas

Northwest Louisiana

Delaware Basin Eagle Ford(1)

Haynesville Cotton Valley(2)

Total

Annual Net Production Volumes
Oil (MBbl)
Natural gas (Bcf)
Total oil equivalent (MBOE)(3)
Percentage of total annual net production
Average Net Daily Production Volumes
Oil (Bbl/d)
Natural gas (MMcf/d)
Total oil equivalent (BOE/d)
Average Sales Prices(4)
Oil (per Bbl)
Natural gas (per Mcf)
Total oil equivalent (per BOE)
Production Costs(5)
Lease operating, transportation and processing (per BOE)

17,279
72.7
29,395

93.4%

558
1.3
776
2.5%

—
7.3
1,217

3.9%

47,339
199.2
80,534

$ 67.65
$
6.33
$ 55.43

1,528
3.6
2,126

$ 65.41
$ 7.39
$ 59.49

—
20.0
3,334

$ —
$ 3.19
$19.16

3
0.4
66
0.2%

9
1.0
182

$64.40
$ 4.31
$27.81

17,840
81.7
31,454

100.0%

48,876
223.8
86,176

$ 67.58
$
6.06
$ 54.06

$

4.49

$ 19.51

$ 4.84

$25.69

$

4.92

(1)

Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas
from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.

(2)

Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion

ratio of one Bbl of oil per six Mcf of natural gas.

(4) Excludes impact of derivative settlements.

(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

FORM 10-K PART I

20

MATADOR RESOURCES COMPANY

The following table sets forth information regarding our production volumes, sales prices and production costs
for the year ended December 31, 2020 from our operating areas, which we consider to be distinct ﬁelds for purposes
of accounting for production.

Southeast
New Mexico/
West Texas

South Texas

Northwest Louisiana

Delaware Basin Eagle Ford(1)

Haynesville Cotton Valley(2)

Total

Annual Net Production Volumes
Oil (MBbl)
Natural gas (Bcf)
Total oil equivalent (MBOE)(3)
Percentage of total annual net production
Average Net Daily Production Volumes
Oil (Bbl/d)
Natural gas (MMcf/d)
Total oil equivalent (BOE/d)
Average Sales Prices(4)
Oil (per Bbl)
Natural gas (per Mcf)
Total oil equivalent (per BOE)
Production Costs(5)
Lease operating, transportation and processing (per BOE)

15,254
56.8
24,713

89.8%

674
1.2
883
3.2%

—
11.0
1,835

6.7%

41,678
155.1
67,522

$ 37.38
$
2.23
$ 28.19

1,840
3.4
2,412

$ 37.42
$ 2.82
$ 32.56

—
30.1
5,015

$28.77
$ 1.66
$ 9.94

3
0.5
83
0.3%

8
1.3
226

$38.31
$ 1.69
$11.09

15,931
69.5
27,514

100.0%

43,526
189.9
75,175

$ 37.38
$
2.14
$ 27.06

$

4.52

$ 20.52

$ 4.71

$19.39

$

5.09

(1)

Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas
from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.

(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion

ratio of one Bbl of oil per six Mcf of natural gas.

(4) Excludes impact of derivative settlements.

(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

Our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022

increased 22% from our total oil equivalent production of approximately 31.5 million BOE for the year ended
December 31, 2021. This increased production was primarily due to our delineation and development operations in
the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Our average daily
oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, as compared to
86,176 BOE per day for the year ended December 31, 2021. Our average daily oil production for the year ended
December 31, 2022 was 60,119 Bbl of oil per day, an increase of 23% from 48,876 Bbl of oil per day for the year
ended December 31, 2021. Our average daily natural gas production for the year ended December 31, 2022 was
272.1 MMcf of natural gas per day, an increase of 22% from 223.8 MMcf of natural gas per day for the year ended
December 31, 2021.

Our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021

increased 14% from our total oil equivalent production of approximately 27.5 million BOE for the year ended
December 31, 2020. This increased production was primarily due to our delineation and development operations in
the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales.
Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, as
compared to 75,175 BOE per day for the year ended December 31, 2020. Our average daily oil production for the
year ended December 31, 2021 was 48,876 Bbl of oil per day, an increase of 12% from 43,526 Bbl of oil per day for
the year ended December 31, 2020. Our average daily natural gas production for the year ended December 31,
2021 was 223.8 MMcf of natural gas per day, an increase of 18% from 189.9 MMcf of natural gas per day for the
year ended December 31, 2020.

FORM 10-K PART I

2022 ANNUAL REPORT

21

PRODUCING WELLS

The following table sets forth information relating to producing wells at December 31, 2022. Wells are classiﬁed
as oil wells or natural gas wells according to their predominant production stream. We had an approximate average
working interest of 81% in all wells that we operated at December 31, 2022. For wells where we are not the
operator, our working interests range from less than 1% to approximately 52% and average approximately 10%.
In the table below, gross wells are the total number of producing wells in which we own a working interest, and net
wells represent the total of our fractional working interests owned in the gross wells.

Southeast New Mexico/West Texas:

Delaware Basin(1)

South Texas:

Eagle Ford(2)

Northwest Louisiana:

Haynesville
Cotton Valley(3)
Area Total
Total

Oil Wells

Natural Gas Wells

Total Wells

Gross

Net

Gross

Net

Gross

Net

929

461.8

158

81.5

1,087

543.3

91

72.3

—
1
1
1,021

—
1.0
1.0
535.1

—

246
64
310
468

—

91

72.3

19.1
38.8
57.9
139.4

246
65
311
1,489

19.1
39.8
58.9
674.5

(1)

Includes 239 gross (87.5 net) vertical wells that were primarily acquired in multiple transactions.

(2) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.

(3) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

ESTIMATED PROVED RESERVES

The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2022, 2021 and

2020. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and
liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford
shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural
gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on
evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell &
Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with
SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and
do not include any unproved reserves classiﬁed as probable or possible reserves that might exist for our properties,
nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage
beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the
estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

FORM 10-K PART I

22

MATADOR RESOURCES COMPANY

Estimated Proved Reserves Data:(2)
Estimated proved reserves:

Oil (MBbl)
Natural Gas (Bcf)
Total (MBOE)(3)

Estimated proved developed reserves:

Oil (MBbl)
Natural Gas (Bcf)
Total (MBOE)(3)

Percent developed

Estimated proved undeveloped reserves:

Oil (MBbl)
Natural gas (Bcf)
Total (MBOE)(3)

Standardized Measure(4) (in millions)
PV-10(5) (in millions)

(1) Numbers in table may not total due to rounding.

At December 31,(1)

2022

2021

2020

196,289
962.6
356,722

116,030
632.9
221,507

181,306
852.5
323,397

102,233
546.2
193,262

159,949
662.3
270,332

69,647
323.2
123,507

62.1%

59.8%

45.7%

80,259
329.7
135,215

79,073
306.4
130,135

90,301
339.1
146,825

$ 6,983.2
$ 9,132.2

$ 4,375.4
$ 5,347.6

$ 1,584.4
$ 1,658.0

(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving
effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the
ﬁrst-day-of-the-month prices for the 12 months ended December 31, 2022 were $90.15 per Bbl for oil and $6.36 per MMBtu for natural gas, for
the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas and for the 12 months ended
December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas. These prices were adjusted by property for quality, energy
content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead.
We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included
in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold.

(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4) Standardized Measure represents the present value of estimated future net cash ﬂows from proved reserves, less estimated future development,
production, plugging and abandonment and income tax expenses, discounted at 10% per annum to reﬂect the timing of future cash ﬂows.
Standardized Measure is not an estimate of the fair market value of our properties.

(5) PV-10 is a non-GAAP ﬁnancial measure and generally differs from Standardized Measure, the most directly comparable GAAP ﬁnancial measure,

because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our
properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
and of the potential return on investment related to the companies’ properties without regard to the speciﬁc tax characteristics of such entities.
Our PV-10 at December 31, 2022, 2021 and 2020 may be reconciled to our Standardized Measure of discounted future net cash ﬂows at such
dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income
taxes at December 31, 2022, 2021 and 2020 were $2.15 billion, $972.2 million and $73.6 million, respectively.

Our estimated total proved oil and natural gas reserves increased 10% from 323.4 million BOE at December 31,
2021 to 356.7 million BOE at December 31, 2022. This increase in proved oil and natural gas reserves was primarily
attributable to (i) our delineation and development operations in the Delaware Basin during 2022 and (ii) the 43%
increase in oil prices and the 77% increase in natural gas prices used to estimate total proved reserves at
December 31, 2022, as compared to December 31, 2021. We added 71.1 million BOE in proved oil and natural gas
reserves through extensions and discoveries during 2022, of which 24.7 million BOE resulted from new well
locations turned to sales during 2022 to establish proved developed reserves and 53.8 million BOE resulted primarily
from new proved undeveloped locations identiﬁed as a result of drilling activities on our existing acreage in the
Delaware Basin during 2022, but which were partially offset by the removal of 7.4 million BOE in proved undeveloped
reserves that were not developed or were no longer expected to be developed within ﬁve years of their initial
booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin.
As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 7.4 million BOE to
proved reserves at a future date.

FORM 10-K PART I

2022 ANNUAL REPORT

23

Our proved oil reserves grew 8% from approximately 181.3 million Bbl at December 31, 2021 to approximately

196.3 million Bbl at December 31, 2022. Our proved natural gas reserves increased 13% from 852.5 Bcf at
December 31, 2021 to 962.6 Bcf at December 31, 2022. Our proved reserves to production ratio at December 31,
2022 was 9.3, a decrease of 10% from 10.3 at December 31, 2021.

The Standardized Measure of our total proved oil and natural gas reserves increased 60% from $4.38 billion at

December 31, 2021 to $6.98 billion at December 31, 2022. The PV-10 of our total proved oil and natural gas
reserves increased 71% from $5.35 billion at December 31, 2021 to $9.13 billion at December 31, 2022. The
increases in our Standardized Measure and PV-10 are primarily a result of the signiﬁcantly higher unweighted
arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2022, as compared
to December 31, 2021, but also due to the 10% increase in our total proved oil and natural gas reserves at
December 31, 2022, as compared to December 31, 2021. The unweighted arithmetic averages of ﬁrst-day-of-the-
month oil and natural gas prices used to estimate proved reserves at December 31, 2022 were $90.15 per Bbl and
$6.36 per MMBtu, an increase of 43% and 77%, respectively, as compared to average oil and natural gas prices
of $63.04 per Bbl and $3.60 per MMBtu used to estimate proved reserves at December 31, 2021. Our total proved
reserves were made up of 55% oil and 45% natural gas at December 31, 2022 and 56% oil and 44% natural gas
at December 31, 2021. PV-10 is a non-GAAP ﬁnancial measure. For a reconciliation of PV-10 to Standardized Measure,
see the preceding table.

The following table summarizes changes in our estimated proved developed reserves at December 31, 2022.

As of December 31, 2021

Extensions and discoveries
Net acquisitions of minerals-in-place
Revisions of prior estimates
Production
Conversion of proved undeveloped to proved developed

As of December 31, 2022

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Proved
Developed
Reserves

(MBOE)(1)

193,262
24,717
753
2,867
(38,495)
38,403
221,507

Our proved developed oil and natural gas reserves increased 15% from 193.3 million BOE at December 31, 2021

to 221.5 million BOE at December 31, 2022. We added 24.7 million BOE in proved developed reserves through
extensions and discoveries during 2022, which resulted from new well locations drilled during 2022 to establish
proved reserves. We realized approximately 2.9 million BOE in net upward revisions to prior estimates, most of which
was attributable to the signiﬁcantly higher commodity prices used to estimate proved reserves at December 31,
2022, which resulted in longer estimated economic lives for certain of our producing properties. In addition, we
converted 38.4 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our
development activities in the Delaware Basin during 2022, primarily in our Ranger, Stateline, Antelope Ridge and
Rustler Breaks asset areas. In addition, we realized 0.8 million BOE in net upward revisions to our proved developed
reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. These
cumulative net upward revisions of 66.7 million BOE to our proved developed reserves exceeded by 1.7 times our
total oil and natural gas production of 38.5 million BOE in 2022.

FORM 10-K PART I

24

MATADOR RESOURCES COMPANY

Our proved developed oil reserves increased 13% from 102.2 million Bbl at December 31, 2021 to 116.0 million

Bbl at December 31, 2022. Our proved developed natural gas reserves increased 16% from 546.2 Bcf at
December 31, 2021 to 632.9 Bcf at December 31, 2022. Proved developed reserves constituted 62% of our total
proved oil and natural gas reserves at December 31, 2022, as compared to 60% at December 31, 2021.

The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2022.

As of December 31, 2021

Extensions and discoveries
Net acquisitions of minerals-in-place
Revisions of prior estimates
Conversion of proved undeveloped to proved developed

As of December 31, 2022

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Proved
Undeveloped
Reserves

(MBOE)(1)

130,135
46,388
264
(3,169)
(38,403)
135,215

Our proved undeveloped oil and natural gas reserves increased 4% from 130.1 million BOE at December 31,
2021 to 135.2 million at December 31, 2022. We added 53.8 million BOE in proved undeveloped reserves through
extensions and discoveries during 2022, which resulted primarily from new proved undeveloped locations identiﬁed
as a result of drilling activities on our existing acreage in the Delaware Basin during 2022 but which were partially
offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed or were no longer
expected to be developed within ﬁve years of their initial booking resulting from changes in development plans for
certain of the properties in the Delaware Basin. We realized approximately 3.2 million BOE in net downward
revisions to our prior estimates of proved undeveloped reserves, most of which was attributable to forecast updates
at December 31, 2022. In addition, we realized 0.3 million BOE in net upward revisions to our proved undeveloped
reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. During
2022, we also converted 38.4 million BOE of our proved undeveloped reserves to proved developed reserves
primarily through our development activities in the Delaware Basin during 2022.

At December 31, 2022, we had no proved undeveloped reserves in our estimates that remained undeveloped for

ﬁve years or more following their initial booking, and we currently have plans to use anticipated capital resources
to develop the proved undeveloped reserves remaining as of December 31, 2022 within ﬁve years of booking these
reserves. The following table sets forth, since 2019, proved undeveloped reserves converted to proved developed
reserves during each year and the investments associated with these conversions (dollars in thousands).

2019
2020
2021
2022

Total

Proved Undeveloped Reserves
Converted to
Proved Developed Reserves

Oil

(MBbl)

13,832
16,256
23,965
22,515
76,568

Natural Gas

Total

(Bcf)

(MBOE)(1)

58.8
76.1
96.6
95.3
326.8

23,629
28,944
40,071
38,403
131,047

Investment in Conversion
of Proved Undeveloped
Reserves to Proved
Developed Reserves

$ 318,609
257,590
240,664
434,336
$1,251,199

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

FORM 10-K PART I

2022 ANNUAL REPORT

25

The following table sets forth additional summary information by operating area with respect to our estimated

net proved reserves at December 31, 2022.

Southeast New Mexico/West Texas:

Delaware Basin

South Texas:

Eagle Ford(5)

Northwest Louisiana

Haynesville
Cotton Valley(6)
Area Total
Total

Net Proved Reserves (1)

Oil

(MBbl)

Natural Gas

Oil
Equivalent

Standardized
Measure(2)

PV-10 (3)

(Bcf)

(MBOE)(4)

(in millions)

(in millions)

193,500

919.7

346,788

$6,852.8

$8,961.8

2,780

6.5

3,861

68.4

89.8

—
10
10
196,290

30.8
5.6
36.4
962.6

5,126
947
6,073
356,722

56.5
5.2
61.7
$6,982.9

73.9
6.8
80.7
$9,132.3

(1) Numbers in table may not total due to rounding.

(2) Standardized Measure represents the present value of estimated future net cash ﬂows from proved reserves, less estimated future development,
production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reﬂect the timing of future cash ﬂows.
Standardized Measure is not an estimate of the fair market value of our properties.

(3) PV-10 is a non-GAAP ﬁnancial measure and generally differs from Standardized Measure, the most directly comparable GAAP ﬁnancial measure,

because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our
properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
and of the potential return on investment related to the companies’ properties without regard to the speciﬁc tax characteristics of such entities.
Our PV-10 at December 31, 2022 may be reconciled to our Standardized Measure of discounted future net cash ﬂows at such date by adding the
discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31,
2022 were approximately $2.15 billion.

(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(5) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.

(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

Technology Used to Establish Reserves

Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience

and engineering data, can be estimated with reasonable certainty to be economically producible from a given date
forward, from known reservoirs and under existing economic conditions, operating methods and government
regulations. The term “reasonable certainty” implies a high degree of conﬁdence that the quantities of oil and/or
natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using
techniques that have been proven effective by actual production from projects in the same reservoir or an analogous
reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is
a grouping of one or more technologies (including computational methods) that have been ﬁeld tested and have
been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being
evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies
that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data
used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core
analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for
proved developed producing wells were estimated using production performance methods. Certain new producing
properties with little production history were forecasted using a combination of production performance and analogy
to offset production. Non-producing reserves estimates for both developed and undeveloped properties were
forecasted using either analogy and/or volumetric methods.

FORM 10-K PART I

26

MATADOR RESOURCES COMPANY

Internal Control Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity,

accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible
for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams
are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the
assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible
for overseeing the preparation of our reserves estimates in 2022. He received Bachelor of Science degrees in
both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional
Engineer in the state of Texas and has over ten years of industry experience. Our Vice President of Reservoir
Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir
Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering
from Texas A&M University and has over 15 years of industry experience. The Company has established internal
controls over its reserves estimation processes and procedures to support the accurate and timely preparation
and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include
oversight of the reserves estimation processes by our internal reserves group as well as accounting and ﬁnance
personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness
by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee
and members of the Operations and Engineering Committee of our Board of Directors review the reserves report
and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of
our Board of Directors as well.

ACREAGE SUMMARY

The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at

December 31, 2022.

Southeast New Mexico/West Texas:

Delaware Basin

South Texas:
Eagle Ford

Northwest Louisiana:

Haynesville
Cotton Valley
Area Total(1)
Total

Developed Acres

Undeveloped Acres

Total Acres

Gross

Net

Gross

Net

Gross

Net

191,300

99,200

45,800

30,200

237,100

129,400

15,400

13,100

—

—

15,400

13,100

16,200
15,800
18,500
225,200

8,900
14,900
17,300
129,600

—
—
—
45,800

—
—
—
30,200

16,200
15,800
18,500
271,000

8,900
14,900
17,300
159,800

(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation.
Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana.

FORM 10-K PART I

2022 ANNUAL REPORT

27

UNDEVELOPED ACREAGE EXPIRATION

The following table sets forth the approximate number of gross and net undeveloped acres at December 31,
2022 that will expire over the next ﬁve years by operating area unless production is established within the spacing
units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or
continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped
acreage expiring in 2028 and beyond totals 7,100 net acres, all of which is in the Delaware Basin. All of our leasehold
in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was
held by existing production at December 31, 2022.

Acres Expiring 2023

Acres Expiring 2024

Acres Expiring 2025

Acres Expiring 2026

Acres Expiring 2027

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Southeast New Mexico/
West Texas:

Delaware Basin(1)

Total

7,000
7,000

4,300
4,300

5,300
5,300

1,800
1,800

8,600
8,600

3,700
3,700

5,900
5,900

2,000
2,000

11,600
11,600

11,300
11,300

(1) Approximately 75% of the acreage expiring in the Delaware Basin in the next ﬁve years is associated with our Twin Lakes asset area in northern
Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling
activities or by paying an additional lease bonus, where applicable.

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective

primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration
of the primary term or production from the acreage has been established prior to such date, in which event the
lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have
options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary
term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage;
however, there may be third-party leases, or top leases, that become effective immediately if our leases expire
at the end of their respective terms and production has not been established prior to such date or operations are not
conducted to maintain the leases in effect beyond the primary term. As of December 31, 2022, our leases are
primarily fee and state leases with primary terms of three to ﬁve years and federal leases with primary terms of
10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary
term and royalty interests. At December 31, 2022, approximately 1% of our proved oil and natural gas reserves
would be impacted by the expirations of this undeveloped acreage.

FORM 10-K PART I

28

MATADOR RESOURCES COMPANY

DRILLING RESULTS

The following table summarizes our drilling activity for the years ended December 31, 2022, 2021 and 2020.

Development Wells

Productive
Dry

Exploration Wells
Productive(1)
Dry

Total Wells

Productive
Dry

Year Ended December 31,

2022

2021

2020

Gross

Net

Gross

Net

Gross

Net

138
—

20
—

158
—

61.4
—

11.0
—

72.4
—

96
—

8
—

104
—

40.2
—

8.0
—

48.2
—

89
—

4
—

93
—

44.5
—

3.3
—

47.8
—

(1)

Includes 17 gross (9.4 net) horizontal and three gross (1.6 net) vertical wells.

At December 31, 2022, we had a total of 25 gross (19.4 net) development wells and nine gross (7.8 net)
exploration wells that were in the process of being drilled, being completed or awaiting completion operations.

MARKETING AND CUSTOMERS

Our crude oil is sold under both long-term and short-term oil purchase agreements with unafﬁliated purchasers

based on published price bulletins reﬂecting an established ﬁeld posting price. As a consequence, the prices we
receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it
reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently
of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil
and liquids are also deducted from the price received for crude oil and liquids.

Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas

produced by us is sold at various delivery points to both unafﬁliated independent marketing companies and unafﬁliated
midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an
opportunity to do so, we may have our natural gas processed at San Mateo’s, Pronto’s or third parties’ processing
facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids, or NGLs,
based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids or other
negotiated pricing arrangements using then-current market pricing less ﬁxed rate processing, transportation and
fractionation fees.

The prices we receive for our oil, natural gas and NGL production ﬂuctuate widely. Factors that, directly or
indirectly, cause price ﬂuctuations include, but are not limited to: the domestic and foreign supply of, and demand
for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain
other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’
supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates;
domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts;
the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and
NGLs and gathering and disposal systems for produced water; the availability of reﬁning capacity; the prices and
availability of alternative fuel sources; weather conditions and natural disasters, including hurricanes in the Gulf
Coast region and severe cold weather in the Delaware Basin; political conditions in or affecting oil and natural gas
producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and

FORM 10-K PART I

2022 ANNUAL REPORT

29

China; the ongoing military conﬂict between Russia and Ukraine; domestic or global health concerns, including the
outbreak of contagious or pandemic diseases such as COVID-19; the continued threat of terrorism and the impact of
military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and
local governments to stop, signiﬁcantly limit or regulate oil and natural gas operations, including hydraulic fracturing
activities; the level of global oil and natural gas inventories and exploration and production activity; the impact of
energy conservation efforts; technological advances affecting energy consumption; and overall worldwide economic
conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and
our revenues, proﬁtability and cash ﬂows. Short-term disruptions of our oil and natural gas production occur from
time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as
maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production
capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial
Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices
and the continued volatility in these prices may adversely affect our ﬁnancial condition and our ability to meet our
capital expenditure requirements and ﬁnancial obligations.”

The prices we receive for our oil and natural gas production often reﬂect a discount to the relevant benchmark
prices, such as the NYMEX WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the
benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark
price for oil and natural gas and the wellhead price we receive could adversely affect our business, ﬁnancial
condition, results of operations and cash ﬂows. See “Risk Factors—Risks Related to our Financial Condition—An
increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead
price we receive for our production could adversely affect our business, ﬁnancial condition, results of operations and
cash ﬂows.”

For the years ended December 31, 2022, 2021 and 2020, we had three, three and two signiﬁcant purchasers,
respectively, that accounted for approximately 70%, 72% and 65%, respectively, of our total oil, natural gas and
NGL revenues. If we lost one or more of these signiﬁcant purchasers and were unable to sell our production to
other purchasers on terms we consider acceptable, it could materially and adversely affect our business, ﬁnancial
condition, results of operations and cash ﬂows. For further details regarding these purchasers, see Note 2 to
the consolidated ﬁnancial statements in this Annual Report. Such information is incorporated herein by reference.

TITLE TO PROPERTIES

We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil
and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in
ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior
to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells
or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our
title to these contractual interests may be contingent upon our satisfactory fulﬁllment of such obligations. Some
of our properties are also subject to customary royalty interests, liens incident to ﬁnancing arrangements, operating
agreements, taxes and other similar burdens that we believe will not materially interfere with the use and
operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease
rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of
various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial
Condition—We may incur losses or costs as a result of title deﬁciencies in the properties in which we invest.”

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We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject

to customary encumbrances, such as customary interests generally retained in connection with the acquisition of
real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other
burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe
that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use
and operation of these properties in the conduct of our business. In addition, we believe that we have obtained
sufﬁcient right-of-way grants and permits from public authorities and private parties for us to operate our business.
As discussed below in “—Regulation,” the Biden administration has issued certain orders and implemented
certain policies limiting or delaying the issuance of federal drilling permits and other necessary federal approvals.
Although some of these restrictions have lapsed, the impact of these and similar federal actions related to the oil
and natural gas industry remains unclear, and should those or other limitations or prohibitions be imposed or continue
to be applied, our oil and natural gas operations on federal lands could be adversely impacted.

SEASONALITY

Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during
summer. To lessen seasonal demand ﬂuctuations, pipelines, utilities, local distribution companies and industrial users
utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the
summer. However, increased summertime demand for electricity can place increased demand on storage volumes.
Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil
prices are affected more signiﬁcantly by global supply and demand. Seasonal anomalies, such as mild winters,
sometimes lessen these ﬂuctuations. Certain of our drilling, completion and other operations are also subject to
seasonal limitations where equipment may not be available during periods of peak demand or where weather
conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because
our reserves and production are concentrated in a few core areas, problems with production in and markets for a
particular area could have a material impact on our business.”

COMPETITION

The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural
gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and
other equipment and labor required to drill, complete, operate and develop our properties. We also compete with
public and private midstream companies for natural gas gathering and processing opportunities, as well as produced
water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In
addition, competition in the midstream industry is based on the geographic location of facilities, business reputation,
reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies
that provide similar services in its areas of operations, and such companies may have legacy relationships with
producers in those areas and may have a longer history of efﬁciency and reliability.

Many of our competitors have substantially greater ﬁnancial resources, staffs, facilities and other resources. In
addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and
regulations more easily than we can, which could adversely affect our competitive position. These competitors may
be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas
properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of
properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their
own drilling rigs and hydraulic fracturing equipment.

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Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream

services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. In addition, many of our competitors may have a
longer history of operations.

The oil and natural gas industry also competes with other energy-related industries in supplying the energy and

fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to
Third Parties—Competition in the oil and natural gas industry is intense, making it more difﬁcult for us to acquire
properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors
may use superior technology and data resources that we may be unable to afford.”

ENVIRONMENTAL

Emissions Mitigation

We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly

drilled wells are connected to natural gas pipelines with expected sufﬁcient reliability and capacity to support our
production operations. We connect many of our wells to San Mateo’s and Pronto’s natural gas gathering systems.
This greatly reduces the need to ﬂare natural gas. We design our production facilities and use advanced natural gas
capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize
natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might
otherwise be ﬂared. This reduces emissions and increases the volumes of natural gas that we can sell. When
possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of
economies of scale to use these VRUs and other specialized equipment in our production facilities.

Our ﬁeld employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we

have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture.
These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions
that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control
systems through Supervisory Control And Data Acquisition (“SCADA”) equipment at a number of larger production
facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more
frequently and at more locations than federal and state regulations require.

Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows

us to forego using internal combustion-powered generators on-site, which further reduces emissions.

Water Management

Using improving technologies, we are able to take produced water from our existing wells and from third-party
systems, treat the water and then reuse that water in our completions operations on new wells. This use of recycled
water saves signiﬁcant amounts of fresh water that would otherwise have been used for hydraulic fracturing
operations. As well as conserving fresh water, our use of recycled water in our completions operations reduces the
amount of produced water that must be disposed. It also results in signiﬁcant cost savings and efﬁciencies. In
addition to using recycled water where feasible, we also use other sources of non-fresh water.

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Land Stewardship

We attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, which results in

fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil
Conservation Division (the “NMOCD”) and Bureau of Land Management (“BLM”), to obtain approval to commingle
production from different wells into centralized tank batteries. We also take steps to ensure we conduct our
operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of
that effort, we have entered into voluntary agreements with the U.S. Fish and Wildlife Service (the “USFWS”)
and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to
protect certain wildlife, including the habitats of the lesser prairie-chicken, sand dune lizard and Texas hornshell
mussel. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology
surveys and undertake reviews for caves, karsts and potential hydrology considerations.

During 2022, 89% of our gross operated oil production and 99% of our gross operated water production were
connected to pipelines. In addition to the ﬁnancial beneﬁts to us and our stakeholders of connecting oil, natural gas
and water to pipelines, these pipeline connections have many other beneﬁts, including the reduction in the
number of trucks needed to transport the produced oil and water. This is signiﬁcant because it both (i) reduces truck
trafﬁc and increases road safety and (ii) reduces emissions.

REGULATION

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production, midstream and related operations are subject to

extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and
regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden
on the oil and natural gas industry increases our cost of doing business and affects our proﬁtability. Because these
laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are
promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations
to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject
to the same regulatory requirements and restrictions that affect our operations.

Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and

reports concerning operations and impose other requirements relating to the exploration, development and
production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil
and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties,
the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and
restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting
or ﬂaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process,
the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While
not presently the case in the states in which we operate, some states restrict production to the market demand for
oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some
regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the
rate of ﬂow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and
natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production
and sale of oil, natural gas and NGLs within its jurisdiction.

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Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies
of the states in which we operate. These leases contain various restrictions on access and development and other
requirements that may impede our ability to conduct operations on the acreage represented by these leases. In
January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for
a 60-day pause limiting the authority of local ofﬁces of the BLM to issue new leases and grant federal drilling
permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal
oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the
Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and
consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration
Federal Lease Orders”). The U.S. District Court for the District of Louisiana enjoined the pause within 13 states,
including Texas, in August 2022.

In 2019, 2020 and 2021, an environmental group ﬁled multiple lawsuits in federal district courts in New Mexico

and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased
leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold
the lease sales based on alleged defects in the environmental reviews conducted under the National Environmental
Policy Act (“NEPA”) in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the
case pending there. That decision was appealed to the Tenth Circuit Court of Appeals, but the appeal was voluntarily
dismissed in 2021. The lawsuits in the District of Columbia were also dismissed in 2022. In connection with
these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits
associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the
BLM conducted additional NEPA analyses. In November 2022, the BLM published a supplemental environmental
assessment of the greenhouse gas emissions related to the leases that evaluated a proposal to afﬁrm its previous
decisions to offer and approve the leases. Public comment on the supplemental environmental assessment
closed on December 27, 2022. The outcome of the supplemental environmental assessment, including the BLM’s
response to public comments and any future litigation regarding the leases at issue and any related drilling permits
is uncertain.

In 2021, ten states, led by the State of Louisiana, ﬁled a lawsuit in federal district court in Louisiana against

President Biden and various other federal government ofﬁcials and agencies challenging an executive order directing
the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases
in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order
were NEPA reviews conducted in connection with oil and natural gas leasing and permitting decisions by the
BLM. After Louisiana and Missouri-led litigation in the federal district courts and the Fifth and Eighth Circuit Courts
of Appeals, in May 2022, the U.S. Supreme Court let the challenged interim social cost of greenhouse gases go
into effect. In November 2022, the EPA suggested increasing the value of the social cost of carbon from $51 per
metric ton to $190 per metric ton.

In 2022, environmental groups ﬁled a lawsuit alleging that the BLM failed to conduct adequate NEPA reviews

prior to issuing drilling permits in 2021 and 2022 for wells on federal acreage in New Mexico and Wyoming,
including some drilling permits issued to the Company. In February 2023, in a separate lawsuit, the Tenth Circuit
Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued
without adequate NEPA review (collectively with the 2022 lawsuit, the “Drilling Permit Litigation”). The outcome
of the Drilling Permit Litigation, as well as any process changes that the BLM may implement in response to such
lawsuits, is uncertain.

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Although some of the restrictions in the Biden Administration Federal Lease Orders lapsed at the end of 2021, the

impact of federal actions related to the oil and natural gas industry, including those in response to the Lease Sale
Litigation, Social Cost of Carbon Litigation and Drilling Permit Litigation, remains unclear, and should limitations or
prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be
adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold
and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting
requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas
operations on federal lands.”

Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms
and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas
by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of
1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas
gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil
pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State
regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various
safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate
regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has
used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo
placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County,
New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in
committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The
Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season
in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins
Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines
from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil
pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an
intrastate facility not subject to FERC jurisdiction.

In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act,
among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of
natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity
and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate
commerce. The Energy Policy Act also signiﬁcantly increased the penalties for violations of, among other things, the
NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement
the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to
FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent

by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of
regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state.
Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable
basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is
materially different from our competitors that are similarly situated.

As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System.

The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act
of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged
for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude

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oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires
tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services
on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained
on ﬁle with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate
crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index
their rates down to the prescribed ceiling level if the index is negative.

The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of

transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can
change rates based on an inﬂation index, though other rate mechanisms may be used in speciﬁc circumstances.
Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions,
which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on
our operations.

In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other

things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or
petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission
may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for
violations thereunder.

The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements

on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act
and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject
to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity
management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years,
pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES
Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to
requirements regarding damage prevention, corrosion control, public education programs, maximum allowable
operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated
gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed
rulemaking that would amend existing integrity management requirements, expand assessment and repair
requirements in areas with medium population densities and extend regulatory requirements to onshore natural
gas gathering lines that are currently exempt. In October 2019, PHMSA submitted three major rules, including
rules focused on: the safety of gas transmission pipelines (the ﬁrst of three parts of the so-called gas Mega Rule),
the safety of hazardous liquid pipelines and enhanced emergency order procedures. The ﬁnal 2019 gas transmission
rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength
of their lines by reconﬁrming the maximum allowable operating pressure. In addition, the rule updates reporting and
records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in
November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters
and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to
onshore gas transmission pipelines and clariﬁes integrity management regulations, expands corrosion control
requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High
Consequence Areas (“HCA”) and non-HCA pipelines. In addition, states have adopted regulations, similar to
existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to
Laws and Regulations—We may incur signiﬁcant costs and liabilities resulting from compliance with pipeline
safety regulations.”

Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly

safety standards, which could result in increased operating costs or operational delays.

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U.S. Federal and State Taxation

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural

gas products we sell and, for many of our wells, sales and use taxes on signiﬁcant portions of our drilling and
operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction
of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to
impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for
our natural gas processed in New Mexico.

In addition, from time to time there has been a signiﬁcant amount of discussion by legislators and presidential
administrations concerning a variety of energy tax proposals at the federal level. Such changes include, but are not
limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the
elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction
for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological
and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas
within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions
within the industry that are currently available with respect to oil and natural gas exploration and development, and
any such changes could negatively affect our ﬁnancial condition, results of operations, and cash ﬂows.

Changes to state or federal tax laws could adversely affect our business and our ﬁnancial results. See “Risk
Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become
subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with
respect to oil and natural gas exploration and production activities as a result of future legislation, which could
adversely affect our business, ﬁnancial condition, results of operations and cash ﬂows.”

Hydraulic Fracturing Policies and Procedures

We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well
that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing
training programs taught by industry professionals. Although average drilling and completion costs for each area
will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for
our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic
fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion
of our wells and are included in and funded through our normal capital expenditure budget. A change to any
federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect
our business and ﬁnancial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state
legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional
operating restrictions or delays.”

The protection of groundwater quality is important to us. We believe that we follow all state and federal

regulations and apply industry standard practices for groundwater protection in our operations. These measures are
subject to close supervision by state and federal regulsators (including the BLM, with respect to federal acreage).

Although rare, if the cement and steel casing used in well construction requires remediation, we deal with
these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature
logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate
remedial measures.

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The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of

man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives
that are used in fracturing operations as required by the appropriate governmental agencies. These service
companies fracture stimulate thousands of wells each year for the industry and employ rigorous safety procedures
to protect the environment and work to develop more environmentally friendly fracturing ﬂuids. We follow safety
procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection.
We do not pump any diesel in the ﬂuid systems of any of our fracture stimulation procedures.

While current fracture stimulation procedures utilize a signiﬁcant amount of water, we typically recover less than

10% of this fracture stimulation water before produced water becomes a signiﬁcant portion of the ﬂuids produced.
All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated
disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been
recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water
mitigates the need for produced water disposal and also provides cost savings to us. Furthermore, an increasing
percentage of the water used in our hydraulic fracturing operations is sourced from recycled produced water from
our wells or other sources, further reducing the amount of fresh water in our hydraulic fracturing operations.

Environmental, Health and Safety Regulation

The exploration, development, production, gathering and processing of oil and natural gas, including the operation

of produced water injection and disposal wells, are subject to various federal, state and local environmental laws
and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and
operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our
activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution
Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response,
Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air
Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”),
as well as comparable state statutes and regulations. We are also subject to regulations governing the handling,
transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive
materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal ﬁnes
and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations
and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource
damages, permit modiﬁcations or revocations, operational interruptions or shutdowns and other liabilities. Additionally,
these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking
some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other
activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These
laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of
produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in
compliance in all material respects with currently applicable environmental laws and regulations and do not expect
that these laws and regulations will have a material adverse impact on us.

The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude
oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the
exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or
operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several ﬁnancial liability
for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill
that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal
enforcement action.

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The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced
waters, ﬁll materials and other materials into navigable waters. These controls have become more stringent over the
years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge
pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands.
The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination
resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the
“EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the deﬁnition of “waters of the United States”
(“WOTUS”) for all CWA programs, thereby deﬁning the scope of the EPA’s and the Corps’ jurisdiction, became
effective. The EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule (the “NWPR”)
in 2020. The NWPR was viewed as narrowing the scope of WOTUS as compared to the 2015 rule. In August 2021,
the U.S. District Court for the District of Arizona vacated and remanded the NWPR. On December 30, 2022, the
EPA and the Corps jointly issued a pre-publication of a ﬁnal rule revising the deﬁnition of WOTUS that largely returns
to the pre-2015 regulatory regime. The rule will become effective 60 days after publication in the Federal Register.

Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and
enjoined the Corps from authorizing any dredge or ﬁll activities under NWP 12 until the agency completed formal
consultation with the USFWS under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The
court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines,
and that order was partially vacated in the Ninth Circuit Court of Appeals as moot, based on the Corps’ re-issuance
of NWPs in 2021. In 2021, the Corps issued a new set of NWPs to replace the NWPs for dredge or ﬁll discharges
into WOTUS that the Corps last issued and made available in 2017, but elected not to consult with the USFWS.
The re-issued NWPs were subject to the same legal challenges based on the lack of a formal ESA consultation, but
in September 2022, the U.S. District Court for Montana dismissed the ESA-consultation challenges as moot and
dismissed the remainder of the lawsuit without prejudice.

CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the

original conduct, on various classes of persons that are considered to have contributed to the release of a
“hazardous substance” into the environment. These persons include the owner or operator of the site where the
release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances
found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject
to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural
resources. In addition, it is not uncommon for neighboring landowners and other third parties to ﬁle claims for
personal injury and property damage allegedly caused by hazardous substances released into the environment.
Although CERCLA generally exempts petroleum from the deﬁnition of hazardous substances, our operations may,
and in all likelihood will, involve the use or handling of materials that are classiﬁed as hazardous substances under
CERCLA. Each state also has environmental cleanup laws analogous to CERCLA.

RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal,

of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in
connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated
with crude oil and natural gas exploration and production to be classiﬁed as nonhazardous waste. A similar
exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within
these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the
exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modiﬁcations of this
exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would
increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well
as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and
costly disposal requirements than nonhazardous wastes.

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The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas

production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA.
These laws and any implementing regulations impose stringent air permit requirements and require us to obtain
pre-approval for the construction or modiﬁcation of certain projects or facilities expected to produce air emissions,
or to use speciﬁc equipment or technologies to control emissions. Federal and state regulatory agencies can
impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the
CAA and associated state laws and regulations. See “Risk Factors—Risks Related to Laws and Regulations—
New regulations on all emissions from our operations could cause us to incur signiﬁcant costs.” Internationally, in
2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation
of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires
countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”),
which set greenhouse gas emission reduction goals, every ﬁve years beginning in 2020. The United States exited
the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021,
the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005
levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and
other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address
climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions
30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. On
August 16, 2022, the Inﬂation Reduction Act created the Methane Emissions Reduction Program to incentivize
methane emission reductions and imposes a fee on greenhouse gas (“GHG”) emissions from certain facilities that
exceed speciﬁed emissions levels. In addition, on November 11, 2022, the EPA issued a supplemental notice of
proposed rulemaking on GHGs from new and existing sources in the oil and natural gas industry. On December 6,
2022, the EPA published a supplemental proposal to reduce methane and volatile organic chemicals emissions from
the oil and natural gas sector, which strengthens and expands the EPA’s November 1, 2021 proposed revisions to
the New Source Performance Standards program established under Section 111 of the CAA. On December 23, 2022,
the EPA proposed a rule that would enable states to implement more stringent methane emissions standards than
the federal guidelines require. Also in November 2022, the BLM proposed a new rule designed to reduce natural
gas waste through limitation of certain oil and natural gas production activities and the imposition of more stringent
royalty obligations on natural gas that is “avoidably lost” during operations.

In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support
the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed
to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective
of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030
as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an
“enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented
rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require
upstream and midstream operators to reduce natural gas waste by a ﬁxed amount each year and achieve a 98%
natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) adopted
rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and
natural gas operations. In August 2022, the NMED issued a ﬁnal rule imposing additional controls on oil and natural
gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in
New Mexico state court.

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MATADOR RESOURCES COMPANY

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent
and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely
affect our operations and ﬁnancial condition, as well as those of the oil and natural gas industry in general. For
instance, in January 2021, President Biden issued Executive Order 14088, which directed a government-wide effort
to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions
by 2050 or before. That effort is designed to infuse climate policy in all aspects of federal decision-making, including
speciﬁc directives that touch on foreign policy, national security, ﬁnancial regulation, federal procurement,
infrastructure, and environmental justice among other things. Based on this Executive Order and other ﬁndings, the
EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse
gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and
greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely
affecting our proﬁts and could adversely affect demand for the oil and natural gas we produce, depressing the
prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or
regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of
energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce,
while the physical effects of climate change could disrupt our production and cause us to incur signiﬁcant costs
in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New
regulations on all emissions from our operations could cause us to incur signiﬁcant costs.”

We own and operate underground injection wells throughout our areas of operation. Underground injection is the

subsurface placement of ﬂuid through a well, such as the reinjection of brine produced and separated from oil and
natural gas production. Underground injection allows us to safely and economically dispose of produced water. The
SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the
mechanical integrity of the injection apparatus and to prevent migration of ﬂuids from the injection zone into
underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD
require injected ﬂuids to be conﬁned to a permitted injection interval to aid in the protection of potentially productive
intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the
disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits
could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the
operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of
ﬂawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to
the location and operation of underground injection wells. In addition, a number of lawsuits have been ﬁled in some
states against others in our industry alleging that ﬂuid injection or oil and natural gas extraction have caused damage
to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to
these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional
requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess
the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule
amendments designed, among other things, to require applicants for new disposal wells that will receive non-
hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S.
Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of
100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit
fails to demonstrate that the produced water or other ﬂuids are conﬁned to the disposal zone, or if scientiﬁc data
indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may
deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The
RRC has used this authority to deny permits for waste disposal wells and to restrict the volumes authorized to be
injected by permitted wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in

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response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits
in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. The protocols
also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells,
including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity
of the seismic event. The potential adoption of federal, state and local legislation and regulations intended to
address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as
well as our ability to dispose of produced water gathered from such activities, which could result in increased costs
and additional operating restrictions or delays that could, in turn, materially impact our production volumes,
revenues, reserves, cash ﬂows and availability under our Credit Agreement.

Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations,

see “Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal
regulation as underground injection (unless diesel is a component of the fracturing ﬂuid) under the SDWA. The
process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers,
regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on
hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could also reduce the amount
of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional
regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those
activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium
on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations.
In addition, separate and apart from the referenced potential connection between injection wells and seismicity,
concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientiﬁc
community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity
and induced seismicity, and some state regulatory agencies have modiﬁed their regulations or guidance to mitigate
potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if
other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic
fracturing, this could have a material adverse impact on our ﬁnancial condition, results of operations and cash ﬂows.
Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in
additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased
costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—
Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which
are subject to administrative permitting requirements and potential federal legislation, regulation and orders that
may limit or restrict oil and natural gas operations on federal lands.”

Oil and natural gas exploration and production operations and other activities have been conducted on some of

our properties by previous owners and operators. Operations by previous owners and operators may not have
been conducted in compliance with applicable rules and regulations, and materials from these operations may remain
on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree
to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental
claims or violations associated with the properties we purchase or sell, respectively. While we do not believe that
costs we incur for compliance with environmental regulations and remediating previously or currently owned or
operated properties will be material, we cannot provide any assurances that these costs will not result in material
expenditures that adversely affect our proﬁtability.

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MATADOR RESOURCES COMPANY

Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including
casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and
environmental compliance. It is also possible that our oil and natural gas operations may require us to manage
NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and
may become concentrated in scale, ﬁlm and sludge in equipment that comes in contact with crude oil and natural
gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted
regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to
control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly
by us but operated by others, the failure of the operator to comply with the applicable environmental regulations
may, in certain circumstances, be attributable to us.

We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication

Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and
Reauthorization Act and similar state statutes require us to organize information about hazardous materials used,
released or produced in our operations. Certain of this information must be provided to employees, state and
local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in
OSHA workplace standards.

The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is

listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’
habitat. On November 25, 2022, a ﬁnal rule was published that lists the lesser prairie-chicken as endangered under
the ESA in certain portions of Southeast New Mexico where we operate. The effective date of the ﬁnal rule is
March 27, 2023. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald
and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’
critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable
habitat designation could result in material restrictions on land use and may materially impact oil and natural gas
development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by
seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin
and other areas in which we operate. See “Risk Factors—Risks Related to Laws and Regulations—We are subject
to government regulation and liability, including complex environmental laws, which could require signiﬁcant
expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions.

As of December 31, 2022, approximately 31% of our Delaware Basin acreage position consisted of federal

leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take signiﬁcantly
longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining
necessary permits can disrupt our operations and have a material adverse effect on our business. These BLM
leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are
subject to change. These operations are also subject to BLM rules regarding engineering and construction
speciﬁcations for production facilities, safety procedures, the valuation of production, the payment of royalties, the
removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of
environmental protection. These rules could result in increased compliance costs for our operations, which in turn
could have a material adverse effect on our business and results of operations. Under certain circumstances,
the BLM may require our operations on federal leases to be suspended or terminated. In January 2021, the Biden
administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling
permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation, the Social Cost of

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Carbon Litigation and the Drilling Permit Litigation could delay lease sales and the approval of drilling permits.
Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of
these and similar federal actions related to the oil and natural gas industry remains unclear. Should these or other
limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands
could be adversely impacted.

Oil and natural gas exploration and production activities on federal lands are also subject to NEPA. NEPA requires

federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to
signiﬁcantly impact the environment. In the course of such evaluations, an agency will prepare an environmental
assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship”
to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement
that may be made available for public review and comment. This process, including any additional requirements or
procedures that may be included in the process or litigation over the sufﬁciency of the process, has the potential
to delay or even halt development of future oil and natural gas projects with NEPA applicability.

We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that
are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since
these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance.
We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or
that we will not otherwise incur material expenses in connection with environmental laws and regulations in the
future. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and
liability, including complex environmental laws, which could require signiﬁcant expenditures.”

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may

affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement
policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport,
disposal or remediation requirements could have a material adverse effect on our operations and ﬁnancial
condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental
releases or spills may occur in the course of our operations, and we have no assurance that we will not incur
signiﬁcant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to
property, natural resources or persons.

We maintain insurance against some, but not all, potential risks and losses associated with our industry and

operations. We generally do not carry business interruption insurance. For some risks, we may not obtain
insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition,
pollution and environmental risks generally are not fully insurable. If a signiﬁcant accident or other event occurs and
is not fully covered by insurance, it could materially adversely affect our ﬁnancial condition, results of operations
and cash ﬂows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not
available to us.”

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MATADOR RESOURCES COMPANY

OFFICE LOCATION

Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240.

HUMAN CAPITAL

At December 31, 2022, we had 360 full-time employees. We believe that our relationships with our employees

are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the
services of independent consultants and contractors to perform various professional services, including in the areas
of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance
and supervision, permitting and environmental assessment, legal and income tax preparation and accounting
services. Independent contractors, at our request, drill and complete all of our wells and usually perform ﬁeld and
on-site production operation services for us, including midstream services, facilities construction, pumping,
maintenance, dispatching, inspection and testing. If signiﬁcant opportunities for company growth arise and require
additional management and professional expertise, we will seek to employ qualiﬁed individuals to ﬁll positions
where that expertise is necessary to develop those opportunities.

Employee Recruiting, Retention and Professional Development

We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment

or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion,
gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status.

Our employees are our most important asset. We have invested the time, attention and resources necessary to
recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay,
discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee
stock purchase plan and an affordable and comprehensive health insurance program, among other beneﬁts. We also
provide employees the opportunity to have signiﬁcant responsibility and daily interaction with our executive
management and team leaders.

We encourage continuing education and study, requiring every employee to complete at least 40 hours of

professional training annually. In 2022, for example, our employees completed approximately 16,000 hours of continuing
education and study. We also have a formal leadership program that fosters the development and growth of many
of our staff with regular meetings and opportunities to enhance their leadership skills.

Proactive Safety Culture

We are proud to have a company culture that emphasizes safety throughout our operations. Between 2017 and

2022, we estimate our employees have worked approximately 3.3 million combined hours without experiencing
a single lost time incident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”)
group and of the experienced ﬁeld and ofﬁce staff involved in our drilling, completion, production and midstream
operations to proactively minimize safety risks and address any potential areas of concern.

We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important

that our HSE group has actual hands-on experience in the ﬁeld to understand the challenges and issues that can
arise. Our HSE group’s experience allows us to understand the technical issues faced by our ﬁeld employees and
contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential
safety issues and mitigation efforts.

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AVAILABLE INFORMATION

Our Internet website address is www.matadorresources.com. We make available, free of charge, through our

website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and
amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the
charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive
Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and
Business Conduct for Ofﬁcers, Directors and Employees and information regarding certain of our ESG initiatives,
investor presentations, press releases and shareholder communications are available through our website, and we
also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on
behalf of our Chief Executive Ofﬁcer, Chief Financial Ofﬁcer or Chief Accounting Ofﬁcer, on our website. All of these
corporate governance materials are available free of charge and in print to any shareholder who provides a written
request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The
contents of our website are not intended to be incorporated by reference into this Annual Report or any other report
or document we ﬁle and any reference to our website is intended to be an inactive textual reference only.

ITEM 1A. RISK FACTORS.

SUMMARY OF RISK FACTORS

The following is a summary of some of the risks and uncertainties that could materially adversely affect our
business, ﬁnancial condition, results of operations and cash ﬂows. You should read this summary together with the
more detailed risk factors contained below.

Risks Related to the Pending Advance Acquisition

• There can be no assurance as to when or if the Advance Acquisition will be completed.

• We may be unable to successfully integrate Advance’s business or achieve anticipated beneﬁts.

Risks Related to our Financial Condition

• Our success is dependent on the prices of oil, natural gas and NGLs, the volatility of which may adversely

affect our ﬁnancial condition.

• Our industry and the broader U.S. economy experienced higher than expected inﬂationary pressures in 2022.

• We face numerous risks related to the COVID-19 pandemic, including its impact on global oil demand.

• We cannot predict the impact of the ongoing military conﬂict between Russia and Ukraine.

• Our business requires substantial capital expenditures that may exceed our cash ﬂows from operations and

potential borrowings.

• Our oil and natural gas reserves are estimated , and signiﬁcant inaccuracies in our oil and natural gas reserves
estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

• The calculated present value of future net revenues from our proved oil and natural gas reserves will not

necessarily be the same as the current market value of our estimated oil and natural gas reserves.

• Approximately 38% of our total proved reserves at December 31, 2022 consisted of undeveloped and
developed non-producing reserves, and those reserves may not ultimately be developed or produced.

• Unless we replace our oil and natural gas reserves, our reserves and production will decline.

• We may be required to write down the carrying value of our proved properties under accounting rules.

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MATADOR RESOURCES COMPANY

• Hedging transactions, or the lack thereof, may limit our potential gains and could result in ﬁnancial losses.

• Changes in price differentials between benchmark prices of oil and natural gas and the wellhead price we

receive for our production could adversely affect us.

• Our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper

our growth.

• We may purchase properties or midstream assets with liabilities or risks that we did not know about or

assess correctly.

• We may incur losses or costs as a result of title deﬁciencies in the properties in which we invest.

• Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our

control, and in certain cases we may be required to retain liabilities for certain matters.

Risks Related to our Liquidity

• We may not be able to generate sufﬁcient cash to fund our capital expenditures, service all of our

indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which
could reduce our ﬁnancial ﬂexibility.

• The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject

to interest rate risk under our Credit Agreement and the San Mateo Credit Facility.

• The terms of the agreements governing our outstanding indebtedness may restrict our current and future

operations.

• Our credit rating may be downgraded, which could reduce our ﬁnancial ﬂexibility.

• Dividend payments are at the discretion of our Board of Directors and subject to numerous factors.

Risks Related to our Operations

• Drilling for and producing oil and natural gas involve a high degree of operational and ﬁnancial risk.

• Our reserves and production are concentrated in a few core areas.

• There is no guarantee that we will be successful in optimizing our spacing, drilling and completions

techniques.

• Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and

certain of our wells may be adversely affected by actions of other operators.

• Multi-well pad drilling may result in volatility in our operating results.

• The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel

could adversely affect our ability to establish and execute exploration and development plans within budget
and on a timely basis.

• We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations

or dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules.

• Regulatory changes could prevent our ability to continue to pool wells in accordance with our past practices.

• Midstream projects are subject to risks of construction delays and cost over-runs.

• Our identiﬁed drilling locations are scheduled over several years, making them susceptible to uncertainties

and lease expirations that could materially alter the occurrence or timing of their drilling.

• The seismic data and other technologies we use cannot eliminate exploration risk.

FORM 10-K PART I

2022 ANNUAL REPORT

47

Risks Related to Third Parties

• Financial difﬁculties encountered by purchasers, operators or other third parties could decrease our cash

ﬂows from operations.

• The marketability of our production is dependent upon gathering, processing and transportation facilities.

• We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us

to certain risks.

• San Mateo’s and Pronto’s long-term success depends on their ability to obtain new sources of products,

which depends on certain factors beyond their control.

• Certain of our long-term contracts require us to pay fees to our service providers based on minimum

volumes regardless of actual volume throughput and may limit our ability to use other service providers.

• We do not own all of the land on which our midstream assets are located, which could disrupt our

operations.

• Competition in our industry is intense, and our competitors may use superior technology and data

resources.

• Strategic relationships upon which we may rely are subject to change.

We have limited control over activities on properties we do not operate.

Risks Related to Laws and Regulations

• Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands,

which are subject to various requirements and regulations.

• We are subject to government regulation, including complex environmental laws, which could require

signiﬁcant expenditures.

• We are subject to tax laws, and changes thereto could eliminate or reduce certain federal income tax

deductions currently available.

• Legislation and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and
climate change could result in increased costs and additional operating restrictions or delays, and the
physical effects of climate change could disrupt our production and cause us to incur signiﬁcant costs.

• New climate disclosure rules proposed by the SEC could increase our costs of compliance.

• We may incur signiﬁcant costs and liabilities resulting from compliance with pipeline safety regulations.

• A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by

FERC may result in increased regulation of our assets.

• The rates of our regulated assets are subject to review and reporting by federal regulators.

• Should we fail to comply with FERC-administered statutes, rules, regulations and orders, we could be

subject to substantial penalties and ﬁnes.

• Derivatives legislation adopted by Congress could limit our ability to hedge risks associated with

our business.

FORM 10-K PART I

48

MATADOR RESOURCES COMPANY

Risks Relating to Our Common Stock

• The price of our common stock has ﬂuctuated substantially and may ﬂuctuate substantially in the future.

• Conservation measures and a negative shift in market perception towards the oil and natural gas industry

could adversely affect us.

• Future sales and offerings of our common stock could depress the price of our common stock.

• Our directors and executive ofﬁcers own a signiﬁcant percentage of our equity, which could give them

inﬂuence in corporate transactions and other matters, and their interests could differ from other shareholders.

• The issuance of preferred stock could diminish the rights of holders of our common stock.

General Risk Factors

• We may have difﬁculty managing growth in our business.

• The loss of any key personnel, Board member or special Board advisor could disrupt our business operations.

• A cyber incident could occur and result in information theft, data corruption, operational disruption or

ﬁnancial loss.

• Our governing documents and Texas law may have anti-takeover effects that could prevent a change

in control.

• We operate in a litigious environment and may be involved in legal proceedings.

RISKS RELATED TO THE PENDING ADVANCE ACQUISITION

The consummation of the Advance Acquisition is subject to a number of conditions that may not be
satisﬁed or completed on a timely basis or at all. Accordingly, there can be no assurance as to when or if
the Advance Acquisition will be completed, and the failure to complete the Advance Acquisition could have
a material and adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

Although we expect to complete the Advance Acquisition in the second quarter of 2023, there can be no assurances

as to the exact timing of the closing or that the Advance Acquisition will be completed at all. The consummation
of the Advance Acquisition is subject to the satisfaction or waiver of a number of conditions contained in the related
securities purchase agreement, including, among others, the expiration or termination of any applicable waiting
period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Such conditions, some of
which are beyond our control, may not be satisﬁed or waived in a timely manner or at all and therefore make the
completion and timing of the Advance Acquisition uncertain. In addition, the securities purchase agreement contains
certain termination rights for both parties, which if exercised will also result in the Advance Acquisition not being
consummated. Any such termination or any failure to otherwise complete the Advance Acquisition could result in
various consequences, including, among others: our business being adversely impacted by the failure to pursue
other beneﬁcial opportunities due to the time and resources committed by our management to the Advance
Acquisition, without realizing any of the beneﬁts of completing the Advance Acquisition; being required to pay our
legal, accounting and other expenses relating to the Advance Acquisition; the market price of our common stock
being adversely impacted to the extent that the current market price reﬂects a market assumption that the Advance
Acquisition will be completed; and negative reactions from the ﬁnancial markets and customers that may occur
if the anticipated beneﬁts of the Advance Acquisition are not realized. Such consequences could materially and
adversely affect our business, ﬁnancial condition, results of operations and cash ﬂows.

FORM 10-K PART I

2022 ANNUAL REPORT

49

Even if the Advance Acquisition is completed, we may be unable to successfully integrate Advance’s
business into our business or achieve the anticipated beneﬁts of the Advance Acquisition.

The success of the Advance Acquisition will depend, in part, on our ability to realize the anticipated beneﬁts and

cost savings from integrating the assets and operations of Advance into our business, and there can be no
assurance that we will be able to successfully integrate or otherwise realize the anticipated beneﬁts of the Advance
Acquisition. Difﬁculties in integrating Advance into our company and our ability to manage the combined company
may result in us performing differently than expected, in operational challenges or in the delay or failure to realize
anticipated expense-related efﬁciencies, and could have a material adverse effect on our business, ﬁnancial condition,
results of operations and cash ﬂows. Potential difﬁculties that may be encountered in the integration process
include, among others:

•

the inability to successfully integrate Advance operationally, in a manner that permits us to achieve the full
revenue, expected cash ﬂows and cost savings anticipated from the Advance Acquisition;

• not realizing anticipated operating synergies; and

• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the

Advance Acquisition.

RISKS RELATED TO OUR FINANCIAL CONDITION

Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices
and the continued volatility in these prices may adversely affect our ﬁnancial condition and our ability to
meet our capital expenditure requirements and ﬁnancial obligations.

The prices we receive for the oil, natural gas and NGLs we produce heavily inﬂuence our revenue, proﬁtability,

cash ﬂow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any,
access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and
NGLs are commodities and, therefore, their prices are subject to wide ﬂuctuations in response to relatively minor
changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile and
will likely continue to be volatile in the future. For the year ended December 31, 2022, oil prices averaged $94.33
per Bbl, as compared to $68.11 per Bbl in 2021, ranging from a high of $123.70 per Bbl in early March to a low
of $71.02 per Bbl in early December, based upon the WTI oil futures contract price for the earliest delivery date.
For the year ended December 31, 2022, natural gas prices averaged $6.54 per MMBtu, as compared to $3.71 per
MMbtu in 2021, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date.
During 2022, natural gas prices ranged from a low of $3.72 per MMBtu in early January to a high of $9.68 per
MMBtu in mid-August before ﬁnishing the year at $4.48 per MMBtu.

The prices we receive for our production, and the levels of our production, depend on numerous factors. These

factors include, but are not limited to, the following:

•

•

•

•

•

the domestic and foreign supply of, and demand for, oil, natural gas and NGLs;

the actions of OPEC+ and state-controlled oil companies;

the prices and availability of competitors’ supplies of oil, natural gas and NGLs;

the price and quantity of foreign imports;

the impact of U.S. dollar exchange rates;

• domestic and foreign governmental regulations and taxes;

FORM 10-K PART I

50

MATADOR RESOURCES COMPANY

• speculative trading of oil and natural gas futures contracts;

•

•

•

the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural
gas and NGLs and gathering and disposal systems for produced water;

the availability of reﬁning capacity;

the prices and availability of alternative fuel sources;

• weather conditions and natural disasters, including hurricanes in the Gulf Coast region and severe cold

weather in the Delaware Basin;

• political conditions in or affecting oil, natural gas and NGL producing regions or countries, including the

United States, the Middle East, South America, Russia, Ukraine and China;

•

the ongoing military conﬂict between Russia and Ukraine;

• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as

COVID-19 and its variants;

•

the continued threat of terrorism and the impact of military action and civil unrest;

• public pressure on, and legislative and regulatory interest within, federal, state and local governments to

stop, signiﬁcantly limit or regulate oil, natural gas and NGL operations, including hydraulic fracturing
activities;

•

•

•

the level of global oil, natural gas and NGL inventories and exploration and production activity;

the impact of energy conservation efforts;

technological advances affecting energy consumption; and

• overall worldwide economic conditions.

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

Declines in oil, natural gas or NGL prices not only reduce our revenue, but could also reduce the amount of oil,
natural gas and NGLs that we can produce economically and, as a result, could have a material adverse effect on our
ﬁnancial condition, results of operations, cash ﬂows and reserves and our ability to comply with the ﬁnancial
covenants under our Credit Agreement. Should oil, natural gas or NGL prices decrease to economically unattractive
levels and remain there for an extended period of time, we may elect to delay some of our exploration and
development plans for our prospects, cease exploration or development activities on certain prospects due to the
anticipated unfavorable economics from such activities or cease or delay further expansion of our midstream
projects, each of which could have a material adverse effect on our business, ﬁnancial condition, results of
operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing
base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any
time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase
the borrowing base to an amount sufﬁcient to cover such excess or repay the deﬁcit in equal installments over a
period of six months.

FORM 10-K PART I

2022 ANNUAL REPORT

51

Our industry and the broader U.S. economy experienced higher than expected inﬂationary pressures
in 2022 related to increases in oil and natural gas prices, continued supply chain disruptions, labor
shortages and geopolitical instability, among other pressures. Should these conditions persist, it may
impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and,
as a result, our business, ﬁnancial condition, results of operations and cash ﬂows could be materially and
adversely affected.

Inﬂation in the U.S. has become much more signiﬁcant in recent years, and in 2022 it reached its highest levels in

approximately 40 years. Throughout 2022, we began to experience signiﬁcant increases in the costs of certain
oilﬁeld services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion
costs, among others, as a result of the recent increases in oil and natural gas prices, as well as availability constraints,
supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force,
inﬂation and other factors. These challenges are due in part to increased demand for oil and natural gas production
driven by the continued economic recovery from the COVID-19 pandemic and, more broadly, systemic
underinvestment in global oil and natural gas development. These supply and demand fundamentals have been
further aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the
ongoing military conﬂict between Russia and Ukraine. We expect for the foreseeable future to experience supply
chain constraints and inﬂationary pressure on our cost structure. Should oil and natural gas prices remain at their
current levels or increase, we expect to be subject to additional service cost inﬂation in future periods, which
may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other
inﬂationary pressures being experienced throughout the U.S. and global economy and in the oil and natural gas
industry may limit our ability to procure the necessary products and services we need for drilling, completing and
producing wells in a timely fashion, which could result in delays to our operations and could, in turn, have a
material adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

We face numerous risks related to the COVID-19 pandemic, including its impact on global oil demand,
which has had and, depending on the progression of the pandemic, may continue to have, a material
adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies and

industries around the world, including the exploration and production and midstream businesses. The rapid spread
of COVID-19 and its variants has led to the implementation of various responses, including federal, state and local
government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel and other public
health and safety measures, nearly all of which materially reduced global demand for crude oil, natural gas and NGLs
in 2020. Although demand for crude oil, natural gas and NGLs generally increased in 2021 and 2022 as many travel
restrictions, business closures and other restrictions on conducting business were lifted in response to improved
treatments and availability of vaccinations, we cannot reasonably predict the future impact of COVID-19 or its
variants on overall economic activity and the demand for, and pricing of, our products.

The extent to which COVID-19 or its variants will continue to affect our business, ﬁnancial condition, results of
operations and cash ﬂows and the demand for our production will depend on future developments, which are highly
uncertain and cannot be predicted, including the duration or any recurrence of the pandemic and responsive
measures, the emergence, contagiousness and threat of new strains of the virus and their severity, additional or
modiﬁed government actions, new information that may emerge concerning the severity of COVID-19 or its
variants, the effectiveness of treatments, vaccines and other actions taken to contain COVID-19 or its variants or
treat its impact now or in the future, disruptions in the supply chain and an increasingly competitive labor market
due to a sustained labor shortage or increased turnover caused by the COVID-19 pandemic, among others.

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MATADOR RESOURCES COMPANY

Some impacts of the COVID-19 pandemic that could have a material adverse effect on our business, ﬁnancial

condition, results of operations and cash ﬂows include:

• signiﬁcantly reduced prices for our oil production, resulting from a world-wide decrease in demand for

hydrocarbons and a resulting oversupply of existing production;

• decreases in the demand for our oil production, resulting from signiﬁcantly decreased levels of global,

regional and local travel as a result, in part, of federal, state and local government-imposed quarantines,
including shelter-in-place mandates, enacted to slow the spread of COVID-19 or its variants;

•

increased likelihood that we may, either voluntarily or as a result of third-party and regulatory mandates,
curtail or shut in production, resulting from depressed oil prices, lack of storage and other market or political
forces;

• signiﬁcant decreases in the volumes of oil, natural gas and produced water that are transported, gathered,

processed or disposed of by San Mateo or Pronto due to curtailed or shut-in production by Matador or other
of San Mateo’s or Pronto’s customers;

•

•

•

•

•

•

•

•

•

•

increased costs associated with, or actual unavailability of, facilities for the storage of oil, natural gas and
NGL production in the markets in which we operate;

increased operational difﬁculties associated with the delivery of oil, natural gas and NGLs to end-markets,
resulting from pipeline and storage constraints;

the potential for the operations of the Black River Processing Plant, the Marlan Processing Plant and other
critical midstream infrastructure to be adversely impacted by outbreaks of COVID-19 or its variants among the
relevant workforce;

the potential for forced curtailment of oil and natural gas production by state governmental agencies,
resulting in a need to signiﬁcantly curtail or shut in our production;

the potential for loss of leasehold interests due to the failure to produce oil and natural gas in paying
quantities as a result of signiﬁcantly lower commodity prices, voluntary or forced curtailments or other
factors related to the misalignment of supply and demand, and the potential to incur signiﬁcant costs
associated with litigation related to the foregoing;

increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil,
natural gas and NGL production, resulting from adverse market conditions, a lack of access to capital and
storage or the failure of certain of our counterparties to continue as going concerns;

increased likelihood that counterparties to our existing agreements may seek to invoke force majeure
provisions to avoid the performance of contractual obligations, resulting from signiﬁcantly adverse market
conditions;

the potential impact for delays in construction or increased costs related to midstream construction projects;

increased costs, stafﬁng requirements and difﬁculties sourcing oilﬁeld services related to social distancing
measures implemented in connection with federal, state or local government and voluntarily imposed
quarantines; and

increased legal and operational costs related to compliance with signiﬁcant changes in federal, state and
local laws and regulations.

FORM 10-K PART I

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53

The COVID-19 pandemic continues to evolve, and the extent to which the pandemic may impact our business,
ﬁnancial condition, results of operations and cash ﬂows will depend highly on future developments, which are very
uncertain and cannot be predicted. Additionally, the extent and duration of the impact of the COVID-19 pandemic
on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors. As a
result, there may be a less active trading market for our common stock, our stock price may be more volatile and
our ability to raise capital could be impaired.

We cannot predict the impact of the ongoing military conﬂict between Russia and Ukraine and the related
humanitarian crisis on the global economy, energy markets, geopolitical stability and our business.

On February 24, 2022, Russian military forces commenced a military operation in Ukraine, and sustained conﬂict

and disruption in the region is likely. Although our leasehold acreage is located primarily in the Delaware Basin,
the broader consequences of the Russian-Ukrainian conﬂict, which may include further sanctions, embargoes, supply
chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic
conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks, cause
disruptions in global supply chains, increase foreign currency ﬂuctuations, cause constraints or disruption in the
capital markets and limit sources of liquidity. We cannot predict the extent of the conﬂict’s effect on our business and
results of operations as well as on the global economy and energy markets.

Our exploration, development, exploitation and midstream projects require substantial capital expenditures
that may exceed our cash ﬂows from operations and potential borrowings, and we may be unable to obtain
needed capital on satisfactory terms, which could adversely affect our future growth.

Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash

ﬂows, contributions from our joint venture partners and potential future borrowings, under our Credit Agreement,
the San Mateo Credit Facility or otherwise, may not be sufﬁcient to fund all of our future acquisitions or future capital
expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and
on terms we determine to be acceptable.

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

• our estimated proved oil and natural gas reserves;

•

•

•

•

the amount of oil and natural gas we produce;

the prices at which we sell our production;

the costs of developing and producing our oil and natural gas reserves;

the costs of constructing, operating and maintaining our midstream facilities;

• our ability to attract third-party customers for our midstream services;

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

•

the ability and willingness of banks to lend to us; and

• our ability to access the equity and debt capital markets.

FORM 10-K PART I

54

MATADOR RESOURCES COMPANY

In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or
extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak
of contagious or pandemic diseases, ﬁnancial market disruptions, general economic recessions, oil and natural gas
industry recessions, oil and natural gas company bankruptcies, accounting scandals, overstated reserves estimates
by public oil companies and disruptions in the ﬁnancial and capital markets, has caused ﬁnancial institutions, credit
rating agencies and the public to more closely review the ﬁnancial statements, capital structures and spending and
earnings of public companies, including energy companies. Such events have constrained the capital available to
the energy industry in the past, and such events or similar events could adversely affect our access to funding for
our operations in the future.

If our revenues decrease as a result of lower oil and natural gas prices, operating difﬁculties, declines in reserves

or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain
our operations at current levels, further develop and exploit our current properties or invest in certain opportunities.
Alternatively, to fund acquisitions, increase our rate of growth, expand our midstream operations, develop our
properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through
the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream
assets, oil and natural gas producing assets or leasehold interests, the sale or joint venture of oil and natural gas
mineral interests, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in
selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions,
the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences
or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt
securities or additional indebtedness, we may become subject to additional covenants that restrict our business
activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, ﬁnancial
condition and results of operations could be adversely affected.

Our oil and natural gas reserves are estimated and may not reﬂect the actual volumes of oil and natural
gas we will recover, and signiﬁcant inaccuracies in these reserves estimates or underlying assumptions
will materially affect the quantities and present value of our reserves.

The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous

inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and
production data. The extent, quality and reliability of this technical data can vary. This process also requires certain
economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:

•

•

•

•

the quality and quantity of available data;

the interpretation of that data;

the judgment of the persons preparing the estimate; and

the accuracy of the assumptions used.

The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of

production history. Due to the limited production history of certain of our properties, the estimates of future
production associated with these properties may be subject to greater variance to actual production than would be
the case with properties having a longer production history. As our wells produce over time and more data becomes
available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to
reﬂect new information based upon our actual production history, results of exploration and development, prevailing
oil and natural gas prices and other factors.

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55

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating

expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that
future production declines in our wells may be greater than we have estimated. Any signiﬁcant variance from our
estimates could materially affect the quantities and present value of our reserves.

The calculated present value of future net revenues from our proved oil and natural gas reserves will not
necessarily be the same as the current market value of sour estimated oil and natural gas reserves.

It should not be assumed that the present value of future net cash ﬂows included in this Annual Report is the
current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations,
the estimated discounted future net cash ﬂows from proved oil and natural gas reserves are based on current costs
held constant over time without escalation and on commodity prices using an unweighted arithmetic average of
ﬁrst-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date
of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used
for these estimates and will be affected by factors such as:

• actual prices we receive for oil and natural gas;

• actual costs and timing of development and production expenditures;

•

the amount and timing of actual production; and

• changes in governmental regulations or taxation.

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for
reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital
in effect from time to time and risks associated with our business and the oil and natural gas industry in general.

Approximately 38% of our total proved reserves at December 31, 2022 consisted of undeveloped and
developed non-producing reserves, and those reserves may not ultimately be developed or produced.

At December 31, 2022, approximately 38% of our total proved reserves were undeveloped and less than 1% of

our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing
reserves may never be developed or produced, or such reserves may not be developed or produced within the time
periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions,
proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within ﬁve
years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop
such reserves would reduce the present value of our estimated proved undeveloped reserves and future net
revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total
proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices
used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves
as unproved reserves. Any reduction in our proved reserves caused by the reclassiﬁcation of undeveloped or
developed non-producing reserves could materially affect our business, ﬁnancial condition, results of operations and
cash ﬂows.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which
would adversely affect our business, ﬁnancial condition, results of operations and cash ﬂows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil

and natural gas reserves and production and, therefore, our income and cash ﬂow are highly dependent on our
success in efﬁciently developing and exploiting our current reserves and economically ﬁnding or acquiring additional oil
and natural gas producing properties. We are currently focusing on developing our assets in the Delaware Basin, an
area with intense competition and industry activity. As a result of this activity, we may have difﬁculty growing our current
production or acquiring new properties in this area and may experience such difﬁculty in other areas in the future.

FORM 10-K PART I

56

MATADOR RESOURCES COMPANY

During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become
more difﬁcult to raise the capital necessary to ﬁnance expansion activities. If we are unable to replace our current
and future production, our reserves will decrease, and our business, ﬁnancial condition, results of operations and
cash ﬂows would be adversely affected.

We may be required to write down the carrying value of our proved properties under accounting rules,
and these write-downs could adversely affect our ﬁnancial condition.

There is a risk that we will be required to write down the carrying value of our oil and natural gas properties
when oil or natural gas prices are low or are declining, as occurred in 2020. In addition, non-cash write-downs may
occur if we have:

• downward adjustments to our estimated proved reserves;

•

increases in our estimates of development costs; or

• deterioration in our exploration and development results.

We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules.
Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may
not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and
costs projected forward from a single point in time, of estimated future after-tax net cash ﬂows from proved reserves,
discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes
exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the
excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does
not affect net cash ﬂows from operating activities, liquidity or capital resources, but it does reduce the book value
of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock.

Hedging transactions, or the lack thereof, may limit our potential gains and could result in ﬁnancial losses.

To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily
“costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with
downside price protection through the purchase of a put option, which is ﬁnanced through the sale of a call option.
Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially
“costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of
a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase
of both the put option and call option are ﬁnanced through the sale of a call option. Because the proceeds from the
call option sale are used to offset the cost of the purchased put and call options, these arrangements are also
initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different
ﬁxed price components. In a swap contract, a ﬂoating price is exchanged for a ﬁxed price over the speciﬁed period,
providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of
collars or a ﬁxed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash
ﬂows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price
established by the call option or swap as applicable, and may offer protection if prices fall below the minimum price
established by the put option or swap, as applicable, only to the extent of the volumes then hedged.

In addition, hedging transactions may expose us to the risk of ﬁnancial loss in certain other circumstances, including

instances in which our production is less than expected or the counterparties to our put and call option or swap
contracts fail to perform under the contracts. Disruptions in the ﬁnancial markets could lead to sudden changes in a
counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to
predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do
accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.

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Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have
been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difﬁcult
and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and
we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ
from those that we have used in the past, and neither the continued application of our current strategies nor our
use of different hedging strategies may be successful. See Note 12 to the consolidated ﬁnancial statements in this
Annual Report for a summary of our open derivative ﬁnancial instruments at December 31, 2022.

A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and
the wellhead price we receive for our production could adversely affect our business, ﬁnancial condition,
results of operations and cash ﬂows.

The prices we receive for our oil and natural gas production often reﬂect a discount to the relevant benchmark
prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark
price and the price we receive is called a differential. Increases in the differential between the benchmark price for
oil and natural gas and the wellhead price we receive could adversely affect our business, ﬁnancial condition, results
of operations and cash ﬂows.

Over the past several years, these oil and natural gas basis differentials were volatile and widened at various
times. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General
Outlook and Trends” for additional information regarding the differentials. These wider oil and natural gas basis
differentials were largely attributable to industry concerns regarding the near-term sufﬁciency of pipeline takeaway
capacity for oil, natural gas and NGL production in the Delaware Basin. If we do experience any interruptions
with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, ﬁnancial condition, results
of operations and cash ﬂows could be adversely affected.

Although the completion of additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf
Coast and other end markets improved these price differentials in 2020 and 2021, these price differentials for natural
gas widened in 2022 and could widen further in future periods. Should we experience future periods of negative
pricing for natural gas as we did at certain times in 2020, we may temporarily shut in certain high gas-oil ratio wells
and take other actions to mitigate the impact on our realized natural gas prices and results.

A component of our growth may come through acquisitions, and our failure to identify or complete
future acquisitions successfully could reduce our earnings and hamper our growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider

economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for
acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion
of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity ﬁnancing and,
in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in
operations and ﬁnancial and management information systems and to attract, retain, motivate and effectively
manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings
could be reduced and our growth could be restricted.

In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The

inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions
and current operations and could negatively impact our results of operations and growth potential. Members of our
senior management team may be required to devote considerable amounts of time to the integration process,
which will decrease the time they will have to manage our business.

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MATADOR RESOURCES COMPANY

Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics

or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our
ﬁnancial condition, results of operations and cash ﬂows may ﬂuctuate signiﬁcantly from period to period as a result
of the completion of signiﬁcant acquisitions during particular periods.

We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or
increase substantially our capitalization to ﬁnance these acquisitions through the use of cash on hand, the issuance of
debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and
natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement, the San Mateo
Credit Facility and the indenture governing our outstanding senior notes include covenants limiting our ability to
incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common
stock, our shareholders would suffer dilution of their interests.

We may purchase oil and natural gas properties or midstream assets with liabilities or risks that we
did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities
that could adversely affect our results of operations.

Before acquiring oil and natural gas properties or midstream assets, we assess the potential reserves, future oil

and natural gas prices, operating costs, potential environmental liabilities, condition of the assets, customer
contracts and other factors relating to the properties or assets, as applicable. However, our review process is complex
and involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not
discover all existing or potential problems associated with the properties or assets we buy. We may not become
sufﬁciently familiar with the properties or assets to assess fully their deﬁciencies and capabilities. We may not perform
inspections on every well, property or asset, and we may not be able to observe mechanical and environmental
problems even when we conduct an inspection. Even when problems with a property or asset are identiﬁed, the
seller may not be willing or ﬁnancially able to give us contractual protection against any identiﬁed problems,
and we may decide to assume environmental and other risks and liabilities in connection with properties or assets
we acquire. If we acquire properties or assets with risks or liabilities we did not know about or that we did not
assess correctly, our ﬁnancial condition, results of operations and cash ﬂows could be adversely affected as we
settle claims and incur cleanup costs related to these liabilities.

We may incur losses or costs as a result of title deﬁciencies in the properties in which we invest.

If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or

mineral interests have been purchased in error from a person who is not the owner of such interests or if the
property has other title deﬁciencies, our interest would likely be worth less than what we paid or may be worthless.
In such an instance, all or part of the amount paid for such oil and natural gas lease or mineral interest, as well as all
or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect, would be lost.

It is not our practice in all acquisitions of oil and natural gas leases or mineral interests, or undivided interests in

such interests, to undergo the expense of retaining lawyers to examine the title to the interest. Rather, in certain
acquisitions we rely upon the judgment of oil and natural gas brokers and/or landmen who perform the ﬁeld work by
examining records in the appropriate governmental ofﬁce before attempting to acquire a lease or mineral interest.

Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the
well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure
there are no obvious deﬁciencies in title to the well. Frequently, as a result of such examinations, certain curative

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59

work must be done to correct deﬁciencies in the marketability of the title, and such title review and curative work
entails expense, which may be signiﬁcant and difﬁcult to accurately predict. Our failure to cure any title defects may
delay or prevent us from utilizing the associated leasehold right or mineral interest, which may adversely impact our
ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title
failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If
there are any title defects or defects in assignment of leasehold rights or mineral interests in properties in which we
hold an interest, we will suffer a ﬁnancial loss that could adversely affect our ﬁnancial condition, results of
operations and cash ﬂows.

Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond
our control, and in certain cases we may be required to retain liabilities for certain matters.

From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the
asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic
assets, the disposition of which would increase capital resources available for other activities and create
organizational and operational efﬁciencies. Various factors could materially affect our ability to dispose of such
interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of
governmental agencies or third parties and the identiﬁcation of purchasers willing to acquire the interests or
purchase the nonstrategic assets on terms and at prices acceptable to us.

Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of

litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained
liability or indemniﬁcation obligation may be difﬁcult to quantify at the time of the transaction and ultimately may be
material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees
or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may
remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails
to perform these obligations.

RISKS RELATED TO OUR LIQUIDITY

We may not be able to generate sufﬁcient cash to fund our capital expenditures, service all of our
indebtedness and pay dividends to our shareholders, and we may be forced to take other actions to
satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to reﬁnance our indebtedness obligations depends on our

ﬁnancial condition and operating performance, which are subject to prevailing economic and competitive conditions
and certain ﬁnancial, business and other factors beyond our control. We may not be able to maintain a level of
cash ﬂows from operating activities sufﬁcient to permit us to pay the principal, premium, if any, and interest on
our indebtedness.

If our cash ﬂows and capital resources are insufﬁcient to fund debt service obligations, we may be forced to

reduce or delay investments and capital expenditures, sell assets, cease the payment of any dividends to our
shareholders, seek additional capital or restructure or reﬁnance indebtedness. Our ability to restructure or reﬁnance
indebtedness will depend on the condition of the capital markets and our ﬁnancial condition at such time. Any
reﬁnancing of indebtedness could be at higher interest rates and may require us to comply with more onerous
covenants, which could further restrict business operations. The terms of existing or future debt instruments may
restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and
principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which
could harm our ability to incur additional indebtedness. In the absence of sufﬁcient cash ﬂows and capital resources,

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MATADOR RESOURCES COMPANY

we could face substantial liquidity problems and might be required to dispose of material assets or operations to
meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indenture
governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds
from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such
disposition may not be adequate to meet any debt service obligations then due. These alternative measures may
not be successful and may not permit us to meet scheduled debt service obligations, which could have a material
adverse effect on our ﬁnancial condition and results of operations.

We may incur additional indebtedness, which could reduce our ﬁnancial ﬂexibility, increase interest
expense and adversely impact our operations and our unit costs.

As of February 21, 2023, the maximum facility amount under the Credit Agreement was $1.50 billion, the
borrowing base was $2.25 billion and our elected borrowing commitment was $775.0 million. Borrowings under
the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the
elected borrowing commitment (subject to compliance with the covenants noted below). At February 21, 2023, we
had available borrowing capacity of approximately $729.4 million under our Credit Agreement (after giving effect
to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on
the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request
one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by
our interests in the majority of our oil and natural gas properties and contains covenants restricting our ability to
incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is
subject to periodic redeterminations, if a redetermination resulted in a borrowing base that was less than our
borrowings under the Credit Agreement, we would be required to provide additional collateral satisfactory in nature
and value to the lenders to increase the borrowing base to an amount sufﬁcient to cover such excess or repay the
deﬁcit in equal installments over a period of six months. If we are required to do so, we may not have sufﬁcient
funds to fully make such repayments. The Credit Agreement requires us to maintain a debt to EBITDA ratio, which
is deﬁned as debt outstanding (net of up to $75.0 million of unrestricted cash and cash equivalents), divided by a
rolling four quarter EBITDA calculation, of 3.50 or less and a current ratio, which is deﬁned as (x) consolidated
current assets plus the unused availability under the Credit Agreement divided by (y) consolidated current liabilities
less current maturities under the Credit Agreement, of equal to or greater than 1.0.

As of February 21, 2023, the facility amount under the San Mateo Credit Facility was $485.0 million, and

San Mateo had available borrowing capacity of approximately $11.0 million (after giving effect to outstanding letters
of credit and subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility
includes an accordion feature, which could expand the commitments of the lenders to up to $735.0 million. The
San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed
by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The
San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is deﬁned as total consolidated
funded indebtedness outstanding (as deﬁned in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA
calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo
to maintain an interest coverage ratio, which is deﬁned as a rolling four quarter EBITDA calculation divided by
San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also
restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the
lender commitments under the San Mateo Credit Facility. In addition to these restrictions, the San Mateo Credit
Facility also contains covenants restricting San Mateo’s ability to incur additional indebtedness, sell assets, pay
dividends and make certain investments.

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In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other
instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo
Credit Facility), we may incur signiﬁcant amounts of additional indebtedness, including under our Credit Agreement
and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to develop our
properties, fund acquisitions or invest in certain opportunities. Interest rates on such future indebtedness may be
higher than current levels, causing our ﬁnancing costs to increase accordingly.

A high level of indebtedness could affect our operations in several ways, including the following:

•

•

requiring a signiﬁcant portion of our cash ﬂows to be used for servicing our indebtedness;

increasing our vulnerability to general adverse economic and industry conditions;

• placing us at a competitive disadvantage compared to our competitors that are less leveraged and,

therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us
from pursuing;

•

restricting our ability to obtain additional ﬁnancing in the future for working capital, capital expenditures,
acquisitions and general corporate or other purposes; and

•

increasing the risk that we may default on our debt obligations.

The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are
subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by

the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31
and June 30 of each year, respectively. We and the lenders may each request an unscheduled redetermination of
the borrowing base once between scheduled redetermination dates. In addition, our lenders have the ﬂexibility to
reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 21,
2023, our borrowing base was $2.25 billion, our elected borrowing commitment was $775.0 million, the maximum
facility amount under the Credit Agreement was $1.50 billion and we had no outstanding borrowings under, and
approximately $45.6 million in outstanding letters of credit issued pursuant to, the Credit Agreement. Borrowings
under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected
borrowing commitment (subject to compliance with the covenant noted above). We could be required to repay a
portion of any outstanding debt under the Credit Agreement to the extent that, after a redetermination, our outstanding
borrowings at such time exceeded the redetermined borrowing base. We may not have sufﬁcient funds to make
such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the
loans thereunder, requiring us to negotiate renewals, arrange new ﬁnancing or sell signiﬁcant assets, all of which
could have a material adverse effect on our business and ﬁnancial results.

Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the

San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a
loan based on the secured overnight ﬁnancing rate administered by the Federal Reserve Bank of New York (“SOFR”).
If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the
prime rate for such day, (ii) the Federal Funds Effective Rate (as deﬁned in the Credit Agreement) on such day, plus
0.50%, and (iii) the Adjusted Term SOFR Rate (as deﬁned in the Credit Agreement) for a one month tenor, plus
1.00%, plus, in each case, an amount ranging from 0.75% to 1.75% per annum depending on the level of borrowings
under the Credit Agreement. If we borrow funds as a SOFR loan, such borrowings will bear interest at a rate equal
to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 1.75% to 2.75%
per annum depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings
under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse
effect on our results of operations and ﬁnancial condition.

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MATADOR RESOURCES COMPANY

Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a SOFR loan.
If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of
(i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as deﬁned in the San Mateo Credit Facility)
on such day, plus 0.50% and (iii) the Adjusted Term SOFR Rate (as deﬁned in the San Mateo Credit Facility) for a
one month tenor, plus 1.00% plus, in each case, an amount ranging from 1.25% to 2.25% per annum depending
on San Mateo’s Consolidated Total Leverage Ratio (as deﬁned in the San Mateo Credit Facility). If San Mateo borrows
funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for
the chosen interest period plus (y) an amount ranging from 2.25% to 3.25% per annum depending on San Mateo’s
Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility
and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San
Mateo’s results of operations and ﬁnancial condition.

Interest rates rose signiﬁcantly during 2022 as the Federal Reserve sought to control inﬂation, and interest rates

are likely to rise higher during 2023. Our Credit Agreement and the San Mateo Credit Facility have ﬂoating rates
tied to SOFR or other interest rate benchmarks that generally rise alongside the increase in the federal funds rates.
As a result, interest expense on our existing ﬂoating rate debt rose during 2022 and will likely rise during 2023. In
addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our
ﬁnancing costs to increase accordingly.

The terms of the agreements governing our outstanding indebtedness may restrict our current and
future operations, particularly our ability to respond to changes in business or to take certain actions.

Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our senior notes contain, and

any future indebtedness we incur will likely contain, a number of restrictive covenants that impose signiﬁcant
operating and ﬁnancial restrictions, including restrictions on our ability to engage in acts that may be in our best
long-term interest. One or more of these agreements include covenants that, among other things, restrict our
ability to:

•

incur or guarantee additional debt or issue certain types of preferred stock;

• pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated

indebtedness;

•

transfer or sell assets;

• make certain investments;

• create certain liens;

• enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries

(as deﬁned in the indenture) to us;

• consolidate, merge or transfer all or substantially all of our assets;

• engage in transactions with afﬁliates; and

• create unrestricted subsidiaries.

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A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo

Credit Facility and the indenture governing our outstanding senior notes. For example, our Credit Agreement
requires us to maintain a debt to EBITDA ratio, which is deﬁned as debt outstanding (net of up to $75 million of
unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less and
a current ratio, which is deﬁned as current assets plus the unused availability under the Credit Agreement, divided
by current liabilities, of equal to or greater than 1.0. Low oil and natural gas prices or a decline in our oil or natural
gas production may adversely impact our EBITDA, cash ﬂows and debt levels, and therefore our ability to comply
with this covenant.

Similarly, the San Mateo Credit Facility requires San Mateo to meet a debt to EBITDA ratio, which is deﬁned as
consolidated total funded indebtedness outstanding (as deﬁned in the San Mateo Credit Facility) divided by a rolling
four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also
requires San Mateo to maintain an interest coverage ratio, which is deﬁned as a rolling four quarter EBITDA
calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. Lower revenues
as a result of less volumes than anticipated, or otherwise, or an increase in interest rates may adversely impact
San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants. The
San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s
liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility.

Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could

be declared to be immediately due and payable and all applicable commitments to extend further credit could be
terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indenture governing
our outstanding senior notes is accelerated, there can be no assurance that we will have sufﬁcient assets to repay
such indebtedness. The operating and ﬁnancial restrictions and covenants in these debt agreements and any
future ﬁnancing agreements could materially adversely affect our ability to ﬁnance future operations or capital needs
or to engage in other business activities.

Our credit rating may be downgraded, which could reduce our ﬁnancial ﬂexibility, increase interest
expense and adversely impact our operations.

In March 2020, our corporate credit rating from S&P Global Ratings was downgraded from “B+” to “B-” and
our corporate credit rating from Moody’s Investors Service was downgraded from “B1” to “B3.” The downgrades
resulted in signiﬁcant part due to the sudden decline in oil prices in early 2020. Moody’s Investor Services
subsequently upgraded our corporate credit rating to “B2” in July 2020, to “B1” in September 2021 and to “Ba3” in
September 2022. S&P Global Ratings upgraded our corporate credit rating to “B” in June 2021, “B+” in January
2022 and “BB-” in September 2022. In September 2021, Fitch Ratings assigned us a corporate credit rating of “B+”
and subsequently upgraded our corporate credit rating to “BB-” in September 2022. As of February 21, 2023, our
corporate credit ratings from S&P Global Ratings, Moody’s Investors Service and Fitch Ratings remained “BB-,”
“Ba3” and “BB-,” respectively. We cannot assure you that our credit ratings will remain in effect for any given
period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment,
circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future.

Any increase in our ﬁnancing costs resulting from a credit rating downgrade could adversely affect our ability to
obtain additional ﬁnancing in the future for working capital, capital expenditures, additional letters of credit or other
credit support we may be required to provide to counterparties, acquisitions and general corporate or other
purposes. If a credit rating downgrade were to occur at a time when we were experiencing signiﬁcant working
capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected.

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MATADOR RESOURCES COMPANY

The payment of dividends will be at the discretion of our Board of Directors and subject to numerous
factors, and we do not presently intend to repurchase any shares of our common stock.

In February 2022 and April 2022, our Board of Directors declared quarterly cash dividends of $0.05 per share of
common stock. In June 2022, the Board amended our dividend policy to increase the quarterly dividend to $0.10 per
share of common stock. In July 2022 and October 2022, the Board declared quarterly cash dividends of $0.10 per
share of common stock. In December 2022, the Board amended our dividend policy to increase the quarterly
dividend to $0.15 per share of common stock for future dividend payments. On February 15, 2023, the Board declared
a quarterly cash dividend of $0.15 per share of common stock payable on March 9, 2023 to shareholders of record
as of February 27, 2023. We intend to continue to pay a quarterly dividend in the future pursuant to the dividend
policy adopted by our Board of Directors. However, the payment and amount of future dividend payments, if any,
are subject to declaration by our Board of Directors. Such payments will depend on, among other things, our
available cash, earnings, ﬁnancial condition, capital requirements, level of indebtedness, stock price, statutory and
contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors
deems relevant. Cash dividend payments in the future may only be made out of legally available funds, and, if we
experience substantial losses, such funds may not be available.

We do not presently intend to repurchase any shares of our common stock. Certain covenants in our Credit

Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends or
repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in
order to generate cash ﬂow from your investment, and there is no guarantee that the price of our common stock
will exceed the price you paid. We are under no obligation to make dividend payments on our common stock and
may cease such payments at any time in the future. Any elimination of or downward revision in our dividend payout
could have a material adverse effect on our stock price.

RISKS RELATED TO OUR OPERATIONS

Drilling for and producing oil and natural gas are highly speculative and involve a high degree of
operational and ﬁnancial risk, with many uncertainties that could adversely affect our business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and ﬁnancial risk, which

precludes us from deﬁnitively predicting the costs involved and time required to reach certain objectives. Our
drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will
require substantial additional interpretation and approvals before they can be drilled. The budgeted costs of
planning, drilling, completing and operating wells may be exceeded and such costs can increase signiﬁcantly due to
various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur
signiﬁcant geological, geophysical and land costs, including seismic acquisition costs, which are incurred whether or
not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells could
bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells,
more fully explored locations or producing ﬁelds may not be applicable to our drilling locations. If our actual drilling
and development costs are signiﬁcantly more than our estimated costs, we may not be able to continue our operations
as proposed and could be forced to modify our drilling plans accordingly.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs

will be found or produced. We may drill or participate in new wells that are not productive. We may drill or
participate in wells that are productive, but that do not produce sufﬁcient net revenues to return a proﬁt after drilling,

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65

operating and other costs. There is no way to afﬁrmatively determine in advance of drilling and testing whether
any particular location will yield oil or natural gas in sufﬁcient quantities to recover exploration, drilling and
completion costs or to be economically viable. Even if sufﬁcient amounts of oil or natural gas exist, we may
damage the potentially productive hydrocarbon-bearing formation or experience mechanical difﬁculties while drilling
or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well.
The productivity and proﬁtability of a well may be negatively affected by a number of additional factors, including
the following:

• general economic and industry conditions, including the prices received for oil and natural gas;

• shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and

qualiﬁed personnel;

• potential drainage of oil and natural gas from our properties by operations on adjacent properties;

•

•

the existence or magnitude of faults or unanticipated geological features;

loss of or damage to oilﬁeld development and service tools;

• accidents, equipment failures or mechanical problems;

•

•

title defects of the underlying properties;

increases in severance taxes;

• adverse weather conditions that delay drilling activities or cause producing wells to be shut in;

• domestic and foreign governmental regulations; and

• proximity to and capacity of gathering, processing, transportation and disposal facilities.

Furthermore, our exploration and production operations involve using some of the latest drilling and completion
techniques developed by us, other operators and service providers. Risks that we face while drilling and completing
horizontal wells include, but are not limited to, the following:

•

landing our wellbore in the desired drilling zone;

• staying in the desired drilling zone while drilling horizontally through the formation;

•

•

running our casing the entire length of the wellbore;

fracture stimulating the planned number of stages;

• drilling out the plugs between stages following hydraulic fracturing operations; and

• being able to run tools and other equipment consistently through the horizontal wellbore.

Each of these risks is magniﬁed in wells with longer laterals. In 2022, 98% of the operated wells we turned to

sales had lateral lengths of greater than one mile. In 2023, we anticipate that 96% of the operated wells we turn
to sales should have lateral lengths of greater than one mile. If we do not drill productive and proﬁtable wells in the
future, our business, ﬁnancial condition, results of operations, cash ﬂows and reserves could be materially and
adversely affected.

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MATADOR RESOURCES COMPANY

Our operations are subject to operational hazards and risks, which could result in signiﬁcant damages
and the loss of revenue.

There are numerous operational hazards inherent in oil and natural gas exploration, development, production,

gathering, transportation and processing, including:

• natural disasters;

• adverse weather conditions;

• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such

as COVID-19 and its variants;

•

loss of drilling ﬂuid circulation;

• blowouts where oil or natural gas ﬂows uncontrolled at a wellhead;

• cratering or collapse of the formation;

• pipe or cement leaks, failures or casing collapses;

• damage to pipelines, processing plants and disposal wells and associated facilities;

• ﬁres or explosions;

•

releases of hazardous substances or other waste materials that cause environmental damage;

• pressures or irregularities in formations; and

• equipment failures or accidents.

In addition, there is an inherent risk of incurring signiﬁcant environmental costs and liabilities in the performance of

our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and
wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic
fracturing ﬂuids and historical industry operations and waste disposal practices. Any of these or other similar
occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or
loss of human life, signiﬁcant damage to property, environmental pollution and substantial revenue losses. The
location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential
areas, commercial business centers and industrial sites, could signiﬁcantly increase the level of damages resulting
from these risks.

Furthermore, our operations may be subject to curtailment due to seismic events. In 2021, the NMOCD

implemented new rules establishing protocols in response to seismic events in New Mexico. The protocols require
enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including
potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity to the
seismic event. If a seismic event were to occur in the area of our operations, the salt water disposal wells that
we deliver to or operate may be shut in or curtailed, which may result in increased expenses or the curtailment of
our oil and natural gas production. In addition, if such a seismic event occurred in the area of San Mateo’s
operations, San Mateo may be required to shut in or curtail the volumes disposed in its salt water disposal wells.
Any such events could adversely impact our and San Mateo’s revenues and cash ﬂows.

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There are also signiﬁcant risks associated with the operation of cryogenic natural gas processing plants such as
the Marlan Processing Plant and the Black River Processing Plant. Natural gas and NGLs are volatile and explosive
and may include carcinogens. Damage to or improper operation of the Black River Processing Plant or the Marlan
Processing Plant could result in an explosion or the discharge of toxic gases, which could result in signiﬁcant
damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced
from our wells or third-party wells located in nearby asset areas. Furthermore, if we were unable to process such
natural gas, we may be forced to ﬂare natural gas from, or shut in, the affected wells for an indeﬁnite period of time.

In addition, San Mateo’s and Pronto’s gathering, processing and transportation assets connect to other pipelines
or facilities owned and operated by unafﬁliated third parties. The continuing operation of, and our continuing access
to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These
pipelines, plants, salt water disposal wells and other midstream facilities may become unavailable because of
testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory
requirements and curtailments of receipt or deliveries due to insufﬁcient capacity or because of damage from
severe weather conditions or other operational issues. In addition, if San Mateo’s or Pronto’s costs to access and
transport on these third-party pipelines signiﬁcantly increase, their proﬁtability could be reduced. If any such
increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport,
process or dispose of product, or if the volumes San Mateo or Pronto gathers, processes or transports do not
meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash ﬂows
could be adversely affected.

Insurance against all operational risks is not available to us.

Insurance against all operational risks is not available to us. We are not fully insured against all risks, including
development and completion risks that are generally not recoverable from third parties or insurance. Pollution and
environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe
that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore,
occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover,
insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms.
Changes in the insurance markets due to various factors may make it more difﬁcult for us to obtain certain types
of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would have
otherwise obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain
hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and
liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a
material adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

Because our reserves and production are concentrated in a few core areas, problems with production
in and markets for a particular area could have a material impact on our business.

Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties

in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the
Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing
focus for us, and approximately 95% of our total oil and natural gas production for 2022 was attributable to our
properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to
the Delaware Basin. We expect that substantially all of our capital expenditures in 2023 will continue to be in
the Delaware Basin, with the exception of amounts allocated to limited operations and certain non-operated well
opportunities in our South Texas and Haynesville shale positions.

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MATADOR RESOURCES COMPANY

The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our
oil and natural gas production due to signiﬁcant competition for access to gathering systems, pipelines, processing
and reﬁnery facilities and oil, condensate and produced water trucking operations. Due to the concentration of
our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from
our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of
production, availability of equipment, facilities, personnel or services, signiﬁcant governmental regulation, natural
disasters, adverse weather conditions or plant closures for scheduled maintenance. Due to our concentration of
properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of
oil and natural gas and the wellhead price we receive for our production. See “—Risks Related to our Financial
Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and
the wellhead price we receive for our production could adversely affect our business, ﬁnancial condition, results of
operations and cash ﬂows.”

Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical

storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and
equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely
manner. For example, in recent years, including in February 2021 and December 2022, the Delaware Basin has
experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and
freezing temperatures have resulted in shut ins of producing wells, power outages, curtailments in trucking,
delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have
also experienced periods of severe ﬂooding that impacted our operations as well as many other operators in the
area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our
operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather.

Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane
Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational
interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future
storms might cause more severe damage and interruptions or disrupt our ability to market production from our
operating areas, including the Eagle Ford shale and the Delaware Basin.

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of

the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they
might have on other companies that have a more diversiﬁed portfolio of properties. For example, our operations in
the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities
and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material
adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

There is no guarantee that we will be successful in optimizing our spacing, drilling and completions
techniques in order to maximize our rate of return, cash ﬂow from operations and shareholder value.

As we accumulate and process geological and production data, we attempt to create a development plan,
including well spacing and completion design, that maximizes our rate of return, cash ﬂow from operations and
shareholder value. Due to many factors, however, including some beyond our control, there is no guarantee that
we will be able to ﬁnd the optimal plan. Future drilling and completion efforts may impact production from existing
wells, and parent-child well effects may impact future well productivity as a result of timing, spacing proximity
or other factors. If we are unable to design and implement an effective spacing, drilling and completions strategy, it
may have a material adverse effect on our ﬁnancial condition, results of operations and cash ﬂows.

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Certain of our properties are in areas that may have been partially depleted or drained by offset wells,
and certain of our wells may be adversely affected by actions other operators may take when drilling,
completing or operating wells that they own.

Certain of our properties are in areas that may have already been partially depleted or drained by earlier offset

drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling
and completing additional wells, which could adversely affect our operations. When a new well is completed and
produced, the pressure differential in the vicinity of the well causes the migration of reservoir ﬂuids toward the new
wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential
locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved
reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause
production from our wells to be shut in for indeﬁnite periods of time, could result in increased lease operating
expenses and could adversely affect the production and reserves from our wells after they re-commence
production. We have no control over the operations or activities of offsetting operators.

Multi-well pad drilling may result in volatility in our operating results.

We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not produced until other

wells being drilled on the pad at the same time are drilled and completed, multi-well pad drilling delays the
commencement of production from wells drilled on a given pad, which may cause volatility in our operating results.
In addition, problems affecting one well could adversely affect production from other wells on the same pad. As
a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in
ongoing production. Additionally, infrastructure expansion, including more complex facilities and takeaway capacity,
could become challenging in project development areas. Managing capital expenditures for infrastructure expansion
could cause economic constraints when considering design capacity.

The unavailability or high cost of drilling rigs, completion equipment and services, supplies and
personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability
to establish and execute exploration and development plans within budget and on a timely basis,
which could have a material adverse effect on our business, ﬁnancial condition, results of operations
and cash ﬂows.

Shortages or the high cost of drilling rigs, completion equipment and services, drill pipe, casing and other tubular

goods, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations.
When drilling activity in the United States or a particular operating area increases, associated costs typically also
increase, including those costs related to drilling rigs, equipment, supplies, drill pipe, casing and other tubular goods,
including sand and other proppants, and personnel and the services and products of other industry vendors. These
costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical
prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability
to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business,
ﬁnancial condition, results of operations and cash ﬂows. In addition, should oil and natural gas prices decline,
third-party service providers may face ﬁnancial difﬁculties and be unable to provide services. A reduction in the number
of service providers available to us may negatively impact our ability to retain qualiﬁed service providers, or obtain
such services at costs acceptable to us. Further, supply chain disruptions being experienced throughout the United
States may limit our ability to procure the necessary products and services for drilling and completing wells,
which could cause delays in our drilling and completion activities which, in turn, could adversely affect our business,
ﬁnancial condition, results of operations and cash ﬂows.

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MATADOR RESOURCES COMPANY

In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing
equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear
of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas ﬁelds characterized
by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew
shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were
to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business,
ﬁnancial condition, results of operations and cash ﬂows.

If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing
operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable
environmental rules, our ability to produce oil and natural gas commercially and in commercial
quantities could be impaired.

We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain
sufﬁcient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing,
could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced
severe drought. As a result, we may experience difﬁculty in securing the necessary volumes of water for our
operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on
our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of
fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water,
drilling ﬂuids and other wastes associated with the exploration, development and production of oil and natural gas.
Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and
use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs
and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which
could have a material adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

If regulatory changes prevent our ability to continue to pool wells in the manner we have been, it could
have a material adverse impact on our future production results.

In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not
pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in
order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation
wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such
wells, the applicable state agency denies or signiﬁcantly delays the permitting of such wells, legislation is enacted
that negatively impacts the current process under which such wells are permitted or litigation challenges the
regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to
drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our
anticipated future production.

Construction of midstream projects subjects us to risks of construction delays, cost over-runs,
limitations on our growth and negative effects on our ﬁnancial condition, results of operations, cash
ﬂows and liquidity.

From time-to-time, we, through San Mateo, Pronto or otherwise, plan and construct midstream projects, some

of which may take a number of months before commercial operation, such as construction of oil, natural gas
and produced water gathering or transportation systems, construction of natural gas processing plants, drilling of
commercial salt water disposal wells and construction of related facilities. These projects are complex and subject
to a number of factors beyond our control, including delays from third-party landowners, the permitting process,
government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions,

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71

environmental hazards, ﬁnancing, accidents, weather and other factors. Any delay in the completion of these
projects could have a material adverse effect on our business, results of operations, liquidity and ﬁnancial condition.
The construction of produced water disposal facilities, pipelines and gathering and processing facilities requires the
expenditure of signiﬁcant amounts of capital, which may exceed our estimated costs. Estimating the timing and
expenditures related to these development projects is very complex and subject to variables that can signiﬁcantly
increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and ﬁnancial
condition could be adversely affected. This level of development activity requires signiﬁcant effort from our
management and technical personnel and places additional requirements on our ﬁnancial resources and internal
ﬁnancial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the
skills required to bring complicated projects to successful conclusions.

Our identiﬁed drilling locations are scheduled over several years, making them susceptible to
uncertainties that could materially alter the occurrence or timing of their drilling.

Our management team has identiﬁed and scheduled drilling locations in our operating areas over a multi-year
period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas
prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital,
approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral
lengths greater than one mile have become increasingly common in the Delaware Basin, we may have to cooperate
with other operators to ensure that our acreage is included in drilling units or otherwise developed. In January 2021,
the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal
drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation and the Social
Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the
restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal
actions related to the natural gas industry remains unclear. Should these or other limitations or prohibitions be
imposed or continue to be applied, our drilling locations on federal lands may not be drilled as scheduled. The ﬁnal
determination on whether to drill any of the identiﬁed locations will be dependent upon the factors described
elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to
our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have
identiﬁed will be drilled within our expected timeframe, or at all, or if we will be able to economically produce
hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially
different from our current expectations, which could adversely affect our business, ﬁnancial condition, results of
operations and cash ﬂows.

Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next
several years unless production is established on units containing the acreage.

At December 31, 2022, we had leasehold interests in approximately 23,100 net acres across all of our areas of

interest that are not currently held by production and are subject to leases with primary or renewed terms that
expire prior to 2028. Unless we establish and maintain production, generally in paying quantities, on units containing
these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases
may increase signiﬁcantly, and we may not be able to renew such leases on commercially reasonable terms or at
all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could
become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases,
we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ
from our current expectations, which could adversely affect our business, ﬁnancial condition, results of operations
and cash ﬂows.

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MATADOR RESOURCES COMPANY

The 2-D and 3-D seismic data and other advanced technologies we use cannot eliminate exploration
risk, which could limit our ability to replace and grow our reserves and materially and adversely affect
our results of operations and cash ﬂows.

We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities

where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon
indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible.
We could incur losses by drilling unproductive wells based on these technologies. Furthermore, the acquisition of
seismic and geological data can be expensive and require the incurrence of various risks and liabilities, and we may
not be able to license or obtain such data at an acceptable cost. Poor results from our exploration and development
activities could limit our ability to replace and grow reserves and adversely affect our business, ﬁnancial condition,
results of operations and cash ﬂows.

RISKS RELATED TO THIRD PARTIES

Financial difﬁculties encountered by our oil and natural gas purchasers, third-party operators or other
third parties could decrease our cash ﬂows from operations and adversely affect the exploration and
development of our prospects and assets.

We derive most of our revenues from the sale of our oil, natural gas and NGLs to unafﬁliated third-party

purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to
the concentration of our oil and natural gas receivables with several signiﬁcant customers. For the years ended
December 31, 2022, 2021 and 2020, we had three, three and two signiﬁcant purchasers, respectively, that collectively
accounted for approximately 70%, 72% and 65%, respectively, of our total oil, natural gas and NGL revenues.
We cannot ensure that we will continue to have ready access to suitable markets for our future production. If we
lost one or more of these customers and were unable to sell our production to other customers on terms we
consider acceptable, it could materially and adversely affect our business, ﬁnancial condition, results of operations
and cash ﬂows. Furthermore, we cannot predict the extent to which counterparties’ businesses would be
impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other
conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by ﬁnancial
problems encountered by them could have an immediate negative effect on our results of operations and cash ﬂows.

In addition to credit risk related to purchasers of our production, we also face credit risk through receivables from

joint interest owners on properties we operate and from San Mateo’s and Pronto’s customers. Joint interest
receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in
our wells primarily based on their ownership in leases on which we drill. We are generally unable to control which
co-owners participate in our wells. Liquidity and cash ﬂow problems encountered by our joint interest owners or the
third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of
a project. Our joint interest owners may be unwilling or unable to pay their share of the costs of projects as they
become due. In the case of a farmout party, we would have to ﬁnd a new farmout party or obtain alternative funding
in order to complete the exploration and development of the prospects subject to a farmout agreement. In the
case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs.
If we are not able to obtain the capital necessary to fund either of these contingencies or ﬁnd a new farmout party,
our results of operations and cash ﬂows could be negatively affected.

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73

The marketability of our production is dependent upon oil, natural gas and NGL gathering, processing
and transportation facilities, and the unavailability of satisfactory oil, natural gas and NGL gathering,
processing and transportation arrangements could have a material adverse effect on our revenue.

The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements

may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a
ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for,
and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability
to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines,
processing facilities and oil and condensate trucking operations. Such systems and operations include those of
San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation
of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who
operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable
terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing
facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line
loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds,
line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and
curtailments of receipt or deliveries due to insufﬁcient capacity or because of damage from severe weather conditions
or other operational issues.

We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines,
gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize
revenue from those wells until production arrangements were made to deliver our production to market.
Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain
mineral interest owners in order to maintain our leases.

The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively
impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these
pipelines signiﬁcantly increase, our proﬁtability could be reduced. Third parties control when or if their facilities
are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing
interruptions and capacity and infrastructure constraints associated with natural gas production. While we have
entered into natural gas processing and transportation agreements covering the anticipated natural gas production
from a signiﬁcant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance
can be given that these agreements will alleviate these issues completely, and we may be required to pay deﬁciency
payments under such agreements if we do not meet the gathering or processing commitments, as applicable.
We may experience similar interruptions and processing capacity constraints as we continue to explore and develop
our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2023. If we were required to shut
in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of
these facilities, it could have a material adverse effect on our business, ﬁnancial condition, results of operations
and cash ﬂows.

We conduct a portion of our operations through joint ventures, which subjects us to additional risks
that could have a material adverse effect on the success of these operations, our ﬁnancial position,
results of operations or cash ﬂows.

We own and operate substantially all of our midstream assets in Eddy County, New Mexico and Loving County,

Texas through San Mateo, and we have and may continue to enter into other joint venture arrangements in the
future. The nature of a joint venture requires us to share a portion of control with unafﬁliated third parties. If our joint
venture partners do not fulﬁll their contractual and other obligations, the affected joint venture may be unable
to operate according to its business plan, and we may be required to increase our level of ﬁnancial commitment or

FORM 10-K PART I

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MATADOR RESOURCES COMPANY

seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet
our ﬁnancial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with
respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can
be no assurance that any joint venture will be successful or generate cash ﬂows at the level we have anticipated, or
at all. Differences in views among joint venture participants could also result in delays in business decisions or
otherwise, failures to agree on major issues, operational inefﬁciencies and impasses, litigation or other issues. We
provide management functions for certain joint ventures and may provide such services for future joint venture
arrangements, which may require additional time and attention of management or require us to hire or contract
additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any
other difﬁculties that cause a joint venture to deviate from its original business plan could have a material adverse
effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

Because of the natural decline in production in the regions of San Mateo’s and Pronto’s midstream
operations, San Mateo’s and Pronto’s long-term success depend on their ability to obtain new sources
of products, which depends on certain factors beyond San Mateo’s and Pronto’s control. Any decrease
in supplies to its midstream facilities could adversely affect San Mateo’s and Pronto’s business and
operating results.

San Mateo’s and Pronto’s midstream facilities are, or will be, connected to oil and natural gas wells operated by

us or by third parties from which production will naturally decline over time, which means that the cash ﬂows
associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of
these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on
San Mateo’s and Pronto’s gathering systems and the utilization rate at its other midstream facilities, San Mateo
and Pronto must continually obtain new sources of products. San Mateo’s and Pronto’s ability to obtain additional
sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and
production activity near its gathering and transportation systems and other midstream facilities. San Mateo and
Pronto have no control over the level of activity in the areas of their operations, the amount of reserves associated
with the wells or the rate at which production from a well will decline. In addition, San Mateo and Pronto have no
control over producers or their drilling or production decisions, which are affected by, among other things, prevailing
and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations,
governmental regulations, the availability of drilling rigs, other production and development costs and the availability
and cost of capital.

We have entered into certain long-term contracts that require us to pay fees to our service providers
based on minimum volumes regardless of actual volume throughput and that may limit our ability to
use other service providers.

From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced
water gathering or transportation agreements, natural gas processing agreements, NGL transportation agreements,
produced water disposal agreements or similar commercial arrangements with midstream companies, including
San Mateo. Certain of these agreements require us to meet minimum volume commitments, often regardless of
actual throughput. Reductions in our drilling activity could result in insufﬁcient production to fulﬁll our obligations
under these agreements. As of December 31, 2022, our long-term contractual obligations under agreements with
minimum volume commitments totaled approximately $833.1 million over the terms of the agreements. If we have
insufﬁcient production to meet the minimum volume commitments under any of these agreements, our cash
ﬂow from operations will be reduced, which may require us to reduce or delay our planned investments and capital
expenditures or seek alternative means of ﬁnancing, all of which may have a material adverse effect on our results
of operations.

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Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future
leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use
other gathering, processing, disposal and transportation service providers, even if such service providers are able
to offer us more favorable pricing or more efﬁcient service.

We do not own all of the land on which our midstream assets are located, which could disrupt
our operations.

We do not own all of the land on which our midstream assets are located, and we are therefore subject to the

possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do
not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the
rights to land owned by third parties and governmental agencies for a speciﬁc period of time. Our loss of these
rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations
on the affected land or ﬁnd alternative locations for our operations at increased costs, each of which could have a
material adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

Competition in the oil and natural gas industry is intense, making it more difﬁcult for us to acquire
properties, market oil and natural gas, provide midstream services and secure trained personnel, and
our competitors may use superior technology and data resources that we may be unable to afford.

Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to ﬁnd

and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and
to consummate transactions in a highly competitive environment for acquiring properties, to market oil and natural
gas and to secure trained personnel. Similarly, our midstream business, and particularly the success of San Mateo and
Pronto, depends in part on our ability to compete with other midstream service companies to attract third-party
customers to our midstream facilities. San Mateo and Pronto compete with other midstream companies that
provide similar services in their areas of operations, and such companies may have legacy relationships with producers
in those areas and may have a longer history of efﬁciency and reliability. Also, there is substantial competition for
capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ
ﬁnancial, technical, technological and personnel resources substantially greater than ours. Those companies may be
able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for
and purchase a greater number of properties and prospects than our ﬁnancial, technical, technological or personnel
resources permit. As our competitors use or develop new technologies, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. We
cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to
us. One or more of the technologies that we use or that we may implement in the future may become obsolete,
and our operations may be adversely affected.

In addition, other companies may be able to offer better compensation packages to attract and retain qualiﬁed
personnel than we are able to offer. The cost to attract and retain qualiﬁed personnel has increased in recent years
due to competition and may increase substantially in the future. We may not be able to compete successfully
in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing
hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material
adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

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Strategic relationships upon which we may rely are subject to change, which may diminish our ability
to conduct our operations.

Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural
gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close
working relationships with industry participants and on our ability to select and evaluate suitable acquisition
opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our
ability to grow may be impaired.

To develop our business, we endeavor to use the business relationships of our management, Board of Directors
and special Board advisors to enter into strategic relationships, which may take the form of contractual arrangements
with other oil and natural gas companies and service companies, including those that supply equipment and other
resources that we expect to use in our business, as well as midstream companies and certain ﬁnancial institutions.
We may not be able to establish these strategic relationships, or if established, we may not be able to maintain
them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or
undertake activities we would not otherwise be inclined to incur or undertake in order to fulﬁll our obligations
to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our
business prospects may be limited, which could diminish our ability to conduct our operations.

We have limited control over activities on properties we do not operate.

We are not the operator on some of our properties in Northwest Louisiana, particularly in the Haynesville shale.

We also have other non-operated acreage positions in Southeast New Mexico, West Texas and South Texas.
Because we are not the operator for these properties, our ability to exercise inﬂuence over the operations of these
properties or their associated costs is limited. Our dependence on the operators and other working interest owners
of these projects and our limited ability to inﬂuence operations and associated costs, or control the risks, could
materially and adversely affect the drilling results, reserves and future cash ﬂows from these properties. The
success and timing of our drilling and development activities on properties operated by others therefore depends
upon a number of factors, including:

•

•

•

the timing and amount of capital expenditures;

the operator’s expertise and ﬁnancial resources;

the rate of production of reserves, if any;

• approval of other participants in drilling wells; and

• selection and implementation or execution of technology.

In areas where we do not have the right to propose the drilling of wells, we may have limited inﬂuence on when,

how and at what pace our properties in those areas are developed. Further, the operators of those properties may
experience ﬁnancial problems in the future or may sell their rights to another operator not of our choosing, both of
which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the
operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these
properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production
and associated revenues from these properties until the operator elects to return them to production.

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RISKS RELATED TO LAWS AND REGULATIONS

Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands,
which are subject to administrative permitting requirements and potential federal legislation, regulation
and orders that may limit or restrict oil and natural gas operations on federal lands.

At December 31, 2022, Matador held approximately 129,400 net leasehold and mineral acres in the Delaware
Basin in Eddy and Lea Counties, New Mexico and in Loving County, Texas, of which approximately 39,500 net acres,
or about 31%, was on federal lands administered by the BLM. In addition to permits issued by state and local
authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and
natural gas activities on federal lands can take signiﬁcantly longer than the permitting process for oil and natural
gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and
have a material adverse effect on our business. These BLM leases contain relatively standardized terms and require
compliance with detailed regulations and orders, which are subject to change. For example, on August 16, 2022,
H.R. 5376, commonly known as the Inﬂation Reduction Act of 2022 (the “IRA”), was enacted. Pursuant to the IRA,
the royalty rate for federal leases issued on or after August 16, 2022 was increased to 16.67 percent. These
operations are also subject to BLM rules regarding engineering and construction speciﬁcations for production
facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting
of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules
could result in increased compliance costs for our operations, which in turn could have a material adverse effect on
our business and results of operations. Under certain circumstances, the BLM may require our operations on federal
leases to be suspended or terminated. In addition, litigation related to leasing and permitting of federal lands could
also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal
leasehold. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting
the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease
Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits.
Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of
these and similar federal actions remains unclear. Should these or other limitations or prohibitions be imposed or
continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. At the
federal level, various policy makers, regulatory agencies and political candidates, including President Biden, have
also proposed restrictions on hydraulic fracturing, including its outright prohibition. It is possible that any such
restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations
or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material
adverse impact on our business, ﬁnancial condition, results of operations and cash ﬂows.

Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires

federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to
signiﬁcantly impact the environment. In the course of such evaluations, an agency will prepare an environmental
assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal
relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact
statement that may be made available for public review and comment. This process, including any additional
requirements that may be implemented or litigation regarding the process, has the potential to delay or even halt
development of future oil and natural gas projects with NEPA applicability.

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We are subject to government regulation and liability, including complex environmental laws, which
could require signiﬁcant expenditures.

The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas

in the United States are subject to many federal, state and local laws, rules and regulations, including complex
environmental laws and regulations. A change in the presidential administration, as well as a closely divided Congress,
may also increase the uncertainty with regard to potential changes in these laws, rules and regulations and the
enforcement of any new legislation or directives by governmental authorities. Matters subject to regulation include
discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of
properties, taxation, gathering and transportation of oil, natural gas and NGLs, gathering and disposal of produced
water, environmental matters and health and safety criteria addressing worker protection. Under these laws and
regulations, we may be required to make large expenditures that could materially adversely affect our ﬁnancial
condition, results of operations and cash ﬂows. If existing laws and regulations are revised or reinterpreted, or if
new laws and regulations become applicable to our operations or those of our service providers, such changes may
affect the costs that we pay for such services or the results of business. In addition to expenditures required in
order for us to comply with such laws and regulations, expenditures required by such laws and regulations could
also include payments and ﬁnes for:

• personal injuries;

• property damage;

• containment and clean-up of oil, produced water and other spills;

• venting, ﬂaring or other emissions;

• management and disposal of hazardous materials;

•

remediation, clean-up costs and natural resource damages; and

• other environmental damages.

We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure

to comply with these laws and regulations may also result in the suspension or termination of our operations and
subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or
other remedial obligations. The costs of remedying noncompliance may be signiﬁcant, and remediation obligations
could adversely affect our ﬁnancial condition, results of operations and leasehold acreage. Laws, rules and
regulations protecting the environment have changed frequently and the changes often include increasingly stringent
requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal
of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to
be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we
performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal
and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled
or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or
non-governmental organizations such as environmental groups, may also pursue legal actions against us based on
alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have
been ﬁled in some states against others in our industry alleging that ﬂuid injection or oil and natural gas extraction
have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste
disposal. Private parties may also pursue legal actions challenging permitting programs that authorize certain of our
operations. For example, it is possible that courts could vacate relevant NWPs as such potential permit coverage
relates to activities in the oil and natural gas sector, or the Biden administration could choose to suspend the
availability of NWPs in the future, thereby forcing our relevant operations to seek coverage under individual permits
under CWA Section 404 (which is a longer and more administratively complex process that is subject to NEPA).

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Part of the regulatory environment in which we operate includes, in some cases, federal requirements for
obtaining environmental assessments, environmental impact statements and/or plans of development before
commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our
operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to
protect various wildlife. For example, on November 25, 2022, a ﬁnal rule was published that, among other things,
will list the lesser prairie-chicken as endangered under the ESA in certain portions of southeastern New Mexico
where we operate. The effective date of the ﬁnal rule is currently set to be March 27, 2023. We participate in
candidate conservation agreements for the lesser prairie-chicken, as well as the sand dune lizard and the Texas
hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain
times. The listing of the lesser prairie-chicken as endangered, participation in such candidate conservation agreements
or the designation of previously unprotected species as threatened or endangered species could prohibit drilling
or other operations in certain of our operating areas, cause us to incur increased costs arising from species
protection measures or result in limitations on our exploration and production and midstream activities, each of
which could have a material adverse impact on our business, ﬁnancial condition, results of operations and cash
ﬂows. See “Business—Regulation.”

We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated
or reduced certain federal income tax deductions currently available with respect to oil and natural gas
exploration and production activities as a result of future legislation, which could adversely affect our
business, ﬁnancial condition, results of operations and cash ﬂows.

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural

gas products we sell and, for many of our wells, sales and use taxes on signiﬁcant portions of our drilling and
operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction
of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to
impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for
our natural gas processed in New Mexico.

Historically, we have generated and carried forward net operating losses (“NOL”) in amounts sufﬁcient to offset

substantially all of our taxable income and, thus, have not incurred material federal or state income tax liabilities.
As of December 31, 2022, we had utilized all or substantially all of our federal NOL carryovers. As a result, unless
additional NOLs are generated, we expect that we will begin to incur material federal and state income tax liabilities.

Additionally, the IRA contains a number of revisions to the Internal Revenue Code, including (i) a 15% corporate

minimum income tax for certain corporations with more than $1 billion in average adjusted ﬁnancial statement
income for the three-year tax period ending with the corporation’s current tax year, (ii) a 1% excise tax on corporate
stock repurchases in tax years beginning after December 31, 2022 and (iii) expanded business tax credits and
incentives for the development of clean energy projects and the production of clean energy. The impact of the 15%
corporate minimum tax will depend on our results of operations each year and anticipated guidance from the
Internal Revenue Service. While we do not expect such minimum tax (or any other tax provision contained in the
IRA) to have any immediate material impact, we will continue to evaluate its future impact as further information
becomes available.

In addition, there has been a signiﬁcant amount of discussion by legislators and presidential administrations

concerning a variety of energy tax proposals at the U.S. federal level. Periodically, legislation is introduced to eliminate
certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production
companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance
for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and
development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and

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MATADOR RESOURCES COMPANY

(iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with
the exploration for, or development of, oil or natural gas within the United States. The passage of any legislation or
any other similar change in U.S. federal income or state tax law could affect certain tax deductions that are currently
available with respect to oil and natural gas exploration and production activities and could negatively impact our
ﬁnancial condition, results of operations and cash ﬂows.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in
increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into
rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells
in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the
Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated
at the state and local level through permitting and compliance requirements. Federal, state and local laws or
regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed
or implemented. In past sessions, Congress has considered, but has not passed, legislation to amend the SDWA,
to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using ﬂuids
containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the
hydraulic fracturing process. Also at the federal level, in March 2015, the BLM issued ﬁnal rules, including new
requirements relating to public disclosure, wellbore integrity and handling of ﬂowback water, to regulate hydraulic
fracturing on federal and Indian lands, but these rules never became effective. These rules were rescinded by rule in
December 2017. The rescission was challenged, and the challenge remains pending before the Ninth Circuit Court
of Appeals. Separately, in 2016, BLM issued the 2016 Waste Prevention Rule to address ﬂaring, venting and leaks
from oil and natural gas operations on federal lands. Following litigation, the 2016 Waste Prevention Rule was
vacated. However, the August 16, 2022 Inﬂation Reduction Act contains a suite of provisions addressing onshore
and offshore oil and natural gas development under federal leases. Under the authority of the Inﬂation Reduction
Act, on November 30, 2022, BLM proposed new regulations to reduce the waste of natural gas from venting, ﬂaring,
and leaks during oil and natural gas production activities on federal and Indian leases.

Various policymakers, regulatory agencies and political candidates at the federal, state and local levels have
proposed restrictions on hydraulic fracturing, including its outright prohibition. Any such restrictions on hydraulic
fracturing on federal lands could adversely impact our operations in the Delaware Basin, and an outright prohibition
would adversely impact essentially all of our operations. In addition, a number of states and local regulatory authorities
are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing,
including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use
of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on
high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety
of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions
are the subject of legal challenges. Texas and New Mexico have adopted regulations that require the disclosure of
information regarding the substances used in the hydraulic fracturing process. Recently, bills have been introduced in
the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing activities, including
prohibiting the injection of fresh water in such operations. Although such bills have not passed, similar laws, rules,
regulations or orders, if passed at the local, state or federal level could limit our operations.

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The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or

prohibiting, the hydraulic fracturing process could make it more difﬁcult to complete oil and natural gas wells in
unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal
legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to
additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which
could adversely affect our business and results of operations.

The potential adoption of federal, state and local legislation and regulations intended to address
potential induced seismicity in the areas in which we operate could restrict our drilling and production
activities, as well as our ability to dispose of produced water gathered from such activities, which
could decrease our and San Mateo’s revenues and result in increased costs and additional operating
restrictions or delays.

State and federal regulatory agencies recently have focused on a possible connection between the operation of

injection wells used for produced water disposal and the increased occurrence of seismic activity. When caused by
human activity, such events are called “induced seismicity.” Regulatory agencies at all levels are continuing to study
the possible link between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits
have been ﬁled in some states against others in our industry alleging that ﬂuid injection or oil and natural gas
extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating
waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are
seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal
wells or otherwise, to assess the relationship between seismicity and the use of such wells.

While the scientiﬁc community and regulatory agencies at all levels are continuing to study the possible link
between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas and
New Mexico, have modiﬁed their regulations or guidance to mitigate potential causes of induced seismicity. For
example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in
New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico
with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced
reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially
shutting in wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event.
See “Business—Regulation—Environmental, Health and Safety Regulation.”

Increased seismicity in areas in which we operate could result in additional regulation and restrictions on the use

of injection wells by us or by third parties whom we may contract with to dispose of produced water. Additional
regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil
and natural gas activities. Any one or more of these developments may result in operational delays, increase our
operating and compliance costs or otherwise adversely affect our operations. We and San Mateo dispose of large
volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it
into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While
these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change,
which could result in the imposition of more stringent operating constraints or new monitoring and reporting
requirements, owing to, among other things, concerns of the public or governmental authorities regarding such
gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict
our ability to dispose of produced water gathered from drilling and production activities could adversely impact our
business, cash ﬂows and results of operations and could decrease our and San Mateo’s revenues and result in
increased costs and additional operating restrictions or delays.

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Legislation or regulations restricting emissions of greenhouse gases or promoting the development
of alternative sources of energy could result in increased operating costs and reduced demand for the
oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt
our production and cause us to incur signiﬁcant costs in preparing for or responding to those effects.

We believe it is likely that scientiﬁc and political attention to issues concerning the extent, causes of and

responsibility for climate change will continue, with the potential for further regulations and litigation that could affect
our operations. Our operations result in greenhouse gas emissions. The EPA has published its ﬁnal ﬁndings that
emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and
welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s
atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a
cap and trade program, but that legislation did not pass. Further, various states have considered or adopted
legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally,
in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the
creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016,
requires countries to review and “represent a progression” in their intended NDCs, which set greenhouse gas
emission reduction goals, every ﬁve years beginning in 2020. The United States exited the Paris Agreement in
November 2020 but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its
NDC submittal, setting a goal to achieve a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse
gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow
Climate Pact, which includes a range of measures designed to address climate change, including but not limited
to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the
advancement of the development of alternative sources of energy. On August 16, 2022, the IRA created the
Methane Emissions Reduction Program to incentivize methane emission reductions and, for the ﬁrst time ever,
imposes a fee on GHG emissions from certain facilities that exceed speciﬁed emissions levels. Further, on
November 11, 2022, the EPA issued a supplemental notice of proposed rulemaking on methane and GHG emissions
from new and existing sources in the oil and natural gas industry. On December 6, 2022, the EPA published a
supplemental proposal to reduce methane and volatile organic chemicals emissions from the oil and natural gas
sector, which strengthens and expands the EPA’s November 1, 2021 proposed revisions to the New Source
Performance Standards program established under Section 111 of the CAA. On December 23, 2022, the EPA
proposed a rule that would enable states to implement more stringent methane emissions standards than the
federal guidelines require. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico
would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of
governors committed to reducing GHG emissions consistent with the goals of the Paris Agreement. The stated
objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by
2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an
“enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented
rules regarding the reduction of natural gas waste and the control of emissions that, among other items, prohibits
ﬂaring in certain circumstances and requires upstream and midstream operators to reduce natural gas waste by
a ﬁxed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED adopted rules
and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural
gas operations. In August 2022, the NMED issued a ﬁnal rule imposing additional controls on oil and natural gas
operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in
New Mexico state court. The EPA has begun adopting and implementing a comprehensive suite of regulations to
restrict GHG emissions under existing provisions of the CAA and the recent authority of the IRA. Legislative and
regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would,
require us to incur increased operating costs adversely affecting our proﬁts and could adversely affect demand for
the oil and natural gas we produce, depressing the prices we receive for oil and natural gas.

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In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have
an effect on the severity of weather (including hurricanes and ﬂoods), sea levels, the arability of farmland and water
availability and quality. If such effects were to occur, there is the potential for our exploration and production
operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful
winds or rising waters in low-lying areas, disruption of our production, less efﬁcient or non-routine operating
practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects.
Any future exploration and development activities and equipment could also be adversely affected by extreme
weather conditions such as hurricanes or freezing temperatures, which may cause a loss of production from
temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. Such
extreme weather conditions could also impact access to our drilling and production facilities for routine operations,
maintenance and repairs and the availability of and our access to, necessary third-party services, such as
gathering, processing, compression and transportation services. These constraints and the resulting shortages or
high costs could delay or temporarily halt our operations and materially increase our operation and capital costs,
which could have a material adverse effect on our business, ﬁnancial condition and results of operations. Signiﬁcant
physical effects of climate change could also have an indirect effect on our ﬁnancing and operations by disrupting
the transportation or process-related services provided by us or other midstream companies, service companies or
suppliers with whom we have a business relationship. We may not be able to recover through insurance some
or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition,
our hydraulic fracturing operations require large amounts of water. See “—Risks Related to our Operations—If we
are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to
dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to
produce oil and natural gas commercially and in commercial quantities could be impaired.” Should climate change or
other drought conditions occur, our ability to obtain water of a sufﬁcient quality and quantity could be impacted and
in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.

The adoption of legislation or regulatory programs to reduce greenhouse gas emissions could require us to incur

increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions
allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs
could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.
Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have a material
adverse effect on our business, ﬁnancial condition and results of operations. Reduced demand for the oil and
natural gas that we produce could also have the effect of lowering the value of our reserves. In addition, there have
also been efforts in recent years to inﬂuence the investment community, including investment advisors and certain
family foundations and sovereign wealth, pension and endowment funds, promoting divestment of fossil fuel
equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such
environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere
with our business activities, operations and ability to access capital. Additionally, the threat of climate change has
resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political
candidates at the federal, state and local levels have proposed bans of new leases for production of minerals on
federal properties and various restrictions on hydraulic fracturing, including its outright prohibition. In January 2021,
the Biden administration issued the Biden Administration Federal Lease Orders, limiting the issuance of federal
drilling permits and other federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of
Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in
the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions remains
unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural
gas operations on federal lands could be adversely impacted.

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President Biden and the Democratic Party, which now controls the U.S. Senate, have identiﬁed climate change

as a priority, and new executive orders, regulatory action and/or legislation targeting greenhouse gas emissions,
promoting energy efﬁciency or the development and consumption of alternative forms of energy, or prohibiting or
restricting oil and natural gas development activities in certain areas, have been and likely will be proposed and/or
promulgated during the Biden administration. In addition, the Biden administration has already issued multiple
executive orders pertaining to environmental regulations and climate change, including the Executive Order on
Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and the
Executive Order on Tackling the Climate Crisis at Home and Abroad. In the latter executive order, President Biden
established climate change as a primary foreign policy and national security consideration, afﬁrmed that achieving
net-zero greenhouse gas emissions by or before 2050 is a critical priority, afﬁrmed his administration’s desire
to establish the United States as a leader in addressing climate change and generally further integrated climate
change and environmental justice considerations into government agencies’ decision-making, among other
measures. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of
lawsuits or investigations brought by public and private entities against oil and natural gas companies in
connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations,
we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could
be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating
factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our
ﬁnancial performance is highly uncertain because we are unable to predict, for a multitude of individual
jurisdictions, the outcome of political decision-making processes and the variables and trade-offs that inevitably
occur in connection with such processes.

New climate disclosure rules proposed by the SEC could increase our costs of compliance and adversely
impact our business.

On March 21, 2022, the SEC released proposed new rules that would require signiﬁcantly expanded climate-
related disclosures in SEC ﬁlings, including certain climate-related risks, climate-related metrics and GHG emissions,
information about climate-related targets and goals, transition plans, if any, and extensive attestation requirements.
The proposed rules include certain phase-in compliance dates for disclosure of Scope 1, 2 and 3 GHG emissions. As
initially proposed, large accelerated ﬁlers such as us would be obligated to disclose Scope 1 and 2 GHG emissions
for ﬁscal year 2023 in the 2024 ﬁling year and disclose Scope 3 GHG emissions for ﬁscal year 2024 in the 2025 ﬁling
year. While we are currently assessing the proposed rule, the ﬁnal form and substance of the rule is not yet known,
and at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the
rule. To the extent the rule is ﬁnalized as proposed, we could incur signiﬁcant additional costs relating to the
assessment and disclosure of climate-related risks, including costs relating to monitoring, collecting, analyzing and
reporting the new metrics and implementing systems and procuring additional internal and external personnel with
the requisite skills and expertise to serve those functions. These additional costs or changes in operations could
have a material adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows. We may
also face increased litigation risks related to disclosures made pursuant to the rule if ﬁnalized as proposed. In
addition, enhanced climate disclosure requirements could accelerate the trend of certain investors and lenders
restricting or seeking more stringent conditions with respect to their investments in carbon-intensive sectors.
Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public
ﬁlings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures
to be misleading or deﬁcient.

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New regulations on all emissions from our operations could cause us to incur signiﬁcant costs.

In recent years, the EPA issued ﬁnal rules to subject oil and natural gas operations to regulation under the New

Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs
under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS
standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators,
storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to
our operations, including the installation of new equipment to control emissions. The EPA ﬁnalized a more stringent
National Ambient Air Quality Standard (“NAAQS”) for ozone in October 2015. The EPA ﬁnished promulgating ﬁnal
area designations under the new standard in 2018, which, to the extent areas in which we operate have been
classiﬁed as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for
additional monitoring and testing, as well as a more cumbersome permitting process. To the extent regions
reclassiﬁed as non-attainment areas under the lower ozone standard have begun implementing new, more stringent
regulations, those regulations could also apply to our or San Mateo’s customers’ operations. Generally, it takes
states several years to develop compliance plans for their non-attainment areas. In November 2016, BLM issued
ﬁnal rules relating to the venting, ﬂaring and leaking of natural gas by oil and natural gas producers who operate on
federal and Indian lands. The rules were designed to limit routine ﬂaring of natural gas, require the payment of
royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak
detection and repair. Following litigation, the 2016 Waste Prevention Rule was vacated. However, the August 16,
2022 IRA contains a suite of provisions addressing onshore and offshore oil and natural gas development under
Federal leases. Under the authority of the Inﬂation Reduction Act, on November 30, 2022, BLM proposed new
regulations to reduce the waste of natural gas from venting, ﬂaring, and leaks during oil and natural gas production
activities on Federal and Indian leases. If not withdrawn or signiﬁcantly revised, these proposed rules are expected
to result in an increase to our operating costs and changes in our operations. In November 2021, the EPA also
proposed new NSPS updates and emission guidelines (the “2021 Proposed Methane Rules”) to reduce methane
and other pollutants from the oil and gas industry. The EPA issued a supplemental notice of proposed rulemaking on
this topic in December 2022 to update, strengthen and expand the 2021 Proposed Methane Rules that would make
the proposed requirements more stringent and include sources not previously regulated under the oil and natural
gas source category. The EPA has announced that it plans to ﬁnalize these rulemakings in 2023. In addition, several
states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil
and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations
of the oil and natural gas industry remain a possibility and could result in increased compliance costs for our operations.

We may incur signiﬁcant costs and liabilities resulting from compliance with pipeline safety regulations.

Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity

management. For instance, the Department of Transportation, through PHMSA, has established a series of rules
that require pipeline operators to develop and implement integrity management programs for hazardous liquid
(including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The
Rustler Breaks Oil Pipeline System is subject to such rules. PHMSA also recently ﬁnalized rulemaking to expand
existing integrity management, reporting and records retention, and safety requirements to certain natural gas
transmission lines. Additional action by PHMSA with respect to pipeline integrity management requirements may
occur in the future. At this time, we cannot predict the cost of such requirements, but they could be signiﬁcant.
Moreover, violations of pipeline safety regulations can result in the imposition of signiﬁcant penalties.

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MATADOR RESOURCES COMPANY

Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with

pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the RRC and the
NMOCD could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new
or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance
that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of
operations or ﬁnancial position.

A change in the jurisdictional characterization of some of our assets by FERC or a change in policy
by FERC may result in increased regulation of our assets, which may cause our revenues to decline and
operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA.
We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to
establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-
regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation,
so the classiﬁcation and regulation of our gathering facilities are subject to change based on future determinations
by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by
FERC under the ICA. San Mateo’s Rustler Breaks Oil Pipeline System, which includes crude oil gathering and
transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains, is subject to
FERC jurisdiction. We believe the other crude oil pipelines in our gathering systems meet the traditional tests
FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a
pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined
on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts
or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased
regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

The rates of our regulated assets are subject to review and reporting by federal regulators, which could
adversely affect our revenues.

The Rustler Breaks Oil Pipeline System transports crude oil in interstate commerce. FERC regulates the rates,

terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an
economic interest were to ﬁle either a complaint against our tariff rates or protest any proposed increases to our
tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review.
If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could
order us to reduce our rates and to refund the amount by which the rate increases were determined to be
excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we
could be ordered to refund the excess we collected for up to two years prior to the date of the ﬁling of the
complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state
commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or
at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels
justiﬁed by our cost of service, the state commission could order us to reduce our rates. Any such reductions may
result in lower revenues and cash ﬂows.

In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues
received on the Rustler Breaks Oil Pipeline System and any other natural gas or crude oil pipeline that is determined
to be under the jurisdiction of FERC.

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Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders,
we could be subject to substantial penalties and ﬁnes.

Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current
violations of up to approximately $1.3 million per day for each violation and disgorgement of proﬁts associated with
any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for
inﬂation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC,
the Rustler Breaks Oil Pipeline System does transport crude oil in interstate commerce and, therefore, is subject
to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted
by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future
could subject us to civil penalty liability.

Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks
associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things,

established federal oversight and regulation of certain derivative products, including commodity hedges of the
type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to
promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has ﬁnalized certain
regulations, others remain to be ﬁnalized or implemented, and it is not possible at this time to predict when, or if,
this will be accomplished.

In 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major
energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the
United States District Court for the District of Columbia in 2012. However, in 2013, the CFTC proposed new rules
that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain
physical commodities, subject to exceptions for certain bona ﬁde hedging transactions. In 2016, the CFTC decided
to re-propose, rather than ﬁnalize, certain regulations, including limitations on speculative futures and swap
positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules
are not yet ﬁnal, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result
in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting
and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may
increase the cost of our derivative arrangements in the future.

If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase,

which would increase the volatility of revenues and may decrease the amount of credit available to us. Any
limitations or changes in our use of derivative arrangements could also materially affect our cash ﬂows, which could
adversely affect our ability to make capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which

some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural
gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing
regulations is to lower commodity prices.

Any of these consequences could have a material adverse effect on our business, ﬁnancial condition and results

of operations.

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MATADOR RESOURCES COMPANY

RISKS RELATING TO OUR COMMON STOCK

The price of our common stock has ﬂuctuated substantially and may ﬂuctuate substantially in the future.

Our stock price has experienced volatility and could vary signiﬁcantly as a result of a number of factors. In 2022,

our stock price ﬂuctuated between a high of $73.78 and a low of $37.01. In addition, the trading volume of our
common stock may continue to ﬂuctuate and cause signiﬁcant price variations to occur. In the event of a drop in the
market price of our common stock, you could lose a substantial part or all of your investment in our common stock.
In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the
operating performance of particular companies. These broad market ﬂuctuations may adversely affect the trading
price of our common stock.

Factors that could affect our stock price or result in ﬂuctuations in the market price or trading volume of our

common stock include:

• our actual or anticipated operating and ﬁnancial performance and drilling locations, including oil and natural

gas reserves estimates;

• quarterly variations in the rate of growth of our ﬁnancial indicators, such as net income per share, net

income and cash ﬂows, or those of companies that are perceived to be similar to us;

• changes in revenue, cash ﬂows or earnings estimates or publication of reports by equity research analysts;

• declaration of dividends or adjustments to our dividend policy;

• speculation in the press or investment community;

• announcement or consummation of acquisitions, dispositions or joint ventures by us;

• public reaction to our operations or plans, press releases, announcements and ﬁlings with the SEC;

•

•

the publication of research or reports by industry analysts regarding the Company, its competitors or our
industry;

the enactment of federal, state or local laws, rules or regulations that restrict our ability to conduct our
operations, such as the Biden Administration Federal Lease Orders;

• sales of our common stock by the Company, directors, ofﬁcers or other shareholders, or the perception that

such sales may occur;

• general ﬁnancial market conditions and oil and natural gas industry market conditions, including ﬂuctuations

in the price of oil, natural gas and NGLs;

• domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as

COVID-19 and its variants;

•

•

the realization of any of the risk factors presented in this Annual Report;

the recruitment or departure of key personnel;

• commencement of, involvement in or unfavorable resolution of litigation;

•

the success of our exploration and development operations, our midstream business (including San Mateo)
and the marketing of any oil, natural gas and NGLs we produce;

• changes in market valuations of companies similar to ours; and

• domestic and international economic, legal and regulatory factors unrelated to our performance.

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89

Conservation measures and a negative shift in market perception towards the oil and natural gas
industry could adversely affect demand for oil and natural gas and our stock price.

Certain segments of the investor community have recently expressed negative sentiment towards investing in

the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry
sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors,
including certain pension funds, sovereign wealth funds, university endowments and family foundations, have
stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and
environmental considerations. Other signiﬁcant investors have published ESG disclosure standards that companies
in which they invest are expected to adopt or follow. Furthermore, fuel conservation measures, alternative
fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in
fuel economy and energy generation devices could reduce demand for oil and natural gas. Such developments
could result in downward pressure on the stock prices of oil and natural gas companies, including ours.

Certain other stakeholders have pressured commercial and investment banks and other capital providers to

stop funding oil and natural gas projects. With the continued volatility in oil and natural gas prices, and the possibility
that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized
capital efﬁciency and free cash ﬂow from earnings as key drivers for energy companies, especially those primarily
focused in the shale plays. This may also result in a reduction of available capital funding for potential development
projects, further impacting our future ﬁnancial results. Furthermore, if we are unable to achieve the desired
level of capital efﬁciency or free cash ﬂow within the timeframe expected by the market, our stock price may be
adversely affected.

Future sales of shares of our common stock by existing shareholders and future offerings of our
common stock by us could depress the price of our common stock.

The market price of our common stock could decline as a result of sales of a large number of shares of our
common stock in the market, including shares of equity or debt securities convertible into common stock, and the
perception that these sales could occur may also depress the market price of our common stock. If our existing
shareholders, including directors or ofﬁcers, sell, or indicate an intent to sell, substantial amounts of our common
stock in the public market, the trading price of our common stock could decline signiﬁcantly. Sales of our common
stock may make it more difﬁcult for us to sell equity securities in the future at a time and at a price that we deem
appropriate. These sales could also cause our stock price to decrease and make it more difﬁcult for you to sell
shares of our common stock.

We may also sell or issue additional shares of common stock or equity or debt securities convertible into common

stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances
of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our
common stock or convertible securities would have on the market price of our common stock.

Our directors and executive ofﬁcers own a signiﬁcant percentage of our equity, which could give
them inﬂuence in corporate transactions and other matters, and their interests could differ from other
shareholders.

As of February 21, 2023, our directors and executive ofﬁcers beneﬁcially owned approximately 5.5% of our
outstanding common stock. These shareholders could inﬂuence or control to some degree the outcome of matters
requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certiﬁcate
of formation or bylaws and the approval of mergers and other signiﬁcant corporate transactions. Their inﬂuence or
control of the Company may have the effect of delaying or preventing a change of control of the Company and
may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in
our common stock, our directors and executive ofﬁcers may be able to remain entrenched in their positions.

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MATADOR RESOURCES COMPANY

Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of
our common stock and make a change of control of the Company more difﬁcult even if it might beneﬁt
our shareholders.

Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to ﬁx the voting

powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of
preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or
dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock.

Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock,
may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of
control might beneﬁt our shareholders.

GENERAL RISK FACTORS

We may have difﬁculty managing growth in our business, which could have a material adverse effect
on our business, ﬁnancial condition, results of operations and cash ﬂows and our ability to execute our
business plan in a timely fashion.

Because of our size, growth in accordance with our business plans, if achieved, will place a signiﬁcant strain on

our ﬁnancial, technical, operational and management resources. As and when we expand our activities, including
our midstream business, through San Mateo, Pronto or otherwise, there will be additional demands on our ﬁnancial,
technical and management resources. The failure to continue to upgrade our technical, administrative, operating
and ﬁnancial control systems or the occurrence of unexpected expansion difﬁculties, including the inability to recruit
and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals,
attorneys and ﬁnancial and accounting professionals, could have a material adverse effect on our business, ﬁnancial
condition, results of operations and cash ﬂows and our ability to execute our business plan in a timely fashion.

Our success depends, to a large extent, on our ability to retain our key personnel, including our
chairman and chief executive ofﬁcer, management and technical team, the members of our Board and
our special Board advisors, and the loss of any key personnel, Board member or special Board advisor
could disrupt our business operations.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management

and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our
performance and success are dependent to a large extent on the efforts and continued employment of our management
and technical personnel, including our Chairman and Chief Executive Ofﬁcer, Joseph Wm. Foran. We do not
believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors
may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel.
However, these employment agreements do not ensure that these individuals will remain in our employment.
If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not
adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we
do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in
our business and the determination of our operational strategies. Members of our Board of Directors work closely
with management to identify potential prospects, acquisitions and areas for further development. If any of our
directors resign or become unable to continue in their present role, it may be difﬁcult to ﬁnd replacements with the
same knowledge and experience and, as a result, our operations may be adversely affected.

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91

In addition, our Board of Directors consults regularly with our special Board advisors regarding our business and

the evaluation, exploration, engineering and development of our prospects and properties. Due to the knowledge
and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions
regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to
continue in their present role, our operations may be adversely affected.

It has also been widely reported in the press and elsewhere that businesses have faced a more challenging
hiring environment since the onset of the COVID-19 pandemic and the subsequent recovery, which has resulted
in increased costs to attract skilled labor, such as higher wages or costs for contractors. We may experience
employee turnover or labor shortages if our business requirements, compensation, beneﬁts and/or perquisites are
inconsistent with the expectations of current or prospective employees, or if workers pursue employment in
ﬁelds with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain
sufﬁcient qualiﬁed personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive
position, our business could be adversely affected.

A cyber incident could occur and result in information theft, data corruption, operational disruption or
ﬁnancial loss.

The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development,

production, gathering, processing and ﬁnancial activities, including technologies that are managed by third-party
service providers or other providers to our industry on whom we directly or indirectly rely to help us collect, host or
process information. We depend on such digital technology to, among other things, estimate oil and natural gas
reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal
operations, process and record ﬁnancial and operating data and communicate with employees, shareholders,
royalty owners and other third-party industry participants. Industrial control systems, such as our SCADA systems,
control important processes and facilities that are critical to our operations.

While we and our third-party service providers commit resources to the design, implementation and monitoring

of our information systems, there is no guarantee that these security measures will provide absolute security.
Despite these security measures, we may not be able to anticipate, detect or prevent cyberattacks, particularly
because the methodologies used by attackers change frequently or may not be recognized until launch, and
because attackers are increasingly using technologies designed to circumvent controls and avoid detection. If any
of such programs or systems were to fail or create erroneous information in our hardware or software network
infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences
include ﬁnancial losses, damage to our reputation and the inability to engage in any of the aforementioned
activities. Any such consequence could have a material adverse effect on our business. In addition, any failure of
our third-party providers’ computer systems, or those of our customers, suppliers or others with whom we do
business, could materially disrupt our ability to operate our business.

While we have experienced certain phishing schemes and efforts to access our network, we have not experienced

any material losses due to cyber incidents. However, we may suffer such losses in the future. If our or our third-
party providers’ systems for protecting against cyber incidents prove to be insufﬁcient, we could be adversely
affected by unauthorized access to proprietary information, which could lead to data corruption, communication
interruption, exposure of our or third parties’ conﬁdential or proprietary information, operational disruptions, damage
to our reputation or ﬁnancial loss. Additionally, costs for insurance may also increase as a result of cybersecurity
threats, and insurance against losses relating to cyber incidents may become more difﬁcult to obtain.

92

MATADOR RESOURCES COMPANY

As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify

and further enhance our protective systems or to investigate and remediate any vulnerabilities. In addition, the
continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including
increased regulatory focus on prevention, which could lead to increased regulatory compliance costs, insurance
coverage cost or capital expenditures. Any failure by us to comply with any additional regulations could result in
signiﬁcant penalties and liability to us, and we cannot predict the potential impact to our business or the energy
industry resulting from additional regulations. We may also be subject to regulatory investigations or litigation relating
from cybersecurity issues.

Provisions of our certiﬁcate of formation, bylaws and Texas law may have anti-takeover effects that
could prevent a change in control even if it might be beneﬁcial to our shareholders.

Our certiﬁcate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger

or acquisition of the Company or other change in control transaction that our shareholders may consider favorable.
These provisions include:

• authorization for our Board of Directors to issue preferred stock without shareholder approval;

• a classiﬁed Board of Directors so that not all members of our Board of Directors are elected at one time;

•

the prohibition of cumulative voting in the election of directors; and

• a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our

outstanding shares of common stock.

Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us,

which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneﬁcially
owns more than 20% of our voting stock, or an afﬁliated shareholder, cannot acquire us for a period of three years
from the date this person became an afﬁliated shareholder, unless various conditions are met, such as approval
of the transaction by our Board of Directors before this person became an afﬁliated shareholder or approval of the
holders of at least two-thirds of our outstanding voting shares not beneﬁcially owned by the afﬁliated shareholder.

We operate in a litigious environment and may be involved in legal proceedings that could have a
material adverse effect on our results of operations and ﬁnancial condition.

Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings,

such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage
matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results
cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us
because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible
that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments,
consent decrees or orders requiring a change in our business practices, which could materially and adversely
affect our business, operating results and ﬁnancial condition. Accruals for such liability, penalties or sanctions may
be insufﬁcient. Judgments and estimates to determine accruals or range of losses related to legal and other
proceedings could change from one period to the next, and such changes could be material.

FORM 10-K PART I

2022 ANNUAL REPORT

93

ITEM 1B. UNRESOLVED STAFF COMMENTS.

Not applicable.

ITEM 2. PROPERTIES.

See “Business” for descriptions of our properties. We also have various operating leases for rental of ofﬁce
space and ofﬁce and ﬁeld equipment. See Note 4 to the consolidated ﬁnancial statements in this Annual Report for
the future minimum rental payments. Such information is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS.

We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate
outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these
legal proceedings will have a material adverse impact on our ﬁnancial condition, results of operations or cash ﬂows.

On November 4, 2019, we received a Notice of Violation and Finding of Violation from the EPA and a Notice of
Violation from the NMED alleging violations of the CAA and New Mexico State Implementation Plan at certain of our
operated locations in New Mexico. We have provided information to the EPA and the NMED and are engaged in
discussions regarding a resolution of the alleged violations. We believe it is remote that the resolution of this matter
will have a material adverse impact on our ﬁnancial condition, results of operations or cash ﬂows. Resolution of the
matter may result in monetary sanctions of more than $300,000.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

FORM 10-K PART I

94

MATADOR RESOURCES COMPANY

Part II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS

AND ISSUER PURCHASES OF EQUITY SECURITIES.

GENERAL MARKET INFORMATION

Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded
on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for
our common stock.

On February 21, 2023, we had 119,071,975 shares of common stock outstanding held by approximately 325 record

holders, excluding shareholders for whom shares are held in “nominee” or “street” name.

DIVIDENDS

In February 2022 and April 2022, our Board of Directors declared quarterly cash dividends of $0.05 per share of

common stock. In June 2022, the Board amended our dividend policy to increase the quarterly dividend to $0.10
per share of common stock. In July 2022 and October 2022, the Board declared quarterly cash dividends of $0.10 per
share of common stock. In December 2022, the Board amended our dividend policy to increase the quarterly
dividend to $0.15 per share of common stock for future dividend payments. On February 15, 2023, the Board declared
a quarterly cash dividend of $0.15 per share of common stock payable on March 9, 2023 to shareholders of record
as of February 27, 2023. We expect that, based on current circumstances, comparable cash dividends will continue
to be paid in the foreseeable future.

EQUITY COMPENSATION PLAN INFORMATION

The following table presents the securities authorized for issuance under our equity compensation plans as of

December 31, 2022.

Plan Category

Equity compensation plans approved by security holders(1)(2)(3)
Equity compensation plans not approved by security holders

Total

Equity Compensation Plan Information

Number of Shares
to be Issued
Upon Exercise of
Outstanding Options,
Warrants and Rights

Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights

1,357,496
—
1,357,496

$22.92
—
$22.92

Number of Shares
Remaining Available
for Future Issuance
Under Equity
Compensation Plans

8,755,116
—
8,755,116

(1) Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company Amended and

Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”).

(2) The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board of Directors in April 2019

and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated ﬁnancial
statements in this Annual Report.

(3) The Matador Resources Company 2022 Employee Stock Purchase Plan (the “ESPP”) was adopted by our Board of Directors in April 2022

and approved by our shareholders on June 10, 2022. For a description of our ESPP, see Note 9 to the consolidated ﬁnancial statements in this
Annual Report.

FORM 10-K PART I I

2022 ANNUAL REPORT

95

SHARE PERFORMANCE GRAPH

The following graph compares the cumulative return on a $100 investment in our common stock from

December 31, 2016 through December 31, 2021, to that of the cumulative return on a $100 investment in the
Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return,
reinvestment of dividends, if any, is assumed.

This graph is not “soliciting material,” is not deemed ﬁled with the SEC and is not to be incorporated by

reference in any of our ﬁlings under the Securities Act or the Exchange Act, whether made before or after the date
hereof and irrespective of any general incorporation language in any such ﬁling. This graph is included in accordance
with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance.

COMPARISON OF CUMULATIVE TOTAL RETURN AMONG MATADOR RESOURCES COMPANY,
THE RUSSELL 2000 INDEX AND THE RUSSELL 2000 ENERGY INDEX

200

180

160

140

120

100

80

60

40

20

12/31/17

06/30/18

12/31/18

06/30/19

12/31/19

06/30/20

12/31/20

06/30/21

12/31/21

06/30/22

12/31/22

MTDR

Russell 2000

Russell 2000 Energy

FORM 10-K PART I I

96

MATADOR RESOURCES COMPANY

REPURCHASE OF EQUITY BY THE COMPANY OR AFFILIATES

During the quarter ended December 31, 2022, the Company re-acquired shares of common stock from certain

employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.

Period

Total Number of
Shares Purchased(1)

Average Price Paid
Per Share

Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs

Maximum Number of
Shares that May Yet
Be Purchased under
the Plans or Programs

October 1, 2022 to October 31, 2022
November 1, 2022 to November 30, 2022
December 1, 2022 to December 31, 2022

Total

388
—
136
524

$66.04
—
61.46
$64.85

—
—
—
—

—
—
—
—

(1) The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain

employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.

FORM 10-K PART I I

2022 ANNUAL REPORT

97

ITEM 6. SELECTED FINANCIAL DATA.

Not applicable.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS.

The following discussion and analysis of our ﬁnancial condition and results of operations should be read in

conjunction with our consolidated ﬁnancial statements and related notes appearing elsewhere in this Annual
Report. The following discussion contains “forward-looking statements” that reﬂect our future plans, estimates,
beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs
about future events may, and often do, vary from actual results, and the differences can be material. Some of
the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas
prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo
Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors
affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well
as our ability to access them, the ongoing impact of COVID-19 on oil and natural gas demand, oil and natural gas
prices and our business, the proximity to and capacity of gathering, processing and transportation facilities,
availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other
legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere
in this Annual Report, all of which are difﬁcult to predict. In light of these risks, uncertainties and assumptions, the
forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

For a comparison of our results of operations for the years ended December 31, 2021 and December 31, 2020,
see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report
on Form 10-K for the year ended December 31, 2021, ﬁled with the SEC on February 28, 2022.

OVERVIEW

We are an independent energy company founded in July 2003 engaged in the exploration, development,

production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural
gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich
portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas.
We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in
Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and
production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced
water gathering services and produced water disposal services to third parties.

2022 Operational Highlights

We began 2022 operating ﬁve drilling rigs in the Delaware Basin but contracted a sixth drilling rig during the ﬁrst

quarter of 2022 to begin development of certain acquired assets in the western portion of the Ranger asset area
in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated seven drilling rigs
throughout the remainder of 2022. We have built signiﬁcant optionality into our drilling program, which should
generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity
prices and other factors. We were able to achieve D/C/E capital expenditures for 2022 of $772.5 million, which
was at the low end of our revised estimated range for 2022 D/C/E capital expenditures of $765.0 to $835.0 million
as provided on July 26, 2022 and afﬁrmed on October 25, 2022.

FORM 10-K PART I I

98

MATADOR RESOURCES COMPANY

During the year ended December 31, 2022, we completed and began producing oil and natural gas from 81 gross

(64.5 net) operated and 63 gross (5.4 net) non-operated wells in the Delaware Basin. We did not conduct any
operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during
2022, although we did participate in the drilling and completion of 11 gross (1.0 net) non-operated Haynesville
shale wells that began producing in 2022.

Substantially all of our 2022 capital expenditures were directed to (i) the further delineation and development

of our leasehold position in the Delaware Basin, (ii) the acquisition, construction, installation and maintenance of
midstream assets, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin, with the
exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions, including
certain non-operated well opportunities, and (iv) the acquisition of additional producing properties, leasehold and
mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin.

Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day,

including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, an increase of 22%, as compared to
86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, for the year ended
December 31, 2021. Our average daily oil production in 2022 was 60,119 Bbl of oil per day, an increase of 23%,
as compared to 48,876 Bbl of oil per day in 2021. This increase in oil production was primarily a result of our ongoing
delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the
Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our
average daily natural gas production of 272.1 MMcf per day in 2022, an increase of 22%, as compared to 223.8
MMcf per day in 2021. This increase in natural gas production was primarily attributable to our ongoing delineation
and development drilling activities in the Delaware Basin. Oil production comprised 57% of our total production for
each of the years ended December 31, 2022 and 2021.

For the year ended December 31, 2022, our oil and natural gas revenues were $2.91 billion, an increase of 71%

from oil and natural gas revenues of $1.70 billion for the year ended December 31, 2021. Our oil revenues
increased 75% to $2.11 billion, as compared to $1.21 billion for the year ended December 31, 2021. The increase in
oil revenues resulted from a signiﬁcantly higher weighted average realized oil price of $96.32 per Bbl in 2022, as
compared to $67.58 per Bbl in 2021, as well as the 23% increase in oil production for the year ended December 31,
2022 noted above. Our natural gas revenues increased 60% to $792.1 million, as compared to $494.9 million for
the year ended December 31, 2021. The increase in natural gas revenues resulted from an increase in our weighted
average realized natural gas price of $7.98 per Mcf in 2022, as compared to $6.06 per Mcf in 2021, as well as the
22% increase in natural gas production for the year ended December 31, 2022 noted above.

We reported net income attributable to Matador shareholders of approximately $1.21 billion, or $10.11 per
diluted common share, on a GAAP basis for the year ended December 31, 2022, as compared to a net income of
$585.0 million, or $4.91 per diluted common share, for the year ended December 31, 2021. Adjusted EBITDA for
the year ended December 31, 2022 was $2.13 billion, as compared to Adjusted EBITDA of $1.05 billion for the year
ended December 31, 2021. Adjusted EBITDA is a non-GAAP ﬁnancial measure. For a deﬁnition of Adjusted EBITDA
and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see
“Selected Financial Data—Non-GAAP Financial Measures.”

FORM 10-K PART I I

2022 ANNUAL REPORT

99

At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including

196.3 million Bbl of oil and 962.6 Bcf of natural gas, with a Standardized Measure of $6.98 billion and a PV-10 of
$9.13 billion. At December 31, 2021, our estimated total proved oil and natural gas reserves were 323.4 million
BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, with a Standardized Measure of $4.38 billion
and a PV-10 of $5.35 billion. Our estimated total proved reserves of 356.7 million BOE at December 31, 2022
represented a 10% year-over-year increase, as compared to 323.4 million BOE at December 31, 2021. Our
estimated proved oil reserves were 196.3 million Bbl at December 31, 2022, an increase of 8%, as compared to
181.3 million Bbl at December 31, 2021, and our estimated proved natural gas reserves were 962.6 Bcf at
December 31, 2022, an increase of 13%, as compared to 852.5 Bcf at December 31, 2021. Proved oil reserves
comprised 55% of our total proved reserves at December 31, 2022, as compared to 56% at December 31, 2021.
At December 31, 2022, 62% of our total proved reserves were proved developed reserves, as compared to 60% at
December 31, 2021.

Our proved oil and natural gas reserves in the Delaware Basin increased 11% to 346.8 million BOE at December 31,

2022, as compared to 312.0 million BOE at December 31, 2021, primarily as a result of our ongoing delineation
and development operations there. At December 31, 2022, approximately 97% of our total proved oil and natural gas
reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin
increased 9% to 193.5 million Bbl at December 31, 2022, as compared to 177.1 million Bbl at December 31, 2021,
and our proved natural gas reserves in the Delaware Basin increased 14% to 919.7 Bcf, as compared to 809.3 Bcf
at December 31, 2021. Proved oil reserves comprised 56% of our Delaware Basin total proved reserves at
December 31, 2022, as compared to 57% at December 31, 2021.

At both December 31, 2022 and December 31, 2021, these reserves estimates were based on evaluations
prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC
guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents
the present value of estimated future net cash ﬂows from proved reserves, less estimated future development,
production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reﬂect the
timing of future cash ﬂows. Standardized Measure is not an estimate of the fair market value of our properties.
PV-10 is a non-GAAP ﬁnancial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—
Estimated Proved Reserves.”

2022 Midstream Highlights

On June 30, 2022, our wholly-owned subsidiary acquired the Marlan Processing Plant, three compressor
stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as
part of the Pronto Acquisition. We assumed certain takeaway capacity on a FERC-regulated natural gas pipeline.
As consideration for the business combination, we paid approximately $77.8 million in cash, subject to certain
customary post-closing purchase price adjustments.

San Mateo achieved strong operating results in 2022, highlighted by (i) free cash ﬂow generation, (ii) increased

midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water
handling volumes and oil gathering and transportation volumes, all as compared to 2021. Volumes for the years
ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been
delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries
were made in both years), but for which San Mateo recognized revenues during the years ended December 31,
2022 and 2021. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.

FORM 10-K PART I I

100

MATADOR RESOURCES COMPANY

During 2022, San Mateo closed seven new midstream transactions with oil and natural gas producers and other

counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering
and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these
new opportunities reﬂect additional business awarded to San Mateo by existing customers, which we believe is
indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. For example,
San Mateo was able to keep its gathering, processing and disposal systems operational throughout the historically
prolonged cold weather conditions experienced in New Mexico and Texas during Winter Storm Uri in February 2021.

At December 31, 2022, San Mateo’s midstream system included:

• Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and

approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County,
Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset
area to the Greater Stebbins Area in Eddy County, New Mexico;

• Oil Assets: Three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately
100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County,
Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil
production in Eddy County, New Mexico; and

• Produced Water Assets: 15 commercial salt water disposal wells and associated facilities with designed
produced water disposal capacity of 445,000 Bbl per day and approximately 165 miles of produced water
gathering pipelines in Eddy County, New Mexico and Loving County, Texas.

2023 Capital Expenditure Budget

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital
expenditures in 2023. We began 2022 operating ﬁve drilling rigs in the Delaware Basin but contracted a sixth drilling
rig during the ﬁrst quarter of 2022 to begin development of certain acquired assets in the western portion of the
Ranger asset area in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated
seven drilling rigs throughout the remainder of 2022. We have built signiﬁcant optionality into our 2023 drilling program,
which should generally allow us to decrease or increase the number of rigs we operate as necessary based on
changing commodity prices and other factors. Our 2023 estimated capital expenditure budget consists of $1.18 to
$1.32 billion for D/C/E capital expenditures, which includes expected D/C/E capital expenditures on acreage acquired
in the Advance Acquisition, and $150.0 to $200.0 million for midstream capital expenditures, which reﬂects our
proportionate share of San Mateo’s estimated 2023 capital expenditures as well as the estimated 2023 capital
expenditures for other wholly-owned midstream projects, including projects completed by Pronto. Substantially all
of these 2023 estimated capital expenditures are expected to be allocated to (i) the further delineation and
development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and
(iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and Haynesville
shale. Our 2023 Delaware Basin operated drilling program is expected to focus on the continued development
of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a
high percentage of longer horizontal wells in 2023, including 96% with anticipated completed lateral lengths of
one mile or greater.

FORM 10-K PART I I

2022 ANNUAL REPORT

101

On January 24, 2023, our wholly-owned subsidiary entered into a deﬁnitive agreement to acquire Advance from

afﬁliates of EnCap Investments L.P., including certain oil and natural gas producing properties and undeveloped
acreage primarily located in Lea County, New Mexico and Ward County, Texas. The consideration for the Advance
Acquisition is expected to consist of $1.6 billion in cash, subject to customary closing adjustments, including for
working capital and title and environmental defects, plus additional cash consideration of $7.5 million for each month
during 2023 in which the average price of crude oil (as deﬁned in the securities purchase agreement) exceeds $85
per barrel. The consummation of the Advance Acquisition is subject to customary closing conditions and is expected
to close early in the second quarter of 2023 with an effective date of January 1, 2023.

At December 31, 2022, we had $505.2 million in cash (excluding restricted cash) and $729.4 million in undrawn
borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our
elected borrowing commitment of $775.0 million). We intend to fund the Advance Acquisition with a combination of
cash on hand, free cash ﬂow prior to closing and borrowings under our Credit Agreement, under which we expect
to increase our elected commitment in connection with this transaction. Excluding the Advance Acquisition and any
other signiﬁcant acquisitions, we expect to fund our 2023 capital expenditures through a combination of cash on
hand, operating cash ﬂows and performance incentives paid to us by Five Point in connection with San Mateo. If
capital expenditures were to exceed our operating cash ﬂows in 2023, we expect to fund any excess capital
expenditures, including for other signiﬁcant acquisitions, through borrowings under the Credit Agreement or the
San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including
borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and
natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or
convertible securities, none of which may be available on satisfactory terms or at all.

We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the

Haynesville shale in Northwest Louisiana (as we have done in recent years), as well as consider monetizing other
assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise.
In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and
mineral interests and midstream assets, principally in the Delaware Basin, during 2023. These monetizations,
divestitures and expenditures are opportunity-speciﬁc, and purchase price multiples and per-acre prices can vary
signiﬁcantly based on the asset or prospect. As a result, it is difﬁcult to estimate these 2023 monetizations,
divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated
proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing
properties, acreage and mineral interests and midstream assets for 2023.

FORM 10-K PART I I

102

MATADOR RESOURCES COMPANY

REVENUES

The following table summarizes our revenues and production data for the periods indicated.

Operating Data:
Revenues (in thousands):(1)

Oil
Natural gas

Total oil and natural gas revenues
Third-party midstream services revenues
Sales of purchased natural gas
Lease bonus - mineral acreage
Realized (loss) gain on derivatives
Unrealized gain (loss) on derivatives

Total revenues

Net Production Volumes:(1)

Oil (MBbl)
Natural gas (Bcf)

Total oil equivalent (MBOE)(2)
Average daily production (BOE/d)(2)

Average Sales Prices:

Oil, without realized derivatives (per Bbl)
Oil, with realized derivatives (per Bbl)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)

Year Ended December 31,

2022

2021

2020

$2,113,606
792,132
2,905,738
90,606
200,355
—
(157,483)
18,809
$3,058,025

21,943
99.3
38,495
105,465

$1,205,608
494,934
1,700,542
75,499
86,034
—
(220,105)
21,011
$1,662,981

17,840
81.7
31,454
86,176

$595,507
148,954
744,461
64,932
41,742
4,062
38,937
(32,008)
$862,126

15,931
69.5
27,514
75,175

$
$
$
$

96.32
92.87
7.98
7.15

$
$
$
$

67.58
56.70
6.06
5.74

$
$
$
$

37.38
39.83
2.14
2.14

(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with

NGLs are included with our natural gas revenues.

(2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Year Ended December 31, 2022 as Compared to Year Ended December 31, 2021

Oil and natural gas revenues. Our oil and natural gas revenues increased $1.21 billion, or 71%, to $2.91 billion

for the year ended December 31, 2022, as compared to $1.70 billion for the year ended December 31, 2021.
Our oil revenues increased $908.0 million, or 75%, to $2.11 billion for the year ended December 31, 2022, as
compared to $1.21 billion for the year ended December 31, 2021. This increase in oil revenues resulted from a 43%
increase in the weighted average oil price realized for the year ended December 31, 2022 to $96.32 per Bbl, as
compared to $67.58 per Bbl realized for the year ended December 31, 2021, and the 23% increase in our oil
production to 21.9 million Bbl of oil for the year ended December 31, 2022, as compared to 17.8 million Bbl of
oil for the year ended December 31, 2021. The increase in oil production was primarily attributable to our ongoing
delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increased by
$297.2 million, or 60%, to $792.1 million for the year ended December 31, 2022, as compared to $494.9 million for
the year ended December 31, 2021. The increase in natural gas revenues was primarily attributable to the 32%
increase in the weighted average natural gas price realized for the year ended December 31, 2022 to $7.98 per Mcf,
as compared to $6.06 per Mcf realized for the year ended December 31, 2021, and the 22% increase in our natural
gas production to 99.3 Bcf for the year ended December 31, 2022, as compared to 81.7 Bcf for the year ended
December 31, 2021. The increase in natural gas production was primarily attributable to our ongoing delineation and
development drilling activities in the Delaware Basin.

FORM 10-K PART I I

2022 ANNUAL REPORT

103

Third-party midstream services revenues. Our third-party midstream services revenues increased $15.1 million,

or 20%, to $90.6 million for the year ended December 31, 2022, as compared to $75.5 million for the year ended
December 31, 2021. Third-party midstream services revenues are those revenues from midstream operations
related to third parties, including working interest owners in our operated wells. This increase was primarily attributable
to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $45.1 million
for the year ended December 31, 2022, which includes $4.4 million associated with operating our Pronto midstream
assets that were purchased on June 30, 2022 as part of the Pronto Acquisition, as compared to $37.6 million for
the year ended December 31, 2021, and (ii) an increase in third-party produced water disposal revenues to $35.6 million
for the year ended December 31, 2022, as compared to $27.6 million for the year ended December 31, 2021.

Sales of purchased natural gas. Our sales of purchased natural gas increased $114.3 million, or 133%, to
$200.4 million for the year ended December 31, 2022, as compared to $86.0 million for the year ended December 31,
2021. This increase was primarily the result of the increase in realized natural gas prices and an increase in natural
gas volumes sold during the year ended December 31, 2022. Sales of purchased natural gas primarily reﬂect those
natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural
gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at Pronto’s Marlan
Processing Plant or San Mateo’s Black River Processing Plant and subsequently sell the residue gas and NGLs
to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural
gas,” are presented on a gross basis in our consolidated statements of operations.

Realized (loss) gain on derivatives. Our realized net loss on derivatives was $157.5 million for the year ended
December 31, 2022, as compared to a realized net loss of approximately $220.1 million for the year ended December 31,
2021. We realized a net loss of $73.9 million related to our oil costless collar for the year ended December 31, 2022,
resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and
above the strike price of certain of our oil swap contracts. We also realized a net loss of approximately $81.7 million
related to our natural gas costless collar contracts for the year ended December 31, 2022, resulting primarily from
natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We
realized a net gain of $1.9 million from our oil basis swap contracts for the year ended December 31, 2022, resulting
from oil basis prices that were lower than the ﬁxed prices of certain of our oil basis swap contracts. We realized a net
loss of $197.5 million related to our oil costless collar and swap contracts for the year ended December 31, 2021,
resulting primarily from oil prices that were above the ceiling prices of certain of
our oil costless collar contracts and above the strike price of certain of our oil swap contracts. We also realized a net
loss of approximately $26.1 million related to our natural gas costless collar contracts for the year ended December 31,
2021, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas
costless collar contracts. We realized a net gain of $3.5 million from our oil basis swap contracts for the year ended
December 31, 2021, resulting from oil basis prices that were lower than the ﬁxed prices of certain of our oil basis
swap contracts. We realized an average loss on our oil derivatives of approximately $3.45 per Bbl of oil produced
during the year ended December 31, 2022, as compared to an average loss of $10.88 per Bbl of oil produced during
the year ended December 31, 2021. We realized an average gain on our natural gas derivatives of approximately
$0.83 per Mcf of natural gas produced during the year ended December 31, 2022, as compared to an average loss
on our natural gas derivatives of approximately $0.32 per Mcf of natural gas produced during the year ended
December 31, 2021. Our total oil volumes hedged represented 42% and 61% of our total oil production for the
years ended December 31, 2022 and 2021, respectively. Our total natural gas volumes hedged represented 61%
and 62% of our total natural gas production the years ended December 31, 2022 and 2021, respectively.

FORM 10-K PART I I

104

MATADOR RESOURCES COMPANY

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $18.8 million for the
year ended December 31, 2022, as compared to an unrealized gain of $21.0 million for the year ended December 31,
2021. During the year ended December 31, 2022, the aggregate net fair value of our open oil and natural gas
derivatives and oil basis swap contracts changed from a net liability of approximately $14.9 million to an asset of
approximately $3.9 million, resulting in an unrealized gain on derivatives of approximately $18.8 million for the
year ended December 31, 2022. During the year ended December 31, 2021, the aggregate net fair value of our
open oil and natural gas derivative and oil basis swap contracts decreased from a net liability of approximately
$35.9 million to a net liability of approximately $14.9 million, resulting in an unrealized gain on derivatives of
approximately $21.0 million for the year ended December 31, 2021.

EXPENSES

The following table summarizes our operating expenses and other income (expense) for the periods indicated.

(In thousands, except expenses per BOE)

Expenses:

Production taxes, transportation and processing
Lease operating
Plant and other midstream services operating
Purchased natural gas
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
General and administrative

Total expenses
Operating income (loss)
Other income (expense):

Net loss on asset sales and inventory impairment
Interest expense
Other (expense) income

Total other (expense) income

Income (loss) before income taxes

Income tax provision (beneﬁt)

Current
Deferred

Total income tax provision (beneﬁt)

Net income attributable to non-controlling interest in subsidiaries
Net income (loss) attributable to Matador Resources Company shareholders
Expenses per BOE:

Production taxes, transportation and processing
Lease operating
Plant and other midstream services operating
Depletion, depreciation and amortization
General and administrative

Year Ended December 31,

2022

2021

2020

$ 282,193
157,105
95,522
178,937
466,348
2,421
—
116,229
1,298,755
1,759,270

(1,311)
(67,164)
(5,121)
(73,596)
1,685,674

54,877
344,480
399,357
(72,111)
$1,214,206

$
$
$
$
$

7.33
4.08
2.48
12.11
3.02

$178,987
108,964
61,459
77,126
344,905
2,068
—
96,396
869,905
793,076

(331)
(74,687)
(2,712)
(77,730)
715,346

—
74,710
74,710
(55,668)
$584,968

$
$
$
$
$

5.69
3.46
1.95
10.97
3.06

$

93,338
104,953
41,500
32,734
361,831
1,948
684,743
62,578
1,383,625
(521,499)

(2,832)
(76,692)
1,864
(77,660)
(599,159)

—
(45,599)
(45,599)
(39,645)
$ (593,205)

$
$
$
$
$

3.39
3.81
1.51
13.15
2.27

FORM 10-K PART I I

2022 ANNUAL REPORT

105

Year Ended December 31, 2022 as Compared to Year Ended December 31, 2021

Production taxes, transportation and processing. Our production taxes and transportation and processing
expenses increased $103.2 million, or 58%, to $282.2 million for the year ended December 31, 2022, as compared
to $179.0 million for the year ended December 31, 2021. On a unit-of-production basis, our production taxes and
transportation and processing expenses increased 29% to $7.33 per BOE for the year ended December 31, 2022,
as compared to $5.69 per BOE for the year ended December 31, 2021. These increases were primarily attributable
to the $93.0 million increase in our production taxes to $222.9 million for the year ended December 31, 2022, as
compared to $129.8 million for the year ended December 31, 2021, resulting from the $1.21 billion increase in oil
and natural gas revenues for the year ended December 31, 2022, as compared to the year ended December 31,
2021, and the $10.2 million increase in transportation and processing expenses to $59.3 million for the year ended
December 31, 2022, as compared to $49.2 million for the year ended December 31, 2021, primarily resulting from
the 22% increase in total oil equivalent production between the respective periods.

Lease operating expenses. Our lease operating expenses increased $48.1 million, or 44%, to $157.1 million
for the year ended December 31, 2022, as compared to $109.0 million for the year ended December 31, 2021. On a
unit-of-production basis, our lease operating expenses increased 18% to $4.08 per BOE for the year ended
December 31, 2022, as compared to $3.46 per BOE for the year ended December 31, 2021. These increases in our
lease operating expenses for the year ended December 31, 2022 were primarily attributable to the increased
number of wells being operated by us and other operators (where we own a working interest) and to operating cost
inﬂation during the year-ended December 31, 2022, as compared to the year ended December 31, 2021.

Plant and other midstream services operating. Our plant and other midstream services operating expenses
increased $34.1 million, or 55%, to $95.5 million for the year ended December 31, 2022, as compared to $61.5 million
for the year ended December 31, 2021. This increase was primarily attributable to increased throughput volumes
at San Mateo from Matador and other San Mateo customers, which resulted in (i) increased expenses associated
with our commercial produced water disposal operations of $46.5 million for the year ended December 31, 2022,
as compared to $30.8 million for the year ended December 31, 2021, (ii) increased expenses associated with our
expanded pipeline operations of $28.0 million for the year ended December 31, 2022, as compared to $17.5 million
for the year ended December 31, 2021, and (iii) increased expenses associated with operating the Black River
Processing Plant of $15.8 million for the year ended December 31, 2022, as compared to $13.1 million for the year
ended December 31, 2021. In addition, $5.2 million for the year ended December 31, 2022 was associated with
operating our Pronto midstream assets, which were purchased on June 30, 2022 as part of the Pronto Acquisition.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased

$121.4 million, or 35%, to $466.3 million for the year ended December 31, 2022, as compared to $344.9 million
for the year ended December 31, 2021, primarily as a result of the 22% increase in our total oil equivalent production
between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization
expenses increased 10% to $12.11 per BOE for the year ended December 31, 2022, as compared to $10.97 per BOE
for the year ended December 31, 2021, primarily as a result of the increase in actual costs and estimated future
costs to drill, complete and equip our wells between the two periods.

FORM 10-K PART I I

106

MATADOR RESOURCES COMPANY

General and administrative. Our general and administrative expenses increased $19.8 million, or 21%, to
$116.2 million for the year ended December 31, 2022, as compared to $96.4 million for the year ended December 31,
2021, primarily due to increased compensation expenses for our existing employees as well as the addition of
new employees to support the continued growth in our land, geoscience, drilling, completion, production, midstream
and administration functions. While our general and administrative expenses increased 21% on an absolute basis,
our general and administrative expenses on a unit-of-production basis decreased 1% to $3.02 per BOE for the year
ended December 31, 2022, as compared to $3.06 per BOE for the year ended December 31, 2021, primarily as a
result of the 22% increase in our total oil equivalent production between the two periods.

Interest expense. For the year ended December 31, 2022, we incurred total interest expense of approximately

$77.2 million. We capitalized approximately $10.1 million of our interest expense on certain qualifying projects for
the year ended December 31, 2022 and expensed the remaining $67.2 million to operations. For the year ended
December 31, 2021, we incurred total interest expense of approximately $79.5 million. We capitalized $4.8 million
of our interest expense on certain qualifying projects for the year ended December 31, 2021 and expensed the
remaining $74.7 million to operations.

Total income tax provision (beneﬁt). As a result of the full-cost ceiling impairments recorded during 2020, we

recognized a valuation allowance against our federal net deferred tax assets as of September 30, 2020. Due to a
variety of factors, including our signiﬁcant net income during 2021, our federal valuation allowance was reversed in
the third quarter of 2021. As a result, we recorded a deferred income tax provision of $74.7 million for the year
ended December 31, 2021. Our effective tax rate was 11% for the year ended December 31, 2021, which differed
from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due to reversing the
valuation allowance against our U.S. federal net deferred tax assets, differences between book and taxable income
and state taxes, primarily in New Mexico. We recorded a total income tax provision of $399.4 million for the year
ended December 31, 2022. Our effective tax rate was 25% for the year ended December 31, 2022, which differed
from the U.S. federal statutory rate due primarily to permanent differences between book and taxable income and
state taxes, primarily in New Mexico.

LIQUIDITY AND CAPITAL RESOURCES

Our primary use of capital has been, and we expect will continue to be during 2023 and for the foreseeable

future, for the acquisition, exploration and development of oil and natural gas properties and for midstream
investments. In January 2023, we announced the Advance Acquisition. We intend to fund the Advance Acquisition
with a combination of cash on hand, free cash ﬂow prior to closing and borrowings under our Credit Agreement,
under which we expect to increase our elected commitment in connection with this transaction. Excluding the
Advance Acquisition and any other signiﬁcant acquisitions, we expect to fund our 2023 capital expenditures through
a combination of cash on hand, operating cash ﬂows and performance incentives paid to us by Five Point in
connection with San Mateo. If capital expenditures were to exceed our operating cash ﬂows in 2023, we expect to
fund any excess capital expenditures, including for other signiﬁcant acquisitions, through borrowings under the
Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other
capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of
midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential
issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
Our future success in growing proved reserves and production will be highly dependent on our ability to generate
operating cash ﬂows and access outside sources of capital.

FORM 10-K PART I I

2022 ANNUAL REPORT

107

At December 31, 2022, we had cash totaling $505.2 million and restricted cash totaling $42.2 million, which was

primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-
wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital
expenditures and operations of these less-than-wholly-owned subsidiaries.

At December 31, 2022, we had (i) $699.2 million of outstanding 5.875% senior notes due September 2026 (the
“Notes”), (ii) no borrowings outstanding under the Credit Agreement and (iii) approximately $45.6 million in outstanding
letters of credit issued pursuant to the Credit Agreement. During the ﬁrst quarter of 2022, our approximately
$7.5 million unsecured U.S. Small Business Administration loan, which was issued through Iberiabank in April 2020
as part of the Paycheck Protection Program, was forgiven in full under the terms of the loan agreement and
recorded as a gain on the extinguishment of debt within “Other expense” on the consolidated statement of operations.
During the year ended December 31, 2022, we repurchased an aggregate principal amount of $350.8 million of
our Notes for $344.3 million.

In April 2022, the lenders under the Credit Agreement completed their review of our proved oil and natural
gas reserves, and, as a result, the borrowing base was increased from $1.35 billion to $2.00 billion, the borrowing
commitment was increased from $700.0 million to $775.0 million and the maximum facility amount remained
$1.50 billion. In addition, the terms of the Credit Agreement were amended to increase the sublimit for issuances of
letters of credit under the Credit Agreement from $50 million to $100 million and replace the London Interbank
Offered Rate (“LIBOR”) interest rate benchmark with an Adjusted Term SOFR (as deﬁned in the Credit Agreement)
interest rate benchmark. This April 2022 redetermination constituted the regularly scheduled May 1 redetermination.
In November 2022, the lenders completed their review of the our proved oil and natural gas reserves, and, as
a result, the borrowing base was increased from $2.00 billion to $2.25 billion. We elected to keep the borrowing
commitment at $775.0 million, and the maximum facility amount remained $1.50 billion. Borrowings under the
Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected
commitment (subject to compliance with the covenants noted below). The Credit Agreement requires us to
maintain (i) a current ratio, which is deﬁned as (x) total consolidated current assets plus the unused availability under
the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit
Agreement, of not less than 1.0 to 1.0 at the end of each ﬁscal quarter and (ii) a debt to EBITDA ratio, which is
deﬁned as debt outstanding (net of up to $75 million of unrestricted cash and cash equivalents) divided by a rolling
four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each ﬁscal quarter. We believe that we were
in compliance with the terms of the Credit Agreement at December 31, 2022.

At December 31, 2022, San Mateo had $465.0 million in borrowings outstanding under the San Mateo Credit

Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit
Facility. In December 2022, the lenders under the San Mateo Credit Facility extended the maturity of the facility
from December 19, 2023 to December 9, 2026 and increased the lender commitments from $450.0 million to
$485.0 million. In addition, the lenders agreed to refresh the San Mateo Credit Facility’s accordion feature, which
could expand lender commitments to up to $735.0 million. The San Mateo Credit Facility is non-recourse with
respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured
by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo
to maintain a debt to EBITDA ratio, which is deﬁned as total consolidated funded indebtedness outstanding (as
deﬁned in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject
to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio,
which is deﬁned as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense

FORM 10-K PART I I

108

MATADOR RESOURCES COMPANY

for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute
cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo
Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at
December 31, 2022. Between December 31, 2022 and February 21, 2023, we repaid an additional $30.0 million
of borrowings outstanding under the San Mateo Credit Facility.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital

expenditures in 2023. We began 2023 operating seven contracted drilling rigs in the Delaware Basin. Upon the
consummation of the Advance Acquisition, which we anticipate to occur in the second quarter of 2023, we expect
to operate the drilling rig that Advance was operating during the ﬁrst quarter of 2023, bringing our total contracted
drilling rigs to eight. We expect to operate eight contracted drilling rigs for the remainder of 2023. We have built
signiﬁcant optionality into our drilling program, which should generally allow us to decrease or increase the number of
rigs we operate as necessary based on changing commodity prices and other factors. Our 2023 estimated capital
expenditure budget consists of $1.18 to $1.32 billion for D/C/E capital expenditures, which includes expected D/C/E
capital expenditures on acreage acquired in the Advance Acquisition, and $150.0 to $200.0 million for midstream
capital expenditures, which reﬂects our proportionate share of San Mateo’s estimated 2023 capital expenditures as
well as the estimated 2023 capital expenditures for other wholly-owned midstream projects, including projects
completed by Pronto. Substantially all of these 2023 estimated capital expenditures are expected to be allocated to
(i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance
of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin,
South Texas and Haynesville shale. Our 2023 Delaware Basin operated drilling program is expected to focus on the
continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on
drilling and completing a high percentage of longer horizontal wells in 2023, including 96% with anticipated completed
lateral lengths of greater than one mile.

We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the

Haynesville shale in Northwest Louisiana (as we have done in recent years), as well as consider monetizing other
assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise.
In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and
mineral interests and midstream assets, principally in the Delaware Basin, during 2023. These monetizations,
divestitures and expenditures are opportunity-speciﬁc, and purchase price multiples and per-acre prices can vary
signiﬁcantly based on the asset or prospect. As a result, it is difﬁcult to estimate these 2023 monetizations,
divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated
proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing
properties, acreage and mineral interests and midstream assets for 2023.

Our 2023 capital expenditures may be adjusted as business conditions warrant and the amount, timing and
allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we
will expend may ﬂuctuate materially based on market conditions, the actual costs to drill, complete and place on
production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities,
the ability of our joint venture partners to meet their capital obligations, other opportunities that may become
available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase signiﬁcantly,
we have the ﬂexibility to defer a signiﬁcant portion of our capital expenditures until later periods to conserve cash
or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash
ﬂows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability
of ﬁnancing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the
availability of rigs, success or lack of success in our exploration and development activities, contractual obligations,
drilling plans for properties we do not operate and other factors both within and outside our control.

FORM 10-K PART I I

2022 ANNUAL REPORT

109

Exploration and development activities are subject to a number of risks and uncertainties, which could cause
these activities to be less successful than we anticipate. A signiﬁcant portion of our anticipated cash ﬂows from
operations for 2023 is expected to come from producing wells and development activities on currently proved
properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and
the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting
and our exploration and development activities in these areas may not be as successful as we anticipate.
Additionally, our anticipated cash ﬂows from operations are based upon current expectations of oil and natural gas
prices for 2023 and the hedges we currently have in place. For a discussion of our expectations of such commodity
prices, see “—General Outlook and Trends” below. We use commodity derivative ﬁnancial instruments at times
to mitigate our exposure to ﬂuctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash
ﬂows from operations resulting from declines in commodity prices. See Note 12 to the consolidated ﬁnancial
statements in this Annual Report for a summary of our open derivative ﬁnancial instruments at December 31, 2022.
See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and
midstream projects require substantial capital expenditures that may exceed our cash ﬂows from operations and
potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely
affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil and natural
gas are highly speculative and involve a high degree of operational and ﬁnancial risk, with many uncertainties that
could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identiﬁed drilling
locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the
occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately
31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject
to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or
restrict oil and natural gas operations on federal lands.”

Our cash ﬂows for the years ended December 31, 2022, 2021 and 2020 are presented below.

(In thousands)

Net cash provided by operating activities
Net cash used in investing activities
Net cash (used in) provided by ﬁnancing activities
Net change in cash

Year Ended December 31,

2022

2021

2020

$ 1,978,739
(1,037,477)
(480,852)
460,410

$

$1,053,355
(729,265)
(328,553)
(4,463)

$

$ 477,582
(775,666)
324,339
$ 26,255

Adjusted EBITDA attributable to Matador Resources Company shareholders(1) $ 2,127,156

$1,051,973

$ 519,277

(1) Adjusted EBITDA is a non-GAAP ﬁnancial measure. For a deﬁnition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income

(loss) and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below.

FORM 10-K PART I I

110

MATADOR RESOURCES COMPANY

Cash Flows Provided by Operating Activities

Net cash provided by operating activities increased by $925.4 million to $1.98 billion for the year ended
December 31, 2022, as compared to net cash provided by operating activities of $1.05 billion for the year ended
December 31, 2021. Excluding changes in operating assets and liabilities, net cash provided by operating
activities increased to $2.10 billion for the year ended December 31, 2022 from $1.05 billion for the year ended
December 31, 2021. This increase was primarily attributable to signiﬁcantly higher realized oil and natural gas
prices for the year ended December 31, 2022, as compared to the year ended December 31, 2021, as well as the
22% increase in total oil equivalent production during 2022, as compared to 2021. Changes in our operating assets
and liabilities between December 31, 2021 and December 31, 2022 resulted in a net decrease of approximately
$117.0 million in net cash provided by operating activities for the year ended December 31, 2022, as compared to
the year ended December 31, 2021.

Our operating cash ﬂows are sensitive to a number of variables, including changes in our production and

the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the
actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets
and other variable factors signiﬁcantly impact the prices of oil and natural gas. For example, the effects of COVID-19
and the corresponding decline in oil demand signiﬁcantly impacted the prices we received for our oil production
in recent periods, particularly in 2020. These factors are beyond our control and are difﬁcult to predict. From time to
time, we use commodity derivative ﬁnancial instruments to mitigate our exposure to ﬂuctuations in oil, natural
gas and NGL prices. For additional information on the impact of changing prices on our ﬁnancial condition, see
“Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our
Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and
NGL prices and the continued volatility in these prices may adversely affect our ﬁnancial condition and our ability
to meet our capital expenditure requirements and ﬁnancial obligations.”

Cash Flows Used in Investing Activities

Net cash used in investing activities increased by $308.2 million to $1.04 billion for the year ended December 31,

2022 from $729.3 million for the year ended December 31, 2021. This increase in net cash used in investing
activities was primarily attributable an increase of $340.7 million in D/C/E capital expenditures as compared to the
year ended December 31, 2021 and the Pronto Acquisition for $75.8 million. These increases were partially offset
by an $83.5 million decrease in acquisitions of oil and natural gas properties and a $42.3 million increase in
proceeds from the sale of primarily non-core oil and natural gas assets. Cash used for D/C/E capital expenditures for
the year ended December 31, 2022 was primarily attributable to our operated and non-operated drilling and
completion activities in the Delaware Basin.

Cash Flows (Used in) Provided by Financing Activities

Net cash used in ﬁnancing activities increased by $152.3 million to $480.9 million for the year ended December 31,

2022, as compared to $328.6 million for the year ended December 31, 2021. The net cash used in ﬁnancing
activities for the year ended December 31, 2022 was primarily attributable to (i) the repurchase of an aggregate
principal amount of $350.8 million of the Notes for $344.3 million, (ii) net repayments under our Credit Agreement
of $100.0 million, (iii) net borrowings under the San Mateo Credit Facility of $80.0 million, (iv) net distributions
related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $57.7 million and (v) dividends
paid of $35.2 million.

FORM 10-K PART I I

2022 ANNUAL REPORT

111

See Note 7 to the consolidated ﬁnancial statements in this Annual Report for a summary of our debt, including

the Credit Agreement, the San Mateo Credit Facility and the Notes.

Guarantor Financial Information

The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”)

on a full and unconditional basis (except for customary release provisions). At December 31, 2022, the Guarantor
Subsidiaries were each 100% owned by Matador. Matador is a parent holding company and has no independent
assets or operations, and there are no signiﬁcant restrictions on the ability of Matador to obtain funds from the
Guarantor Subsidiaries by dividend or loan. Neither San Mateo nor Pronto is a guarantor of the Notes.

The following tables present summarized ﬁnancial information of Matador (as issuer of the Notes) and the

Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between
the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that
is a non-guarantor. This ﬁnancial information is presented in accordance with the amended requirements of Rule 3-10
of Regulation S-X. The following ﬁnancial information may not necessarily be indicative of results of operations or
ﬁnancial position had the Guarantor Subsidiaries operated as independent entities.

(In thousands)

Summarized Balance Sheet
Assets

Current assets
Net property and equipment
Other long-term assets

Liabilities

Current liabilities
Long-term debt
Other long-term liabilities

Summarized Statement of Operations
Revenues
Expenses

Operating income

Other expense
Tax provision
Net income

December 31, 2022

$ 991,280
$ 3,491,834
73,561
$

$ 559,087
$ 695,245
$ 496,425

Year Ended
December 31, 2022

$ 2,080,396
1,271,359
$ 809,037
(55,935)
(399,357)
$ 353,745

FORM 10-K PART I I

112

MATADOR RESOURCES COMPANY

Non-GAAP Financial Measures

We deﬁne Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before

interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations,
property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-
based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure
of net income (loss) or cash ﬂows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP ﬁnancial
measure that is used by management and external users of our consolidated ﬁnancial statements, such as industry
analysts, investors, lenders and rating agencies.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance

and compare the results of operations from period to period without regard to our ﬁnancing methods or capital
structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these
amounts can vary substantially from company to company within our industry depending upon accounting methods
and book values of assets, capital structures and the method by which certain assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net

cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our
operating performance or liquidity. Certain items excluded from Adjusted EBITDA are signiﬁcant components of
understanding and assessing a company’s ﬁnancial performance, such as a company’s cost of capital and tax
structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because
all companies may not calculate Adjusted EBITDA in the same manner.

The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to

the GAAP ﬁnancial measures of net income (loss) and net cash provided by operating activities, respectively.

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss):
Net income (loss) attributable to Matador Resources Company shareholders
Net income attributable to non-controlling interest in subsidiaries

Net income (loss)

Interest expense
Total income tax provision (beneﬁt)
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
Unrealized (gain) loss on derivatives
Non-cash stock-based compensation expense
Net loss on asset sales and impairment
Expense related to contingent consideration and other

Consolidated Adjusted EBITDA

Adjusted EBITDA attributable to non-controlling interest in subsidiaries
Adjusted EBITDA attributable to Matador Resources Company

Year Ended December 31,

2022

2021

2020

$1,214,206
72,111
1,286,317
67,164
399,357
466,348
2,421
—
(18,809)
15,123
1,311
4,926
2,224,158
(97,002)

$ 584,968
55,668
640,636
74,687
74,710
344,905
2,068
—
(21,011)
9,039
331
1,485
1,126,850
(74,877)

$(593,205)
39,645
(553,560)
76,692
(45,599)
361,831
1,948
684,743
32,008
13,625
2,832
—
574,520
(55,243)

shareholders

$2,127,156

$1,051,973

$ 519,277

FORM 10-K PART I I

2022 ANNUAL REPORT

113

Year Ended December 31,

2022

2021

2020

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to Net Cash

Provided by Operating Activities:

Net cash provided by operating activities
Net change in operating assets and liabilities
Interest expense, net of non-cash portion
Current income tax provision
Expense related to contingent consideration and other
Adjusted EBITDA attributable to non-controlling interest in subsidiaries

Adjusted EBITDA attributable to Matador Resources Company shareholders

$1,978,739
117,935
63,064
54,877
9,543
(97,002)
$2,127,156

$1,053,355
982
71,028
—
1,485
(74,877)
$1,051,973

$477,582
23,078
73,860
—
—
(55,243)
$519,277

For the year ended December 31, 2022, we reported net income attributable to Matador shareholders of

$1.21 billion, as compared to $585.0 million for the year ended December 31, 2021. This increase primarily resulted
from signiﬁcantly higher realized oil and natural gas prices and higher oil and natural gas production, for the year
ended December 31, 2022, as compared to the year ended December 31, 2021. These increases were partially
offset by an increase in operating expenses, depletion, depreciation and amortization and income tax expense
between the two periods.

Adjusted EBITDA, a non-GAAP ﬁnancial measure, increased $1.08 billion to $2.13 billion for the year ended

December 31, 2022, as compared to $1.05 billion for the year ended December 31, 2021. This increase was
primarily attributable to the signiﬁcantly higher realized oil and natural gas prices and higher oil and natural gas
production noted above for the year ended December 31, 2022, as compared to the year ended December 31,
2021. These increases were partially offset by an increase in operating expenses between the two periods.

OFF-BALANCE SHEET ARRANGEMENTS

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material
off-balance sheet obligations. As of December 31, 2022, the material off-balance sheet arrangements and transactions
that we have entered into include (i) non-operated drilling commitments, (ii) ﬁrm gathering, transportation, processing,
fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement
amounts are not ﬁxed and determinable, such as derivative contracts that are sensitive to future changes in
commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain
volumes of future throughput, open delivery commitments and indemniﬁcation obligations following certain
divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions,
arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely
to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and
Commitments” below and Note 14 to the consolidated ﬁnancial statements in this Annual Report for more
information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.

FORM 10-K PART I I

114

MATADOR RESOURCES COMPANY

OBLIGATIONS AND COMMITMENTS

We had the following material contractual obligations and commitments at December 31, 2022.

(In thousands)

Contractual Obligations:
Borrowings, including letters of credit(1)
Senior unsecured notes(2)
Ofﬁce leases
Non-operated drilling commitments(3)
Drilling rig contracts(4)
Asset retirement obligations(5)
Transportation, gathering, processing and

Payments Due by Period

Total

Less Than
1 Year

1-3 Years

3-5 Years

More Than
5 Years

$ 519,572
699,191
14,373
25,992
17,703
53,741

$

— $
—
4,242
25,992
17,703
756

— $ 519,572
699,191
—
1,460
8,671
—
—
—
—
1,889
5,199

$

—
—
—
—
—
45,897

disposal agreements with non-afﬁliates(6)

541,085

70,648

142,424

131,083

196,930

Transportation, gathering, processing and
disposal agreements with San Mateo(7)

Midstream compressor contracts(8)

Total contractual cash obligations

291,979
29,833
$2,193,469

1,773
29,833
$150,947

182,740
—
$ 339,034

107,466
—
$1,460,661

—
—
$242,827

(1) The amounts included in the table above represent principal maturities only. At December 31, 2022, we had no borrowings outstanding under
the Credit Agreement and approximately $45.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit
Agreement matures in October 31, 2026. At December 31, 2022 San Mateo had $465.0 million of borrowings outstanding under the San Mateo
Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo
Credit Facility matures December 9, 2026. Assuming the amounts outstanding and interest rate of 6.68% for the San Mateo Credit Facility at
December 31, 2022, the interest expense for such facilities is expected to be approximately $31.5 million each year until maturity.

(2) The amounts included in the table above represent principal maturities only. Interest expense on the $699.2 million of Notes that were

outstanding as of December 31, 2022 is expected to be approximately $41.1 million each year until maturity.

(3) At December 31, 2022, we had outstanding commitments to participate in the drilling and completion of various non-operated wells.

(4) We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the

consolidated ﬁnancial statements in this Annual Report for more information regarding these contractual commitments.

(5) The amounts included in the table above represent discounted cash ﬂow estimates for future asset retirement obligations at December 31,

2022.

(6) From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and

produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these
agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we
would be required to pay certain deﬁciency fees. See Note 14 to the consolidated ﬁnancial statements in this Annual Report for more information
about these contractual commitments.

(7) We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and the Greater Stebbins
Area and Stateline asset area pursuant to 15-year, ﬁxed-fee oil transportation, oil, natural gas and produced water gathering and produced water
disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area
and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, ﬁxed-fee natural gas processing agreements. See Note 14
to the consolidated ﬁnancial statements in this Annual Report for more information regarding these contractual commitments.

(8) At December 31, 2022, we had outstanding commitments to purchase 12 compressors to be utilized in San Mateo and Pronto operations.

FORM 10-K PART I I

2022 ANNUAL REPORT

115

GENERAL OUTLOOK AND TRENDS

Our business success and ﬁnancial results are dependent on many factors beyond our control, such as

economic, political and regulatory developments, as well as competition from other sources of energy. Commodity
price volatility, in particular, is a signiﬁcant risk to our business, cash ﬂows and results of operations. Commodity
prices are affected by changes in market supply and demand, which are impacted by overall economic activity,
the ongoing military conﬂict between Russia and Ukraine as well as political instability in China and the Middle East,
the actions of OPEC+, the ongoing impact of COVID-19 and its variants, weather, pipeline capacity constraints,
inventory storage levels, oil and natural gas price differentials and other factors.

The prices we receive for oil, natural gas and NGLs heavily inﬂuence our revenues, proﬁtability, cash ﬂow

available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital,
borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGL prices are
subject to wide ﬂuctuations in response to relatively minor changes in supply and demand. Historically, the markets
for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future.
Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil,
natural gas and NGLs we can produce economically and, as a result, could have a material adverse effect on our
ﬁnancial condition, results of operations, cash ﬂows and reserves and our ability to comply with the ﬁnancial
covenants under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our success
is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued
volatility in these prices may adversely affect our ﬁnancial condition and our ability to meet our capital expenditure
requirements and ﬁnancial obligations.”

During the years ended December 31, 2021 and 2022 and through February 21, 2023, the oil and natural gas
industry experienced continued improvement in commodity prices, as compared to 2020, primarily resulting from
(i) improvements in oil demand as the impact from COVID-19 subsided, (ii) actions taken by OPEC+ to moderate
the worldwide supply of oil and (iii) changes in supply and demand dynamics, particularly with respect to the
ongoing military conﬂict between Russia and Ukraine. While oil and natural gas prices improved signiﬁcantly in 2021,
2022 and early 2023, the general outlook for the oil and natural gas industry for the remainder of 2023 remains
unclear, and we can provide no assurances that commodity prices will remain at current levels or increase further.
In fact, commodity prices may decline from their current levels, particularly in response to the spread of new variants,
if any, of COVID-19, the actions of OPEC+ and other governmental authorities and state-controlled oil companies to
increase the global oil supply and milder weather conditions, among other factors. See “Risk Factors—Risks Related
to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural
gas and NGL prices and the continued volatility in these prices may adversely affect our ﬁnancial condition and our
ability to meet our capital expenditure requirements and ﬁnancial obligations” in this Annual Report. The economic
disruptions associated with COVID-19 and its variants, the ongoing military conﬂict between Russia and Ukraine and
the volatility in oil and natural gas prices have also impacted our ability to access the capital markets on reasonably
similar terms as were available prior to 2020.

FORM 10-K PART I I

116

MATADOR RESOURCES COMPANY

For the year ended December 31, 2022, oil prices averaged $94.33 per Bbl, as compared to $68.11 per Bbl in

2021, ranging from a high of $123.70 per Bbl in early March to a low of $71.02 per Bbl in early December, based
upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $96.32
per Bbl ($92.87 per Bbl including realized losses from oil derivatives) for our oil production for the year ended
December 31, 2022, as compared to $67.58 per Bbl ($56.70 per Bbl including realized losses from oil derivatives) for
the year ended December 31, 2021. At February 21, 2023, the WTI oil futures contract price for the earliest
delivery date had decreased from year-end 2022, closing at $76.16 per Bbl, and was also lower compared to
$91.07 per Bbl on February 18, 2022.

Natural gas prices also increased signiﬁcantly during 2022. For the year ended December 31, 2022, natural gas

prices averaged $6.54 per MMBtu, as compared to $3.71 per MMBtu in 2021, based upon the NYMEX Henry
Hub natural gas futures contract price for the earliest delivery date. During 2022, natural gas prices ranged from
a low of $3.72 per MMBtu in early January to a high of $9.68 per MMBtu in mid-August. As a result of milder-than-
expected winter weather, natural gas prices declined over the course of the fourth quarter of 2022, ﬁnishing the
year at $4.48 per MMBtu. We realized a weighted average natural gas price of $7.98 per Mcf ($7.15 per Mcf
including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31,
2022, as compared to $6.06 per Mcf ($5.74 per Mcf including realized losses from natural gas derivatives) for the
year ended December 31, 2021. As a two-stream reporter, the revenues associated with our NGL production are
included in the weighted average natural gas price. At February 21, 2023, the NYMEX Henry Hub natural gas futures
contract price for the earliest delivery date had decreased from year-end 2022, closing at $2.31 per MMBtu, and
was also lower as compared to $4.43 per MMBtu at February 18, 2022.

From time to time, we use derivative ﬁnancial instruments to mitigate our exposure to commodity price risk

associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production
volumes to hedge are difﬁcult and depend on market conditions and our forecast of future production and oil,
natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect
the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital
markets. During year ended December 31, 2022, we incurred realized losses on our oil and natural gas derivative
contracts of approximately $157.5 million, primarily as a result of oil and natural gas prices that were above the ceiling
prices of certain of our oil and natural gas costless collar contracts and above the strike price of certain oil basis
swap contracts. At December 31, 2022, almost all of the derivative contracts we had in place that contributed to these
realized losses on derivatives in 2022 had expired. At February 21, 2023, given current oil and natural gas prices
and the oil and natural gas derivative contracts we have in place, we do not anticipate losses of such magnitude
from our derivative contracts in 2023, although there may be periods where we realize losses from derivatives.
At December 31, 2022, we had natural gas costless collar contracts in place for approximately 2.4 million MMBtu.

The prices we receive for oil and natural gas production often reﬂect a discount to the relevant benchmark

prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the
benchmark price and the price we receive is called a differential. At December 31, 2022, most of our oil production
from the Delaware Basin was sold based on prices established in Midland, Texas, and a signiﬁcant portion of
our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the
remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the
Waha hub in far West Texas.

FORM 10-K PART I I

2022 ANNUAL REPORT

117

The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 21, 2023,
this oil price differential was approximately +$2.17 per Bbl. At February 21, 2023, we had no derivative contracts in
place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2023.

Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis

differential, which has also been highly volatile in recent years. In early 2022, concerns about natural gas pipeline
takeaway capacity out of the Delaware Basin, particularly beginning in the latter half of 2022, began to increase.
As a result, the Waha basis differential began to widen, and, at February 21, 2023, this natural gas price differential
was approximately ($0.70) per MMBtu. A signiﬁcant portion of our Delaware Basin natural gas production, however,
is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2021 and 2022, we typically
realized a premium to natural gas sold at the Waha hub despite higher transportation charges incurred to transport
the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into
other markets to improve our realized natural gas pricing. Further, approximately 10% of our reported natural gas
production for the year ended December 31, 2022 was attributable to the Haynesville and Eagle Ford shale plays,
which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the
Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes
exposed to Waha pricing.

As of February 21, 2023, we had not experienced material pipeline-related interruptions to our oil, natural gas
or NGL production. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain
operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can
provide no assurances that such problems will not arise. If we do experience any interruptions with takeaway capacity
or NGL fractionation, our oil and natural gas revenues, business, ﬁnancial condition, results of operations and cash
ﬂows could be adversely affected. Should we experience future periods of negative pricing for natural gas as we
have in previous periods, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate
the impact on our realized natural gas prices and results. In addition, although we have contracted ﬁrm physical
transports that limit our exposure to the Waha basis differential, we had derivative contracts in place to mitigate our
exposure to these natural gas price differentials as of February 21, 2023.

In 2022, we began to experience signiﬁcant increases in the costs of certain oilﬁeld services, materials and
equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others, as a result
of the recent increases in oil and natural gas prices, as well as availability constraints, supply chain disruption,
increased demand, labor shortages associated with a fully employed U.S. labor force, inﬂation and other factors.
Should oil and natural gas prices remain at their current levels or increase further, we expect to be subject to
additional service cost inﬂation in future periods, which may increase our costs to drill, complete, equip and operate
wells. In addition, supply chain disruptions and other inﬂationary pressures being experienced throughout the
United States and global economy and in the oil and natural gas industry may limit our ability to procure the
necessary products and services we need for drilling, completing and producing wells in a timely fashion, which
could result in delays to our operations and could, in turn, adversely affect our business, ﬁnancial condition, results
of operations and cash ﬂows.

In addition, we utilized substantially all of our federal and state NOL carryforwards in 2022 and became subject
to federal and state income taxes, which is reﬂected in our current income tax provision of $54.9 million for the year
ended December 31, 2022. At February 21, 2023, given our current projections, we expect to continue to pay
federal income taxes and state income taxes in New Mexico for 2023.

FORM 10-K PART I I

118

MATADOR RESOURCES COMPANY

Our oil and natural gas exploration, development, production, midstream and related operations are subject to

extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and
regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden
on the oil and natural gas industry increases our cost of doing business and affects our proﬁtability. Because
these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are
proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules
and regulations to which we are, or will become, subject. For example, although such bills have not passed, in
recent years, various bills have been introduced in the New Mexico legislature proposing to add a surtax on natural
gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including
prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor signed an executive
order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate
Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the
goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in
greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires
New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission
reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control
of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste
by a ﬁxed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED has
implemented similar rules and regulations. These and other laws, rules and regulations, including any federal
legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if
enacted, could have a material adverse impact on our business, ﬁnancial condition, results of operations and cash
ﬂows. See “Business—Regulation.”

In January 2021, President Biden signed an executive order instructing the Department of the Interior to pause

new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration
of federal oil and natural gas permitting and leasing practices, which lapsed at December 31, 2022. In 2019, 2020 and
2021, an environmental group ﬁled multiple lawsuits in federal district courts in New Mexico and the District of
Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico.
In 2021, ten states, led by the State of Louisiana, ﬁled a lawsuit in federal district court in Louisiana against
President Biden and various other federal government ofﬁcials and agencies challenging an executive order directing
the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases
in its decision making. The BLM indicated that the Lease Sale Litigation or the Social Cost of Carbon Litigation could
delay lease sales and the approval of drilling permits. The impact of federal actions and lawsuits related to the oil
and natural gas industry remains unclear, and should other limitations or prohibitions be imposed or continue to be
applied, our operations on federal lands could be adversely impacted. Such limitations or prohibitions would
almost certainly impact our future drilling and completion plans and could materially impact our production volumes,
revenues, reserves, cash ﬂows and availability under our Credit Agreement. See “Risk Factors—Risks Related to
Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on
federal lands, which are subject to administrative permitting requirements and potential federal legislation,
regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”

We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and
production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing
such disposal activities. State and federal regulatory agencies recently have focused on a possible connection
between the operation of injection wells used for produced water disposal and the increased occurrence of seismic
activity, also known as “induced seismicity.” This has resulted in stricter regulatory requirements in some
jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits

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have been ﬁled in some states against others in our industry alleging that ﬂuid injection or oil and natural gas
extraction have caused damage to neighboring properties or otherwise violated state and federal rules regarding
waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are
seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal
wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in 2021,
the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under
these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic
activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying
levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the
area of seismic events based on the magnitude, timing and proximity of the seismic event. The adoption of federal,
state and local legislation and regulations intended to address induced seismicity in the areas in which we operate
could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered
from such activities, and could result in increased costs and additional operating restrictions or delays, that could, in
turn, materially impact our production volumes, revenues, reserves, cash ﬂows and availability under our Credit
Agreement. The adoption of such legislation and regulations could also decrease our and San Mateo’s revenues and
result in increased costs and additional operating restrictions for San Mateo as well.

Certain segments of the investor community have recently expressed negative sentiment towards investing in

the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry
sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors,
including certain pension funds, sovereign wealth funds, university endowments and family foundations, have
stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and
environmental considerations.

Like other oil and natural gas producing companies, our properties are subject to natural production declines.
By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome
these production declines by drilling to develop and identify additional reserves, by exploring for new sources
of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however,
drilling additional oil or natural gas wells may not be economic, and we may ﬁnd it necessary to reduce capital
expenditures and curtail drilling operations in order to preserve liquidity. A signiﬁcant reduction in capital expenditures
and drilling activities could materially impact our production volumes, revenues, reserves, cash ﬂows and the
availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our
exploration, development, exploitation and midstream projects require substantial capital expenditures that may
exceed our cash ﬂows from operations and potential borrowings, and we may be unable to obtain needed capital
on satisfactory terms, which could adversely affect our future growth”.

We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at

a level that is appropriate for long-term operations. Our ability to ﬁnd and develop sufﬁcient quantities of oil and
natural gas reserves at economical costs is critical to our long-term success. Future ﬁnding and development costs
are subject to changes in the costs of acquiring, drilling and completing our prospects.

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MATADOR RESOURCES COMPANY

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of ﬁnancial statements in conformity with GAAP requires us to make estimates and assumptions

that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period.
We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ
signiﬁcantly from those reported; however, such estimates and assumptions are subject to a number of risks and
uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates.
We consider the following to be our most critical accounting policies and estimates involving signiﬁcant judgment
or estimates by our management. See Note 2 to the consolidated ﬁnancial statements in this Annual Report for
further details on our accounting policies at December 31, 2022.

Oil and Natural Gas Properties

We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this

method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and
reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in
a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs
include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties,
costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and
administrative expenses directly related to acquisition, exploration and development activities, but do not include
any costs related to production, selling or general corporate administrative activities.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon

production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded
from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for
possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment
includes consideration of the following factors, among others: the assignment of proved reserves, geological and
geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the
costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry
holes are included in the amortization base immediately upon the determination that the well is not productive.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less

related deferred income taxes or the cost center “ceiling.” The cost center ceiling is deﬁned as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced

by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being

amortized, if any, less

(d) any income tax effects related to the properties involved.

Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations
as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we
do not designate these instruments as hedge instruments for accounting purposes.

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Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net

revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected
to present only proved reserves in this Annual Report. The applicable rules deﬁne proved reserves as the quantities
of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible—from a given date forward, from known reservoirs and under existing
economic conditions, operating methods and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of
whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons
must have commenced, or the operator must be reasonably certain that it will commence the project within a
reasonable time.

Our engineers and technical staff must make many subjective assumptions based on their professional judgment in

developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and
other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of
the numerous uncertainties inherent in the process. The process relies on interpretations of available geological,
geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and
the associated interpretations can vary. The process also requires certain economic assumptions, including, but
not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and
taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly,
reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.
Any signiﬁcant variance could materially and adversely affect our future reserves estimates, ﬁnancial condition,
results of operations and cash ﬂows. We cannot predict the amounts or timing of future reserves revisions. If such
revisions are signiﬁcant, they could signiﬁcantly affect future amortization of capitalized costs and result in an
impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil
and natural gas reserves are estimated and may not reﬂect the actual volumes of oil and natural gas we will recover,
and signiﬁcant inaccuracies in these reserves estimates or underlying assumptions will materially affect the
quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may
be required to write down the carrying value of our proved properties under accounting rules, and these write-
downs could adversely affect our ﬁnancial condition.”

Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling

test and the fair value assigned to proved oil and natural gas reserves acquired in a business combination. The
estimated present value of future net cash ﬂows from proved oil and natural gas reserves is highly dependent upon
the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas
reserves are estimated using then-current operating and economic conditions, with no provision for price and cost
escalations in future periods except by contractual arrangements. The associated commodity prices and the
applicable discount rate used to determine the fair value assigned to proved oil and natural gas reserves acquired in
a business combination are based upon a variety of factors on the date of acquisition. The associated commodity
prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with
guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that
represent the arithmetic averages of the ﬁrst-day-of-the-month oil and natural gas prices for the previous 12-month
period, and a 10% discount factor is used to determine the present value of future net revenues.

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Derivative Financial Instruments

From time to time, we use derivative ﬁnancial instruments to mitigate our exposure to commodity price risk

associated with oil, natural gas and NGL prices. Prior to settlement, our derivative ﬁnancial instruments are recorded
on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge
accounting for our existing derivative ﬁnancial instruments, and as a result, we recognize the change in derivative
fair value between reporting periods currently as an unrealized gain or loss on derivatives in our consolidated
statements of operations. Changes in the fair value of these open derivative ﬁnancial instruments can have a
signiﬁcant impact on our reported results from period to period but do not impact our cash ﬂows from operations,
liquidity or capital resources. The fair value of our open derivative ﬁnancial instruments is determined using
industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time
value of money and (iii) current market and contractual prices for the underlying instruments, as well as other
relevant economic measures.

Stock-Based Compensation

We may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock

units, performance stock units and other awards permitted under any long-term incentive plan then in effect to
members of our Board of Directors and certain employees, contractors and advisors. We use the fair value method
to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest
over three or four years, and the associated compensation expense is recognized on a straight-line basis over
the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and
compensation expense is recognized on a straight line basis over the vesting period. We use our own historical
volatility to estimate the future volatility of our stock.

We use the Black Scholes Merton model to determine the fair value of service-based option awards and the

Monte Carlo method to determine the fair value of awards that contain a market condition. The fair value of
restricted stock and restricted stock unit awards is recognized based on the closing price of our common stock on
the date of the grant for awards issued under the 2012 Incentive Plan and on the trading day prior to the date of
grant for awards issued under the 2019 Incentive Plan. See Note 9 to the consolidated ﬁnancial statements in this
Annual Report for further details on our stock-based compensation at December 31, 2022.

Income Taxes

We account for income taxes using the asset and liability approach for ﬁnancial accounting and reporting. The

amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state
taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses
and tax carryforwards. We evaluate the probability of realizing the future beneﬁts of our deferred tax assets and
provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income
tax beneﬁt in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the ﬁnancial statement beneﬁt of a tax position
only after determining that the relevant tax authority would more likely than not sustain the position following an
audit. For tax positions meeting the more likely than not threshold, the amount recognized in the ﬁnancial
statements is the beneﬁt that has a greater than 50% likelihood of being realized upon ultimate settlement with
the relevant tax authority.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty
and customer risk. We address these risks through a program of risk management including the use of derivative
ﬁnancial instruments, but we do not enter into derivative ﬁnancial instruments for trading purposes.

Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs ﬂuctuate

as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these
market ﬂuctuations, we have entered into derivative ﬁnancial instruments in the past and expect to enter into
derivative ﬁnancial instruments in the future to cover a signiﬁcant portion of our anticipated future production.

We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to

changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the
purchase of a put option that is ﬁnanced through the sale of a call option. Because the call option proceeds are used
to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also
provide us with downside price protection through the purchase of a put option, but they also allow us to participate
in price upside through the purchase of a call option. The purchase of both the put option and call option are ﬁnanced
through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the
purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar,
the put option or options and the call option or options have different ﬁxed price components. In a swap contract, a
ﬂoating price is exchanged for a ﬁxed price over a speciﬁed period, providing downside price protection.

We record all derivative ﬁnancial instruments at fair value. The fair value of our derivative ﬁnancial instruments
is determined using purchase and sale information available for similarly traded securities. At December 31, 2022,
PNC Bank was the counterparty for our derivative instrument. We have considered the credit standing of the
counterparty in determining the fair value of our derivative ﬁnancial instruments.

At December 31, 2022, we had entered into a costless collar contract to mitigate our exposure to ﬂuctuations in

natural gas prices, with an established price ﬂoor and ceiling. When the settlement price is below the price ﬂoor
established by the collar, we receive from our counterparty an amount equal to the difference between the
settlement price and the price ﬂoor multiplied by the contract oil or natural gas volume. When the settlement price
is above the price ceiling established by the costless collar, we pay our counterparty an amount equal to the
difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume.

See Note 12 to the consolidated ﬁnancial statements in this Annual Report for a summary of our open derivative

ﬁnancial instruments at December 31, 2022. Such information is incorporated herein by reference.

Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and

regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act
requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the
CFTC has ﬁnalized certain regulations, others remain to be ﬁnalized or implemented, and it is not possible at this
time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with
respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and
adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act
could result in the implementation of position limits and additional regulatory requirements on our derivative
arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation
could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements
in the future. See “Risk Factors—Risks Related to Laws and Regulations—The derivatives legislation adopted by
Congress could have an adverse impact on our ability to hedge risks associated with our business.”

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Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an

attempt to reduce interest rate expense on existing debt. At December 31, 2022, we had no outstanding
borrowings under our Credit Agreement, $699.2 million in Notes outstanding at a coupon rate of 5.875% per annum
and $465.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 6.68% per
annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate
derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the
overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial
interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases
on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit
risk due to concentration of our oil and natural gas receivables with several signiﬁcant customers and San Mateo and
Pronto are subject to the credit risk of their customers. The inability or failure of our, San Mateo’s or Pronto’s
signiﬁcant customers to meet their obligations or their insolvency or liquidation may adversely affect our ﬁnancial
condition, results of operations and cash ﬂows. In addition, our derivative arrangements expose us to credit risk in
the event of nonperformance by our counterparties.

While we do not require our customers to post collateral and we do not have a formal process in place to evaluate
and assess the credit standing of our signiﬁcant customers for oil and natural gas receivables and the counterparties
on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate
under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit
terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest ﬁnancial information and,
in the case of a customer with which we have receivables, its historical payment record and the ﬁnancial ability
of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to
determine credit terms and credit limits. The counterparty on our derivative ﬁnancial instruments in place at
February 21, 2023 was PNC Bank, who is also a lender (or afﬁliate thereof) under our Credit Agreement.

Impact of inﬂation. Inﬂation in the United States has become much more signiﬁcant in recent years, and in
2022 it reached its highest levels in approximately 40 years. At February 21, 2023, we do not know how long these
inﬂationary pressures may persist or the impact they may have on our business moving forward. We tend to
speciﬁcally experience inﬂationary pressure on the cost of oilﬁeld services and equipment with increases in oil and
natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and
Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. We have begun
to experience such inﬂationary pressure in our drilling and completion and midstream operations, and we
budgeted a 10 to 20% increase in oilﬁeld service costs in preparing our full year 2023 D/C/E and midstream capital
expenditures estimates. See “Risk Factors—Risks Related to our Financial Condition—Our industry and the
broader U.S. economy experienced higher than expected inﬂationary pressures in 2022, related to increases in oil
and natural gas prices, continued supply chain disruptions, labor shortages and geopolitical instability. Should these
conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis,
or at all, and, as a result, our business, ﬁnancial condition, results of operations and cash ﬂows could be materially
and adversely affected” and “Risk Factors—Risks Related to our Operations—The unavailability or high cost of
drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment
and personnel, could adversely affect our ability to establish and execute exploration and development plans within
budget and on a timely basis, which could have a material adverse effect on our ﬁnancial condition, results of
operations and cash ﬂows.”

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our ﬁnancial statements appear at the end of this Annual Report beginning on page F-1.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and
operation of the Company’s disclosure controls and procedures (as deﬁned in Rule 13a-15(e) under the Exchange
Act) under the supervision and with the participation of our management, including our Chief Executive Ofﬁcer and
our Chief Financial Ofﬁcer. Based on that evaluation, our Chief Executive Ofﬁcer and our Chief Financial Ofﬁcer
concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2022 to
ensure that (i) information required to be disclosed in the reports it ﬁles and submits under the Exchange Act is
recorded, processed, summarized and reported within the time periods speciﬁed in the SEC’s rules and forms and
that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the
Company’s management, including our Chief Executive Ofﬁcer and our Chief Financial Ofﬁcer, as appropriate to
allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2022, there were no changes in our internal controls that have materially

affected or are reasonably likely to have a material effect on our internal control over ﬁnancial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over ﬁnancial reporting

as deﬁned in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the
participation of our management, including our Chief Executive Ofﬁcer and our Chief Financial Ofﬁcer, we assessed
the effectiveness of our internal control over ﬁnancial reporting as of the end of the period covered by this Annual
Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Ofﬁcer and
our Chief Financial Ofﬁcer concluded that our internal control over ﬁnancial reporting was effective to provide
reasonable assurance regarding the reliability of our ﬁnancial reporting and the preparation of our ﬁnancial statements
for external purposes in accordance with U.S. generally accepted accounting principles.

KPMG, our independent registered public accounting ﬁrm, has issued an attestation report on our controls over

ﬁnancial reporting as of December 31, 2022 as included herein.

Important Considerations

The effectiveness of our disclosure controls and procedures and our internal control over ﬁnancial reporting is
subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions
about the likelihood of future events, the soundness of our systems, the possibility of human error and the
risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions and the risk that the degree of compliance
with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that
any system of disclosure controls and procedures or internal control over ﬁnancial reporting will be successful
in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate
levels of management.

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MATADOR RESOURCES COMPANY

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors
Matador Resources Company:

Opinion on Internal Control Over Financial Reporting

We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over ﬁnancial

reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the
Company maintained, in all material respects, effective internal control over ﬁnancial reporting as of December 31,
2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission.

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, 2022 and 2021, the
related consolidated statements of operations, changes in shareholders’ equity, and cash ﬂows for each of the
years in the three-year period ended December 31, 2022, and the related notes (collectively, the consolidated
ﬁnancial statements), and our report dated March 1, 2023 expressed an unqualiﬁed opinion on those consolidated
ﬁnancial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over ﬁnancial reporting and

for its assessment of the effectiveness of internal control over ﬁnancial reporting, included in the accompanying
Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on
the Company’s internal control over ﬁnancial reporting based on our audit. We are a public accounting ﬁrm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with the
U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective internal control over ﬁnancial reporting
was maintained in all material respects. Our audit of internal control over ﬁnancial reporting included obtaining an
understanding of internal control over ﬁnancial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audit also included performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.

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Deﬁnition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over ﬁnancial reporting is a process designed to provide reasonable assurance
regarding the reliability of ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over ﬁnancial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reﬂect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of ﬁnancial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the ﬁnancial statements.

Because of its inherent limitations, internal control over ﬁnancial reporting may not prevent or detect

misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.

Dallas, Texas
March 1, 2023

/s/ KPMG LLP

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MATADOR RESOURCES COMPANY

ITEM 9B. OTHER INFORMATION.

Not applicable.

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Part III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The information required in response to this Item 10 is incorporated herein by reference to our deﬁnitive

proxy statement for our 2023 Annual Meeting of Shareholders to be ﬁled with the SEC pursuant to Regulation 14A
promulgated under the Exchange Act not later than 120 days after the end of the ﬁscal year covered by this
Annual Report (our “Deﬁnitive Proxy Statement”). Such responsive information is expected to be included under
the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Compensation” and
“Director Compensation.”

ITEM 11. EXECUTIVE COMPENSATION.

The information required in response to this Item 11 is incorporated herein by reference to our Deﬁnitive Proxy

Statement under the caption “Executive Compensation.”

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

AND RELATED STOCKHOLDER MATTERS.

Certain information regarding securities authorized for issuance under our equity compensation plans is
included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is
incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein
by reference to our Deﬁnitive Proxy Statement under the caption “Security Ownership of Certain Beneﬁcial Owners
and Management.”

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,

AND DIRECTOR INDEPENDENCE.

The information required in response to this Item 13 is incorporated herein by reference to our Deﬁnitive

Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—
Independence of Directors.”

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information required in response to this Item 14 is incorporated herein by reference to our Deﬁnitive Proxy

Statement under the caption “Proposal 3—Ratiﬁcation of Appointment of KPMG LLP.”

FORM 10-K PART III

130

MATADOR RESOURCES COMPANY

Part IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

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

1.

Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm,
Consolidated Balance Sheets as of December 31, 2022 and 2021, Consolidated Statements of Operations
for the Years Ended December 31, 2022, 2021 and 2020, Consolidated Statements of Changes in
Shareholders’ Equity for the Years Ended December 31, 2022, 2021 and 2020 and Consolidated Statements
of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020.

2. Financial Statement Schedules: All other schedules for which provision is made in the applicable accounting
regulations of the SEC are omitted because the required information is either not applicable, not required or
is shown in the respective ﬁnancial statements or in the notes thereto.

3. Exhibits: The exhibits required to be ﬁled by this Item 15 are set forth in the Exhibit Index included below.

ITEM 16. FORM 10-K SUMMARY.

None.

FORM 10-K PART I V

2022 ANNUAL REPORT

131

Exhibit Index

Exhibit
Number Description

2.1*

2.2*

3.1

3.2

3.3

3.4

4.1

4.2

4.3

4.4

4.5

10.1†

10.2†

10.3†

Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream
Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to
the Current Report on Form 8-K ﬁled on February 24, 2017).

Securities Purchase Agreement, dated January 24, 2023, by and among MRC Hat Mesa, LLC, MRC Energy
Company (solely for the limited purposes stated therein), AEP EnCap HoldCo, LLC, Ameradvance Management
LLC and Advance Energy Partners Holdings, LLC (incorporated by reference to Exhibit 2.1 to the Current Report
on Form 8-K ﬁled on January 24, 2023).

Amended and Restated Certiﬁcate of Formation of Matador Resources Company (incorporated by reference to
Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

Certiﬁcate of Amendment to the Amended and Restated Certiﬁcate of Formation of Matador Resources Company
dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 2017).

Certiﬁcate of Amendment to the Amended and Restated Certiﬁcate of Formation of Matador Resources Company
effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the
quarter ended June 30, 2017).

Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to
Exhibit 3.1 to the Current Report on Form 8-K ﬁled on February 22, 2018).

Form of Common Stock Certiﬁcate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the
Registration Statement on Form S-1 ﬁled on January 19, 2012).

Indenture, dated as of August 21, 2018, by and among Matador Resources Company, the subsidiary guarantors
party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to
the Current Report on Form 8-K ﬁled on August 21, 2018).

First Supplemental Indenture, dated as of February 27, 2019, by and among Matador Resources Company,
WR Permian, LLC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee
(incorporated by reference to Exhibit 4.3 to the Annual Report on Form 10-K for the year ended December 31, 2018).

Second Supplemental Indenture, dated as of December 14, 2021, by and among Matador Resources Company,
the subsidiary guarantors party thereto and Computershare Trust Company, N. A., as agent for Wells Fargo Bank,
National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K ﬁled
on December 14, 2021).

Description of Capital Stock (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the
year ended December 31, 2019).

Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference
to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran
(incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 ﬁled on
November 14, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm.
Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1
ﬁled on December 30, 2011).

FORM 10-K PART I V

132

MATADOR RESOURCES COMPANY

Exhibit
Number Description

10.4†

10.5†

10.6†

10.7†

10.8†

10.9†

10.10†

10.11

10.12

10.13

10.14

Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by
reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013).

Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective
February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended
December 31, 2014).

Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and
G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on
Form 10-Q for the quarter ended March 31, 2017).

First Amendment to the Employment Agreement between Matador Resources Company and Billy E. Goodwin
(incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).

First Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug
(incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).

Form of Employment Agreement between Matador Resources Company and each of Michael D. Frenzel,
W. Thomas Elsener and Brian J. Willey (incorporated by reference to Exhibit 10.1 to the Quarterly Report on
Form 10-Q for the quarter ended September 20, 2022).

Form of Indemniﬁcation Agreement between Matador Resources Company and each of the directors and
executive ofﬁcers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company,
Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated
as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for
the year ended December 31, 2012).

Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company,
MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc.,
Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as
Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the
Annual Report on Form 10-K for the year ended December 31, 2012).

Fourth Amended and Restated Credit Agreement, dated as of November 18, 2021, by and among MRC Energy
Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of
Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K
ﬁled on November 18, 2021).

First Amendment to Fourth Amended and Restated Credit Agreement dated as of April 25, 2022, by and among
MRC Energy Company, as Borrower, the lending entities from time to time parties thereto as Lenders, and
Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Quarterly Report
on Form 10-Q for the quarter ended March 31, 2022).

10.15†

Matador Resources Company Nonqualiﬁed Deferred Compensation Plan for Non-Employee Directors (incorporated
by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015).

FORM 10-K PART I V

2022 ANNUAL REPORT

133

Exhibit
Number Description

10.16†

10.17†

10.18†

10.19†

10.20†

10.21†

10.22†

10.23†

10.24†

10.25†

10.26†

10.27†

10.28†

Matador Resources Company Annual Cash Incentive Plan, effective as of January 1, 2019 (incorporated by
reference to Exhibit 10.66 to the Annual Report on Form 10-K for the year ended December 31, 2018).

Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current
Report on Form 8-K ﬁled on June 11, 2015).

Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive
Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended
September 30, 2017).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company Amended and
Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by
reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated
2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to
Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015).

Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company
2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for
the year ended December 31, 2016).

Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the
Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference
to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the
Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference
to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

Form of Nonqualiﬁed Stock Option Agreement for awards under the Matador Resources Company Amended
and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by
reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

Form of Nonqualiﬁed Stock Option Agreement for awards under the Matador Resources Company Amended and
Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference
to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and
Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by
reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and
Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference
to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).

Form of Phantom Unit Award Agreement for awards under the Matador Resources Company Amended and
Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference
to Exhibit 10.67 to the Annual Report on Form 10-K for the year ended December 31, 2018).

FORM 10-K PART I V

134

MATADOR RESOURCES COMPANY

Exhibit
Number Description

10.29†

Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company
Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated
by reference to Exhibit 10.68 to the Annual Report on Form 10-K for the year ended December 31, 2018).

10.30† Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to the

Registration Statement on Form S-8 ﬁled on June 6, 2019).

10.31†

10.32†

10.33†

10.34†

10.35†

10.36†

10.37†

10.38†

10.39†

First Amendment to Matador Resources Company 2019 Long-Term Incentive Plan effective April 21, 1011
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on June 16, 2022).

Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company 2019
Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the
quarter ended June 30, 2019).

Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador
Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly
Report on Form 10-Q for the quarter ended June 30, 2019).

Form of Phantom Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term
Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.1 to the
Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).

Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019
Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.2
to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).

Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019
Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.58
to the Annual Report on Form 10-K for the year ended December 31, 2021).

Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019
Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit
10.59 to the Annual Report on Form 10-K for the year ended December 31, 2021).

Form of Restricted Stock Award Agreement for awards under the Matador Resources Company 2019 Long-Term
Incentive Plan with ratable vesting for employees without employment agreements (incorporated by reference to
Exhibit 10.60 to the Annual Report on Form 10-K for the year ended December 31, 2021).

Form of Stock Option Cancellation Agreement for certain stock options under the Matador Resources Company
Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.56 to the Annual
Report on Form 10-K for the year ended December 31, 2020).

10.40† Matador Resources Company 2022 Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.2 to

the Current Report on Form 8-K ﬁled on June 16, 2022).

FORM 10-K PART I V

2022 ANNUAL REPORT

135

Exhibit
Number Description

21.1

22.1

23.1

23.2

31.1

31.2

32.1

32.2

99.1

101

List of Subsidiaries of Matador Resources Company (ﬁled herewith).

List of Subsidiary Guarantors (ﬁled herewith).

Consent of KPMG LLP (ﬁled herewith).

Consent of Netherland, Sewell & Associates, Inc. (ﬁled herewith).

Certiﬁcation of Principal Executive Ofﬁcer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (ﬁled
herewith).

Certiﬁcation of Principal Financial Ofﬁcer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (ﬁled
herewith).

Certiﬁcation of Principal Executive Ofﬁcer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (furnished herewith).

Certiﬁcation of Principal Financial Ofﬁcer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (furnished herewith).

Audit report of Netherland, Sewell & Associates, Inc. (ﬁled herewith).

The following ﬁnancial information from Matador Resources Company’s Annual Report on Form 10-K for the year
ended December 31, 2021, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the
Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of
Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated
Financial Statements (submitted electronically herewith).

104

Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101).

†

*

Indicates a management contract or compensatory plan or arrangement.

This ﬁling excludes certain schedules and exhibits pursuant to Item 601(a)(5) of Regulation S-K, which the Company agrees to furnish
supplementally to the SEC upon request; provided, however, that the Company may request conﬁdential treatment pursuant to Rule 24b-2 of the
Securities Exchange Act of 1934, as amended, for any schedules or exhibits so furnished.

FORM 10-K PART I V

136

MATADOR RESOURCES COMPANY

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has

duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

March 1, 2023

MATADOR RESOURCES COMPANY

By:

/s/ JOSEPH WM. FORAN
Joseph Wm. Foran
Chairman and Chief Executive Ofﬁcer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below
by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

/s/ JOSEPH WM. FORAN
Joseph Wm. Foran

Chairman and Chief Executive Ofﬁcer
(Principal Executive Ofﬁcer)

Date

March 1, 2023

/s/ BRIAN J. WILLEY
Brian J. Willey

Chief Financial Ofﬁcer, President of Midstream Operations March 1, 2023

and Executive Vice President
(Principal Financial Ofﬁcer)

/s/ ROBERT T. MACALIK
Robert T. Macalik

Executive Vice President and Chief Accounting Ofﬁcer
(Principal Accounting Ofﬁcer)

March 1, 2023

Director

Director

Director

Director

Director

Director

Director

Director

March 1, 2023

March 1, 2023

March 1, 2023

March 1, 2023

March 1, 2023

March 1, 2023

March 1, 2023

March 1, 2023

/s/ REYNALD A. BARIBAULT
Reynald A. Baribault

/s/ R. GAINES BATY
R. Gaines Baty

/s/ WILLIAM M. BYERLEY
William M. Byerley

/s/ MONIKA U. EHRMAN
Monika U. Ehrman

/s/ JULIA P. FORRESTER ROGERS
Julia P. Forrester Rogers

/s/ JAMES M. HOWARD
James M. Howard

/s/ TIMOTHY E. PARKER
Timothy E. Parker

/s/ KENNETH L. STEWART
Kenneth L. Stewart

FORM 10-K Signatures

2022 ANNUAL REPORT

137

Glossary of Oil and Natural Gas Terms

The following is a description of the meanings of some of the oil and natural gas industry terms used in this

Annual Report.

Batch drilling. The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the
surface holes for each well are drilled ﬁrst and then the production holes, including the horizontal laterals for each
well, are drilled.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil,

other liquid hydrocarbons or produced water.

Bcf. One billion cubic feet of natural gas.

Bench. A geologic zone or formation or a subdivision of a geologic formation.

BOE. Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or NGLs to six Mcf

of natural gas.

BOE/d. BOE per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one

degree Fahrenheit.

Central delivery point or CDP. The point on an oil, natural gas or produced water system where such product is
aggregated from one or more gathering or transportation pipelines, wells, tank batteries or leases. Custody is often
transferred to a third party at a central delivery point.

Completion. The operations required to establish production of oil or natural gas from a wellbore, usually involving

perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the
reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reservoir.

Conventional reservoirs or resources. Natural gas or oil that is produced by a well drilled into a geologic formation

in which the reservoir and ﬂuid characteristics permit the natural gas or oil to readily ﬂow to the wellbore.

Coring. The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter,

taken as a sample of an underground formation. It is common practice to take cores from wells in the process
of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the
formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its
characteristics (porosity, permeability, etc.) are determined.

Developed acreage. The number of acres that are allocated or assignable to productive wells.

Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon

known to be productive.

Differential. The difference between a particular oil or natural gas price and the applicable benchmark price, such

as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price.

Dry hole. A well found to be incapable of producing hydrocarbons.

ESP. Electric submersible pump.

Exploratory well. A well drilled to ﬁnd and produce oil or natural gas reserves not classiﬁed as proved, to ﬁnd
a new reservoir in a ﬁeld previously found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.

Glossary of Oil and Natural Gas Terms FORM 10-K

138

MATADOR RESOURCES COMPANY

Farmin or farmout. An agreement under which the owner of a working interest in an oil or natural gas lease
assigns the working interest or a portion of the working interest to another party who desires to drill on the leased
acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.
The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a
“farmin” while the interest transferred by the assignor is a “farmout.”

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same

individual geological structural feature and/or stratigraphic condition.

GAAP, or U.S. GAAP. United States, generally accepted accounting principles.

Gross acres or gross wells. The total acres or wells in which a working interest is owned.

Held by production. An oil and natural gas property under lease in which the lease continues to be in force after

the primary term of the lease in accordance with its terms as a result of production from the property.

Horizontal drilling or well. A drilling operation in which a portion of the well is drilled horizontally within a

productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to
produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace
multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption.

Hydraulic fracturing. The technique of improving a well’s production or injection rates by pumping a mixture of
ﬂuids into the formation and rupturing the rock, creating an artiﬁcial channel. As part of this technique, sand or other
material may also be injected into the formation to prop the channel open, so that ﬂuids or gases may more easily
ﬂow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to
as fracture stimulation.

Lateral length. Length of the drilled or completed portion of a horizontal well.

Liquids. Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane

and natural gasoline resulting from the further processing of liqueﬁable hydrocarbons separated from raw natural
gas by a natural gas processing facility.

MBbl. One thousand barrels of crude oil, other liquid hydrocarbons or produced water.

MBOE. One thousand BOE.

Mcf. One thousand cubic feet of natural gas.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

NGL. Natural gas liquids.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells.

Net revenue interest. The interest that deﬁnes the percentage of revenue that an owner of a well receives from

the sale of oil, natural gas and/or natural gas liquids that are produced from the well.

NYMEX. New York Mercantile Exchange.

Organization of Petroleum Exporting Countries or OPEC. An intergovernmental group of 13 of the world’s major

oil-exporting countries, which was founded in 1960 to coordinate the petroleum policies of its members and to provide
member countries with technical and economic aid.

OPEC+. A loose afﬁliation of the member countries of OPEC and 10 of the world’s other major oil-exporting

countries, including Russia.

FORM 10-K Glossary of Oil and Natural Gas Terms

2022 ANNUAL REPORT

139

Overriding royalty interest. A fractional interest in the gross production of oil and natural gas under a lease, in

addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development,
operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the
lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved
royalty interest.

Pad. The surface constructed to accommodate the drilling, completion and production operations of an oil or

natural gas well.

Pad drilling. The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each

well on the pad is drilled to total depth before the next well is initiated.

Permeability. A reference to the ability of oil and/or natural gas to ﬂow through a reservoir.

Petrophysical analysis. The interpretation of well log measurements, obtained from a string of electronic tools
inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface,
then combining these measurements with other relevant geological and geophysical information to describe the
reservoir rock properties.

Play. A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and
temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.

Possible reserves. Additional reserves that are less certain to be recognized than probable reserves.

Probable reserves. Additional reserves that are less certain to be recognized than proved reserves but which, in

sum with proved reserves, are as likely as not to be recovered.

Producing well, or productive well. A well that is found to be capable of producing hydrocarbons in sufﬁcient
quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes.

Properties. Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other

mineral fee, leasehold and related interests.

Prospect. A speciﬁc geographic area which, based on supporting geological, geophysical or other data and

preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the
discovery of commercial hydrocarbons.

Prospectivity. Having the potential for the discovery and/or future development of commercial hydrocarbons in a

speciﬁc geographic area or formation.

Proved developed non-producing. Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the

production of which has been postponed pending installation of surface equipment or gathering facilities, or
pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons
are classiﬁed as proved developed but non-producing reserves.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells and

facilities and by existing operating methods.

Proved reserves. Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis

of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled

acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. Completing in the same wellbore to reach a new reservoir after production from the original

reservoir has been abandoned.

Glossary of Oil and Natural Gas Terms FORM 10-K

140

MATADOR RESOURCES COMPANY

Repeatability. The potential ability to drill multiple wells within a prospect or trend.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible
oil and/or natural gas that is conﬁned by impermeable rock or water barriers and is individual and separate from
other reservoirs.

Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive

a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not
require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties
may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the
lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a
transfer to a subsequent owner.

2-D seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation

of reﬂection seismic data collected along a single source proﬁle.

3-D seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the
interpretation of reﬂection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed
understanding of the subsurface than do 2-D seismic surveys and contribute signiﬁcantly to ﬁeld appraisal,
exploitation and production.

Spud. The act of beginning to drill an oil or natural gas well.

Throughput. The volume of product transported or passing through a pipeline, plant or other facility.

Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully deﬁned,
having geological characteristics that have been ascertained through supporting geological, geophysical or other data
to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.

Unconventional resource play. A set of known or postulated oil and or natural gas resources or reserves

warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and
(ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural
gas resources.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains
proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable
to productive wells.

Unproved and unevaluated properties. Properties where no drilling or other actions have been undertaken that

permit such properties to be classiﬁed as proved and to which no proved reserves have been assigned.

Vertical well. A hole drilled vertically into the earth from which oil, natural gas or water ﬂows or is pumped.

Visualization. An exploration technique in which the size and shape of subsurface features are mapped and

analyzed based upon information derived from well logs, seismic data and other well information.

Volumetric reserves analysis. A technique used to estimate the amount of recoverable oil and natural gas. It

involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation,
formation volume factor and recovery factor.

WTI. West Texas Intermediate.

Wellbore. The hole made by a well.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating

activities on the property and receive a share of production.

FORM 10-K Glossary of Oil and Natural Gas Terms

2022 ANNUAL REPORT

F-1

Consolidated Financial Statements

MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2022, 2021 and 2020

Contents

Page

Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

F-2

Consolidated Financial Statements

Consolidated Balance Sheets as of December 31, 2022 and 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Consolidated Statements of Operations for the Years Ended December 31, 2022, 2021 and 2020 . . . . . . . . . . .

Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2022,

2021 and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020 . . . . . . . . . .

Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

F-4

F-5

F-6

F-7

F-8

Unaudited Supplementary Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-42

Consolidated Financial Statements FORM 10-K

F-2

MATADOR RESOURCES COMPANY

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors
Matador Resources Company:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Matador Resources Company and

subsidiaries (the Company) as of December 31, 2022 and 2021, the related consolidated statements of operations,
changes in shareholders’ equity, and cash ﬂows for each of the years in the three-year period ended December 31,
2022, and the related notes (collectively, the consolidated ﬁnancial statements). In our opinion, the consolidated
ﬁnancial statements present fairly, in all material respects, the ﬁnancial position of the Company as of December 31,
2022 and 2021, and the results of its operations and its cash ﬂows for each of the years in the three-year period
ended December 31, 2022, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the Company’s internal control over ﬁnancial reporting as of December 31, 2022, based on
criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission, and our report dated March 1, 2023 expressed an opinion on the
effectiveness of the Company’s internal control over ﬁnancial reporting.

Basis for Opinion

These consolidated ﬁnancial statements are the responsibility of the Company’s management. Our responsibility
is to express an opinion on these consolidated ﬁnancial statements based on our audits. We are a public accounting
ﬁrm registered with the PCAOB and are required to be independent with respect to the Company in accordance
with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the consolidated ﬁnancial statements are free of
material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks
of material misstatement of the consolidated ﬁnancial statements, whether due to error or fraud, and performing
procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the
amounts and disclosures in the consolidated 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 consolidated ﬁnancial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated

ﬁnancial statements that was communicated or required to be communicated to the audit committee and that:
(1) relates to accounts or disclosures that are material to the consolidated ﬁnancial statements and (2) involved
our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not
alter in any way our opinion on the consolidated ﬁnancial statements, taken as a whole, and we are not, by
communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the
accounts or disclosures to which it relates.

Impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas
properties on depletion expense and the ceiling test calculation

As discussed in Note 2 to the consolidated ﬁnancial statements, the Company uses the full-cost method of
accounting for its investments in oil and natural gas properties and amortizes capitalized costs of oil and natural
gas properties using the unit-of-production method based on production and estimates of proved reserves

FORM 10-K Consolidated Financial Statements

2022 ANNUAL REPORT

F-3

quantities. The Company is required to perform a ceiling test calculation on a quarterly basis and the applicable
ceiling is equal to the sum of (1) the present value, discounted at 10%, of future net revenues of proved oil and
natural gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and
unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved
and unevaluated properties included in the costs being amortized, if any, less (4) any income tax effects related
to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling is
charged to operations as a full-cost ceiling impairment. Estimates of economically recoverable oil and natural gas
reserves depend upon a number of factors and assumptions, including quantities of oil and natural gas that are
ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the
amount of future development expenditures, and the price received for the production. For the year ended
December 31, 2022, the Company recorded depletion expense of evaluated oil and natural gas properties of
$428.9 million. Additionally, as discussed in Note 3 to the consolidated ﬁnancial statements, the Company
recorded $6.9 billion of gross evaluated oil and natural gas properties as of December 31, 2022. The Company’s
internal reserves engineers prepare an estimate of the proved oil and natural gas reserves, and the Company
engages external reserves engineers to independently evaluate the proved oil and natural gas reserves estimated
by the Company.

We identiﬁed the assessment of the impact of estimated proved oil and natural gas reserves related to
evaluated oil and natural gas properties on both depletion expense and the ceiling test calculation as a critical
audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas
reserves as auditor judgment was required to evaluate the assumptions used by the Company related to
forecasted production, development costs, operating costs, and forecasted oil and natural gas prices inclusive
of price differentials.

The following are the primary procedures we performed to address this critical audit matter. We evaluated
the design and tested the operating effectiveness of certain internal controls over the Company’s depletion and
ceiling test processes. This included controls related to the development of the assumptions listed above used
to estimate proved reserves used in the respective calculations. We evaluated (1) the professional qualiﬁcations of
the Company’s internal reserves engineers as well as the external reserves engineers and external engineering
ﬁrm, (2) the knowledge, skill, and ability of the Company’s internal and external reserves engineers, and (3) the
relationship of the external reserves engineers and external engineering ﬁrm to the Company. We assessed the
methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards.
We also compared the pricing assumptions, including price differentials, used in the reserves engineers’
estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated assumptions
used in the reserves engineers’ estimate regarding future operating and development costs based on
historical actual results. In addition, we compared the Company’s historical production forecasts to actual production
volumes to assess the Company’s ability to accurately forecast and compared the forecasted production
assumption used by the Company in the current period to historical production. We read the ﬁndings of the
Company’s external reserves engineers in connection with our evaluation of the Company’s reserves estimates.
We analyzed the depletion expense calculation for compliance with industry and regulatory standards, and
recalculated it. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory
standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and
compared our results with the Company’s results.

/s/ KPMG LLP

We have served as the Company’s auditor since 2014.

Dallas, Texas
March 1, 2023

Consolidated Financial Statements FORM 10-K

F-4

MATADOR RESOURCES COMPANY

Consolidated Balance Sheets

Matador Resources Company and Subsidiaries

(In thousands, except par value and share data)

ASSETS
Current assets

Cash
Restricted cash
Accounts receivable

Oil and natural gas revenues
Joint interest billings
Other

Derivative instruments
Lease and well equipment inventory
Prepaid expenses and other current assets

Total current assets
Property and equipment, at cost

Oil and natural gas properties, full-cost method

Evaluated
Unproved and unevaluated

Midstream properties
Other property and equipment
Less accumulated depletion, depreciation and amortization

Net property and equipment

Other assets

Other long-term assets
Total assets

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities
Accounts payable
Accrued liabilities
Royalties payable
Amounts due to afﬁliates
Derivative instruments
Advances from joint interest owners
Other current liabilities

Total current liabilities

Long-term liabilities

Borrowings under Credit Agreement
Borrowings under San Mateo Credit Facility
Senior unsecured notes payable
Asset retirement obligations
Deferred income taxes
Other long-term liabilities

Total long-term liabilities

Commitments and contingencies (Note 14)
Shareholders’ equity

Common stock — $0.01 par value, 160,000,000 shares authorized;

118,953,381 and 117,861,923 shares issued; and 118,948,624 and
117,850,233 shares outstanding, respectively

Additional paid-in capital
Retained earnings (accumulated deﬁcit)
Treasury stock, at cost, 4,757 and 11,945 shares, respectively
Total Matador Resources Company shareholders’ equity

Non-controlling interest in subsidiaries

Total shareholders’ equity

Total liabilities and shareholders’ equity

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

FORM 10-K Consolidated Financial Statements

December 31,

2022

2021

$

505,179
42,151

$

48,135
38,785

224,860
180,947
48,011
3,930
15,184
51,570
1,071,832

6,862,455
977,502
1,057,668
32,847
(4,512,275)
4,418,197

164,242
48,366
28,808
1,971
12,188
28,810
371,305

6,007,325
964,714
900,979
30,123
(4,046,456)
3,856,685

64,476
$ 5,554,505

34,163
$ 4,262,153

$

58,848
261,310
117,698
32,803
—
52,357
52,857
575,873

—
465,000
695,245
52,985
428,351
19,960
1,661,541

$

26,256
253,283
94,359
27,324
16,849
18,074
28,692
464,837

100,000
385,000
1,042,580
41,689
77,938
22,721
1,669,928

1,190
2,101,999
1,007,642
(34)
3,110,797
206,294
3,317,091
$ 5,554,505

1,179
2,077,592
(171,318)
(243)
1,907,210
220,178
2,127,388
$ 4,262,153

2022 ANNUAL REPORT

F-5

Consolidated Statements of Operations

Matador Resources Company and Subsidiaries

(In thousands, except per share data)

Revenues

Oil and natural gas revenues
Third-party midstream services revenues
Sales of purchased natural gas
Lease bonus - mineral acreage
Realized (loss) gain on derivatives
Unrealized gain (loss) on derivatives

Total revenues

Expenses

Production taxes, transportation and processing
Lease operating
Plant and other midstream services operating
Purchased natural gas
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
General and administrative

Total expenses
Operating income (loss)
Other income (expense)

Net loss on asset sales and impairment
Interest expense
Other (expense) income
Total other expense

Income (loss) before income taxes

Income tax provision (beneﬁt)

Current
Deferred

Total income tax provision (beneﬁt)

Net income (loss)

Net income attributable to non-controlling interest in subsidiaries
Net income (loss) attributable to Matador Resources Company

shareholders

Earnings (loss) per common share

Basic

Diluted

Weighted average common shares outstanding

Basic

Diluted

Year Ended December 31,

2022

2021

2020

$2,905,738
90,606
200,355
—
(157,483)
18,809
3,058,025

$1,700,542
75,499
86,034
—
(220,105)
21,011
1,662,981

$ 744,461
64,932
41,742
4,062
38,937
(32,008)
862,126

282,193
157,105
95,522
178,937
466,348
2,421
—
116,229
1,298,755
1,759,270

(1,311)
(67,164)
(5,121)
(73,596)
1,685,674

54,877
344,480
399,357
1,286,317
(72,111)

178,987
108,964
61,459
77,126
344,905
2,068
—
96,396
869,905
793,076

(331)
(74,687)
(2,712)
(77,730)
715,346

—
74,710
74,710
640,636
(55,668)

93,338
104,953
41,500
32,734
361,831
1,948
684,743
62,578
1,383,625
(521,499)

(2,832)
(76,692)
1,864
(77,660)
(599,159)

—
(45,599)
(45,599)
(553,560)
(39,645)

$1,214,206

$ 584,968

$ (593,205)

$

$

10.28

10.11

$

$

5.00

4.91

$

$

(5.11)

(5.11)

118,122

120,131

116,999

119,163

116,068

116,068

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

Consolidated Financial Statements FORM 10-K

F-6

MATADOR RESOURCES COMPANY

Consolidated Statements of Changes in Shareholders’ Equity

Matador Resources Company and Subsidiaries

For the Years Ended December 31, 2022, 2021 and 2020

Common Stock

Shares Amount

Additional
paid-in
capital

(Accumulated
deﬁcit)
retained
earnings

Treasury Stock

Shares Amount

Total
shareholders’
equity
attributable
to Matador
Resources
Company

Non-
controlling
interest
in
subsidiaries

Total
shareholders’
equity

116,644 $1,166 $1,981,014 $ (148,500)

1 $

(26) $1,833,654

$135,798 $1,969,452

244

85

—

—
22
—

—

—

—
(148)
—

2

1

—

—
—
—

—

—

—
—
—

(2)

(1)

— —

— —

17,452

— —

—

—

—

(24)
297
—

— —
— —
— 149

—
—
(1,489)

11,613

— —

18,232

— —

—

—

—

—

17,452

(24)
297
(1,489)

11,613

—

—

—

—
—
—

—

—

—

17,452

(24)
297
(1,489)

11,613

18,232

96,622

114,854

—
(1,512)
—

— —
— (148)
(593,205) —

—
1,512
—

—
—
(593,205)

(45,570)
—
39,645

(45,570)
—
(553,560)

116,847
—

1,169
—

2,027,069
—

(741,705)

2
(14,581) —

(3)
—

1,286,530
(14,581)

226,495
—

1,513,025
(14,581)

768

81

—

312
—

—

—
(146)
—

7

1

—

3
—

—

—
(1)
—

(7)

(1)

— —

— —

12,113

— —

—

—

—

(4,258)
—

— —
— 156

—
(2,621)

—

—

12,113

(4,255)
(2,621)

45,056

— —

—

45,056

—

—

—

—
—

—

—

—

12,113

(4,255)
(2,621)

45,056

—
(2,380)
—

— —
— (146)
584,968 —

—
2,381
—

—
—
584,968

(61,985)
—
55,668

(61,985)
—
640,636

117,862 $1,179 $2,077,592 $ (171,318)

—

(35,246) —

12 $ (243) $1,907,210
(35,246)

—

$220,178 $2,127,388
(35,246)

—

—

1,001

25

—

157
—

—

—
(92)
—

—

10

—

—

2
—

—

—
(1)
—

(11,544)

— —

—

— —

20,224

— —

—

—

—

(4,007)
—

— —
— 85

—
(2,376)

(11,534)

—

20,224

(4,005)
(2,376)

22,318

— —

—

22,318

—

—

—

—
—

—

(11,534)

—

20,224

(4,005)
(2,376)

22,318

—
(2,584)

— —
— (92)
— 1,214,206 —

—
2,585

—
—
— 1,214,206

(85,995)
—
72,111

(85,995)
—
1,286,317

118,953 $1,190 $2,101,999 $1,007,642

5 $

(34) $3,110,797

$206,294 $3,317,091

(In thousands)

Balance at January 1, 2020
Issuance of common stock pursuant

to employee stock compensation plan

Issuance of common stock pursuant

to directors’ and advisors’ compensation plan

Stock-based compensation expense related to

equity-based awards including amounts capitalized

Stock options exercised, net of options forfeited

in net share settlements

Liability-based stock option awards settled in equity
Restricted stock forfeited
Contribution related to formation of San Mateo,

net of tax of $3.1 million (See Note 6)

Contributions from non-controlling interest owners
of less-than-wholly-owned subsidiaries, net of tax
of $4.8 million (See Note 6)

Distributions to non-controlling interest owners

of less-than-wholly-owned subsidiaries

Cancellation of treasury stock
Current period net (loss) income

Balance at December 31, 2020
Dividends declared (0.125 per share)
Issuance of common stock pursuant to employee

stock compensation plan

Issuance of common stock pursuant to directors’

and advisors’ compensation plan

Stock-based compensation expense related to

equity-based awards including amounts capitalized

Stock options exercised, net of options forfeited in

net share settlements
Restricted stock forfeited
Contribution related to formation of San Mateo,

net of tax of $3.6 million (See Note 6)

Distributions to non-controlling interest owners

of less-than-wholly-owned subsidiaries

Cancellation of treasury stock
Current period net income

Balance at December 31, 2021
Dividends declared ($0.30 per share)
Issuance of common stock pursuant

to employee stock compensation plan

Issuance of common stock pursuant

to directors’ and advisors’ compensation plan

Stock-based compensation expense related to

equity-based awards including amounts capitalized

Stock options exercised, net of options forfeited

in net share settlements

Restricted stock forfeited
Contributions related to formation of San Mateo,

net of tax of $5.9 million (See Note 6)

Distributions to non-controlling interest owners

of less-than-wholly-owned subsidiaries

Cancellation of treasury stock
Current period net income

Balance at December 31, 2022

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

FORM 10-K Consolidated Financial Statements

2022 ANNUAL REPORT

F-7

Consolidated Statements of Cash Flows

Matador Resources Company and Subsidiaries

(In thousands)

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

operating activities
Unrealized (gain) loss on derivatives
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
Stock-based compensation expense
Deferred income tax provision (beneﬁt)
Amortization of debt issuance cost and other debt related costs
Net loss on asset sales and impairment
Changes in operating assets and liabilities

Accounts receivable
Lease and well equipment inventory
Prepaid expenses and other current assets
Other long-term assets
Accounts payable, accrued liabilities and other current liabilities
Royalties payable
Advances from joint interest owners
Other long-term liabilities

Net cash provided by operating activities

Investing activities

Drilling, completion and equipping capital expenditures
Acquisition of oil and natural gas properties
Midstream capital expenditures
Acquisition of midstream assets
Expenditures for other property and equipment
Proceeds from sale of assets

Net cash used in investing activities

Financing activities

Purchase of senior unsecured notes
Repayments of borrowings under Credit Agreement
Borrowings under Credit Agreement
Repayments of borrowings under San Mateo Credit Facility
Borrowings under San Mateo Credit Facility
Cost to enter into or amend credit facilities
Dividends paid
Contributions related to formation of San Mateo
Contributions from non-controlling interest owners of

less-than-wholly-owned subsidiaries

Distributions to non-controlling interest owners of

less-than-wholly-owned subsidiaries

Taxes paid related to net share settlement of stock-based compensation
Other

Net cash (used in) provided by ﬁnancing activities

Increase (decrease) in cash and restricted cash
Cash and restricted cash at beginning of period
Cash and restricted cash at end of period

Supplemental disclosures of cash ﬂow information (Note 15)

Year Ended December 31,

2022

2021

2020

$ 1,286,317

$ 640,636

$ (553,560)

(18,809)
466,348
2,421
—
15,123
344,480
(517)
1,311

(205,426)
(2,847)
(22,952)
175
63,455
23,339
34,283
(7,962)
1,978,739

(771,830)
(155,074)
(80,051)
(75,816)
(1,213)
46,507
(1,037,477)

(344,302)
(300,000)
200,000
(150,000)
230,000
(3,725)
(35,246)
28,250

(21,011)
344,905
2,068
—
9,039
74,710
3,659
331

(98,456)
(1,537)
(11,786)
56
76,891
28,310
7,018
(1,478)
1,053,355

(431,136)
(238,609)
(63,359)
—
(376)
4,215
(729,265)

—
(600,000)
260,000
(84,000)
135,000
(4,108)
(14,581)
48,626

32,008
361,831
1,948
684,743
13,625
(45,599)
2,832
2,832

53,001
(655)
(3,010)
1,681
(43,844)
(19,144)
(10,646)
(461)
477,582

(471,087)
(72,809)
(234,359)
—
(2,200)
4,789
(775,666)

—
(35,000)
220,000
—
46,000
(660)
—
14,700

—

—

119,700

(85,995)
(19,242)
(592)
(480,852)
460,410
86,920
547,330

$

(61,985)
(8,211)
706
(328,553)
(4,463)
91,383
86,920

$

(45,570)
(1,556)
6,725
324,339
26,255
65,128
$ 91,383

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

Consolidated Financial Statements FORM 10-K

F-8

MATADOR RESOURCES COMPANY

Notes to Consolidated Financial Statements

MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2022, 2021 and 2020

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the

“Company”), is an independent energy company engaged in the exploration, development, production and acquisition
of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other
unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of
the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The
Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley
plays in Northwest Louisiana. Additionally, the Company conducts midstream operations primarily through its
midstream joint venture, San Mateo Midstream, LLC (“San Mateo”), and Pronto Midstream, LLC (“Pronto”) in
support of the Company’s exploration, development and production operations and provides natural gas processing,
oil transportation services, oil, natural gas and produced water gathering services and produced water disposal
services to third parties.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated ﬁnancial statements include the accounts of Matador and its wholly-owned and majority-owned

subsidiaries. These consolidated ﬁnancial statements have been prepared in accordance with generally accepted
accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain
subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas
exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these
subsidiaries have been reported separately as required by Accounting Standards Codiﬁcation (“ASC”), Consolidation
(Topic 810). The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned
and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated
in consolidation.

Use of Estimates

The preparation of ﬁnancial statements in conformity with U.S. GAAP requires management to make estimates

and assumptions that affect the amounts reported in the ﬁnancial statements and accompanying notes. These
estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the ﬁnancial
statements and the reported amounts of revenues and expenses during the reporting period. The Company’s
consolidated ﬁnancial statements are based on a number of signiﬁcant estimates, including oil and natural gas
revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax
assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural
gas reserves quantities and future net cash ﬂows are the basis for the calculations of depletion and impairment of
oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The
Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that
are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering
staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then
audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc.,
independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and
assumptions or the discovery of new information may result in revised estimates. Actual results could differ from
these estimates.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-9

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Restricted Cash

Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned

subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-
than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund
the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquid (“NGL”) production to various purchasers

(see “—Revenues” below). In addition, the Company may participate with industry partners in the drilling,
completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are
due from purchasers of oil, natural gas and NGLs, participants in oil and natural gas wells for which the Company
serves as the operator, customers of San Mateo and Pronto or the Company’s derivative counterparties. Accounts
receivable are typically due within 30 to 60 days of the production date and 30 days of the billing date and are
stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been
outstanding for 60 days or more. No interest is typically charged on past due amounts.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the
allowance, if any, by considering the length of time past due, previous loss history, future net revenues associated
with the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s
ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its
accounts receivable for any reporting period presented.

For the year ended December 31, 2022, three signiﬁcant purchasers accounted for 70% of the Company’s total

oil, natural gas and NGL revenues: Exxon Mobil Corporation (34%), Plains Marketing, L.P. (27%) and BP America
Production Company (9%). For the year ended December 31, 2021, three signiﬁcant purchasers accounted for 72%
of the Company’s total oil, natural gas and NGL revenues: Exxon Mobil Corporation (33%), Plains Marketing, L.P.
(29%) and BP America Production Company (10%). For the year ended December 31, 2020, two signiﬁcant
purchasers accounted for 65% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P.
(57%) and Exxon Mobil Corporation (8%). If the Company lost one or more of these signiﬁcant purchasers and were
unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely
affect the Company’s business, ﬁnancial condition, results of operations and cash ﬂows. At December 31, 2022,
2021 and 2020, approximately 29%, 39% and 35%, respectively, of the Company’s accounts receivable, including
joint interest billings, related to these purchasers.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or net realizable value and consists entirely of

materials or equipment scheduled for use in future well or midstream operations.

Notes to Consolidated Financial Statements FORM 10-K

F-10

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under
this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties
and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a
single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such
costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped
properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and
general and administrative expenses directly related to acquisition, exploration and development activities, but do not
include any costs related to production, selling or general corporate administrative activities. The Company capitalized
$47.8 million, $38.4 million and $30.0 million of its general and administrative costs into oil and natural gas properties in
2022, 2021 and 2020, respectively. The Company capitalized $10.1 million, $4.8 million and $5.0 million of its interest
expense into oil and natural gas properties for the years ended December 31, 2022, 2021 and 2020, respectively.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon

production and estimates of proved reserves quantities. For the years ended December 31, 2022, 2021 and 2020,
the Company recorded depletion expense of $428.9 million, $310.1 million and $334.8 million, respectively. Unproved
and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved
and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating
or economic conditions. This assessment includes consideration of the following factors, among others: the
assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and
drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately
included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon
determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or

loss recognized, unless such adjustments would signiﬁcantly alter the relationship between net capitalized costs
and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are
expensed as incurred. Signiﬁcant workovers that increase the properties’ reserves are capitalized.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less

related deferred income taxes or the cost center “ceiling.” The cost center ceiling is deﬁned as the sum of:

(a)

the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves,
reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c)

the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs
being amortized, if any, less

(d) any income tax effects related to the properties involved.

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is

charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in
the ceiling test computations as the Company does not designate these instruments as hedge instruments for
accounting purposes.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-11

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The estimated present value of after-tax future net cash ﬂows from proved oil and natural gas reserves is highly

dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment.
The associated commodity prices and the applicable discount rate used in these estimates are in accordance with
guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-
current operating and economic conditions, with no provision for price and cost changes in future periods except by
contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages
of the ﬁrst-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is
used to determine the present value of future net revenues. For the period from January through December 2022,
these average oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively. For the period
from January through December 2021, these average oil and natural gas prices were $63.04 per Bbl and $3.60 per
MMBtu, respectively. For the period from January through December 2020, these average oil and natural gas prices
were $36.04 per Bbl and $1.99 per MMBtu, respectively. In estimating the present value of after-tax future net
cash ﬂows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for
quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were
further adjusted by property for energy content, transportation and marketing fees and regional price differentials.

During the years ended December 31, 2022 and 2021, the Company’s full-cost ceiling exceeded the net capitalized
costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs
during the years ended December 31, 2022 and 2021.

For the year ended December 31, 2020, the Company’s net capitalized costs less related deferred income taxes
exceeded the full-cost ceiling. As a result, the Company recorded an impairment charge of $684.7 million, exclusive
of tax effect, to its consolidated statement of operations for the year ended December 31, 2020 with the related
deferred income tax beneﬁt recorded net of a valuation allowance (see Note 8).

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value

of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity,
but it has no impact on the Company’s net cash ﬂows as reported. Changes in oil and natural gas production rates,
oil and natural gas prices, reserves estimates, future development costs and other factors will determine the
Company’s actual ceiling test computation and impairment analyses in future periods.

Midstream Properties and Other Property and Equipment

Midstream properties and other property and equipment are recorded at historical cost and include midstream

equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal
systems, and corporate assets, including furniture, ﬁxtures, equipment, land and leasehold improvements. Midstream
equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention
method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease.
Software, furniture, ﬁxtures and other equipment are depreciated over their useful life (ﬁve to 30 years) using the
straight-line method. The Company capitalized $2.2 million, $1.3 million and $1.8 million of general and administrative
costs into midstream properties in 2022, 2021 and 2020, respectively. The Company did not capitalize any interest
expense into midstream properties for the years ended December 31, 2022 or 2021. The Company capitalized
$0.5 million of interest expense into midstream properties for the year ended December 31, 2020. Maintenance and
repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3
for a detail of midstream properties and other property and equipment.

Notes to Consolidated Financial Statements FORM 10-K

F-12

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The Company evaluates midstream properties and other property and equipment for potential impairment

whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The
carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash
ﬂows expected to result from the use and eventual disposition of the asset. Expected future cash ﬂows represent
management’s estimates based on reasonable and supportable assumptions.

Gains and losses associated with the disposition of midstream properties and other property and equipment are

recognized as a component of other income (expense) in the consolidated statements of operations.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred
if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its
estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream
properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted
value of the estimated liability is recorded as an expense in the consolidated statements of operations.

Derivative Financial Instruments

From time to time, the Company uses derivative ﬁnancial instruments to mitigate its exposure to commodity

price risk associated with oil, natural gas and NGL prices. The Company’s derivative ﬁnancial instruments are
recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company
has elected not to apply hedge accounting for its existing derivative ﬁnancial instruments, and as a result, the
Company recognizes the change in derivative fair value between reporting periods currently in its consolidated
statements of operations. The fair value of the Company’s derivative ﬁnancial instruments is determined using
industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time
value of money and (iii) current market and contractual prices for the underlying instruments, as well as other
relevant economic measures. Realized gains and losses from the settlement of derivative ﬁnancial instruments and
unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative ﬁnancial
instruments are reported as a component of revenues in the consolidated statements of operations. See Note 12
for additional information about the Company’s derivative instruments.

Revenues

The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from
these contracts is recognized when the Company’s performance obligations under these contracts are satisﬁed,
which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally
considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title,
(iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature
of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company
expects to receive in accordance with the price speciﬁed in the contract. Consideration under oil and natural gas
marketing contracts is typically received from the purchaser one to two months after production.

The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead

or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The
majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for
differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-13

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

transfer of control of the oil, the differentials are included in oil revenues on the statements of operations, as they
represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred
prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing
expenses on the Company’s consolidated statements of operations, as they represent payment for services
performed outside of the contract with the customer.

The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or

at an interconnect near a marketing hub following transportation from a processing plant. The majority of the
Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser
gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The
NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural
gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts,
the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the
extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized
as the net amount received from the purchaser. To the extent that control transfers downstream of those services,
revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and
processing expenses on the Company’s consolidated statements of operations.

The Company recognizes midstream services revenues at the time services have been rendered and the price is

ﬁxed and determinable. Third-party midstream services revenues are those revenues from midstream operations
related to third parties, including working interest owners in the Company’s operated wells. All midstream services
revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right
to payment from its customers in amounts that correspond directly to the value that the customer receives from the
performance completed on each contract, the Company applies the practical expedient in Accounting Standards
Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”) that allows recognition of
revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for
each contract and allocating that transaction price to the performance obligations within each contract.

The Company periodically enters into natural gas purchase transactions with third parties whereby the Company
(i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes
the third party’s natural gas at Pronto’s Marlan cryogenic natural gas processing plant in Eddy County, New Mexico
or San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River
Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers.
Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated
statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards
of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and
process the natural gas volumes to be sold.

From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-
party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a speciﬁed
payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the
Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral
acreage” revenues on its consolidated statements of operations.

Notes to Consolidated Financial Statements FORM 10-K

F-14

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The following table summarizes the Company’s total revenues and revenues from contracts with customers on

a disaggregated basis for the years ended December 31, 2022, 2021 and 2020 (in thousands).

Revenues from contracts with customers
Lease bonus - mineral acreage
Realized (loss) gain on derivatives
Unrealized gain (loss) on derivatives

Total revenues

Oil revenues
Natural gas revenues
Third-party midstream services revenues
Sales of purchased natural gas

Total revenues from contracts with customers

Year Ended December 31,

2022

2021

2020

$3,196,699
—
(157,483)
18,809
$3,058,025

$1,862,075
—
(220,105)
21,011
$1,662,981

$ 851,135
4,062
38,937
(32,008)
$ 862,126

Year Ended December 31,

2022

2021

2020

$2,113,606
792,132
90,606
200,355
$3,196,699

$1,205,608
494,934
75,499
86,034
$1,862,075

$ 595,507
148,954
64,932
41,742
$ 851,135

The Company does not disclose the value of unsatisﬁed performance obligations under its contracts with
customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC
606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the
customer. Since each unit of product represents a separate performance obligation, future volumes are wholly
unsatisﬁed and disclosure of the transaction price allocated to remaining performance obligations is not required.

Stock-Based Compensation

The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted

stock units, performance stock units and other awards permitted under any long-term incentive plan of the
Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All
equity-based awards are measured at fair value on the date of grant and are recognized on a straight-line basis
over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated
statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and
administrative expenses for employees involved in acquisition, exploration and development activities. Awards that
are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date
and are recognized over the awards’ vesting periods either as a component of general and administrative expenses
in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing
general and administrative expenses for employees involved in acquisition, exploration and development activities.

The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options and

the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s
common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit
awards granted under the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive
Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to
measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term
Incentive Plan (the “2019 Incentive Plan”).

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-15

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The Company’s consolidated statements of operations for the years ended December 31, 2022, 2021 and
2020 include an equity-based compensation (non-cash) expense of $15.1 million, $9.0 million and $13.6 million,
respectively. This equity-based compensation expense includes common stock issuances and restricted stock
units expense totaling $1.0 million, $0.9 million and $1.0 million for the years ended December 31, 2022, 2021 and
2020, respectively, paid to independent members of the Board of Directors and advisors as compensation
for their services to the Company. The Company’s consolidated statements of operations for the years ended
December 31, 2022, 2021 and 2020 also include expenses of $31.9 million, $20.4 million and $4.0 million,
respectively, related to liability-based restricted stock awards expected to be settled in cash.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for ﬁnancial accounting and

reporting. The Company evaluates the probability of realizing the future beneﬁts of its deferred tax assets
and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that
the beneﬁt from the deferred tax asset will not be realized.

The Company recognizes the tax beneﬁt of an uncertain tax position only if it is more likely than not that the tax
position will be sustained upon examination by the taxing authorities based on the technical merits of the position.
For tax positions meeting the more likely than not threshold, the amount recognized in the ﬁnancial statements
is the beneﬁt that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax
authority. At December 31, 2022, 2021 and 2020, the Company had not established any reserves for, nor recorded
any unrecognized tax beneﬁts related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense”

and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The
Company did not record any interest or penalties related to income taxes for the years ended December 31, 2022,
2021 and 2020.

Allocation of Purchase Price in Business Combinations

As part of the Company’s business strategy, it periodically pursues the acquisition of midstream assets and oil

and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and
liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the
announcement date. Therefore, while the consideration to be paid may be ﬁxed, the fair value of the assets
acquired and liabilities assumed is subject to change during the period between the announcement date and the
acquisition date. The most signiﬁcant estimates in the allocation typically relate to the value assigned to proved
oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is
subject to signiﬁcant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Earnings Per Common Share

The Company reports basic earnings attributable to Matador Resources Company shareholders per common

share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador
Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities,
unless their impact is anti-dilutive.

Notes to Consolidated Financial Statements FORM 10-K

F-16

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The following are reconciliations of the numerators and denominators used to compute the Company’s basic
and diluted earnings per common share as reported for the years ended December 31, 2022, 2021 and 2020 (in
thousands, except per share data).

Year Ended December 31,

2022

2021

2020

Net income (loss) attributable to Matador Resources Company shareholders —

numerator

$1,214,206

$584,968

$(593,205)

Weighted average common shares outstanding — denominator

Basic
Dilutive effect of options and restricted stock units

Diluted weighted average common shares outstanding

Earnings (loss) per common share attributable to
Matador Resources Company shareholders

Basic

Diluted

118,122
2,009
120,131

116,999
2,164
119,163

116,068
—
116,068

$

$

10.28

10.11

$

$

5.00

4.91

$

$

(5.11)

(5.11)

A total of 2.5 million options to purchase shares of Matador’s common stock were excluded from the diluted
weighted average common shares outstanding for the year ended December 31, 2020 because their effects were
anti-dilutive. Additionally, 0.7 million restricted shares, which are participating securities, were excluded from the
calculations above for the year ended December 31, 2020 as the security holders do not have the obligation to share
in the losses of the Company.

Credit Risk

The Company’s cash is held in ﬁnancial institutions and at times these amounts exceed the insurance limits of
the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks
are minimal based on the reputation and history of the institutions selected.

The Company uses derivative ﬁnancial instruments to mitigate its exposure to oil, natural gas and NGL price
volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company
manages counterparty credit risk through established internal derivatives policies that are reviewed on an
ongoing basis. Additionally, the Company’s commodity derivative contract at December 31, 2022 was with PNC
Bank, which is a lender under the Company’s reserves-based revolving credit agreement.

Accounts receivable constitute the principal component of additional credit risk to which the Company may
be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the ﬁnancial
condition and payment history of its purchasers and joint interest partners.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-17

NOTE 3 — PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances as of December 31,

2022 and 2021 (in thousands).

Oil and natural gas properties

Evaluated (subject to amortization)
Unproved and unevaluated (not subject to amortization)

Total oil and natural gas properties

Accumulated depletion

Net oil and natural gas properties

Midstream properties

Midstream equipment and facilities
Accumulated depreciation

Net midstream properties
Other property and equipment

Furniture, ﬁxtures and other equipment
Software
Leasehold improvements

Total other property and equipment

Accumulated depreciation

Net other property and equipment
Net property and equipment

December 31,

2022

2021

$ 6,862,455
977,502
7,839,957
(4,362,292)
3,477,665

$ 6,007,325
964,714
6,972,039
(3,933,355)
3,038,684

1,057,668
(126,706)
930,962

13,257
8,225
11,365
32,847
(23,277)
9,570
$ 4,418,197

900,979
(92,574)
808,405

10,923
8,225
10,975
30,123
(20,527)
9,596
$ 3,856,685

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not
subject to amortization as of December 31, 2022 and the year in which these costs were incurred (in thousands).

Description

Costs incurred for

Property acquisition
Exploration wells
Development wells

Total

2022

2021

2020

2019

2018 and prior

Total

$ 97,748
32,364
42,543
$172,655

$110,077
942
1,641
$112,660

$40,355
354
1,245
$41,954

$ 40,140
802
2,506
$ 43,448

$606,740
36
9
$606,785

$895,060
34,498
47,944
$977,502

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas

properties, but may also include broker and legal expenses, geological and geophysical expenses and capitalized
internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition
costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved
reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for
possible impairment on a periodic basis based upon changes in operating or economic conditions.

Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2022
are related to the Company’s leasehold and mineral acquisitions in the Delaware Basin in Southeast New Mexico
and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A
signiﬁcant portion of these costs are associated with properties that are held by production or have automatic lease
renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that
certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred
to the amortization base.

Notes to Consolidated Financial Statements FORM 10-K

F-18

MATADOR RESOURCES COMPANY

NOTE 3 — PROPERTY AND EQUIPMENT — Continued

Costs excluded from amortization also include those costs associated with exploration and development wells

in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an
ongoing basis as these wells are completed and proved reserves are established or conﬁrmed. These costs totaled
$82.4 million at December 31, 2022. Of this total, $34.5 million was associated with exploration wells and
$47.9 million was associated with development wells. The Company anticipates that most of the $82.4 million
associated with these wells in progress at December 31, 2022 will be transferred to the amortization base during
2023. Unproved and unevaluated property costs for exploration and development wells incurred in years prior to
2022 are costs related to the advanced preparation for wells that the Company intends to drill in the future.

NOTE 4 — LEASES

The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease,

the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a
right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for
non-lease components associated with certain leases when determining the present value of the lease payments.
Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities
represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated
incremental borrowing rate, determined at the lease commencement date using the Company’s average secured
borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates
used for the year ended December 31, 2022 were 3.68% and 4.20% for operating leases and ﬁnancing leases,
respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain
that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on
the consolidated balance sheets unless there is a signiﬁcant cost to terminate the lease, including the cost of
removal of the leased asset. As the Company is the responsible party under these arrangements, the Company
records the resulting assets and liabilities on a gross basis in its consolidated balance sheets.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-19

NOTE 4 — LEASES — Continued

The following table presents supplemental consolidated statement of operations information related to lease

expenses, on a gross basis, for the years ended December 31, 2022 and 2021, respectively (in thousands). Lease
payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially
offset by amounts received from other working interest owners in the Company’s operated wells.

Operating leases

Lease operating
Plant and other midstream services
General and administrative
Total operating leases(1)

Short-term leases
Lease operating
Plant and other midstream services
General and administrative
Total short-term leases(2)(3)

Financing leases

Depreciation of assets
Interest on lease liabilities
Total ﬁnancing leases
Total lease expense

Year Ended December 31,

2022

2021

$15,970
285
3,266
19,521

17,437
4,359
34
21,830

571
143
714
$42,065

$11,393
36
3,645
15,074

11,234
4,037
37
15,308

566
138
704
$31,086

(1) Does not include gross payments related to drilling rig leases of $58.7 million and $31.9 million for the years ended December 31, 2022 and

2021, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets
at December 31, 2022 and 2021, respectively.

(2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are

short-term leases.

(3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $101.5 million and $61.7 million for the

years ended December 31, 2022 and 2021, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method”
in the consolidated balance sheets at December 31, 2022 and 2021, respectively.

The following table presents supplemental consolidated balance sheet information related to leases as of

December 31, 2022 and 2021, respectively (in thousands).

Operating leases

Other long-term assets

Other current liabilities
Other long-term liabilities

Total operating lease liabilities

Financing leases

Other property and equipment, at cost
Accumulated depreciation

Net property and equipment

Other current liabilities
Other long-term liabilities

Total ﬁnancing lease liabilities

December 31,

2022

2021

$ 58,798

$ 29,519

$(43,921)
(19,532)
$(63,453)

$(19,649)
(15,340)
$(34,989)

$ 7,425
(4,470)
$ 2,955

$

(685)
(630)
$ (1,315)

$ 5,914
(3,485)
$ 2,429

$

$

(378)
(45)
(423)

Notes to Consolidated Financial Statements FORM 10-K

F-20

MATADOR RESOURCES COMPANY

NOTE 4 — LEASES — Continued

The following table presents supplemental consolidated cash ﬂow information related to lease payments for

the years ended December 31, 2022 and 2021, respectively (in thousands).

Cash paid related to lease liabilities

Operating cash payments for operating leases
Investing cash payments for operating leases
Financing cash payments for ﬁnancing leases

Right of use assets obtained in exchange for lease obligations entered into during the period

Operating leases
Financing leases

Year Ended December 31,

2022

2021

$ 19,290
$ 58,693
620
$

$ 80,254
$ 1,511

$ 14,430
$ 31,967
629
$

$ 18,454
$ 2,241

The following table presents the maturities of lease liabilities at December 31, 2022 (in years).

Weighted-Average Remaining Lease Term

Operating leases
Financing leases

December 31,
2022

1.8
2.4

The following table presents a schedule of future minimum lease payments required under all lease agreements

as of December 31, 2022 (in thousands).

2023
2024
2025
2026
2027
Thereafter
Total lease payments
Less imputed interest

Total lease obligations
Less current obligations

Long-term lease obligations

December 31, 2022

Operating
Leases

Financing
Leases

$ 43,921
12,443
6,218
2,708
572
—
65,862
(2,409)
63,453
(43,921)
$ 19,532

$ 685
541
309
—
—
—
1,535
(220)
1,315
(685)
$ 630

NOTE 5 — ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations primarily relate to future costs associated with plugging and

abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from
leased acreage and returning such land to its original condition. The amounts recognized are based on numerous
estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas,
future inﬂation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur
due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and
abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the
Company includes any gain or loss associated with the operation in the amortization base to the extent the actual
costs are different from the estimated liability.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-21

NOTE 5 — ASSET RETIREMENT OBLIGATIONS — Continued

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended

December 31, 2022 and 2021 (in thousands).

Beginning asset retirement obligations
Liabilities incurred during period
Liabilities settled during period
Revisions in estimated cash ﬂows
Divestitures during the period
Accretion expense
Ending asset retirement obligations

Less: current asset retirement obligations(1)
Long-term asset retirement obligation +s

Year Ended December 31,

2022

2021

$41,959
4,069
(1,198)
10,794
(4,304)
2,421
53,741
(756)
$52,985

$38,542
2,294
(151)
86
(880)
2,068
41,959
(270)
$41,689

(1)

Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2022 and 2021.

NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES

Business Combinations

On December 14, 2021, the Company completed an acquisition of assets from a private operator. This
acquisition was accounted for as a business combination in accordance with ASC Topic 805, which requires the
assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date. The
Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and
Eddy Counties, New Mexico, strategically located primarily within the Company’s existing acreage in its Ranger
and Arrowhead asset areas.

As consideration for the business combination, the Company paid approximately $161.7 million in cash, subject

to certain customary post-closing working capital adjustments, including adjusting for production, revenues,
operating expenses and capital expenditures from August 1, 2021 to closing. In addition, the Company increased
the purchase price by $5.0 million for each quarter during 2022 in which the average oil price, as deﬁned in
the purchase and sale agreement, was greater than $75.00 per barrel. The Company recorded this contingent
consideration at fair value on the date of the business combination and recorded the change in the fair value in
future periods as “Other income (expense)” in its consolidated statements of operations. The change in the fair
value of the contingent consideration included in “Other expense” during the years ended December 31, 2022 and
2021 was $11.8 million and $1.5 million, respectively. During the year ended December 31, 2022, the Company
paid $15.0 million in cash related to this contingent consideration. The remaining payment of $5.0 million was made
in the ﬁrst quarter of 2023. The Company used the Monte Carlo simulation method to measure the fair value
of the contingent consideration, which has unobservable inputs and is thus classiﬁed at Level 3 in the fair value
hierarchy (see Note 13 for discussion of the fair value hierarchy).

Notes to Consolidated Financial Statements FORM 10-K

F-22

MATADOR RESOURCES COMPANY

NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued

The allocation of the consideration given related to this business combination was as follows (in thousands),

which the Company considered to be ﬁnal as of September 30, 2022.

Consideration given
Cash
Working capital adjustments
Fair value of contingent consideration at December 14, 2021

Total consideration given

Allocation of purchase price
Oil and natural gas properties

Evaluated
Unproved and unevaluated

Accrued liabilities
Advances from joint interest owners
Asset retirement obligations
Net assets acquired

Allocation

$161,680
(4,444)
6,718
$163,954

$139,312
32,260
(360)
(6,865)
(393)
$163,954

On June 30, 2022, the Company acquired a cryogenic gas processing plant, three compressor stations and

approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of
the acquisition (the “Pronto Acquisition”) of a wholly-owned subsidiary of Summit Midstream Partners, LP that was
subsequently renamed Pronto. This acquisition was also accounted for as a business combination in accordance
with ASC Topic 805. In addition, the Company assumed certain takeaway capacity on a Federal Energy Regulatory
Commission regulated natural gas pipeline. As consideration for the business combination, the Company paid
approximately $77.8 million in cash, subject to certain customary post-closing purchase price adjustments. The
pro forma impact of this business combination to revenues and net income for 2022 would not be material to
the Company’s 2022 revenues and net income as reported.

The allocation of the consideration given related to this business combination was as follows (in thousands),

which the Company considered to be ﬁnal as of December 31, 2022.

Consideration given

Total cash consideration given

Allocation of purchase price

Cash acquired
Property, plant & equipment
Accounts receivable
Other assets
Accrued liabilities

Net assets acquired

Allocation

$77,828

$ 2,012
74,100
6,093
296
(4,673)
$77,828

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-23

NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued

Joint Ventures

At December 31, 2022, the Company owned 51% of San Mateo, a midstream joint venture with a subsidiary of

Five Point Energy LLC (“Five Point”) in portions of Eddy County, New Mexico and Loving County, Texas. At
December 31, 2022, Five Point owned the remaining 49% of San Mateo. The midstream assets include (i) the
Black River Processing Plant, (ii) 15 salt water disposal wells and associated commercial salt water disposal facilities
and (iii) approximately 415 miles of oil gathering and transportation pipelines, natural gas gathering pipelines and
produced water pipelines. The Company operates San Mateo, and San Mateo is consolidated in the Company’s
ﬁnancial statements, with Five Point’s interest being accounted for as a non-controlling interest.

As part of the joint venture agreements with Five Point, the Company had the potential to earn two different
sets of performance incentives. These performance incentives are recorded as additional contributions related to
the formation of San Mateo as they are received. Beginning in 2017, the Company had the potential to earn up
to $73.5 million in performance incentives related to the Company’s performance in its Rustler Breaks asset area
in Eddy County and its Wolf asset area in Loving County over a ﬁve-year period, which in October 2020 was
extended by an additional year to January 31, 2023. At February 21, 2023, the Company had earned all of the potential
$73.5 million in performance incentives. Five Point had paid $14.7 million in performance incentives in each of the
ﬁrst quarters of 2018, 2019, 2020 and 2021 and the remaining $14.7 million in performance incentives is expected
to be paid during the ﬁrst quarter of 2023. Beginning in 2019, the Company had the potential to earn up to
$150.0 million in additional deferred performance incentives in its Stebbins area and surrounding leaseholds in the
southern portion of its Arrowhead asset area (the “Greater Stebbins Area”) and Stateline asset area through mid-
2024, of which the Company has earned $62.2 million, plus additional performance incentives for securing volumes
from third-party customers. During the years ended December 31, 2022 and 2021, Five Point paid $28.3 million and
$33.9 million in these additional performance incentives. Both of these performance incentives are recorded when
received, net of the $5.9 million and $3.6 million deferred tax impact to Matador for the years ended December 31,
2022 and 2021, respectively, in “Additional paid-in-capital” in the Company’s consolidated balance sheets.

The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and

Wolf asset areas and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, ﬁxed-fee
oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In
addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks
asset area and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, ﬁxed-fee
natural gas processing agreements (see Note 14).

During the years ended December 31, 2022, 2021 and 2020, San Mateo distributed $89.5 million, $64.5 million

and $47.4 million respectively, to the Company and $86.0 million, $62.0 million and $45.6 million, respectively, to
Five Point. During the years ended December 31, 2022 and 2021, neither the Company nor Five Point contributed
cash to San Mateo. During the year ended December 31, 2020, the Company contributed $75.0 million and Five Point
contributed $119.7 million of cash to San Mateo, of which $23.1 million was paid to carry Matador’s proportionate
interest in San Mateo Midstream II, LLC (“San Mateo II”). Five Point agreed to carry a portion of Matador’s
proportionate interest as part of the formation agreement for San Mateo II. The amount that Five Point paid to carry
Matador’s proportionate interest in San Mateo was recorded in “Additional paid-in capital” in the Company’s
consolidated balance sheets at December 31, 2020, net of the $4.8 million deferred tax impact to Matador related
to this equity contribution. San Mateo II was merged with and into San Mateo effective October 1, 2020.

Divestitures

During 2022 and 2021, the Company converted approximately $46.5 million and $4.2 million, respectively, of

non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana.

Notes to Consolidated Financial Statements FORM 10-K

F-24

MATADOR RESOURCES COMPANY

NOTE 7 — DEBT

At December 31, 2022, the Company had (i) $699.2 million of outstanding senior notes due 2026, (ii) no borrowings

outstanding under its reserves-based revolving credit facility and (iii) approximately $45.6 million in outstanding
letters of credit issued pursuant to its revolving credit facility. During the ﬁrst quarter of 2022, the Company’s
approximately $7.5 million unsecured U.S. Small Business Administration loan, which was issued through Iberiabank
in April 2020 as part of the Paycheck Protection Program, was forgiven in full under the terms of the loan
agreement and recorded as a gain on the extinguishment of debt within “Other expense” on the unaudited
consolidated statement of operations. During the year ended December 31, 2022, the Company repurchased
an aggregate principal amount of $350.8 million of its Notes for $344.3 million.

At December 31, 2022, San Mateo had $465.0 million in borrowings outstanding under its revolving credit facility

and approximately $9.0 million in outstanding letters of credit issued pursuant to its revolving credit facility.

Credit Agreements

MRC Energy Company

On November 18, 2021, the Company entered into its Fourth Amended and Restated Credit Agreement with the

lenders party thereto, led by Royal Bank of Canada (“RBC”) as administrative agent (the “Credit Agreement”).
MRC Energy Company (“MRC”), a subsidiary of Matador that directly or indirectly holds the ownership interests in
the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower
under the Credit Agreement. Borrowings are secured by mortgages on at least 85% of MRC’s and the Restricted
Subsidiaries’ (as deﬁned in the Credit Agreement) proved oil and natural gas properties and by the equity interests
of certain of MRC’s wholly-owned subsidiaries, which are also guarantors. San Mateo and its subsidiaries and Pronto
are not guarantors of the Credit Agreement. In addition, all obligations under the Credit Agreement are guaranteed
by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the
Credit Agreement (or afﬁliates thereof) are also secured by the collateral of and guaranteed by certain eligible
subsidiaries of MRC. The Credit Agreement matures on October 31, 2026 or, if earlier, the date that is 180 days prior
to the earliest stated redemption date of any senior notes of the Company with an outstanding principal balance in
excess of $25.0 million.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by

the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at
December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled
redetermination of the borrowing base once between scheduled redetermination dates.

In April 2022, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a

result, the borrowing base was increased from $1.35 billion to $2.00 billion, the borrowing commitment was
increased from $700.0 million to $775.0 million and the maximum facility amount remained $1.50 billion. In addition,
the terms of the Credit Agreement were amended to increase the sublimit for issuances of letters of credit under
the Credit Agreement from $50 million to $100 million and replace the London Interbank Offered Rate (“LIBOR”)
interest rate benchmark with a secured overnight ﬁnancing rate administered by the Federal Reserve Bank of
New York (“Adjusted Term SOFR”) (as deﬁned in the Credit Agreement) interest rate benchmark. This April 2022
redetermination constituted the regularly scheduled May 1 redetermination.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-25

NOTE 7 — DEBT — Continued

In November 2022, the lenders completed their review of the Company’s proved oil and natural gas reserves,
and, as a result, the borrowing base was increased from $2.00 billion to $2.25 billion. The Company elected to keep
the borrowing commitment at $775.0 million, and the maximum facility amount remained $1.50 billion. Borrowings
under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the
elected borrowing commitment (subject to compliance with the covenants noted below).

In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal

to a percentage of the amount of the increase, which is determined based on market conditions at the time of the
increase. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding
borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral
satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufﬁcient to cover such
excess or to repay the deﬁcit in equal installments over a period of six months.

Total deferred loan costs were $3.2 million at December 31, 2022, and these costs are being amortized over
the term of the Credit Agreement. At December 31, 2022, the Company had no borrowings outstanding under the
Credit Agreement and approximately $45.6 million in outstanding letters of credit issued pursuant to the Credit
Agreement. If the Company were to borrow funds under the Credit Agreement, the applicable margin that would
be added to Adjusted Term SOFR would have been 1.75% at December 31, 2022.

After giving effect to the amendment to the Credit Agreement, the applicable interest rate margin for borrowings
under the Credit Agreement ranges from 1.75% to 2.75% per annum for borrowings bearing interest with reference
to the Adjusted Term SOFR and from 0.75% to 1.75% per annum for borrowings bearing interest with reference
to the Alternate Base Rate (as deﬁned in the Credit Agreement), in each case depending on the level of borrowings
under the Credit Agreement. In addition, the Adjusted Term SOFR includes a credit spread adjustment of 0.10%
per annum for all interest periods. The interest period for Adjusted Term SOFR borrowings may be one, three or six
months as designated by MRC. If MRC has outstanding borrowings under the Credit Agreement and interest
rates increase, so will MRC’s interest costs, which may have a material adverse effect on the Company’s results of
operations and ﬁnancial condition.

A commitment fee of 0.375% to 0.50% per annum, depending on the level of borrowings under the Credit

Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of
deferred ﬁnancing costs (including origination, borrowing base increase and amendment fees) and annual agency
fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement
requires the Company to maintain (i) a current ratio, which is deﬁned as (x) total consolidated current assets plus
the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less
current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each ﬁscal quarter and
(ii) a debt to EBITDA ratio, which is deﬁned as debt outstanding (net of up to $75 million of unrestricted cash and
cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each
ﬁscal quarter.

Notes to Consolidated Financial Statements FORM 10-K

F-26

MATADOR RESOURCES COMPANY

NOTE 7 — DEBT — Continued

Subject to certain exceptions, the Credit Agreement contains various covenants that limit MRC’s and its

Restricted Subsidiaries’ (as deﬁned in the Credit Agreement) ability to take certain actions, including, but not limited
to, the following:

•

incur indebtedness or grant liens on any of its assets;

• enter into commodity hedging agreements or interest rate agreements;

• declare or pay dividends, distributions or redemptions;

• merge or consolidate;

• make any loans or investments;

• engage in transactions with afﬁliates;

• engage in certain asset dispositions, including a sale of all or substantially all of MRC’s assets; and

•

take certain actions with respect to the Company’s senior unsecured notes.

If an event of default exists under the Credit Agreement, the lenders will be able to terminate their commitments,

accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are
not limited to, the following events:

•

•

failure to pay any principal on the outstanding borrowings when due or any interest on the outstanding
borrowings, any reimbursement obligation under any letter of credit or any fees or other amounts within
certain grace periods;

failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other
loan documents, subject, in certain instances, to certain grace periods;

• bankruptcy or insolvency events involving the Company or any of the Restricted Subsidiaries; and

• a change of control, as deﬁned in the Credit Agreement.

• The Company believes that it was in compliance with the terms of the Credit Agreement at December 31,

2022.

San Mateo Midstream, LLC

On December 19, 2018, San Mateo entered into a credit facility with the lenders party thereto, currently led by

Truist Bank as administrative agent (the “San Mateo Credit Facility”). In December 2022, the lenders under the
San Mateo Credit Facility extended the maturity of the facility from December 19, 2023 to December 9, 2026 and
increased the lender commitments from $450.0 million to $485.0 million. In addition, the lenders agreed to refresh
the San Mateo Credit Facility’s accordion feature, which could expand lender commitments to up to $735.0 million.
The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is
guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property.

Total deferred loan costs were $3.9 million at December 31, 2022, and these costs are being amortized over the

term of the San Mateo Credit Facility. San Masteo’s effective interest rate under the San Mateo Credit Facility
was 6.7% at December 31, 2022. At December 31, 2022, San Mateo had $465.0 million in borrowings outstanding
under the San Mateo Credit Facility and $9.0 million in outstanding letters of credit issued pursuant to the San Mateo
Credit Facility. Between December 31, 2022 and February 21, 2023, San Mateo repaid $30.0 million of borrowings
outstanding under the San Mateo Credit Facility.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-27

NOTE 7 — DEBT — Continued

Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or an Adjusted Term

SOFR loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the
greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as deﬁned in the San Mateo Credit
Facility) on such day, plus 0.50%, and (iii) the Adjusted Term SOFR Rate (as deﬁned in the San Mateo Credit Facility)
for a one month tenor plus 1.0%, plus, in each case, an amount ranging from 1.25% to 2.25% per annum
depending on San Mateo’s Consolidated Total Leverage Ratio (as deﬁned in the San Mateo Credit Facility). If San Mateo
borrows funds as an Adjusted Term SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted
Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.25% to 3.25% per annum
depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the
San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material
adverse effect on San Mateo’s results of operations and ﬁnancial condition.

A commitment fee of 0.30% to 0.50% per annum, depending on San Mateo’s Consolidated Total Leverage
Ratio, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred
ﬁnancing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense
and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to
maintain a debt to EBITDA ratio, which is deﬁned as total consolidated funded indebtedness outstanding (as deﬁned
in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to
certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio,
which is deﬁned as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense
for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute
cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo
Credit Facility.

Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s

and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following:

•

incur indebtedness or grant liens on any of San Mateo’s assets;

• enter into hedging agreements;

• declare or pay dividends, distributions or redemptions;

• merge or consolidate;

• make any loans or investments;

• engage in transactions with afﬁliates;

• engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and

•

issue equity interests in San Mateo or its restricted subsidiaries.

Notes to Consolidated Financial Statements FORM 10-K

F-28

MATADOR RESOURCES COMPANY

NOTE 7 — DEBT — Continued

If an event of default exists under the San Mateo Credit Facility, the lenders will be able to terminate their

commitments, accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default
include, but are not limited to, the following events:

•

•

failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under
any letter of credit when due or any fees or other amounts within certain grace periods;

failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility
or other loan documents, subject, in certain instances, to certain grace periods;

• bankruptcy or insolvency events involving San Mateo or its subsidiaries; and

• a change of control, as deﬁned in the San Mateo Credit Facility.

The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at

December 31, 2022.

Senior Unsecured Notes

At December 31, 2022, the Company had $699.2 million of outstanding 5.875% senior notes due 2026 that

were registered under the Securities Act and mature September 15, 2026 (the “Notes”). Interest is payable on
the Notes semi-annually in arrears on each March 15 and September 15. The Notes are jointly and severally
guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and
its subsidiaries and Pronto are not Restricted Subsidiaries (as deﬁned in the Indenture) or Guarantors of the
Notes. During the year ended December 31, 2022, the Company repurchased an aggregate principal amount of
$350.8 million of its Notes for $344.3 million.

The Company may redeem all or a part of the Notes at any time or from time to time at the following

redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the
applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the
years indicated below:

Year

2022
2023
2024 and thereafter

Redemption Price

102.938%
101.469%
100.000%

Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s and its Restricted

Subsidiaries’ ability to take certain actions, including, but not limited to, the following:

•

incur additional indebtedness;

• sell assets;

• pay dividends or make certain investments;

• create liens that secure indebtedness;

• enter into transactions with afﬁliates; and

• merge or consolidate with another company.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-29

NOTE 7 — DEBT — Continued

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to

Matador, any Restricted Subsidiary (as deﬁned in the Indenture) that is a Signiﬁcant Subsidiary (as deﬁned in the
Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Signiﬁcant Subsidiary,
all outstanding Notes will become due and payable immediately without further action or notice. If any other event
of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then
outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are
not limited to, the following events:

• default for 30 days in the payment when due of interest on the Notes;

• default in the payment when due of the principal of, or premium, if any, on the Notes;

•

•

•

failure by the Company to comply with its obligations to offer to purchase or purchase Notes pursuant
to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating
to mergers;

failure by the Company for 180 days after notice to comply with its reporting obligations under the
Indenture;

failure by the Company for 60 days after notice to comply with any of the other agreements in the
Indenture;

• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted

Subsidiaries in the aggregate principal amount of $50.0 million or more;

•

failure by the Company or any Restricted Subsidiary to pay certain ﬁnal judgments aggregating in excess
of $50.0 million within 60 days;

• any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a

judicial proceeding or is denied or disafﬁrmed by its maker; and

• certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary

that is a Signiﬁcant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute
a Signiﬁcant Subsidiary.

Debt Maturities

The Credit Agreement matures on October 31, 2026. The outstanding borrowings of $465.0 million at
December 31, 2022 under the San Mateo Credit Facility mature on December 9, 2026. The $699.2 million of
outstanding Notes at December 31, 2022 mature on September 15, 2026.

Notes to Consolidated Financial Statements FORM 10-K

F-30

MATADOR RESOURCES COMPANY

NOTE 8 — INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the ﬁnancial statement carrying
values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2022
and 2021 is as follows (in thousands).

Deferred tax assets
Net operating loss carryforwards
Unrealized loss on derivatives
Percentage depletion carryover
Compensation
Lease liabilities
Other

Total deferred tax assets

Valuation allowance on deferred tax assets

Total deferred tax assets, net of valuation allowance

Deferred tax liabilities

Unrealized gain on derivatives
Property and equipment
Less than wholly-owned subsidiaries
Lease right of use assets
Other

Total deferred tax liabilities
Net deferred tax liabilities

Year Ended December 31,

2022

2021

$ 12,874
—
8
14,184
12,585
1,926
41,577
(11,322)
30,255

(995)
(368,283)
(63,388)
(12,585)
(13,355)
(458,606)
$(428,351)

$ 129,651
3,729
1,770
9,838
4,866
9,410
159,264
(10,599)
148,665

—
(179,153)
(39,900)
(4,866)
(2,684)
(226,603)
$ (77,938)

At December 31, 2020, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the
deferred tax assets generated by impairment charges recorded in 2020. As a result, the Company established a
valuation allowance against most of the deferred tax assets beginning in the third quarter of 2020. Due to
a variety of factors, including the Company’s signiﬁcant net income in 2021, the Company’s federal valuation
allowance was reversed as of September 30, 2021 as the deferred tax assets were determined to be more likely
than not to be utilized. As a portion of the Company’s state net operating loss carryforwards are not expected to
be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets
are more likely than not to be utilized.

The current income tax provision and the deferred income tax provision for the years ended December 31, 2022,

2021 and 2020 were comprised of the following (in thousands).

Current income tax provision

Federal income tax
State income tax

Net current income tax provision

Deferred income tax provision (beneﬁt)

Federal income tax
State income tax

Net deferred income tax provision (beneﬁt)

Year Ended December 31,

2022

2021

2020

$ 31,335
23,542
$ 54,877

$302,486
41,994
$344,480

$

$

—
—
—

$ 44,883
29,827
$ 74,710

$

$

—
—
—

$(25,675)
(19,924)
$(45,599)

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-31

NOTE 8 — INCOME TAXES — Continued

Reconciliations of the tax expense (beneﬁt) computed at the statutory federal rate to the Company’s total income

tax provision (beneﬁt) for the years ended December 31, 2022, 2021 and 2020 is as follows (in thousands).

Federal tax expense (beneﬁt) at statutory rate(1)
State income tax expense (beneﬁt)
Permanent differences
Change in federal valuation allowance
Change in state valuation allowance

Total income tax provision (beneﬁt)

Year Ended December 31,

2022

2021

2020

$353,992
59,870
(15,227)
—
722
$399,357

$ 150,223
26,646
(2,078)
(103,262)
3,181
$ 74,710

$(125,823)
(20,607)
(3,114)
103,262
683
$ (45,599)

(1) The statutory federal tax rate was 21% for the years ended December 31, 2022, 2021 and 2020.

The Company ﬁles a United States federal income tax return and several state tax returns, a number of which

remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico
and the State of Louisiana tax returns is 2019. The earliest tax year open for examination for the State of Texas tax
return is 2018.

The Company has evaluated all tax positions for which the statute of limitations remains open and believes that

the material positions taken would more likely than not be sustained by examination. Therefore, at December 31,
2022, the Company had not established any reserves for, nor recorded any unrecognized beneﬁts related to,
uncertain tax positions.

NOTE 9 — STOCK-BASED COMPENSATION

In 2012, the Company’s Board of Directors (the “Board”) adopted and shareholders approved the 2012 Incentive

Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate
that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other
performance award grants.

In 2019, the Board adopted and shareholders approved the 2019 Incentive Plan. In April 2022, the Board adopted,
subject to shareholder approval, the ﬁrst amendment to the 2019 Long-Term Incentive Plan, authorizing an additional
3,725,000 shares of common stock for issuance to employees, directors, contractors or advisors of the Company.
In June 2022, the Company’s shareholders approved such amendment. As of December 31, 2022, the 2019
Incentive Plan provided for a maximum of 4,174,443 shares of common stock in the aggregate that may be issued
pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance
award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors,
contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key
employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the
Company does not expect to make any future awards under the 2012 Incentive Plan, but the 2012 Incentive Plan
will remain in place until all awards outstanding under that plan have been settled.

The 2012 Incentive Plan and 2019 Incentive Plan are administered by the independent members of the Board, who,
upon recommendation of the Strategic Planning and Compensation Committee of the Board, determine the number
of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the
vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or
restricted share grants.

Notes to Consolidated Financial Statements FORM 10-K

F-32

MATADOR RESOURCES COMPANY

NOTE 9 — STOCK-BASED COMPENSATION — Continued

During the years ended December 31, 2022, 2021 and 2020, the Company granted both equity-based and
liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is ﬁxed at the grant
date, while the fair value of liability-based awards is remeasured at each reporting period.

In April 2022, the Board adopted, subject to shareholder approval, an Employee Stock Purchase Plan (the
“ESPP”). The purpose of the ESPP is to encourage and enable the Company’s eligible employees to acquire an
interest in the Company through the ownership of common stock. In June 2022, the Company’s shareholders
approved and authorized a maximum of 4.0 million shares of common stock to be purchased under the ESPP.
At December 31, 2022, the Company had 3,977,456 remaining shares available for issuance under the ESPP.

Stock Options

Under the 2012 Incentive Plan and the 2019 Incentive Plan, stock option awards have been granted and are
outstanding to purchase the Company’s common stock at an exercise price equal to the fair market value on the
date of grant, a typical vesting period of three or four years and a typical maximum term of ﬁve, six or 10 years.
The 2012 Incentive Plan deﬁnes fair market value as the closing price of Matador’s common stock on the date of
grant. Under the 2019 Incentive Plan, such fair market value of a stock option is determined using the closing
price of Matador’s common stock on the trading day prior to the date of grant. The Company did not grant stock
option awards during the years ended December 31, 2022, 2021 and 2020.

Summarized information about stock options outstanding at December 31, 2022 under the 2012 Incentive Plan

and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows.

Options outstanding at December 31, 2021

Options granted
Options exercised
Options forfeited
Options expired

Options outstanding at December 31, 2022

Number of
options
(in thousands)

Weighted
average
exercise price

603
—
(445)
(8)
—
150

$22.92
$ —
$24.35
$14.80
$ —
$19.11

Range of exercise prices

$14.48 - $14.80
$26.86 - $29.68

Options outstanding at
December 31, 2022

Options exercisable at
December 31, 2022

Shares
outstanding
(in thousands)

Weighted average
remaining
contractual life

Weighted
average
exercise price

Shares
exercisable
(in thousands)

Weighted
average
exercise price

103
47

2.66
0.74

$14.80
$28.60

103
47

$14.80
$28.60

At December 31, 2022, the aggregate intrinsic value for both outstanding and exercisable options was

$5.7 million, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs.
The remaining weighted average contractual term of exercisable options at December 31, 2022 was 2.06 years.

The total intrinsic value of options exercised during the years ended December 31, 2022, 2021 and 2020

was $14.4 million, $15.8 million and $0.3 million, respectively. At December 31, 2022, the Company did not have
any unvested stock options or unrecognized compensation expense associated with unvested stock options.

The fair value of options vested during 2022, 2021 and 2020 was $0.8 million, $3.0 million and $6.7 million,

respectively.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-33

NOTE 9 — STOCK-BASED COMPENSATION — Continued

Service-Based Restricted Stock, Restricted Stock Units and Common Stock

The Company has granted stock, restricted stock and restricted stock unit awards to employees, consultants,

outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon
grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued
upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based
restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2022,
2021 and 2020 were service-based awards, which will settle in cash or equity, and vest over a one-year to three-year
period. Performance-based restricted stock units granted in 2022 and 2021 vest in an amount between zero
and 200% of the target units granted based on the Company’s relative total shareholder return over the three-year
periods ending December 31, 2024 and 2023, respectively, as compared to a designated peer group, and will be
settled in equity.

Equity-Based

A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2022

is presented below (in thousands, except fair value).

Non-vested restricted stock
and restricted stock units

Non-vested at December 31, 2021
Granted
Vested(1)
Forfeited
Non-vested at December 31, 2022

Restricted Stock

Restricted Stock Units

Service Based

Service Based

Performance Based

Weighted
average
fair value

$24.59
$45.58
$24.07
$19.12
$24.59

Shares

589
236
(126)
(41)
658

Weighted
average
fair value

$33.39
$66.16
$33.39
$ —
$66.16

Shares

33
16
(33)
—
16

Weighted
average
fair value

$20.26
$65.49
$ 1.74
$ —
$56.31

Shares

963
230
(597)
—
596

(1) On December 31, 2022, 597,414 of the performance-based awards that were granted in 2020 vested. The vested units earned 175% for

each vested award representing 1,045,472 aggregate shares of common stock, which were issued on December 31, 2022.

Liability-Based

A summary of the non-vested liability-based restricted stock units as of December 31, 2022 is presented below

(in thousands).

Non-vested restricted stock units

Non-vested at December 31, 2021
Granted
Vested
Forfeited
Non-vested at December 31, 2022

Shares

1,102
226
(587)
(19)
722

During the years ended December 31, 2022, 2021 and 2020, the Company settled 587,251, 487,252 and
226,363 liability-based awards, respectively, for $30.8 million, $12.4 million and $2.4 million in cash, respectively.

At December 31, 2022, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding

was $114.1 million, of which $41.3 million is expected to be settled in cash as calculated based on the maximum
number of shares of restricted stock units vesting, based on the closing price of Matador’s common stock on the
appropriate date under the LTIPs.

Notes to Consolidated Financial Statements FORM 10-K

F-34

MATADOR RESOURCES COMPANY

NOTE 9 — STOCK-BASED COMPENSATION — Continued

At December 31, 2022, the total remaining unrecognized compensation expense related to unvested restricted
stock and restricted stock units was approximately $56.1 million, of which $23.4 million is expected to be settled in
cash, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The weighted
average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock
units was 1.7 years.

The fair value of restricted stock and restricted stock units vested during 2022, 2021 and 2020 was $99.6 million,

$51.9 million and $8.4 million, respectively.

Summary

During the years ended December 31, 2022, 2021 and 2020, the total expense attributable to stock options was

$0.5 million, $1.0 million and $3.4 million, respectively. During the years ended December 31, 2022, 2021 and
2020, the total expense attributable to restricted stock and restricted stock units was $51.6 million, $36.3 million
and $17.7 million, respectively. During the years ended December 31, 2022, 2021 and 2020, the Company
capitalized $5.0 million, $7.2 million and $3.6 million, respectively, related to stock-based compensation and
expensed the remaining $47.1 million, $30.0 million and $17.6 million, respectively.

The total tax beneﬁt recognized for all stock-based compensation was $11.0 million, $7.9 million and $4.5 million

for the years ended December 31, 2022, 2021 and 2020, respectively.

NOTE 10 — EMPLOYEE BENEFIT PLANS

401(k) Plan

All full-time Company employees are eligible to join the Company’s deﬁned contribution retirement plan the ﬁrst

day of the calendar month immediately following their date of employment. Each employee may contribute up to
the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan
that equals 3% of the employee’s annual compensation, up to the maximum allowable under the Internal Revenue
Code, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $1.8 million, $1.6 million
and $1.4 million in 2022, 2021 and 2020, respectively. In addition, each year, the Company may make a discretionary
matching contribution, as well as additional contributions. The Company’s discretionary matching contributions
totaled $2.3 million, $2.1 million and $1.8 million in 2022, 2021 and 2020, respectively. The Company made no additional
contributions in any reporting period presented.

NOTE 11 — EQUITY

Common Stock Dividend

In February 2022 and April 2022, the Board declared quarterly cash dividends of $0.05 per share of common

stock, each of which totaled $5.9 million and were paid on March 14, 2022 and June 3, 2022, respectively. In
June 2022, the Board amended the Company’s dividend policy to increase the quarterly dividend to $0.10 per share
of common stock. In July 2022 and October 2022, the Board declared quarterly cash dividends of $0.10 per share
of common stock, each of which totaled $11.7 million and were paid on September 1, 2022 and December 1, 2022,
respectively. In December 2022, the Board amended the Company’s dividend policy to increase the quarterly
dividend to $0.15 per share of common stock for future dividend payments. On February 15, 2023, the Board declared
a quarterly cash dividend of $0.15 per share of common stock payable on March 9, 2023 to shareholders of record

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-35

NOTE 11 — EQUITY — Continued

as of February 27, 2023. The Board declared a quarterly cash dividend of $0.025 per share of common stock in each
of the ﬁrst three quarters of 2021 and, in the fourth quarter of 2021, the Board declared a quarterly cash dividend
of $0.05 per share of common stock. Total cash dividends declared and paid totaled $35.2 million and $14.6 million,
respectively, during the years December 31, 2022 and 2021. There were no cash dividends declared or paid
prior to 2021.

Treasury Stock

On October 20, 2022, October 21, 2021 and October 22, 2020, Matador’s Board of Directors canceled all of
the shares of treasury stock outstanding as of September 30, 2022, 2021 and 2020, respectively. These shares
were restored to the status of authorized but unissued shares of common stock of the Company.

The shares of treasury stock outstanding at December 31, 2022, 2021 and 2020 represent forfeitures of non-
vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements
with employees.

Preferred Stock

The Company’s Amended and Restated Certiﬁcate of Formation authorizes 2,000,000 shares of preferred stock.

Before any such shares are issued, the Board of Directors shall ﬁx and determine the designations, preferences,
limitations and relative rights, including voting rights of the shares of each such series.

NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative ﬁnancial instruments to mitigate its exposure to commodity
price risk associated with oil, natural gas and NGL prices. The Company records derivative ﬁnancial instruments on
its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not
to apply hedge accounting for its existing derivative ﬁnancial instruments. As a result, the Company recognizes the
change in derivative fair value between reporting periods currently in its consolidated statements of operations
as an unrealized gain or loss. The fair value of the Company’s derivative ﬁnancial instruments is determined using
industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time
value of money and (iii) current market and contractual prices for the underlying instruments, as well as other
relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties
in determining the fair value of its derivative ﬁnancial instruments.

At December 31, 2022, the Company had one costless collar open and in place to mitigate its exposure to natural

gas price volatility, with a speciﬁc term (calculation period), notional quantity (volume hedged) and price ﬂoor and
ceiling. At December 31, 2022, the contract was set to expire during the ﬁrst quarter of 2023. The Company had no
open contracts associated with oil or NGL prices at December 31, 2022.

The following is a summary of the Company’s open costless collar contract at December 31, 2022.

Commodity

Natural Gas

Total open costless collar

contracts

Calculation Period

Notional
Quantity
(MMBtu)

Weighted
Average
Price Floor
($/MMBtu)

Weighted
Average
Price Ceiling
($/MMBtu)

Fair Value
of Asset
(Liability)
(thousands)

01/01/2023 - 03/31/2023

2,400,000

$ 6.00

$14.00

3,931

$3,931

Notes to Consolidated Financial Statements FORM 10-K

F-36

MATADOR RESOURCES COMPANY

NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

Between December 31, 2022 and February 21, 2023, the Company entered into a Waha-Henry Hub basis
swap contract for natural gas. The basis swap contract included approximately 16,700,000 MMBtu for February 2023
to December 2023 with a ﬁxed price of ($1.85) per MMBtu.

The Company’s derivative ﬁnancial instruments are subject to master netting arrangements, and the Company’s
counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the
same. The Company does not present different types of commodities with the same counterparty on a net basis
in its consolidated balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative

ﬁnancial instruments and the location of these balances in the consolidated balance sheets as of December 31,
2022 and December 31, 2021 (in thousands).

Derivative Instruments

December 31, 2022
Current assets
Current liabilities

Total

December 31, 2021
Current assets
Current liabilities

Total

Gross amounts
recognized

Gross amounts
netted in the
consolidated
balance sheets

Net amounts
presented in
the consolidated
balance sheets

$

$

3,931
—
3,931

$

$

—
—
—

$ 3,931
—
$ 3,931

$ 215,145
(230,023)
$ (14,878)

$ (213,174)
213,174
—

$

$ 1,971
(16,849)
$(14,878)

The following table summarizes the location and aggregate gain (loss) of all derivative ﬁnancial instruments

recorded in the consolidated statements of operations for the periods presented (in thousands).

Type of Instrument

Location in Statements of Operations

2022

2021

2020

Year Ended December 31,

Derivative Instrument

Oil
Natural Gas

Realized (loss) gain
on derivatives

Oil
Natural Gas

Unrealized gain (loss)

on derivatives

Total

Revenues: Realized (loss) gain on derivatives
Revenues: Realized loss on derivatives

$ (75,806)
(81,677)

$(194,058)
(26,047)

$ 38,937
—

Revenues: Unrealized gain (loss) on derivatives
Revenues: Unrealized gain (loss) on derivatives

(157,483)
14,727
4,082

(220,105)
26,857
(5,846)

38,937
(37,703)
5,695

18,809
$(138,674)

21,011
$(199,094)

(32,008)
$ 6,929

NOTE 13 — FAIR VALUE MEASUREMENTS

The Company measures and reports certain ﬁnancial and non-ﬁnancial assets and liabilities on a fair value basis.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date (exit price). Fair value measurements are classiﬁed and
disclosed in one of the following categories.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-37

NOTE 13 — FAIR VALUE MEASUREMENTS — Continued

Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.

Level 2 Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for

substantially the full term of the asset or liability. This category includes those derivative instruments that
are valued with industry standard models that consider various inputs, including: (i) quoted forward prices
for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying
instruments, as well as other relevant economic measures. Substantially all of these inputs are observable
in the marketplace throughout the full term of the derivative instrument and can be derived from
observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3 Unobservable inputs that are not corroborated by market data that reﬂect a company’s own market

assumptions.

Financial and non-ﬁnancial assets and liabilities are classiﬁed based on the lowest level of input that is signiﬁcant

to the fair value measurement. The assessment of the signiﬁcance of a particular input to the fair value
measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their
placement within the fair value hierarchy levels.

The following tables summarize the valuation of the Company’s ﬁnancial assets and liabilities that were accounted

for at fair value on a recurring basis in accordance with the classiﬁcations provided above as of December 31, 2022
and 2021 (in thousands).

Description

Assets (Liabilities)

Natural gas derivatives

Total

Description

Assets (Liabilities)

Fair Value Measurements at December 31, 2022 using

Level 1

Level 2

Level 3

Total

$ —
$ —

$ 3,931
$ 3,931

$ — $ 3,931
$ — $ 3,931

Fair Value Measurements at December 31, 2021 using

Level 1

Level 2

Level 3

Total

Oil derivatives and basis swaps
Natural gas derivatives
Contingent consideration related to business combination

Total

$ —
—
—
$ —

$ (14,727)
(151)
—
$ (14,878)

$ — $(14,727)
(151)
$ (8,203)
$(23,081)

—
(8,203)
$ (8,203)

Additional disclosures related to derivative ﬁnancial instruments are provided in Note 12.

Other Fair Value Measurements

At December 31, 2022 and 2021, the carrying values reported on the consolidated balance sheets for accounts

receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable,
amounts due to afﬁliates, advances from joint interest owners and other current liabilities approximated their fair
values due to their short-term maturities.

At December 31, 2022 and 2021, the carrying value of borrowings under the Credit Agreement and the San Mateo
Credit Facility approximated their fair value as both are subject to short-term ﬂoating interest rates that reﬂect market
rates available to the Company at the time and are classiﬁed at Level 2 in the fair value hierarchy.

At December 31, 2022 and 2021, the fair value of the Notes was $675.7 million and $1.08 billion, respectively,

based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

Notes to Consolidated Financial Statements FORM 10-K

F-38

MATADOR RESOURCES COMPANY

NOTE 13 — FAIR VALUE MEASUREMENTS — Continued

Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities
acquired in a business combination, lease and well equipment inventory when the market value is determined to be
lower than the cost of the inventory and other property and equipment that are reduced to fair value when they
are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or
other property and equipment in 2022 and 2021.

NOTE 14 — COMMITMENTS AND CONTINGENCIES

Processing, Transportation and Produced Water Disposal Commitments

Firm Commitments

From time to time, the Company enters into agreements with third parties whereby the Company commits to

deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for
gathering, transportation, processing, fractionation, sales and disposal. The Company paid approximately $48.3 million
and $48.7 million for deliveries under these agreements during the years ended December 31, 2022 and 2021,
respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet
the minimum volume commitments under these agreements, it will be required to pay certain deﬁciency fees. If the
Company ceased operations in the areas subject to these agreements at December 31, 2022, the total deﬁciencies
required to be paid by the Company under these agreements would be approximately $541.1 million.

San Mateo Commitments

The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks

and Wolf asset areas and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year,
ﬁxed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements.
In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler
Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, ﬁxed-fee
natural gas processing agreements (collectively with the transportation, gathering and produced water disposal
agreements, the “Operational Agreements”). San Mateo provides the Company with ﬁrm service under each of the
Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum
contractual obligation under the Operational Agreements at December 31, 2022 was approximately $292.0 million.

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for

such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s
commitment for the drilling services to be provided. The Company would incur a termination obligation if the
Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for
the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective
contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its
drilling rig contracts were approximately $17.7 million at December 31, 2022.

At December 31, 2022, the Company had outstanding commitments to participate in the drilling and completion of

various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s undiscounted
minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately
$26.0 million at December 31, 2022. The Company expects these costs to be incurred within the next year.

At December 31, 2022, the Company had outstanding commitments of $29.8 million to purchase 12 compressors to

be utilized in San Mateo and Pronto operations. The Company expects these costs to be incurred within the next year.

FORM 10-K Notes to Consolidated Financial Statements

2022 ANNUAL REPORT

F-39

NOTE 14 — COMMITMENTS AND CONTINGENCIES — Continued

Legal Proceedings

The Company is a party to several legal proceedings encountered in the ordinary course of its business. While
the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management,
it is remote that these legal proceedings will have a material adverse impact on the Company’s ﬁnancial condition,
results of operations or cash ﬂows.

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2022 and 2021 (in

thousands).

Accrued evaluated and unproved and unevaluated property costs
Accrued midstream properties costs
Accrued lease operating expenses
Accrued interest on debt
Accrued asset retirement obligations
Accrued partners’ share of joint interest charges
Accrued payable related to purchased natural gas
Other

Total accrued liabilities

Supplemental Cash Flow Information

December 31,

2022

2021

$112,766
11,623
46,975
10,461
756
42,199
11,158
25,372
$261,310

$128,598
7,799
32,182
18,232
270
17,460
11,284
37,458
$253,283

The following table provides supplemental disclosures of cash ﬂow information for the years ended December

31, 2022, 2021 and 2020 (in thousands).

Cash paid for income taxes
Cash paid for interest expense, net of amounts capitalized
Increase (decrease) in asset retirement obligations related to

mineral properties

Increase in asset retirement obligations related to midstream properties
(Decrease) increase in liabilities for drilling, completion and

equipping capital expenditures

(Decrease) increase in liabilities for acquisition of oil and

natural gas properties

Increase (decrease) in liabilities for midstream capital expenditures
Stock-based compensation expense recognized as liability
Transfer of inventory from (to) oil and natural gas properties

NOTE 15 — SUPPLEMENTAL DISCLOSURES

Year Ended December 31,

2022

2021

2020

$ 63,500
$ 72,561

$
—
$74,843

$
—
$ 76,880

$ 9,111
251
$

$ 1,091
257
$

$
$

(208)
690

$(13,304)

$80,255

$(26,126)

$ (2,531)
$ 3,824
$ 31,906
148
$

$ 2,981
$ (4,478)
$24,494
(398)
$

$ (2,346)
$(33,609)
$ 3,702
608
$

The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance

sheets to cash and restricted cash as presented on the consolidated statements of cash ﬂows (in thousands).

Cash
Restricted cash

Total cash and restricted cash

Year Ended December 31,

2022

2021

2020

$505,179
42,151
$547,330

$ 48,135
38,785
$ 86,920

$ 57,916
33,467
$ 91,383

Notes to Consolidated Financial Statements FORM 10-K

F-40

MATADOR RESOURCES COMPANY

NOTE 16 — SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The

exploration and production segment is engaged in the exploration, development, production and acquisition of oil and
natural gas resources in the United States and is currently focused primarily on the oil and liquids-rich portion of
the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The
Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays
in Northwest Louisiana. The midstream segment conducts midstream operations in support of the Company’s
exploration, development and production operations and provides natural gas processing, oil transportation services,
oil, natural gas and produced water gathering services and produced water disposal services to third parties.
Substantially all of the Company’s midstream operations in the Rustler Breaks, Wolf and Stateline asset areas and
the Greater Stebbins Area in the Delaware Basin, which comprise most of the Company’s midstream operations,
are conducted through San Mateo (see Note 6). In addition, on June 30, 2022, an indirect wholly-owned subsidiary
of the Company acquired a cryogenic gas processing plant, three compressor stations and approximately 45 miles
of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition. Neither
San Mateo nor Pronto is a guarantor of the Notes.

The following tables present selected ﬁnancial information for the periods presented regarding the Company’s

business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and
the consolidation and elimination entries necessary to arrive at the ﬁnancial information for the Company on a
consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those
revenues from midstream operations related to third parties, including working interest owners in the Company’s
operated wells. All midstream services revenues associated with Company-owned production are eliminated
in consolidation. In evaluating the operating results of the exploration and production and midstream segments,
the Company does not allocate certain expenses to the individual segments, including general and administrative
expenses. Such expenses are reﬂected in the column labeled “Corporate.”

Year Ended December 31, 2022
Oil and natural gas revenues
Midstream services revenues
Sales of purchased natural gas
Realized loss on derivatives
Unrealized gain on derivatives
Expenses(1)
Operating income(2)

Total assets(3)

Capital expenditures(4)

Exploration and
Production

Midstream

Corporate

Consolidations
and
Eliminations

Consolidated
Company

$2,897,336
—
116,772
(157,483)
18,809
1,177,104
$1,698,330

$

8,402
298,184
83,583
—
—
227,556
$ 162,613

$

—
—
—
—
—
101,673
$(101,673)

$4,022,609

$1,016,580

$ 515,316

$ 903,518

$ 158,544

$

1,213

$

$

$

$

—
(207,578)
—
—
—
(207,578)
—

—

—

$2,905,738
90,606
200,355
(157,483)
18,809
1,298,755
$1,759,270

$5,554,505

$1,063,275

(1)

Includes depletion, depreciation and amortization expenses of $429.7 million and $34.7 million for the exploration and production and midstream
segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.0 million.

(2) Includes $72.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Excludes intercompany receivables and investments in subsidiaries.

(4) Includes $131.0 million attributable to land and seismic acquisition expenditures related to the exploration and production segment, $75.8 million
in midstream acquisition expenditures and $39.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to
the midstream segment.

FORM 10-K Notes to Consolidated Financial Statements

NOTE 16 — SEGMENT INFORMATION — Continued

Exploration and
Production

Midstream

Corporate

and
Eliminations

Consolidated
Company

2022 ANNUAL REPORT

F-41

Year Ended December 31, 2021
Oil and natural gas revenues
Midstream services revenues
Sales of purchased natural gas
Realized loss on derivatives
Unrealized gain on derivatives
Expenses(1)
Operating (loss) income(2)

Total assets(3)

Capital expenditures(4)

$1,695,032
—
47,398
(220,105)
21,011
794,880
$ 748,456

$

5,510
228,817
38,636
—
—
142,444
$130,519

$

—
—
—
—
—
85,899
$(85,899)

$

—
(153,318)
—
—
—
(153,318)
—

$

$3,324,681

$879,672

$ 57,800

$ 778,191

$ 59,361

$

376

$

$

—

—

$1,700,542
75,499
86,034
(220,105)
21,011
869,905
$ 793,076

$4,262,153

$ 837,928

(1)

Includes depletion, depreciation and amortization expenses of $310.9 million and $31.5 million for the exploration and production and midstream
segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.6 million.

(2) Includes $55.7 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Excludes intercompany receivables and investments in subsidiaries.

(4) Includes $263.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and

$28.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

Year Ended December 31, 2020
Oil and natural gas revenues
Midstream services revenues
Sales of purchased natural gas
Lease bonus - mineral acreage
Realized gain on derivatives
Unrealized loss on derivatives
Expenses(1)
Operating income (loss)(2)

Total assets(3)

Capital expenditures(4)

Exploration and
Production

Midstream

Corporate

and
Eliminations

Consolidated
Company

$ 741,092
—
20,736
4,062
38,937
(32,008)
1,334,378
$ (561,559)

$

$

3,369
166,194
21,006
—
—
—
97,599
92,970

$

—
—
—
—
—
—
52,910
$ (52,910)

$2,782,819

$ 836,509

$ 67,952

$ 518,198

$ 201,440

$

2,200

$

$

$

$

—
(101,262)
—
—
—
—
(101,262)
—

—

—

$ 744,461
64,932
41,742
4,062
38,937
(32,008)
1,383,625
$ (521,499)

$3,687,280

$ 721,838

(1)

Includes depletion, depreciation and amortization expenses of $335.8 million and $23.3 million for the exploration and production and midstream
segments, respectively. Includes full-cost ceiling impairment of $684.7 million for the exploration and production segment. Also includes
corporate depletion, depreciation and amortization expenses of $2.7 million.

(2) Includes $39.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) Excludes intercompany receivables and investments in subsidiaries.

(4) Includes $70.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and

$112.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

NOTE 17 — SUBSEQUENT EVENTS

On January 24, 2023, a wholly-owned subsidiary of the Company entered into a deﬁnitive agreement to acquire
Advance Energy Partners Holdings, LLC (“Advance”) from afﬁliates of EnCap Investments L.P., including certain oil
and natural gas producing properties and undeveloped acreage located primarily in Lea County, New Mexico and
Ward County, Texas (the “Advance Acquisition”). The consideration for the Advance Acquisition is expected to consist
of $1.6 billion in cash, subject to customary closing adjustments, including for working capital and title and
environmental defects, plus additional cash consideration of $7.5 million for each month during 2023 in which the
average price of crude oil (as deﬁned in the securities purchase agreement) exceeds $85 per barrel. The consummation
of the Advance Acquisition is subject to customary closing conditions and is expected to close in the second
quarter of 2023 with an effective date of January 1, 2023.

Notes to Consolidated Financial Statements FORM 10-K

F-42

MATADOR RESOURCES COMPANY

Unaudited Supplementary Information

MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2022, 2021 and 2020

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

Costs Incurred

The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and
development of oil and natural gas properties for the years ended December 31, 2022, 2021 and 2020 (in thousands).

Property acquisition costs

Proved
Unproved and unevaluated

Exploration costs
Development costs

Total costs incurred(1)

Year Ended December 31,

2022

2021

2020

$ 36,985
97,127
136,209
643,947
$ 914,268

$145,759
104,582
51,534
476,316
$778,191

$

8,003
61,984
29,370
418,840
$518,197

(1) Excludes midstream-related development and corporate costs of approximately $159.8 million, $59.7 million and $203.6 million for the years

ended December 31, 2022, 2021 and 2020, respectively.

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas

properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years
ended December 31, 2022 and 2020, a majority of the Company’s property acquisition costs resulted from the
acquisition of unproved and unevaluated leasehold and mineral interests, while for the year ended December 31,
2021, 58% of the Company’s property acquisition costs resulted from the acquisition of proved properties.

Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant

further examination and in examining speciﬁc areas that are considered to be prospective for oil and natural gas,
including costs of drilling exploratory wells, geological and geophysical costs and costs of carrying and retaining
unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and
natural gas properties. The Company capitalized $7.5 million of geological and geophysical costs, which are
included as exploration costs in the table above, for the year ended December 31, 2021. The Company did not
capitalize any geological and geophysical costs in 2022 or 2020.

Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting,

treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations
for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities.

Costs incurred also include newly established asset retirement obligations, as well as changes to asset

retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations
included in the table above were an increase of $10.7 million, an increase of $1.4 million and a reduction of
$0.2 million for the years ended December 31, 2022, 2021 and 2020, respectively. Capitalized general and administrative
expenses that are directly related to acquisition, exploration and development activities are also included in the
table above. The Company capitalized $47.8 million, $38.4 million and $30.0 million of these internal costs for the
years ended December 31, 2022, 2021 and 2020, respectively, excluding midstream-related capitalized general
and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above.
The Company capitalized $10.1 million, $4.8 million and $5.0 million of its interest expense for the years ended
December 31, 2022, 2021 and 2020, respectively, excluding midstream-related capitalized interest expense.

FORM 10-K Unaudited Supplementary Information

2022 ANNUAL REPORT

F-43

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

Oil and Natural Gas Reserves

Proved reserves are estimated quantities of oil and natural gas that geological and engineering data demonstrate

with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and
operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous
uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical,
petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated
interpretations of that data can vary. The process also requires certain economic assumptions, including, but not
limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses
and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates.

The Company reports its production and proved reserves in two streams: oil and natural gas, including both
dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and
Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in
South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead
natural gas price on those properties where the NGLs are extracted and sold. The Company’s oil and natural gas
reserves estimates for the years ended December 31, 2022, 2021 and 2020 were prepared by the Company’s
engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness
and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no
provision for price and cost escalations in future periods except by contractual arrangements. The commodity
prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of ﬁrst-day-
of-the-month oil and natural gas prices for the previous 12-month period. For the period from January through
December 2022, these average oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively.
For the period from January through December 2021, these average oil and natural gas prices were $63.04 per Bbl
and $3.60 per MMBtu, respectively. For the period from January through December 2020, these average oil and
natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively.

The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net

proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to
properties located in the United States. The estimated reserves shown below are proved reserves only and do not
include any value for unproved reserves classiﬁed as probable or possible reserves that might exist for these
properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond
those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas
is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas.

Unaudited Supplementary Information FORM 10-K

F-44

MATADOR RESOURCES COMPANY

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

Total at December 31, 2019

Revisions of prior estimates
Net acquisitions of minerals-in-place
Extensions and discoveries
Production

Total at December 31, 2020

Revisions of prior estimates
Net acquisitions of minerals-in-place
Extensions and discoveries
Production

Total at December 31, 2021

Revisions of prior estimates
Net acquisitions (divestitures) of minerals-in-place
Extensions and discoveries
Production

Total at December 31, 2022

Proved Developed Reserves
December 31, 2019
December 31, 2020
December 31, 2021
December 31, 2022

Proved Undeveloped Reserves
December 31, 2019
December 31, 2020
December 31, 2021
December 31, 2022

Net Proved Reserves

Natural
Gas

(MMcf)

627,238
19,444
1,078
84,043
(69,501)
662,302
165,423
11,976
94,532
81,686
852,547
13,190
(1,332)
197,497
(99,308)
962,594

276,258
323,160
546,173
632,858

350,980
339,142
306,374
329,736

Oil
Equivalent

(MBOE)

252,531
9,828
190
35,297
(27,514)
270,332
41,916
9,529
33,074
(31,454)
323,397
(302)
1,017
71,105
(38,495)
356,722

105,710
123,507
193,262
221,507

146,821
146,825
130,135
135,215

Oil

(MBbl)

147,991
6,587
11
21,291
(15,931)
159,949
14,346
7,533
17,318
(17,840)
181,306
(2,502)
1,239
38,189
(21,943)
196,289

59,667
69,647
102,233
116,030

88,324
90,301
79,073
80,259

The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for

the years ended December 31, 2022, 2021 and 2020.

The Company’s proved oil and natural gas reserves increased 10% from 323.4 million BOE at December 31,
2021 to 356.7 million BOE at December 31, 2022. The Company’s proved oil and natural gas reserves increased
by 71.8 million BOE and the Company produced 38.5 million BOE during the year ended December 31, 2022,
resulting in a net increase of 33.3 million BOE. The Company added 71.1 million BOE in proved reserves through
extensions and discoveries during 2022, of which 24.7 million BOE resulted from new well locations drilled during
2022 to establish proved developed reserves and 53.8 million BOE resulted primarily from new proved undeveloped
locations identiﬁed as a result of drilling activities on its existing acreage in the Delaware Basin during 2022, but
which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed
or were no longer expected to be developed within ﬁve years of their initial booking resulting primarily from
changes in development plans for certain of our properties in the Delaware Basin. As the Company continues to
develop its Delaware Basin assets, the Company may reclassify some or all of this 7.4 million BOE to proved
reserves at a future date.

FORM 10-K Unaudited Supplementary Information

2022 ANNUAL REPORT

F-45

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

The Company’s proved developed oil and natural gas reserves increased 15% from 193.3 million BOE at

December 31, 2021 to 221.5 million BOE at December 31, 2022. The Company’s proved developed oil and natural
gas reserves increased by 66.7 million BOE and the Company produced 38.5 million BOE during the year ended
December 31, 2022, resulting in a net increase of 28.2 million BOE. The Company added 24.7 million BOE in proved
developed reserves through extensions and discoveries during 2022, which resulted from new well locations
drilled during 2022 to establish proved reserves. The Company realized approximately 2.9 million BOE in net upward
revisions to prior estimates, most of which was attributable to the higher commodity prices used to estimate
proved reserves at December 31, 2022, which resulted in longer estimated economic lives for certain of our
producing properties. In addition, the Company converted 38.4 million BOE of our proved undeveloped reserves to
proved developed reserves primarily through our development activities in the Delaware Basin during 2022,
primarily in our Ranger, Stateline, Antelope Ridge and Rustler Breaks asset areas. In addition, the Company realized
0.8 million BOE in net upward revisions to our proved developed reserves at December 31, 2022 as a result of
property acquisitions and divestitures completed during 2022.

The Company’s proved undeveloped oil and natural gas reserves increased 4% from 130.1 million BOE at
December 31, 2021 to 135.2 million at December 31, 2022. The Company added 53.8 million BOE in proved
undeveloped reserves through extensions and discoveries during 2022, which resulted primarily from new proved
undeveloped locations identiﬁed as a result of drilling activities on our existing acreage in the Delaware Basin during
2022 but which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that
were not developed or were no longer expected to be developed within ﬁve years of their initial booking resulting
from changes in development plans for certain of the properties in the Delaware Basin. The Company realized
approximately 3.2 million BOE in net downward revisions to our prior estimates of proved undeveloped reserves,
most of which was attributable to forecast updates at December 31, 2022. In addition, the Company realized
0.3 million BOE in net upward revisions to our proved undeveloped reserves at December 31, 2022 as a result of
property acquisitions and divestitures completed during 2022. During 2022, the Company also converted
38.4 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its development
activities in the Delaware Basin during 2022.

At December 31, 2022, the Company’s proved reserves were comprised of 55% oil and 45% natural gas and
were approximately 62% proved developed and 38% proved undeveloped. This increase in the Company’s proved
developed reserves to 62% of its total proved reserves at December 31, 2022 reﬂected a continued increase in
the Company’s percentage of proved developed reserves, as compared to 60% and 46% proved developed reserves
at December 31, 2021 and 2020, respectively.

Unaudited Supplementary Information FORM 10-K

F-46

MATADOR RESOURCES COMPANY

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

The Company’s proved oil and natural gas reserves increased 20% from 270.3 million BOE at December 31,
2020 to 323.4 million BOE at December 31, 2021. The Company’s proved oil and natural gas reserves increased by
84.5 million BOE and the Company produced 31.5 million BOE during the year ended December 31, 2021,
resulting in a net increase of 53.1 million BOE. The Company added 33.1 million BOE in proved reserves through
extensions and discoveries during 2021, of which 22.4 million BOE resulted from new well locations drilled during
2021 to establish proved developed reserves and 26.9 million BOE resulted primarily from new proved undeveloped
locations identiﬁed as a result of drilling activities on its existing acreage in the Delaware Basin during 2021, but
which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed
or were no longer expected to be developed within ﬁve years of their initial booking resulting from changes in
development plans for certain of our properties in the Delaware Basin. As the Company continues to develop its
Delaware Basin assets, the Company may reclassify some or all of this 16.3 million BOE to proved reserves at
a future date. The Company also realized 41.9 million BOE in net upward revisions to prior estimates, 96% of which
was attributable to the signiﬁcantly higher commodity prices used to estimate proved reserves at December 31,
2021, which resulted in longer estimated economic lives for certain of its properties. The Company also had small
upward revisions to prior estimates attributable to increased working interests and lower estimated operating
costs on certain of its properties. In addition, the Company realized 9.5 million BOE in net upward revisions to its
proved oil and natural gas reserves at December 31, 2021 as a result of property acquisitions and divestitures
completed during 2021.

The Company’s proved oil and natural gas reserves increased from 252.5 million BOE at December 31, 2019

to 270.3 million BOE at December 31, 2020. The Company’s proved oil and natural gas reserves increased by
45.3 million BOE and the Company produced 27.5 million BOE during the year ended December 31, 2020, resulting
in a net increase of 17.8 million BOE. The Company added 35.3 million BOE in proved reserves through extensions
and discoveries during 2020, of which 15.2 million BOE resulted from new well locations drilled during 2020 to
establish proved developed reserves and 20.1 million BOE consisted primarily of new proved undeveloped locations
identiﬁed as a result of drilling activities on its existing acreage in the Delaware Basin during 2020. The Company
also realized 9.8 million BOE in net upward revisions to prior estimates at December 31, 2020, which included
positive revisions to prior estimates of 31.2 million BOE attributable primarily to revisions to prior forecasts resulting
from better-than-expected well performance during 2020, which was offset by negative revisions to prior
estimates of 21.4 million BOE primarily resulting from lower weighted oil and natural gas prices used to estimate
proved reserves at December 31, 2020, as compared to December 31, 2019. The Company’s proved developed
oil and natural gas reserves increased to 123.5 million BOE at December 31, 2020 from 105.7 million BOE at
December 31, 2019, primarily due to proved developed reserves added as a result of drilling operations in the
Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2020, the Company’s proved reserves
were made up of approximately 59% oil and 41% natural gas and were approximately 46% proved developed
and 56% proved undeveloped.

FORM 10-K Unaudited Supplementary Information

2022 ANNUAL REPORT

F-47

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved
Oil and Natural Gas Reserves

The standardized measure of discounted future net cash ﬂows relating to proved oil and natural gas reserves is
not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas
properties. An estimate of fair market value would also take into account, among other things, the recovery of
reserves not presently classiﬁed as proved, anticipated future changes in prices and costs, potential improvements
in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different
discount rates.

As noted previously, for the period from January through December 2022, the unweighted, arithmetic averages

of ﬁrst-day-of-the-month oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively. For
the period from January through December 2021, the comparable average oil and natural gas prices were $63.04
per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, the comparable
average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively.

Future net cash ﬂows were computed by applying these oil and natural gas prices, adjusted for all associated
transportation and gathering costs, gravity and energy content and regional price differentials, to year-end quantities
of proved oil and natural gas reserves and accounting for any future production and development costs associated
with producing these reserves; neither prices nor costs were escalated with time in these computations.

Future income taxes were computed by applying the statutory tax rate to the excess of future net cash ﬂows

relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net
operating loss carryforwards available to the Company were also considered in the computation of future income
taxes. Future net cash ﬂows after income taxes were discounted using a 10% annual discount rate to derive the
standardized measure of discounted future net cash ﬂows.

The following table presents the standardized measure of discounted future net cash ﬂows relating to proved

oil and natural gas reserves for the years ended December 31, 2022, 2021 and 2020 (in thousands).

Future cash inﬂows
Future production costs
Future development costs
Future income tax expense
Future net cash ﬂows

10% annual discount for estimated timing of cash ﬂows

Standardized measure of discounted future net cash ﬂows

Year Ended December 31,

2022

2021

2020

$24,952,118
(6,752,752)
(1,776,029)
(3,935,271)
12,488,066
(5,504,863)
$ 6,983,203

$15,174,065
(4,588,677)
(1,251,581)
(1,836,009)
7,497,798
(3,122,373)
$ 4,375,425

$ 6,587,343
(2,606,956)
(1,075,317)
(228,848)
2,676,222
(1,091,823)
$ 1,584,399

Unaudited Supplementary Information FORM 10-K

F-48

MATADOR RESOURCES COMPANY

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

The following table summarizes the changes in the standardized measure of discounted future net cash ﬂows
relating to proved oil and natural gas reserves for the years ended December 31, 2022, 2021 and 2020 (in thousands).

Balance, beginning of period
Net change in sales and transfer prices and in production (lifting) costs

related to future production

Changes in estimated future development costs
Sales and transfers of oil and natural gas produced during the period
Net purchases of reserves in place
Net change due to extensions and discoveries
Net change due to revisions in estimates of reserves quantities
Previously estimated development costs incurred during the period
Accretion of discount
Other
Net change in income taxes

Standardized measure of discounted future net cash ﬂows

Year Ended December 31,

2022

2021

2020

$ 4,375,425

$ 1,584,399

$ 2,033,983

4,046,504
(744,687)
(2,466,440)
28,841
2,017,170
(8,576)
434,336
475,474
1,982
(1,176,826)
$ 6,983,203

3,347,910
(238,871)
(1,412,591)
178,695
620,235
786,061
240,664
165,799
1,737
(898,613)
$ 4,375,425

(1,126,777)
177,074
(546,169)
1,803
296,617
93,066
253,165
240,728
16
160,893
$ 1,584,399

FORM 10-K Unaudited Supplementary Information

2022 ANNUAL REPORT

Exhibit 31.1

CERTIFICATION

I, Joseph Wm. Foran, certify that:

1. I have reviewed this annual report on Form 10-K of Matador Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a

material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the ﬁnancial statements, and other ﬁnancial information included in this report, fairly
present in all material respects the ﬁnancial condition, results of operations and cash ﬂows of the registrant as
of, and for, the periods presented in this report;

4. The registrant’s other certifying ofﬁcer(s) and I are responsible for establishing and maintaining disclosure

controls and procedures (as deﬁned in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
ﬁnancial reporting (as deﬁned in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;

b. Designed such internal control over ﬁnancial reporting, or caused such internal control over ﬁnancial

reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with
generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this

report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over ﬁnancial reporting that occurred

during the registrant’s most recent ﬁscal quarter (the registrant’s fourth ﬁscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over ﬁnancial reporting; and

5. The registrant’s other certifying ofﬁcer(s) and I have disclosed, based on our most recent evaluation of internal
control over ﬁnancial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):

a. All signiﬁcant deﬁciencies and material weaknesses in the design or operation of internal control over

ﬁnancial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report ﬁnancial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a signiﬁcant

role in the registrant’s internal control over ﬁnancial reporting.

March 1, 2023

/s/ Joseph Wm. Foran

Joseph Wm. Foran
Chairman and Chief Executive Ofﬁcer
(Principal Executive Ofﬁcer)

FORM 10-K

MATADOR RESOURCES COMPANY

Exhibit 31.2

CERTIFICATION

I, Brian J. Willey, certify that:

1. I have reviewed this annual report on Form 10-K of Matador Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state

a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the ﬁnancial statements, and other ﬁnancial information included in this report, fairly
present in all material respects the ﬁnancial condition, results of operations and cash ﬂows of the registrant as
of, and for, the periods presented in this report;

4. The registrant’s other certifying ofﬁcer(s) and I are responsible for establishing and maintaining disclosure

controls and procedures (as deﬁned in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
ﬁnancial reporting (as deﬁned in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;

b. Designed such internal control over ﬁnancial reporting, or caused such internal control over ﬁnancial

reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with
generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this

report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over ﬁnancial reporting that occurred

during the registrant’s most recent ﬁscal quarter (the registrant’s fourth ﬁscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over ﬁnancial reporting; and

5. The registrant’s other certifying ofﬁcer(s) and I have disclosed, based on our most recent evaluation of internal
control over ﬁnancial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):

a. All signiﬁcant deﬁciencies and material weaknesses in the design or operation of internal control over

ﬁnancial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report ﬁnancial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a signiﬁcant

role in the registrant’s internal control over ﬁnancial reporting.

March 1, 2023

/s/ Brian J. Willey

Brian J. Willey
Chief Financial Ofﬁcer, President of Midstream Operations
and Executive Vice President
(Principal Financial Ofﬁcer)

FORM 10-K

2022 ANNUAL REPORT

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Matador Resources Company (the “Company”) on Form 10-K for the
year ended December 31, 2022 as ﬁled with the Securities and Exchange Commission on the date hereof (the
“Form 10-K”), I, Joseph Wm. Foran, Chairman and Chief Executive Ofﬁcer of the Company, hereby certify,
pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of
my knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of

1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the ﬁnancial condition and

results of operations of the Company.

March 1, 2023

/s/ Joseph Wm. Foran

Joseph Wm. Foran
Chairman and Chief Executive Ofﬁcer
(Principal Executive Ofﬁcer)

FORM 10-K

MATADOR RESOURCES COMPANY

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Matador Resources Company (the “Company”) on Form 10-K for the year
ended December 31, 2022 as ﬁled with the Securities and Exchange Commission on the date hereof (the
“Form 10-K”), I, Brian J. Willey, Chief Financial Ofﬁcer, President of Midstream Operations and Executive Vice
President of the Company, hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the
Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of

1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the ﬁnancial condition and

results of operations of the Company.

March 1, 2023

/s/ Brian J. Willey

Brian J. Willey
Chief Financial Ofﬁcer, President of Midstream Operations
and Executive Vice President
(Principal Financial Ofﬁcer)

FORM 10-K

2022 ANNUAL REPORT

Additional Financial Information

ADJUSTED EBITDA RECONCILIATION

This Annual Report includes the non-GAAP ﬁnancial measure of Adjusted EBITDA. Adjusted EBITDA is a supplemental
non-GAAP ﬁnancial measure that is used by management and external users of the Company’s consolidated ﬁnancial
statements, such as securities analysts, investors, lenders and rating agencies. “GAAP” means Generally Accepted
Accounting Principles in the United States of America. The Company believes Adjusted EBITDA helps it evaluate its operating
performance and compare its results of operations from period to period without regard to its ﬁnancing methods or capital
structure. The Company deﬁnes, on a consolidated basis and for San Mateo, Adjusted EBITDA as earnings before interest
expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property
impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation
expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income or net cash
provided by operating activities as determined by GAAP. All references to Matador’s Adjusted EBITDA are those values
attributable to Matador Resources Company shareholders after giving effect to Adjusted EBITDA attributable to third-party
non-controlling interests, including in San Mateo.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or net cash provided
by operating activities as determined in accordance with GAAP or as an indicator of the Company’s operating performance
or liquidity. Certain items excluded from Adjusted EBITDA are signiﬁcant components of understanding and assessing a
company’s ﬁnancial performance, such as a company’s cost of capital and tax structure. Adjusted EBITDA may not be
comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in
the same manner. The following table presents the calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA
to the GAAP ﬁnancial measures of net income and net cash provided by operating activities, respectively, that are of a
historical nature. Where references are pro forma, forward-looking, preliminary or prospective in nature, and not based on
historical fact, the table does not provide a reconciliation. The Company could not provide such reconciliation without undue
hardship because such Adjusted EBITDA numbers are estimations, approximations and/or ranges. In addition, it would be
difﬁcult for the Company to present a detailed reconciliation on account of many unknown variables for the reconciling items,
including future income taxes, full-cost ceiling impairments, unrealized gains or losses on derivatives and gains or losses on
asset sales and impairment. For the same reasons, the Company is unable to address the probable signiﬁcance of the
unavailable information, which could be material to future results.

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to Net Income:
Net income attributable to Matador Resources Company shareholders
Net income attributable to non-controlling interest in subsidiaries
Net income
Interest expense
Total income tax provision
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Unrealized gain on derivatives
Non-cash stock-based compensation expense
Net loss on asset sales and impairment
Expense related to contingent consideration and other

Consolidated Adjusted EBITDA

Adjusted EBITDA attributable to non-controlling interest in subsidiaries

Adjusted EBITDA attributable to Matador Resources Company shareholders

Year Ended

December 31,
2022

December 31,
2021

$1,214,206
72,111
1,286,317
67,164
399,357
466,348
2,421
(18,809)
15,123
1,311
4,926
2,224,158
(97,002)
$2,127,156

$ 584,968
55,668
640,636
74,687
74,710
344,905
2,068
(21,011)
9,039
331
1,485
1,126,850
(74,877)
$1,051,973

Additional Financial Information

MATADOR RESOURCES COMPANY

ADJUSTED EBITDA RECONCILIATION — Continued

Year Ended

December 31, December 31,

2022

2021

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities
Net change in operating assets and liabilities
Interest expense, net of non-cash portion
Current income tax provision
Expense related to contingent consideration and other
Adjusted EBITDA attributable to non-controlling interest in subsidiaries

Adjusted EBITDA attributable to Matador Resources Company shareholders

$1,978,739
117,935
63,064
54,877
9,543
(97,002)
$2,127,156

$1,053,355
982
71,028
—
1,485
(74,877)
$1,051,973

Adjusted EBITDA – San Mateo (100%)

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to Net Income:
Net income
Depletion, depreciation and amortization
Interest expense
Accretion of asset retirement obligations
Net loss on impairment and one-time plant payment

Adjusted EBITDA

Year Ended

December 31, December 31,

2022

2021

$147,163
32,378
16,829
282
1,311
$197,963

$113,607
30,522
8,434
247
1,500
$154,310

Year Ended

December 31, December 31,

2022

2021

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities
Net change in operating assets and liabilities
Interest expense, net of non-cash portion
One-time plant payment

Adjusted EBITDA

$178,549
3,848
15,566
—
$197,963

$143,744
1,689
7,377
1,500
$154,310

Additional Financial Information

2022 ANNUAL REPORT

ADJUSTED FREE CASH FLOW RECONCILIATION

This Annual Report includes the non-GAAP ﬁnancial measure of adjusted free cash ﬂow. This non-GAAP item is measured,
on a consolidated basis for the Company and for San Mateo, as net cash provided by operating activities, adjusted for
changes in working capital and cash performance incentives that are not included as operating cash ﬂows, less cash ﬂows
used for capital expenditures, adjusted for changes in capital accruals. On a consolidated basis, these numbers are also
adjusted for the cash ﬂows related to non-controlling interest in subsidiaries that represent cash ﬂows not attributable
to Matador shareholders. Adjusted free cash ﬂow should not be considered an alternative to, or more meaningful than, net
cash provided by operating activities as determined in accordance with GAAP or an indicator of the Company’s liquidity.
Adjusted free cash ﬂow is used by the Company, securities analysts and investors as an indicator of the Company’s ability to
manage its operating cash ﬂow, internally fund its D/C/E capital expenditures, pay dividends and service or incur additional
debt, without regard to the timing of settlement of either operating assets and liabilities or accounts payable related to
capital expenditures. Additionally, this non-GAAP ﬁnancial measure may be different than similar measures used by other
companies. The Company believes the presentation of adjusted free cash ﬂow provides useful information to investors, as it
provides them an additional relevant comparison of the Company’s performance, sources and uses of capital associated
with its operations across periods and to the performance of the Company’s peers. In addition, this non-GAAP ﬁnancial
measure reﬂects adjustments for items of cash ﬂows that are often excluded by securities analysts and other users of the
Company’s ﬁnancial statements in evaluating the Company’s cash spend.

The table below reconciles adjusted free cash ﬂow to its most directly comparable GAAP measure of net cash provided by
operating activities. All references to Matador’s adjusted free cash ﬂow are those values attributable to Matador shareholders
after giving effect to adjusted free cash ﬂow attributable to third-party non-controlling interests, including in San Mateo.

Adjusted Free Cash Flow – Matador Resources Company

(In thousands)

Net cash provided by operating activities

Net change in operating assets and liabilities
San Mateo discretionary cash ﬂow attributable to non-controlling interest in subsidiaries(1)
Performance incentives received from Five Point

Total discretionary cash ﬂow
Drilling, completion and equipping capital expenditures
Midstream capital expenditures
Expenditures for other property and equipment

Net change in capital accruals
San Mateo accrual-based capital expenditures related to non-controlling interest in subsidiaries(2)

Total accrual-based capital expenditures(3)
Adjusted free cash ﬂow

Year Ended
December 31,
2022

$1,978,739
117,935
(89,375)
28,250
2,035,549
771,830
80,051
1,213
4,355
(39,717)
817,732
$1,217,817

(1) Represents Five Point Energy LLC’s (“Five Point”) 49% interest in San Mateo discretionary cash ﬂow, as computed below.

(2) Represents Five Point’s 49% interest in accrual-based San Mateo capital expenditures, as computed below.

(3) Represents drilling, completion and equipping costs, Matador’s share of San Mateo capital expenditures plus 100% of other midstream capital

expenditures not associated with San Mateo.

Adjusted Free Cash Flow - San Mateo (100%)

(In thousands)

Net cash provided by San Mateo operating activities

Net change in San Mateo operating assets and liabilities

Total San Mateo discretionary cash ﬂow
San Mateo capital expenditures

Net change in San Mateo capital accruals
San Mateo accrual-based capital expenditures

San Mateo adjusted free cash ﬂow

Year Ended
December 31,
2022

$178,549
3,848
182,397
79,026
2,029
81,055

$101,342

Additional Financial Information

MATADOR RESOURCES COMPANY

[PAGE INTENTIONALLY LEFT BLANK]

Corporate Information

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(972) 371-5200 

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STOCK TRANSFER AGENT AND REGISTRAR

Please direct general questions about shareholder 
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(800) 368-5948

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FINANCIAL INFORMATION REQUESTS
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at our corporate headquarters.

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OFFICER CERTIFICATIONS
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Note that these documents, along with further 
information about our history, board of directors, 
management team, operations and contact details, 
are available on our website at:  
www.matadorresources.com.

FORWARD-LOOKING STATEMENTS: 

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(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:68)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:17)(cid:3)(cid:36)(cid:79)(cid:79)(cid:3)(cid:73)(cid:82)(cid:85)(cid:90)(cid:68)(cid:85)(cid:71)(cid:16)(cid:79)(cid:82)(cid:82)(cid:78)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:84)(cid:88)(cid:68)(cid:79)(cid:76)(cid:403)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:76)(cid:85)(cid:3)(cid:72)(cid:81)(cid:87)(cid:76)(cid:85)(cid:72)(cid:87)(cid:92)(cid:3)(cid:69)(cid:92)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:70)(cid:68)(cid:88)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:85)(cid:92)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:17)

Gaining Strength. Growing Stronger Together.

OIL PRODUCTION 
(cid:11)(cid:37)(cid:69)(cid:79)(cid:18)(cid:71)(cid:12)

NATURAL GAS PRODUCTION  
(cid:11)(cid:48)(cid:48)(cid:70)(cid:73)(cid:18)(cid:71)(cid:12)

OIL EQUIVALENT PRODUCTION  
(cid:11)(cid:48)(cid:37)(cid:50)(cid:40)(cid:18)(cid:71)(cid:12)

70,000

60,000

50,000

40,000

30,000

20,000

10,000

0

300

250

200

150

100

50

0

120

100

80

60

40

20

0

2018

2019

2020

2021

2022

2018

2019

2020

2021

2022

2018

2019

2020

2021

2022

(cid:48)(cid:36)(cid:55)(cid:36)(cid:39)(cid:50)(cid:53)(cid:3)(cid:53)(cid:40)(cid:54)(cid:50)(cid:56)(cid:53)(cid:38)(cid:40)(cid:54)(cid:3)(cid:38)(cid:50)(cid:48)(cid:51)(cid:36)(cid:49)(cid:60)(cid:3)(cid:3)(cid:3)(cid:95)(cid:3)(cid:3)(cid:3)(cid:24)(cid:23)(cid:19)(cid:19)(cid:3)(cid:47)(cid:37)(cid:45)(cid:3)(cid:41)(cid:85)(cid:72)(cid:72)(cid:90)(cid:68)(cid:92)(cid:15)(cid:3)(cid:54)(cid:88)(cid:76)(cid:87)(cid:72)(cid:3)(cid:20)(cid:24)(cid:19)(cid:19)(cid:3)(cid:3)(cid:3)(cid:95)(cid:3)(cid:3)(cid:3)(cid:39)(cid:68)(cid:79)(cid:79)(cid:68)(cid:86)(cid:15)(cid:3)(cid:55)(cid:72)(cid:91)(cid:68)(cid:86)(cid:3)(cid:26)(cid:24)(cid:21)(cid:23)(cid:19)(cid:3)(cid:3)(cid:3)(cid:95)(cid:3)(cid:3)(cid:3)(cid:11)(cid:28)(cid:26)(cid:21)(cid:12)(cid:3)(cid:22)(cid:26)(cid:20)(cid:16)(cid:24)(cid:21)(cid:19)(cid:19)(cid:3)(cid:3)(cid:3)(cid:95)(cid:3)(cid:3)(cid:3)(cid:90)(cid:90)(cid:90)(cid:17)(cid:80)(cid:68)(cid:87)(cid:68)(cid:71)(cid:82)(cid:85)(cid:85)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:17)(cid:70)(cid:82)(cid:80)