NEW HEIGHTS
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2021
ANNUAL
REPORT
MATADOR RESOURCES COMPANY
Matador 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. Its 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. Matador also
operates in the Eagle Ford shale play in South Texas and
the Haynesville shale and Cotton Valley plays in Northwest
Louisiana. Additionally, Matador conducts midstream
operations, primarily through its midstream joint venture,
San Mateo, in support of its exploration, development
and production operations and provides natural gas
processing, oil transportation services, natural gas, oil and
produced water gathering services and produced water
disposal services to third parties.
FINANCIAL & OPERATING HIGHLIGHTS
($ in millions, unless otherwise noted)
2019
2020
2021
Balance Sheet Data
Cash
Net Property and Equipment
Total Assets
Current Liabilities
Long-Term Liabilities
Total Shareholders’ Equity
Net Production Volumes (Annual)
Oil (MBbl)
Natural Gas (Bcf)
Total Oil Equivalent (MBOE)(1)(2)
% Oil in Production Volumes(2)
Average Daily Production (BOE/d)(2)
Reserves Information
Total Proved Reserves (MMBOE)(2)(3)
% Developed Reserves(2)
Standardized Measure
PV-10(4)
Operating Data
Oil and Natural Gas Revenues
% Oil in Revenues
Net Income (Loss)(5)
Adjusted EBITDA(7)
Realized Pricing
Oil, with Realized Derivatives (per Bbl)
Natural Gas, with Realized Derivatives (per Mcf)
$
40.0
$ 3,699.6
$ 4,069.7
$
399.8
$ 1,700.5
$ 1,969.5
13,984
61.1
24,164
58%
66,203
252.5
40%
$ 2,034.0
$ 2,248.2
$
$
$
$
$
892.3
85%
87.8
610.8
54.98
2.18
$
57.9
$ 3,367.8
$ 3,687.3
$
290.9
$ 1,883.3
$ 1,513.0
15,931
69.5
27,514
58%
75,175
270.3
46%
$ 1,584.4
$ 1,658.0
$
744.5
80%
(593.2)(6)
519.3
39.83
2.14
$
$
$
$
$
48.1
$ 3,856.7
$ 4,262.2
$
464.8
$ 1,669.9
$ 2,127.4
17,840
81.7
31,454
57%
86,176
323.4
60%
$ 4,375.4
$ 5,347.6
$ 1,700.5
71%
$
585.0
$ 1,052.0
$
$
56.70
5.74
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(cid:53)(cid:86)(cid:85)(cid:20)(cid:46)(cid:40)(cid:40)(cid:55)(cid:3)(cid:45)(cid:80)(cid:85)(cid:72)(cid:85)(cid:74)(cid:80)(cid:72)(cid:83)(cid:3)(cid:52)(cid:76)(cid:72)(cid:90)(cid:92)(cid:89)(cid:76)(cid:90)(cid:185)(cid:3)(cid:80)(cid:85)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:40)(cid:85)(cid:85)(cid:92)(cid:72)(cid:83)(cid:3)(cid:57)(cid:76)(cid:87)(cid:86)(cid:89)(cid:91)(cid:3)(cid:86)(cid:85)(cid:3)(cid:45)(cid:86)(cid:89)(cid:84)(cid:3)(cid:24)(cid:23)(cid:20)(cid:50)(cid:3)(cid:76)(cid:85)(cid:74)(cid:83)(cid:86)(cid:90)(cid:76)(cid:75)(cid:3)(cid:79)(cid:76)(cid:89)(cid:76)(cid:80)(cid:85)(cid:21)
AREAS OF OPERATION
MATADOR RESOURCES
COMPANY TOTALS
Production: 87,300 BOE/d(1)
Proved Reserves: 323.4 MMBOE(2)
Acreage: 283,700 gross / 167,600 net(2)
Locations: 4,904 gross / 1,759 net(2)
SOUTHEAST NEW MEXICO
& WEST TEXAS
Production: 82,400 BOE/d(1)
Proved Reserves: 312.0(2) MMBOE(2)
Acreage: 237,200 gross / 124,800 net(2)
Locations: 4,381 gross / 1,534 net(2)
SOUTH TEXAS
Production: 1,900 BOE/d(1)
Proved Reserves: 5.7 MMBOE(2)
Acreage: 27,400 gross / 25,100 net(2)
Locations: 208 gross / 175 net(2)
NORTHWEST LOUISIANA
Production: 3,000 BOE/d(1)
Proved Reserves: 5.7 MMBOE(2)
Acreage: 19,100 gross / 17,700 net(2)
Locations: 315 gross / 50 net(2)
(1) For the three months ended December 31, 2021.
(2) At December 31, 2021.
(3) Source: Enverus.
CHAVES
TWIN LAKES
~42,900 gross/
~20,500 net acres
ARROWHEAD
ARROWHEAD
~64,500 gross/
~64,500 gross/
~26,000 net acres
~26,800 net acres
RANGER
RANGER
~39,700 gross/
~39,700 gross/
~22,600 net acres
~22,600 net acres
RUSTLER BREAKS
RUSTLER BREAKS
~47,500 gross/
~47,500 gross/
~47,500 gross/
~25,900 net acres
~25,900 net acres
~25,900 net acres
ANTELOPE
RIDGE
~24,700 gross/
~15,700 net acres
NEW MEXICO
TEX AS
Matador
Acreage
Note: All acreage
as of December 31,
2021. Some tracts
not shown on map
Y
D
D
E
A
E
L
STATELINE
~2,900 gross/
~2,900 net acres
WOLF/JACKSON
TRUST (LOVING)
~14,400 gross/
~10,700 net acres
LOVING
In 2021, Matador was the #7 oil producer and
the #11 natural gas producer in New Mexico.(3)
AVERAGE DAILY TOTAL DELAWARE BASIN PRODUCTION BOE/d
Q4 2021 BOE; up 7% YoY
0
0
5
,
6
4
0
0
8
,
7
4
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
4
7
7
,
0
0
0
,
8
6
0
0
0
,
6
6
0
0
4
,
6
6
Oil
Natural Gas
0
0
9
,
4
3
0
0
2
,
7
3
90,000
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
0
0
5
7
8
,
0
0
0
,
4
8
0
0
4
,
2
8
4Q17
1Q18
2Q18
3Q18
4Q18
1Q19
2Q19
3Q19
4Q19
1Q20
2Q20
3Q20
4Q20 1Q21
2Q21
3Q21
4Q21
DEAR SHAREHOLDERS & FRIENDS
Earlier this year, we celebrated Matador’s
10-year anniversary as a public company—
and what a decade it has been! Those
who bought Matador stock at the time of
our initial public offering have enjoyed a
return of approximately 5-to-1 on their
investment, almost twice as much as the
approximately 3-to-1 return of the Russell
(cid:211)(cid:228)(cid:228)(cid:228)(cid:3)(cid:136)(cid:152)(cid:96)(cid:105)(cid:221)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:62)(cid:143)(cid:147)(cid:156)(cid:195)(cid:204)(cid:3)(cid:119)(cid:219)(cid:105)(cid:3)(cid:204)(cid:136)(cid:147)(cid:105)(cid:195)(cid:3)(cid:62)(cid:195)(cid:3)(cid:147)(cid:213)(cid:86)(cid:133)(cid:3)
as the approximately 0.3-to-1 loss of the
XOP index, an electronically traded fund
that serves as a proxy for the average
share price performance of the various oil
and natural gas exploration and production companies across the
industry, during the same period.(1)
We are extremely proud of delivering this return to shareholders
while also maintaining a strong balance sheet, with a leverage
ratio of 1.1x at the close of 2021.(2) At Matador, we often say that
(cid:156)(cid:213)(cid:192)(cid:3)(cid:118)(cid:156)(cid:86)(cid:213)(cid:195)(cid:3)(cid:136)(cid:195)(cid:3)(cid:186)(cid:171)(cid:192)(cid:156)(cid:119)(cid:204)(cid:62)(cid:76)(cid:143)(cid:105)(cid:3)(cid:125)(cid:192)(cid:156)(cid:220)(cid:204)(cid:133)(cid:3)(cid:62)(cid:204)(cid:3)(cid:62)(cid:3)(cid:147)(cid:105)(cid:62)(cid:195)(cid:213)(cid:192)(cid:105)(cid:96)(cid:3)(cid:171)(cid:62)(cid:86)(cid:105)(cid:187)(cid:112)(cid:220)(cid:133)(cid:136)(cid:86)(cid:133)(cid:93)(cid:3)(cid:156)(cid:219)(cid:105)(cid:192)(cid:3)
the last decade, has resulted in compounded annual growth rates
of 28% for production, 36% for Adjusted EBITDA and 26% for oil
and natural gas reserves. This represents a 13-fold increase in
production, a 21-fold increase in Adjusted EBITDA and a 9-fold
increase in oil and natural gas reserves!
(cid:386)(cid:195)(cid:3)(cid:22)(cid:3)(cid:192)(cid:105)(cid:121)(cid:105)(cid:86)(cid:204)(cid:3)(cid:156)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:152)(cid:105)(cid:220)(cid:3)(cid:133)(cid:105)(cid:136)(cid:125)(cid:133)(cid:204)(cid:195)(cid:3)(cid:204)(cid:133)(cid:62)(cid:204)(cid:3)(cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:3)(cid:133)(cid:62)(cid:195)(cid:3)(cid:192)(cid:105)(cid:62)(cid:86)(cid:133)(cid:105)(cid:96)(cid:3)
across many dimensions—including share price, balance sheet,
(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:93)(cid:3)(cid:386)(cid:96)(cid:141)(cid:213)(cid:195)(cid:204)(cid:105)(cid:96)(cid:3)(cid:13)(cid:9)(cid:22)(cid:47)(cid:12)(cid:386)(cid:93)(cid:3)(cid:118)(cid:192)(cid:105)(cid:105)(cid:3)(cid:86)(cid:62)(cid:195)(cid:133)(cid:3)(cid:121)(cid:156)(cid:220)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:192)(cid:105)(cid:195)(cid:105)(cid:192)(cid:219)(cid:105)(cid:195)(cid:112)(cid:22)(cid:3)
would like to commend the Board and all the staff for their hard
work and extra effort over the last decade and for 2021’s record
results described in this Annual Report. We are excited by these
achievements—and even more excited about what possibilities
are still ahead of us! The Matador team and the Matador Board are
(cid:118)(cid:156)(cid:86)(cid:213)(cid:195)(cid:105)(cid:96)(cid:3)(cid:156)(cid:152)(cid:3)(cid:119)(cid:152)(cid:96)(cid:136)(cid:152)(cid:125)(cid:3)(cid:62)(cid:192)(cid:105)(cid:62)(cid:195)(cid:3)(cid:220)(cid:136)(cid:204)(cid:133)(cid:3)(cid:125)(cid:192)(cid:105)(cid:62)(cid:204)(cid:3)(cid:192)(cid:156)(cid:86)(cid:142)(cid:93)(cid:3)(cid:76)(cid:213)(cid:136)(cid:143)(cid:96)(cid:136)(cid:152)(cid:125)(cid:3)(cid:125)(cid:192)(cid:105)(cid:62)(cid:204)(cid:3)(cid:204)(cid:105)(cid:62)(cid:147)(cid:195)(cid:3)(cid:204)(cid:156)(cid:3)
develop those rocks and continuous improvement in our process for
planning and decision making.
RECORD RESULTS – NEW HEIGHTS
As mentioned, 2021 was a tremendous year for Matador which
included many record results in both our exploration and
production and midstream businesses. During the year, Matador
reported record production of 86,200 barrels of oil equivalent
(cid:173)(cid:186)(cid:9)(cid:34)(cid:13)(cid:187)(cid:174)(cid:3)(cid:171)(cid:105)(cid:192)(cid:3)(cid:96)(cid:62)(cid:222)(cid:93)(cid:3)(cid:62)(cid:152)(cid:3)(cid:136)(cid:152)(cid:86)(cid:192)(cid:105)(cid:62)(cid:195)(cid:105)(cid:3)(cid:156)(cid:118)(cid:3)(cid:163)(cid:120)(cid:175)(cid:3)(cid:222)(cid:105)(cid:62)(cid:192)(cid:135)(cid:156)(cid:219)(cid:105)(cid:192)(cid:135)(cid:222)(cid:105)(cid:62)(cid:192)(cid:93)(cid:3)(cid:86)(cid:156)(cid:147)(cid:171)(cid:62)(cid:192)(cid:105)(cid:96)(cid:3)(cid:204)(cid:156)(cid:3)
75,200 BOE per day in 2020. Matador’s oil and natural gas revenues
increased 128% year-over-year to approximately $1.70 billion, also
an all-time high for Matador. We reported record net income of
$585 million during 2021, a year-over-year increase from a net loss
of $593 million in 2020. Finally, Matador achieved record Adjusted
EBITDA of $1.05 billion, a year-over-year increase of 103% from
$519 million in 2020.
San Mateo Midstream, LLC, our midstream joint venture business,
also had a record year in 2021, including having all-time high
throughput volumes for natural gas gathering and processing,
oil gathering and transportation and water handling. San Mateo
also achieved record net income of $114 million, a year-over-year
increase of 40% from net income of $81 million in 2020, record
Adjusted EBITDA of $154 million, a year-over-year increase of
37% from $113 million in 2020, and successfully closed seven new
midstream transactions with oil and natural gas producers and
other counterparties in the Delaware Basin during 2021.
FREE CASH FLOW AND INITIATED DIVIDEND
In addition to these record results, both Matador and San Mateo
(cid:220)(cid:105)(cid:192)(cid:105)(cid:3)(cid:171)(cid:62)(cid:192)(cid:204)(cid:136)(cid:86)(cid:213)(cid:143)(cid:62)(cid:192)(cid:143)(cid:222)(cid:3)(cid:171)(cid:143)(cid:105)(cid:62)(cid:195)(cid:105)(cid:96)(cid:3)(cid:204)(cid:156)(cid:3)(cid:125)(cid:105)(cid:152)(cid:105)(cid:192)(cid:62)(cid:204)(cid:105)(cid:3)(cid:118)(cid:192)(cid:105)(cid:105)(cid:3)(cid:86)(cid:62)(cid:195)(cid:133)(cid:3)(cid:121)(cid:156)(cid:220)(cid:3)(cid:96)(cid:213)(cid:192)(cid:136)(cid:152)(cid:125)(cid:3)all
(cid:118)(cid:156)(cid:213)(cid:192)(cid:3)(cid:181)(cid:213)(cid:62)(cid:192)(cid:204)(cid:105)(cid:192)(cid:195)(cid:3)(cid:156)(cid:118)(cid:3)(cid:211)(cid:228)(cid:211)(cid:163)(cid:176)(cid:3)(cid:55)(cid:105)(cid:3)(cid:136)(cid:152)(cid:136)(cid:204)(cid:136)(cid:62)(cid:204)(cid:105)(cid:96)(cid:3)(cid:62)(cid:3)(cid:96)(cid:136)(cid:219)(cid:136)(cid:96)(cid:105)(cid:152)(cid:96)(cid:3)(cid:136)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:119)(cid:192)(cid:195)(cid:204)(cid:3)(cid:181)(cid:213)(cid:62)(cid:192)(cid:204)(cid:105)(cid:192)(cid:3)
of 2021 to begin returning cash to shareholders and then doubled
our dividend in the fourth quarter, further evidencing our growing
(cid:119)(cid:152)(cid:62)(cid:152)(cid:86)(cid:136)(cid:62)(cid:143)(cid:3)(cid:195)(cid:204)(cid:192)(cid:105)(cid:152)(cid:125)(cid:204)(cid:133)(cid:176)(cid:3)(cid:32)(cid:156)(cid:204)(cid:62)(cid:76)(cid:143)(cid:222)(cid:93)(cid:3)(cid:220)(cid:105)(cid:3)(cid:220)(cid:105)(cid:192)(cid:105)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:119)(cid:192)(cid:195)(cid:204)(cid:3)(cid:186)(cid:147)(cid:136)(cid:96)(cid:135)(cid:195)(cid:136)(cid:226)(cid:105)(cid:96)(cid:187)(cid:3)(cid:213)(cid:171)(cid:195)(cid:204)(cid:192)(cid:105)(cid:62)(cid:147)(cid:3)
oil and natural gas company to initiate a dividend.
Matador also aggressively paid down debt in 2021 and ended the
year with a leverage ratio of 1.1x, the lowest we have achieved since
mid-2014. As a result, Matador ended 2021 with $100 million in
borrowings outstanding under its reserves-based revolving credit
(cid:118)(cid:62)(cid:86)(cid:136)(cid:143)(cid:136)(cid:204)(cid:222)(cid:93)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:220)(cid:105)(cid:3)(cid:192)(cid:105)(cid:171)(cid:62)(cid:136)(cid:96)(cid:3)(cid:62)(cid:152)(cid:156)(cid:204)(cid:133)(cid:105)(cid:192)(cid:3)(cid:102)(cid:120)(cid:228)(cid:3)(cid:147)(cid:136)(cid:143)(cid:143)(cid:136)(cid:156)(cid:152)(cid:3)(cid:136)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:119)(cid:192)(cid:195)(cid:204)(cid:3)(cid:181)(cid:213)(cid:62)(cid:192)(cid:204)(cid:105)(cid:192)(cid:3)(cid:156)(cid:118)(cid:3)
2022 to further reduce our leverage ratio to less than 1.0x. This
latest repayment reduced the borrowings outstanding under the
reserves-based credit facility to $50 million, for a total reduction of
$425 million from the $475 million in borrowings outstanding at the
end of the third quarter of 2020.
Matador expects to generate more than $1 billion of adjusted
(cid:118)(cid:192)(cid:105)(cid:105)(cid:3)(cid:86)(cid:62)(cid:195)(cid:133)(cid:3)(cid:121)(cid:156)(cid:220)(cid:3)(cid:136)(cid:152)(cid:3)(cid:62)(cid:125)(cid:125)(cid:192)(cid:105)(cid:125)(cid:62)(cid:204)(cid:105)(cid:3)(cid:118)(cid:156)(cid:192)(cid:3)(cid:118)(cid:213)(cid:143)(cid:143)(cid:3)(cid:222)(cid:105)(cid:62)(cid:192)(cid:3)(cid:211)(cid:228)(cid:211)(cid:211)(cid:3)(cid:62)(cid:204)(cid:3)(cid:102)(cid:153)(cid:228)(cid:3)(cid:173)(cid:55)(cid:47)(cid:22)(cid:174)(cid:3)(cid:156)(cid:136)(cid:143)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)
$4.50 (Henry Hub) natural gas. This would provide the Board and
Matador’s management team with a variety of opportunities and
(cid:156)(cid:171)(cid:204)(cid:136)(cid:156)(cid:152)(cid:195)(cid:3)(cid:118)(cid:156)(cid:192)(cid:3)(cid:133)(cid:156)(cid:220)(cid:3)(cid:76)(cid:105)(cid:195)(cid:204)(cid:3)(cid:204)(cid:156)(cid:3)(cid:213)(cid:195)(cid:105)(cid:3)(cid:204)(cid:133)(cid:136)(cid:195)(cid:3)(cid:118)(cid:192)(cid:105)(cid:105)(cid:3)(cid:86)(cid:62)(cid:195)(cid:133)(cid:3)(cid:121)(cid:156)(cid:220)(cid:3)(cid:204)(cid:156)(cid:3)(cid:86)(cid:156)(cid:152)(cid:204)(cid:136)(cid:152)(cid:213)(cid:105)(cid:3)(cid:76)(cid:213)(cid:136)(cid:143)(cid:96)(cid:136)(cid:152)(cid:125)(cid:3)
value for Matador and its stakeholders and return cash to its
(cid:195)(cid:133)(cid:62)(cid:192)(cid:105)(cid:133)(cid:156)(cid:143)(cid:96)(cid:105)(cid:192)(cid:195)(cid:176)(cid:3)(cid:45)(cid:156)(cid:147)(cid:105)(cid:3)(cid:105)(cid:221)(cid:62)(cid:147)(cid:171)(cid:143)(cid:105)(cid:195)(cid:3)(cid:62)(cid:192)(cid:105)(cid:3)(cid:204)(cid:156)(cid:3)(cid:147)(cid:62)(cid:136)(cid:152)(cid:204)(cid:62)(cid:136)(cid:152)(cid:3)(cid:156)(cid:192)(cid:3)(cid:136)(cid:152)(cid:86)(cid:192)(cid:105)(cid:62)(cid:195)(cid:105)(cid:3)(cid:156)(cid:213)(cid:192)(cid:3)(cid:119)(cid:221)(cid:105)(cid:96)(cid:3)
quarterly dividend, continue paying down debt and look for ways to
enhance our acreage portfolio via accretive acreage leasing, trades
and acquisition opportunities in addition to our normal exploration,
development and operational activities.
ACCOMPLISHED ALL 2021 MILESTONES
(cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:3)(cid:152)(cid:156)(cid:204)(cid:62)(cid:76)(cid:143)(cid:222)(cid:3)(cid:119)(cid:152)(cid:136)(cid:195)(cid:133)(cid:105)(cid:96)(cid:3)(cid:211)(cid:228)(cid:211)(cid:163)(cid:3)(cid:195)(cid:204)(cid:192)(cid:156)(cid:152)(cid:125)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:105)(cid:152)(cid:204)(cid:105)(cid:192)(cid:105)(cid:96)(cid:3)(cid:211)(cid:228)(cid:211)(cid:211)(cid:3)(cid:136)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)
(cid:76)(cid:105)(cid:195)(cid:204)(cid:3)(cid:119)(cid:152)(cid:62)(cid:152)(cid:86)(cid:136)(cid:62)(cid:143)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:156)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:62)(cid:143)(cid:3)(cid:195)(cid:133)(cid:62)(cid:171)(cid:105)(cid:3)(cid:220)(cid:105)(cid:3)(cid:133)(cid:62)(cid:219)(cid:105)(cid:3)(cid:105)(cid:219)(cid:105)(cid:192)(cid:3)(cid:76)(cid:105)(cid:105)(cid:152)(cid:93)(cid:3)(cid:133)(cid:62)(cid:219)(cid:136)(cid:152)(cid:125)(cid:3)
accomplished all our primary goals for 2021—to reduce debt, to
increase shareholder returns, to reduce drilling and completion
(cid:86)(cid:156)(cid:195)(cid:204)(cid:195)(cid:3)(cid:171)(cid:105)(cid:192)(cid:3)(cid:143)(cid:62)(cid:204)(cid:105)(cid:192)(cid:62)(cid:143)(cid:3)(cid:118)(cid:156)(cid:156)(cid:204)(cid:93)(cid:3)(cid:204)(cid:156)(cid:3)(cid:136)(cid:152)(cid:86)(cid:192)(cid:105)(cid:62)(cid:195)(cid:105)(cid:3)(cid:86)(cid:62)(cid:171)(cid:136)(cid:204)(cid:62)(cid:143)(cid:3)(cid:105)(cid:118)(cid:119)(cid:86)(cid:136)(cid:105)(cid:152)(cid:86)(cid:222)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:204)(cid:156)(cid:3)(cid:62)(cid:86)(cid:133)(cid:136)(cid:105)(cid:219)(cid:105)(cid:3)
record operational results for both Matador and San Mateo. The
Board and I would like to once again acknowledge and express our
sincere appreciation to all Matador and San Mateo employees and
contractors for their continued strong execution and teamwork,
which made these record results a reality once again
DRILLING RESULTS
(cid:34)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:62)(cid:143)(cid:143)(cid:222)(cid:93)(cid:3)(cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:3)(cid:62)(cid:86)(cid:86)(cid:156)(cid:147)(cid:171)(cid:143)(cid:136)(cid:195)(cid:133)(cid:105)(cid:96)(cid:3)(cid:62)(cid:143)(cid:143)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:195)(cid:136)(cid:125)(cid:152)(cid:136)(cid:119)(cid:86)(cid:62)(cid:152)(cid:204)(cid:3)(cid:147)(cid:136)(cid:143)(cid:105)(cid:195)(cid:204)(cid:156)(cid:152)(cid:105)(cid:195)(cid:3)
(cid:220)(cid:105)(cid:3)(cid:195)(cid:105)(cid:204)(cid:3)(cid:156)(cid:213)(cid:204)(cid:3)(cid:204)(cid:156)(cid:3)(cid:62)(cid:86)(cid:133)(cid:136)(cid:105)(cid:219)(cid:105)(cid:3)(cid:136)(cid:152)(cid:3)(cid:211)(cid:228)(cid:211)(cid:163)(cid:3)(cid:62)(cid:195)(cid:3)(cid:195)(cid:213)(cid:147)(cid:147)(cid:62)(cid:192)(cid:136)(cid:226)(cid:105)(cid:96)(cid:3)(cid:76)(cid:105)(cid:143)(cid:156)(cid:220)(cid:176)(cid:3)
• Matador turned to sales four Rodney Robinson wells in the
western portion of our Antelope Ridge asset area in March 2021.
These four wells have produced in aggregate approximately
1.6 million BOE in approximately one year of production.
• (cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:3)(cid:204)(cid:213)(cid:192)(cid:152)(cid:105)(cid:96)(cid:3)(cid:204)(cid:156)(cid:3)(cid:195)(cid:62)(cid:143)(cid:105)(cid:195)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:119)(cid:192)(cid:195)(cid:204)(cid:3)(cid:163)(cid:206)(cid:3)(cid:54)(cid:156)(cid:152)(cid:136)(cid:3)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:3)(cid:136)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:45)(cid:204)(cid:62)(cid:204)(cid:105)(cid:143)(cid:136)(cid:152)(cid:105)(cid:3)
asset area in late April and early May 2021. These 13 wells have
produced in aggregate approximately 5.8 million BOE in just
over ten months of production.
• Matador turned to sales four Greater Stebbins Area wells
in July 2021. These four wells have produced in aggregate
approximately 0.7 million BOE in approximately seven months
of production.
• Matador turned to sales the next 13 Boros wells in the Stateline
asset area in August and September 2021—originally planned
(1) Calculated using the closing prices of MTDR, RUT and XOP between February 2, 2012 and April 1, 2022.
(cid:15)(cid:25)(cid:16)(cid:3)(cid:43)(cid:76)(cid:196)(cid:85)(cid:76)(cid:75)(cid:3)(cid:72)(cid:90)(cid:3)(cid:53)(cid:76)(cid:91)(cid:3)(cid:43)(cid:76)(cid:73)(cid:91)(cid:3)(cid:22)(cid:3)(cid:51)(cid:59)(cid:52)(cid:3)(cid:40)(cid:75)(cid:81)(cid:92)(cid:90)(cid:91)(cid:76)(cid:75)(cid:3)(cid:44)(cid:41)(cid:48)(cid:59)(cid:43)(cid:40)(cid:3)(cid:72)(cid:90)(cid:3)(cid:74)(cid:72)(cid:83)(cid:74)(cid:92)(cid:83)(cid:72)(cid:91)(cid:76)(cid:75)(cid:3)(cid:92)(cid:85)(cid:75)(cid:76)(cid:89)(cid:3)(cid:52)(cid:72)(cid:91)(cid:72)(cid:75)(cid:86)(cid:89)(cid:187)(cid:90)(cid:3)(cid:89)(cid:76)(cid:93)(cid:86)(cid:83)(cid:93)(cid:80)(cid:85)(cid:78)(cid:3)(cid:74)(cid:89)(cid:76)(cid:75)(cid:80)(cid:91)(cid:3)(cid:77)(cid:72)(cid:74)(cid:80)(cid:83)(cid:80)(cid:91)(cid:96)(cid:21)
for October 2021. These 13 wells have produced in aggregate
approximately 2.7 million BOE in just over six months
of production.
• Matador turned to sales the remaining nine Greater Stebbins
Area wells in December 2021, all of which were two mile laterals.
2022 OUTLOOK
We believe the outlook for 2022 is very bright as Matador continues
(cid:204)(cid:156)(cid:3)(cid:62)(cid:86)(cid:133)(cid:136)(cid:105)(cid:219)(cid:105)(cid:3)(cid:186)(cid:152)(cid:105)(cid:220)(cid:3)(cid:133)(cid:105)(cid:136)(cid:125)(cid:133)(cid:204)(cid:195)(cid:187)(cid:3)(cid:136)(cid:152)(cid:3)(cid:156)(cid:213)(cid:192)(cid:3)(cid:156)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:62)(cid:143)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:119)(cid:152)(cid:62)(cid:152)(cid:86)(cid:136)(cid:62)(cid:143)(cid:3)(cid:105)(cid:118)(cid:118)(cid:156)(cid:192)(cid:204)(cid:195)(cid:176)(cid:3)
We think this year will be particularly exciting as we work to
continue developing our excellent Delaware Basin assets, deliver
(cid:195)(cid:136)(cid:125)(cid:152)(cid:136)(cid:119)(cid:86)(cid:62)(cid:152)(cid:204)(cid:3)(cid:118)(cid:192)(cid:105)(cid:105)(cid:3)(cid:86)(cid:62)(cid:195)(cid:133)(cid:3)(cid:121)(cid:156)(cid:220)(cid:93)(cid:3)(cid:86)(cid:156)(cid:152)(cid:204)(cid:136)(cid:152)(cid:213)(cid:105)(cid:3)(cid:204)(cid:156)(cid:3)(cid:171)(cid:62)(cid:222)(cid:3)(cid:96)(cid:156)(cid:220)(cid:152)(cid:3)(cid:96)(cid:105)(cid:76)(cid:204)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:147)(cid:62)(cid:136)(cid:152)(cid:204)(cid:62)(cid:136)(cid:152)(cid:3)
or increase our quarterly dividend. Matador’s 2022 drilling program
is expected to be more balanced across our portfolio than in 2021,
drilling wells in each of our Delaware Basin asset areas, which we
believe—and the production records show—that these wells are
located in some of the best areas of the basin. We anticipate 2022
to successfully deliver year-over-year production growth but not
(cid:186)(cid:125)(cid:192)(cid:156)(cid:220)(cid:204)(cid:133)(cid:3)(cid:118)(cid:156)(cid:192)(cid:3)(cid:125)(cid:192)(cid:156)(cid:220)(cid:204)(cid:133)(cid:189)(cid:195)(cid:3)(cid:195)(cid:62)(cid:142)(cid:105)(cid:176)(cid:187)(cid:3)(cid:34)(cid:213)(cid:192)(cid:3)(cid:171)(cid:133)(cid:136)(cid:143)(cid:156)(cid:195)(cid:156)(cid:171)(cid:133)(cid:222)(cid:3)(cid:86)(cid:156)(cid:152)(cid:204)(cid:136)(cid:152)(cid:213)(cid:105)(cid:195)(cid:3)(cid:204)(cid:156)(cid:3)(cid:76)(cid:105)(cid:3)(cid:204)(cid:156)(cid:3)
(cid:125)(cid:105)(cid:152)(cid:105)(cid:192)(cid:62)(cid:204)(cid:105)(cid:3)(cid:171)(cid:192)(cid:156)(cid:119)(cid:204)(cid:62)(cid:76)(cid:143)(cid:105)(cid:3)(cid:125)(cid:192)(cid:156)(cid:220)(cid:204)(cid:133)(cid:3)(cid:62)(cid:204)(cid:3)(cid:62)(cid:3)(cid:147)(cid:105)(cid:62)(cid:195)(cid:213)(cid:192)(cid:105)(cid:96)(cid:3)(cid:171)(cid:62)(cid:86)(cid:105)(cid:176)(cid:3)(cid:55)(cid:105)(cid:3)(cid:76)(cid:105)(cid:125)(cid:62)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)
(cid:222)(cid:105)(cid:62)(cid:192)(cid:3)(cid:156)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:136)(cid:152)(cid:125)(cid:3)(cid:119)(cid:219)(cid:105)(cid:3)(cid:192)(cid:136)(cid:125)(cid:195)(cid:3)(cid:136)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:12)(cid:105)(cid:143)(cid:62)(cid:220)(cid:62)(cid:192)(cid:105)(cid:3)(cid:9)(cid:62)(cid:195)(cid:136)(cid:152)(cid:3)(cid:76)(cid:213)(cid:204)(cid:3)(cid:136)(cid:152)(cid:3)(cid:31)(cid:62)(cid:192)(cid:86)(cid:133)(cid:3)(cid:62)(cid:96)(cid:96)(cid:105)(cid:96)(cid:3)
a sixth operated rig to our drilling program to begin development
immediately on accretive acreage recently acquired in western Lea
(cid:10)(cid:156)(cid:213)(cid:152)(cid:204)(cid:222)(cid:93)(cid:3)(cid:32)(cid:105)(cid:220)(cid:3)(cid:31)(cid:105)(cid:221)(cid:136)(cid:86)(cid:156)(cid:176)
All in all, we anticipate achieving a number of key milestones in
(cid:211)(cid:228)(cid:211)(cid:211)(cid:93)(cid:3)(cid:62)(cid:195)(cid:3)(cid:220)(cid:105)(cid:3)(cid:96)(cid:136)(cid:96)(cid:3)(cid:136)(cid:152)(cid:3)(cid:211)(cid:228)(cid:211)(cid:163)(cid:93)(cid:3)(cid:204)(cid:133)(cid:62)(cid:204)(cid:3)(cid:62)(cid:192)(cid:105)(cid:3)(cid:105)(cid:221)(cid:171)(cid:105)(cid:86)(cid:204)(cid:105)(cid:96)(cid:3)(cid:204)(cid:156)(cid:3)(cid:62)(cid:96)(cid:96)(cid:3)(cid:195)(cid:136)(cid:125)(cid:152)(cid:136)(cid:119)(cid:86)(cid:62)(cid:152)(cid:204)(cid:3)(cid:219)(cid:62)(cid:143)(cid:213)(cid:105)(cid:3)
to Matador and San Mateo and position Matador for continued
(cid:125)(cid:192)(cid:156)(cid:220)(cid:204)(cid:133)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:118)(cid:192)(cid:105)(cid:105)(cid:3)(cid:86)(cid:62)(cid:195)(cid:133)(cid:3)(cid:121)(cid:156)(cid:220)(cid:3)(cid:136)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:86)(cid:156)(cid:147)(cid:136)(cid:152)(cid:125)(cid:3)(cid:222)(cid:105)(cid:62)(cid:192)(cid:195)(cid:176)
• (cid:55)(cid:105)(cid:3)(cid:133)(cid:62)(cid:219)(cid:105)(cid:3)(cid:62)(cid:143)(cid:192)(cid:105)(cid:62)(cid:96)(cid:222)(cid:3)(cid:86)(cid:156)(cid:147)(cid:171)(cid:143)(cid:105)(cid:204)(cid:105)(cid:96)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:119)(cid:192)(cid:195)(cid:204)(cid:3)(cid:156)(cid:118)(cid:3)(cid:204)(cid:133)(cid:105)(cid:195)(cid:105)(cid:3)(cid:147)(cid:136)(cid:143)(cid:105)(cid:195)(cid:204)(cid:156)(cid:152)(cid:105)(cid:195)(cid:3)(cid:136)(cid:152)(cid:3)
February 2022 as production was turned to sales from the 11
(cid:152)(cid:105)(cid:220)(cid:3)(cid:54)(cid:156)(cid:152)(cid:136)(cid:3)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:93)(cid:3)(cid:62)(cid:143)(cid:143)(cid:3)(cid:156)(cid:118)(cid:3)(cid:220)(cid:133)(cid:136)(cid:86)(cid:133)(cid:3)(cid:133)(cid:62)(cid:96)(cid:3)(cid:86)(cid:156)(cid:147)(cid:171)(cid:143)(cid:105)(cid:204)(cid:105)(cid:96)(cid:3)(cid:143)(cid:62)(cid:204)(cid:105)(cid:192)(cid:62)(cid:143)(cid:3)(cid:143)(cid:105)(cid:152)(cid:125)(cid:204)(cid:133)(cid:195)(cid:3)(cid:156)(cid:118)(cid:3)
approximately 12,000 feet, or about 2.3 miles, in our Stateline
asset area.
• We recently completed our second milestone in March 2022
as production from nine Rodney Robinson wells was turned to
sales in the western portion of our Antelope Ridge asset area.
• During the second quarter of 2022, we expect to turn to sales
production from 11 new wells in our Rustler Breaks asset area.
• During the latter portion of the third quarter of 2022, we plan
to turn to sales production from 16 wells in our Antelope Ridge
asset area outside of the Rodney Robinson leasehold.
• (cid:19)(cid:136)(cid:152)(cid:62)(cid:143)(cid:143)(cid:222)(cid:93)(cid:3)(cid:136)(cid:152)(cid:3)(cid:143)(cid:62)(cid:204)(cid:105)(cid:3)(cid:32)(cid:156)(cid:219)(cid:105)(cid:147)(cid:76)(cid:105)(cid:192)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:12)(cid:105)(cid:86)(cid:105)(cid:147)(cid:76)(cid:105)(cid:192)(cid:3)(cid:211)(cid:228)(cid:211)(cid:211)(cid:93)(cid:3)(cid:220)(cid:105)(cid:3)(cid:105)(cid:221)(cid:171)(cid:105)(cid:86)(cid:204)(cid:3)(cid:204)(cid:156)(cid:3)
turn to sales production from 11 wells in our Ranger asset area,
including seven wells drilled on the recently acquired acreage in
that asset area.
San Mateo is also poised for additional growth in 2022. San Mateo
has become a very strategic component of Matador’s overall
business strategy over the years and has become a leading provider
(cid:156)(cid:118)(cid:3)(cid:186)(cid:204)(cid:133)(cid:192)(cid:105)(cid:105)(cid:135)(cid:171)(cid:136)(cid:171)(cid:105)(cid:187)(cid:3)(cid:147)(cid:136)(cid:96)(cid:195)(cid:204)(cid:192)(cid:105)(cid:62)(cid:147)(cid:3)(cid:195)(cid:105)(cid:192)(cid:219)(cid:136)(cid:86)(cid:105)(cid:195)(cid:3)(cid:204)(cid:156)(cid:3)(cid:136)(cid:204)(cid:195)(cid:3)(cid:86)(cid:213)(cid:195)(cid:204)(cid:156)(cid:147)(cid:105)(cid:192)(cid:195)(cid:3)(cid:136)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:12)(cid:105)(cid:143)(cid:62)(cid:220)(cid:62)(cid:192)(cid:105)(cid:3)
(cid:9)(cid:62)(cid:195)(cid:136)(cid:152)(cid:176)(cid:3)(cid:45)(cid:62)(cid:152)(cid:3)(cid:31)(cid:62)(cid:204)(cid:105)(cid:156)(cid:3)(cid:62)(cid:143)(cid:195)(cid:156)(cid:3)(cid:105)(cid:221)(cid:171)(cid:105)(cid:86)(cid:204)(cid:195)(cid:3)(cid:204)(cid:156)(cid:3)(cid:125)(cid:105)(cid:152)(cid:105)(cid:192)(cid:62)(cid:204)(cid:105)(cid:3)(cid:118)(cid:192)(cid:105)(cid:105)(cid:3)(cid:86)(cid:62)(cid:195)(cid:133)(cid:3)(cid:121)(cid:156)(cid:220)(cid:3)(cid:62)(cid:125)(cid:62)(cid:136)(cid:152)(cid:3)(cid:136)(cid:152)(cid:3)
2022. As it did last year, the San Mateo team will be working hard
in 2022 to add new third-party customers and throughput volumes
to its midstream system and continue to improve Matador’s
environmental and safety outlook.
10 YEARS OF BUILDING SHAREHOLDER VALUE
(cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:3)(cid:147)(cid:62)(cid:192)(cid:142)(cid:105)(cid:96)(cid:3)(cid:62)(cid:3)(cid:195)(cid:136)(cid:125)(cid:152)(cid:136)(cid:119)(cid:86)(cid:62)(cid:152)(cid:204)(cid:3)(cid:147)(cid:136)(cid:143)(cid:105)(cid:195)(cid:204)(cid:156)(cid:152)(cid:105)(cid:3)(cid:156)(cid:152)(cid:3)(cid:19)(cid:105)(cid:76)(cid:192)(cid:213)(cid:62)(cid:192)(cid:222)(cid:3)(cid:211)(cid:93)(cid:3)(cid:211)(cid:228)(cid:211)(cid:211)(cid:112)(cid:156)(cid:213)(cid:192)(cid:3)
(cid:204)(cid:105)(cid:152)(cid:135)(cid:222)(cid:105)(cid:62)(cid:192)(cid:3)(cid:62)(cid:152)(cid:152)(cid:136)(cid:219)(cid:105)(cid:192)(cid:195)(cid:62)(cid:192)(cid:222)(cid:3)(cid:62)(cid:195)(cid:3)(cid:62)(cid:3)(cid:171)(cid:213)(cid:76)(cid:143)(cid:136)(cid:86)(cid:3)(cid:86)(cid:156)(cid:147)(cid:171)(cid:62)(cid:152)(cid:222)(cid:3)(cid:204)(cid:192)(cid:62)(cid:96)(cid:136)(cid:152)(cid:125)(cid:3)(cid:156)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:32)(cid:105)(cid:220)(cid:3)(cid:57)(cid:156)(cid:192)(cid:142)(cid:3)
Stock Exchange. As you will see on the back cover of this Annual
Report, Matador has experienced steady growth in production,
Adjusted EBITDA and oil and natural gas reserves over the past
ten years. As an example, in 2011, our last full year as a private
company, Matador produced approximately 2.6 million barrels of
oil equivalent, and ten years later, in 2021, we produced 31.5 million
barrels of oil equivalent, a 12-fold increase. Matador’s average daily
total production was just over 7,000 barrels of oil equivalent per day
in 2011, and in the second quarter of 2022, we expect to average
more than 100,000 barrels of oil equivalent per day. Even more
striking, in 2011, we produced a total of 154,000 barrels of oil, or
about 420 barrels of oil per day, while in 2021, we produced
17.8 million barrels of oil, or 48,900 barrels of oil per day—an
increase of more than 100-fold! One of the key objectives we
set for Matador at the time of our initial public offering was to
(cid:195)(cid:136)(cid:125)(cid:152)(cid:136)(cid:119)(cid:86)(cid:62)(cid:152)(cid:204)(cid:143)(cid:222)(cid:3)(cid:125)(cid:192)(cid:156)(cid:220)(cid:3)(cid:156)(cid:213)(cid:192)(cid:3)(cid:156)(cid:136)(cid:143)(cid:3)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:3)(cid:204)(cid:156)(cid:3)(cid:62)(cid:86)(cid:133)(cid:136)(cid:105)(cid:219)(cid:105)(cid:3)(cid:62)(cid:3)(cid:147)(cid:156)(cid:192)(cid:105)(cid:3)(cid:76)(cid:62)(cid:143)(cid:62)(cid:152)(cid:86)(cid:105)(cid:96)(cid:3)
mix of oil and natural gas production, and we believe we have
clearly accomplished that goal over the past ten years and have
established ourselves as being one of the top ten producers in the
Delaware Basin. In doing so, the bond rating agencies—Moody’s
Investors Services and S&P Global Ratings—both have raised their
credit ratings on Matador, our bonds are trading above par and
Matador has advanced from the S&P 600 SmallCap index into the
S&P 400 MidCap index.
ANNUAL MEETING
Matador’s Board, staff and I are excited for all the opportunities
that lie ahead for Matador and its shareholders and bondholders.
We are especially grateful to have you as stakeholders and have
appreciated all your trust and support throughout the years. Such
(cid:86)(cid:156)(cid:152)(cid:119)(cid:96)(cid:105)(cid:152)(cid:86)(cid:105)(cid:3)(cid:133)(cid:62)(cid:195)(cid:3)(cid:147)(cid:62)(cid:96)(cid:105)(cid:3)(cid:62)(cid:3)(cid:96)(cid:136)(cid:118)(cid:118)(cid:105)(cid:192)(cid:105)(cid:152)(cid:86)(cid:105)(cid:93)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:220)(cid:105)(cid:3)(cid:220)(cid:136)(cid:143)(cid:143)(cid:3)(cid:86)(cid:156)(cid:152)(cid:204)(cid:136)(cid:152)(cid:213)(cid:105)(cid:3)(cid:204)(cid:156)(cid:3)(cid:195)(cid:204)(cid:192)(cid:136)(cid:219)(cid:105)(cid:3)
every day to create long-term value for you and to continue to earn
your ongoing trust and support.
It has been not only a pleasure getting to know many of you, but we
also invite each of you to attend our annual shareholders’ meeting
on Friday, June 10, 2022, at the Hilton Dallas Lincoln Centre. We
hope you will be able to join us, and we will provide additional
details about the meeting arrangements separately. We certainly
look forward to seeing everyone again in person and to sharing
all the latest news about Matador. In the meantime, please stay
safe and well, and please feel free to follow up with us as to any
questions or suggestions that you may have.
Sincerely,
Joseph Wm. Foran
Founder, Chairman
(cid:62)(cid:152)(cid:96)(cid:3)(cid:10)(cid:133)(cid:136)(cid:105)(cid:118)(cid:3)(cid:13)(cid:221)(cid:105)(cid:86)(cid:213)(cid:204)(cid:136)(cid:219)(cid:105)(cid:3)(cid:34)(cid:118)(cid:119)(cid:86)(cid:105)(cid:192)
(972) 371-5206
BOARD OF DIRECTORS
Joseph Wm. Foran
Monika U. Ehrman
Founder, Chairman and Chief Executive
(cid:34)(cid:118)(cid:119)(cid:86)(cid:105)(cid:192)(cid:3)(cid:156)(cid:118)(cid:3)(cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:3)(cid:44)(cid:105)(cid:195)(cid:156)(cid:213)(cid:192)(cid:86)(cid:105)(cid:195)(cid:3)(cid:10)(cid:156)(cid:147)(cid:171)(cid:62)(cid:152)(cid:222)(cid:3)
(Matador II); Founder, Chairman and Chief
(cid:13)(cid:221)(cid:105)(cid:86)(cid:213)(cid:204)(cid:136)(cid:219)(cid:105)(cid:3)(cid:34)(cid:118)(cid:119)(cid:86)(cid:105)(cid:192)(cid:3)(cid:156)(cid:118)(cid:3)(cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:3)(cid:42)(cid:105)(cid:204)(cid:192)(cid:156)(cid:143)(cid:105)(cid:213)(cid:147)(cid:3)
Corporation (Matador I)
Director; Associate Professor of Law,
University of North Texas at Dallas College
of Law; Former Professor of Law, University
of Oklahoma College of Law; Petroleum
Engineer; Former Oil and Gas Company
In-House Legal Counsel
Timothy E. Parker
Julia P. Forrester Rogers
Lead Independent Director; Contractor in
Charge of Research, Brightworks Wealth
Management, LLC; Former Portfolio Manager
and Analyst – Natural Resources, T. Rowe
Price & Associates
Director; Professor of Law, Southern
Methodist University Dedman School of Law;
Former Associate Provost, SMU;
Former Real Estate Attorney, Thompson &
Knight LLP
R. Gaines Baty
Deputy Lead Independent Director;
(cid:10)(cid:133)(cid:136)(cid:105)(cid:118)(cid:3)(cid:13)(cid:221)(cid:105)(cid:86)(cid:213)(cid:204)(cid:136)(cid:219)(cid:105)(cid:3)(cid:34)(cid:118)(cid:119)(cid:86)(cid:105)(cid:192)(cid:93)(cid:3)(cid:44)(cid:176)(cid:3)(cid:20)(cid:62)(cid:136)(cid:152)(cid:105)(cid:195)(cid:3)(cid:9)(cid:62)(cid:204)(cid:222)(cid:3)
Associates, Inc.; Published Author
James M. Howard
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
Reynald A. Baribault
Kenneth L. Stewart
Director; President, CEO and Co-Founder,
IPR Energy Partners, LLC; Executive Vice
President/Engineering and Co-Founder
NP Resources, LLC; Former Vice President
Netherland, Sewell & Associates, Inc.
William M. Byerley
Director; Retired Partner (energy focus),
PricewaterhouseCoopers (PwC)
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
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG)(1)
ENVIRONMENTAL
SOCIAL
CONTINUED REDUCTION OF
PER-BARREL EMISSIONS(2)
INCREASED USE OF NON-FRESH
WATER, INCLUDING RECYCLED WATER
>45% >50%
Reduction
in methane
emissions
intensity from
2020 to 2021
Reduction in
(cid:121)(cid:62)(cid:192)(cid:136)(cid:152)(cid:125)(cid:3)(cid:105)(cid:147)(cid:136)(cid:195)(cid:195)(cid:136)(cid:156)(cid:152)(cid:195)(cid:3)
intensity from
2020 to 2021
>95% >70%
of total water
consumed
in 2021 was
non-fresh water(3)
of wells completed
(cid:136)(cid:152)(cid:3)(cid:211)(cid:228)(cid:211)(cid:163)(cid:3)(cid:213)(cid:204)(cid:136)(cid:143)(cid:136)(cid:226)(cid:105)(cid:96)(cid:3)
recycled produced
water(4)
ZERO
employee lost time
incidents during
approximately
2.7 million employee
man-hours from
2017 to 2021
>45
hours of
continuing
education per
employee in 2021
INCREASED TRANSPORTATION ON PIPELINE
OPERATED PRODUCED OIL ON PIPE
OPERATED PRODUCED WATER ON PIPE
Barrels Transported via Pipeline
Barrels Transported via Trucks
Barrels Transported via Pipeline
Barrels Transported via Trucks
d
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G
70,000
60,000
50,000
40,000
30,000
20,000
0
82%
65%
48%
14%
12%
2017
2018
2019
2020
2021
d
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b
B
,
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o
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s
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G
300,000
250,000
200,000
150,000
100,000
50,000
0
98%
96%
79%
71%
59%
2017
2018
2019
2020
2021
GOVERNANCE
5.6%
of common stock
held by directors
and executive
(cid:156)(cid:118)(cid:119)(cid:86)(cid:105)(cid:192)(cid:195)(5)
8
9
Independence
Eight directors
are independent,
including a lead
independent
director
Diversity
One minority
and two female
directors
2
9
5
9
Refreshment
(cid:29)(cid:105)(cid:195)(cid:195)(cid:3)(cid:204)(cid:133)(cid:62)(cid:152)(cid:3)(cid:119)(cid:219)(cid:105)(cid:3)
years’ tenure for
more than half
the directors
(1) These sustainability metrics have been calculated using the best information available to us at the time of preparation of this report. The data utilized
(cid:136)(cid:152)(cid:3)(cid:86)(cid:62)(cid:143)(cid:86)(cid:213)(cid:143)(cid:62)(cid:204)(cid:136)(cid:152)(cid:125)(cid:3)(cid:195)(cid:213)(cid:86)(cid:133)(cid:3)(cid:147)(cid:105)(cid:204)(cid:192)(cid:136)(cid:86)(cid:195)(cid:3)(cid:136)(cid:195)(cid:3)(cid:195)(cid:213)(cid:76)(cid:141)(cid:105)(cid:86)(cid:204)(cid:3)(cid:204)(cid:156)(cid:3)(cid:86)(cid:105)(cid:192)(cid:204)(cid:62)(cid:136)(cid:152)(cid:3)(cid:192)(cid:105)(cid:171)(cid:156)(cid:192)(cid:204)(cid:136)(cid:152)(cid:125)(cid:3)(cid:192)(cid:213)(cid:143)(cid:105)(cid:195)(cid:93)(cid:3)(cid:192)(cid:105)(cid:125)(cid:213)(cid:143)(cid:62)(cid:204)(cid:156)(cid:192)(cid:222)(cid:3)(cid:192)(cid:105)(cid:219)(cid:136)(cid:105)(cid:220)(cid:195)(cid:93)(cid:3)(cid:96)(cid:105)(cid:119)(cid:152)(cid:136)(cid:204)(cid:136)(cid:156)(cid:152)(cid:195)(cid:93)(cid:3)(cid:86)(cid:62)(cid:143)(cid:86)(cid:213)(cid:143)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:3)(cid:147)(cid:105)(cid:204)(cid:133)(cid:156)(cid:96)(cid:156)(cid:143)(cid:156)(cid:125)(cid:136)(cid:105)(cid:195)(cid:93)(cid:3)(cid:105)(cid:195)(cid:204)(cid:136)(cid:147)(cid:62)(cid:204)(cid:105)(cid:195)(cid:93)(cid:3)(cid:62)(cid:96)(cid:141)(cid:213)(cid:195)(cid:204)(cid:147)(cid:105)(cid:152)(cid:204)(cid:195)(cid:3)
and other factors. As a result, these metrics are subject to change from time to time as updated data or other information becomes available. The
(cid:147)(cid:105)(cid:204)(cid:192)(cid:136)(cid:86)(cid:195)(cid:3)(cid:171)(cid:192)(cid:156)(cid:219)(cid:136)(cid:96)(cid:105)(cid:96)(cid:3)(cid:192)(cid:105)(cid:121)(cid:105)(cid:86)(cid:204)(cid:3)(cid:76)(cid:156)(cid:204)(cid:133)(cid:3)(cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:189)(cid:195)(cid:3)(cid:125)(cid:192)(cid:156)(cid:195)(cid:195)(cid:3)(cid:156)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:105)(cid:96)(cid:3)(cid:105)(cid:221)(cid:171)(cid:143)(cid:156)(cid:192)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:3)(cid:69)(cid:3)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:3)(cid:156)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:195)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:45)(cid:62)(cid:152)(cid:3)(cid:31)(cid:62)(cid:204)(cid:105)(cid:156)(cid:3)(cid:31)(cid:136)(cid:96)(cid:195)(cid:204)(cid:192)(cid:105)(cid:62)(cid:147)(cid:93)(cid:3)(cid:29)(cid:29)(cid:10)(cid:189)(cid:195)(cid:3)(cid:125)(cid:192)(cid:156)(cid:195)(cid:195)(cid:3)(cid:156)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:105)(cid:96)(cid:3)
midstream operations on a consolidated basis, except where otherwise noted.
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(cid:156)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:195)(cid:93)(cid:3)(cid:62)(cid:195)(cid:3)(cid:220)(cid:105)(cid:143)(cid:143)(cid:3)(cid:62)(cid:195)(cid:3)(cid:105)(cid:195)(cid:204)(cid:136)(cid:147)(cid:62)(cid:204)(cid:105)(cid:195)(cid:3)(cid:118)(cid:156)(cid:192)(cid:3)(cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:189)(cid:195)(cid:3)(cid:156)(cid:204)(cid:133)(cid:105)(cid:192)(cid:3)(cid:156)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:195)(cid:176)(cid:3)
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(cid:173)(cid:120)(cid:174)(cid:3)(cid:269)(cid:195)(cid:3)(cid:156)(cid:118)(cid:3)(cid:269)(cid:171)(cid:192)(cid:136)(cid:143)(cid:3)(cid:163)(cid:206)(cid:93)(cid:3)(cid:211)(cid:228)(cid:211)(cid:211)(cid:176)(cid:3)(cid:42)(cid:143)(cid:105)(cid:62)(cid:195)(cid:105)(cid:3)(cid:195)(cid:105)(cid:105)(cid:3)(cid:31)(cid:62)(cid:204)(cid:62)(cid:96)(cid:156)(cid:192)(cid:189)(cid:195)(cid:3)(cid:211)(cid:228)(cid:211)(cid:211)(cid:3)(cid:42)(cid:192)(cid:156)(cid:221)(cid:222)(cid:3)(cid:45)(cid:204)(cid:62)(cid:204)(cid:105)(cid:147)(cid:105)(cid:152)(cid:204)(cid:3)(cid:118)(cid:156)(cid:192)(cid:3)(cid:62)(cid:96)(cid:96)(cid:136)(cid:204)(cid:136)(cid:156)(cid:152)(cid:62)(cid:143)(cid:3)(cid:136)(cid:152)(cid:118)(cid:156)(cid:192)(cid:147)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:176)
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RECORD LOW OPERATING COSTS IN 2021
DRILLING & COMPLETION (D&C) CAPEX/FT(1)
($/ft)
(cid:386)(cid:54)(cid:20)(cid:176)(cid:3)
LATERAL
(cid:29)(cid:13)(cid:32)(cid:20)(cid:47)(cid:21)
(cid:123)(cid:93)(cid:199)(cid:228)(cid:228)(cid:189)
$1,528
+21%
(cid:120)(cid:93)(cid:199)(cid:228)(cid:228)(cid:189)
+54%
(cid:110)(cid:93)(cid:110)(cid:228)(cid:228)(cid:189)
+19%
(cid:163)(cid:228)(cid:93)(cid:120)(cid:228)(cid:228)(cid:189)
-24%
$1,165
-27%
$850
-21%
$670
2018
2019
2020
2021
(cid:42)(cid:13)(cid:44)(cid:22)(cid:34)(cid:12)(cid:3)(cid:47)(cid:49)(cid:44)(cid:32)(cid:13)(cid:12)(cid:3)(cid:47)(cid:34)(cid:3)(cid:45)(cid:386)(cid:29)(cid:13)(cid:45)
CONTINUED GROWTH IN MIDSTREAM
SAN MATEO ADJUSTED EBITDA(2)(3) GROWTH
($ in millions)
Natural Gas
Oil
Water
$154
$113
$96
$62
2018
2019
2020
2021
(cid:173)(cid:163)(cid:174)(cid:3)(cid:10)(cid:156)(cid:195)(cid:204)(cid:3)(cid:171)(cid:105)(cid:192)(cid:3)(cid:86)(cid:156)(cid:147)(cid:171)(cid:143)(cid:105)(cid:204)(cid:105)(cid:96)(cid:3)(cid:143)(cid:62)(cid:204)(cid:105)(cid:192)(cid:62)(cid:143)(cid:3)(cid:118)(cid:156)(cid:156)(cid:204)(cid:3)(cid:147)(cid:105)(cid:204)(cid:192)(cid:136)(cid:86)(cid:3)(cid:195)(cid:133)(cid:156)(cid:220)(cid:152)(cid:3)(cid:192)(cid:105)(cid:171)(cid:192)(cid:105)(cid:195)(cid:105)(cid:152)(cid:204)(cid:195)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:12)(cid:69)(cid:10)(cid:3)(cid:171)(cid:156)(cid:192)(cid:204)(cid:136)(cid:156)(cid:152)(cid:3)(cid:156)(cid:118)(cid:3)(cid:220)(cid:105)(cid:143)(cid:143)(cid:3)(cid:86)(cid:156)(cid:195)(cid:204)(cid:195)(cid:3)(cid:156)(cid:152)(cid:143)(cid:222)(cid:176)(cid:3)(cid:13)(cid:221)(cid:86)(cid:143)(cid:213)(cid:96)(cid:105)(cid:195)(cid:3)(cid:86)(cid:156)(cid:195)(cid:204)(cid:195)(cid:3)(cid:204)(cid:156)(cid:3)(cid:105)(cid:181)(cid:213)(cid:136)(cid:171)(cid:3)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:93)(cid:3)(cid:147)(cid:136)(cid:96)(cid:195)(cid:204)(cid:192)(cid:105)(cid:62)(cid:147)(cid:3)(cid:86)(cid:62)(cid:171)(cid:136)(cid:204)(cid:62)(cid:143)(cid:3)(cid:105)(cid:221)(cid:171)(cid:105)(cid:152)(cid:96)(cid:136)(cid:204)(cid:213)(cid:192)(cid:105)(cid:195)(cid:93)(cid:3)(cid:86)(cid:62)(cid:171)(cid:136)(cid:204)(cid:62)(cid:143)(cid:136)(cid:226)(cid:105)(cid:96)(cid:3)(cid:20)(cid:69)(cid:269)(cid:3)(cid:156)(cid:192)(cid:3)
interest expenses and certain other capital expenditures.
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(cid:76)(cid:222)(cid:3)(cid:156)(cid:171)(cid:105)(cid:192)(cid:62)(cid:204)(cid:136)(cid:152)(cid:125)(cid:3)(cid:62)(cid:86)(cid:204)(cid:136)(cid:219)(cid:136)(cid:204)(cid:136)(cid:105)(cid:195)(cid:93)(cid:3)(cid:195)(cid:105)(cid:105)(cid:3)(cid:186)(cid:45)(cid:105)(cid:143)(cid:105)(cid:86)(cid:204)(cid:105)(cid:96)(cid:3)(cid:19)(cid:136)(cid:152)(cid:62)(cid:152)(cid:86)(cid:136)(cid:62)(cid:143)(cid:3)(cid:12)(cid:62)(cid:204)(cid:62)(cid:3)(cid:113)(cid:3)(cid:32)(cid:156)(cid:152)(cid:135)(cid:20)(cid:269)(cid:269)(cid:42)(cid:3)(cid:19)(cid:136)(cid:152)(cid:62)(cid:152)(cid:86)(cid:136)(cid:62)(cid:143)(cid:3)(cid:31)(cid:105)(cid:62)(cid:195)(cid:213)(cid:192)(cid:105)(cid:195)(cid:187)(cid:3)(cid:136)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:269)(cid:152)(cid:152)(cid:213)(cid:62)(cid:143)(cid:3)(cid:44)(cid:105)(cid:171)(cid:156)(cid:192)(cid:204)(cid:3)(cid:156)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:19)(cid:156)(cid:192)(cid:147)(cid:3)(cid:163)(cid:228)(cid:135)(cid:28)(cid:3)(cid:105)(cid:152)(cid:86)(cid:143)(cid:156)(cid:195)(cid:105)(cid:96)(cid:3)(cid:133)(cid:105)(cid:192)(cid:105)(cid:136)(cid:152)(cid:176)
(cid:173)(cid:206)(cid:174)(cid:3)(cid:9)(cid:62)(cid:195)(cid:105)(cid:96)(cid:3)(cid:156)(cid:152)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:86)(cid:156)(cid:147)(cid:76)(cid:136)(cid:152)(cid:105)(cid:96)(cid:3)(cid:269)(cid:96)(cid:141)(cid:213)(cid:195)(cid:204)(cid:105)(cid:96)(cid:3)(cid:13)(cid:9)(cid:22)(cid:47)(cid:12)(cid:269)(cid:3)(cid:156)(cid:118)(cid:3)(cid:45)(cid:62)(cid:152)(cid:3)(cid:31)(cid:62)(cid:204)(cid:105)(cid:156)(cid:3)(cid:62)(cid:152)(cid:96)(cid:3)(cid:45)(cid:62)(cid:152)(cid:3)(cid:31)(cid:62)(cid:204)(cid:105)(cid:156)(cid:3)(cid:31)(cid:136)(cid:96)(cid:195)(cid:204)(cid:192)(cid:105)(cid:62)(cid:147)(cid:3)(cid:22)(cid:22)(cid:93)(cid:3)(cid:29)(cid:29)(cid:10)(cid:93)(cid:3)(cid:171)(cid:192)(cid:136)(cid:156)(cid:192)(cid:3)(cid:204)(cid:156)(cid:3)(cid:204)(cid:133)(cid:105)(cid:136)(cid:192)(cid:3)(cid:34)(cid:86)(cid:204)(cid:156)(cid:76)(cid:105)(cid:192)(cid:3)(cid:211)(cid:228)(cid:211)(cid:228)(cid:3)(cid:147)(cid:105)(cid:192)(cid:125)(cid:105)(cid:192)(cid:176)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
FORM 10-K
(Mark One)
(cid:2)(cid:22)(cid:2)(cid:2) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
or
(cid:2) 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 (cid:2)(cid:22)(cid:2)(cid:2) No (cid:2)
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 (cid:2) No (cid:2)(cid:22)(cid:2)(cid:2)
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 (cid:2)(cid:22)(cid:2)(cid:2) No (cid:2)
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 (cid:2)(cid:22)(cid:2)(cid:2) No (cid:2)
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 (cid:2)(cid:22)(cid:2)(cid:2)
Non-accelerated filer (cid:2)
(cid:2)
Accelerated filer
Smaller reporting company (cid:2)
Emerging growth company (cid:2)
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. (cid:2)
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. (cid:2)(cid:22)(cid:2)(cid:2)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act. Yes (cid:2) No (cid:2)(cid:22)(cid:2)(cid:2)
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 $3,979,787,498.
As of February 22, 2022, there were 118,043,776 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . 90
ITEM 7A.
Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . 118
Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118
Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122
Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123
Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123
Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . 123
Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124
Form 10-K Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124
FORM 10-K
2021 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 prices and the demand for oil, natural gas and natural gas liquids; our ability to replace
reserves and efficiently develop current reserves; 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; weather and environmental conditions; the impact of the worldwide spread of the novel coronavirus
(“COVID-19”) on oil and natural gas demand, oil and natural gas prices and our business; the operating results of our
midstream joint venture’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; 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 natural gas liquids;
• oil, natural gas and natural gas liquids 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;
the amount, nature and timing of capital expenditures, including future exploration and development costs;
the availability and terms of capital;
FORM 10-K
2
MATADOR RESOURCES COMPANY
• our drilling of wells;
• our ability to negotiate and consummate acquisition and divestiture opportunities;
•
the integration of acquisitions 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 its Black River cryogenic natural gas processing plant and
the drilling of additional salt water disposal wells;
•
the ability of our midstream joint venture 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 on the oil and natural gas industry and our business;
• our future operating results; 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
2021 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 and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, our
midstream joint venture with a subsidiary of Five Point Energy LLC (“Five Point”). 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, primarily through our midstream joint venture, San Mateo,
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;
• 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. 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 2021,
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, initiating and increasing a quarterly cash dividend and earning
performance incentives from Five Point. Further, we concluded several important financing transactions in 2021,
including extending the maturity of and significantly increasing the borrowing base under our Credit Agreement (as
defined below) and increasing the lender commitments under the San Mateo Credit Facility (as defined below).
San Mateo also achieved several important milestones in 2021, 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.
2021 HIGHLIGHTS
Increased Oil, Natural Gas and Oil Equivalent Production
For the year ended December 31, 2021, we achieved record oil, natural gas and average daily oil equivalent
production. In 2021, we produced 17.8 million Bbl of oil, an increase of 12%, as compared to 15.9 million Bbl
of oil produced in 2020. We also produced 81.7 Bcf of natural gas, an increase of 18% from 69.5 Bcf of natural
gas produced in 2020. Our average daily oil equivalent production for the year ended December 31, 2021 was
86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, an increase of 15%,
as compared to 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day,
for the year ended December 31, 2020. The increase in oil and natural gas production was primarily attributable to
our ongoing delineation and development drilling activities in the Delaware Basin throughout 2021, which offset
declining production in the Eagle Ford and Haynesville shales. Oil production comprised 57% of our total production
(using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2021 as
compared to 58% in 2020.
Increased Oil, Natural Gas and Oil Equivalent Reserves
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, an increase of 20% from 270.3 million BOE, including
159.9 million Bbl of oil and 662.3 Bcf of natural gas, at December 31, 2020. The Standardized Measure of our
total proved oil and natural gas reserves increased 176% from $1.58 billion at December 31, 2020 to $4.38 billion
at December 31, 2021. The PV-10 of our total proved oil and natural gas reserves increased 223% from $1.66 billion
at December 31, 2020 to $5.35 billion at December 31, 2021. The increases in our Standardized Measure and
PV-10 were primarily a result of the significantly higher weighted average oil and natural gas prices used to estimate
proved reserves at December 31, 2021, as compared to December 31, 2020, but also due to the 20% increase
in our total proved oil and natural gas reserves at December 31, 2021, as compared to December 31, 2020.
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
2021 ANNUAL REPORT
5
At December 31, 2021, proved developed reserves included 102.2 million Bbl of oil and 546.2 Bcf of natural gas,
and proved undeveloped reserves included 79.1 million Bbl of oil and 306.4 Bcf of natural gas. 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. Proved developed reserves and proved oil reserves comprised 46% and 59%,
respectively, of our total proved oil and natural gas reserves at December 31, 2020. The improvement in proved
developed reserves as a percentage of our total proved oil and natural gas reserves to 60% at December 31, 2021
from 46% at December 31, 2020 was primarily attributable to the development and conversion of approximately
40.1 million BOE of our proved undeveloped reserves to proved developed reserves in the Delaware Basin in 2021.
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 2022.
We completed and began producing oil and natural gas from 97 gross (48.2 net) wells in the Delaware Basin in
2021, including 47 gross (44.2 net) operated and 50 gross (4.0 net) non-operated wells. At December 31, 2021,
our total acreage position in the Delaware Basin was approximately 237,200 gross (124,800 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 19%
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, as compared
to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil
production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020. We expect our
Delaware Basin production to increase in 2022 as we continue the delineation and development of these asset areas.
During 2021, 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:
•
•
•
the second group of Rodney Robinson wells in the western portion of our Antelope Ridge asset area, in
March 2021; these four Rodney Robinson wells have produced in aggregate approximately 1.5 million BOE
in 11 months of production;
the first 13 Voni wells, all of which were 2.3-mile laterals, in the western portion of the Stateline asset area
in a staggered fashion during April and May 2021; these 13 Voni wells have produced in aggregate
approximately 5.2 million BOE in eight months of production;
four wells in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset
area (the “Greater Stebbins Area”) in July 2021; these four wells have produced in aggregate approximately
0.7 million BOE in seven months of production;
FORM 10-K PART I
6
MATADOR RESOURCES COMPANY
•
the second group of 13 Boros wells in the eastern portion of the Stateline asset area in a staggered fashion
at various times primarily throughout September 2021; these 13 Boros wells have produced in aggregate
approximately 2.2 million BOE in five months of production; and
• nine additional wells in the Greater Stebbins Area in December 2021.
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 2021 included:
•
•
the fully realized transition to drilling longer laterals, whereby 98% of the operated horizontal wells we
turned to sales in 2021 had lateral lengths of two miles or greater, as compared to 74% in 2020, 8% in
2019 and only one two-mile lateral in 2018;
the continuing improvement in capital efficiency as demonstrated by our average drilling and completion
costs for all operated horizontal wells turned to sales of approximately $670 per lateral foot in 2021, a
decrease of 21% as compared to $850 per lateral foot in 2020, a decrease of 42% as compared to average
drilling and completion costs of $1,165 per lateral foot in 2019 and a decrease of 56% as compared to
average drilling and completion costs of $1,528 per lateral foot in 2018;
• capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2021
of $513 million, which was below our original estimated range for 2021 D/C/E capital expenditures of $525
to $575 million as provided on February 23, 2021 and our revised estimated range for 2021 D/C/E capital
expenditures of $535 to $565 million as provided on October 26, 2021, despite the acceleration of 11 Voni
well completions forward into the fourth quarter of 2021 and the addition of a fifth operated drilling rig;
•
record-low annual unit operating costs for lease operating expenses of $3.46 per BOE;
• general and administrative expenses of $3.06 per BOE, which were the second lowest general and
administrative expenses we have achieved on an annual basis, as compared to a record low $2.27 per BOE
in 2020. These 2021 general and administrative expenses were achieved despite the impact of increased
cash-settled stock compensation costs and the reinstatement of employee compensation beginning in
March 2021, which had been previously reduced beginning in March 2020 in response to the significantly
lower oil and natural gas price environment at that time.
Capital Resources and Financing Highlights
During 2021, we achieved several significant and important capital resources objectives we set at the beginning
of the year. These objectives included:
•
•
•
the generation of free cash flow in all four quarters of 2021;
the net repayment of $340.0 million in borrowings under our revolving credit facility, resulting in outstanding
borrowings of $100.0 million at December 31, 2021;
the adoption of a dividend policy in the first quarter of 2021 pursuant to which we initiated a quarterly cash
dividend of $0.025 per share of common stock and the subsequent amendment of that dividend policy in
the fourth quarter of 2021, pursuant to which we doubled the quarterly cash dividend to $0.05 per share of
common stock; and
•
the receipt of $48.6 million in performance incentives directly from Five Point;
FORM 10-K PART I
2021 ANNUAL REPORT
7
In addition, we concluded several important financing transactions in 2021 that increased our operational
flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position.
These transactions included:
•
•
the closing of our fourth amended and restated credit agreement (the “Credit Agreement”) in November 2021
to (i) extend the maturity date by three years to October 31, 2026 from October 31, 2023 previously,
(ii) increase the borrowing base by 50% to $1.35 billion, as compared to $900.0 million previously, (iii) reaffirm
the elected borrowing commitment at $700.0 million, (iv) reaffirm the maximum facility amount at
$1.5 billion and (v) add three new banks to our lending group; and
the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in June 2021 to
increase the lender commitments under the revolving credit facility to $450.0 million from $375.0 million and
an accordion feature that provides for potential increases in lender commitments to up to $700.0 million.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and
Capital Resources” for additional information regarding these financing transactions.
Midstream Highlights
San Mateo achieved strong operating results in 2021, 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 2020. Volumes for the years
ended December 31, 2021 and 2020 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. San Mateo is owned 51% by us and
49% by our joint venture partner, Five Point.
During 2021, 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, 2021, San Mateo’s midstream system included:
• Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity in San Mateo’s
cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”)
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 central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput
capacity and approximately 90 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: 14 commercial salt water disposal wells and associated facilities with designed
produced water disposal capacity of 370,000 Bbl per day and approximately 130 miles of produced water
gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
FORM 10-K PART I
8
MATADOR RESOURCES COMPANY
Environmental, Social and Governance (“ESG”) Initiatives
We maintain an active ESG program and continued working in 2021 to improve upon our various ESG efforts.
In May 2021, we published sustainability metrics aligned with standards developed by the Sustainability Accounting
Standards Board (“SASB”), which we subsequently updated in July 2021. In December 2021, we issued our
inaugural Sustainability Report highlighting the results of our 2020 ESG progress and achievements.
In 2020, we grew gross operated oil production by 13% and gross operated natural gas production by 19%, as
compared to 2019, while still reducing our environmental impact and continuing our strong safety record. Highlights
from our 2020 ESG initiatives include:
• Decreased emissions intensity by 19% and flaring intensity by 38%, as compared to 2019;
• Decreased consumption of fresh water by 49%, as compared to 2019;
• Transported 96% of operated produced water and 65% of operated produced oil by pipeline;
•
Incurred no employee lost time incidents during more than 2.1 million employee man-hours from 2017 to 2020;
• Provided approximately 15,000 hours of employee continuing education, equating to approximately 55 hours
per employee; and
• Revised the mandate of the Board of Directors’ Environmental, Social and Corporate Governance Committee
to enhance the focus, oversight and support for our ESG efforts and to measure improvements.
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 2021, 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.
FORM 10-K PART I
2021 ANNUAL REPORT
9
The following table presents certain summary data for each of our operating areas as of and for the year ended
December 31, 2021.
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)
237,200
124,800
944
468.1
4,381
1,534
312,018
58.6
80,534
South Texas:
Eagle Ford(5)
Northwest Louisiana
Haynesville
Cotton Valley(6)
Area Total(7)
Total
27,400
25,100
131
110.5
208
175
5,663
100.0
2,126
16,700
16,100
19,100
283,700
9,100
14,900
17,700
167,600
233
63
296
1,371
18.3
39.6
57.9
636.5
161
154
315
4,904
15
35
50
1,759
4,848
868
5,716
323,397
82.6
100.0
85.3
59.8
3,334
182
3,516
86,176
Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at
December 31, 2021. 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, 2021, 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, 2021, these engineered drilling locations included 358 gross (136 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, Avalon and
Delaware formations, in the Delaware Basin and only eight gross (0.4 net) locations to which we have assigned proved undeveloped reserves in
the Haynesville shale. At December 31, 2021, 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, 2021.
(5) 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. In January 2022, the two wells and associated acreage in Zavala County, Texas, which
included 55 gross (55 net) engineered locations, were divested.
(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.
We are active both as an operator and as a non-operating co-working interest owner with various industry
participants. At December 31, 2021, 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, 2021, we also were the operator for almost all of our Eagle Ford acreage
and approximately half 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.
FORM 10-K PART I
10
MATADOR RESOURCES COMPANY
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, Avalon and Delaware 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, 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, 2021, our total acreage position in Southeast New Mexico and West Texas was approximately
237,200 gross (124,800 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas.
These acreage totals included approximately 39,700 gross (22,600 net) acres in our Ranger asset area in Lea County,
64,500 gross (26,000 net) acres in our Arrowhead asset area in Eddy County, 47,500 gross (25,900 net) acres in
our Rustler Breaks asset area in Eddy County, 24,700 gross (15,700 net) acres in our Antelope Ridge asset area
in Lea County, 14,400 gross (10,700 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 42,900 gross (20,500 net) acres in our
Twin Lakes asset area in Lea County at December 31, 2021. 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 Avalon and Delaware formations, as well as
the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2021, our acreage position
in the Delaware Basin was approximately 75% held by existing production. Excluding the Twin Lakes asset area,
where at December 31, 2021 we had drilled only three vertical operated wells and two horizontal operated wells,
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 86% held by existing production at
December 31, 2021.
During the year ended December 31, 2021, we continued the delineation and development of our Delaware
Basin acreage. We completed and began producing oil and natural gas from 97 gross (48.2 net) wells in the
Delaware Basin, including 47 gross (44.2 net) operated horizontal wells and 50 gross (4.0 net) non-operated
horizontal wells, throughout our various asset areas. At December 31, 2021, 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
FORM 10-K PART I
2021 ANNUAL REPORT
11
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. Most
of our delineation and development efforts have been focused on multiple completion targets between the First
Bone Spring and the Wolfcamp B.
As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production
increased significantly in 2021. Our average daily oil equivalent production from the Delaware Basin increased
approximately 19% 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, as compared to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day
(96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020.
At December 31, 2021, approximately 96% of our estimated total proved oil and natural gas reserves, or
312.0 million BOE, was attributable to the Delaware Basin, including approximately 177.1 million Bbl of oil and 809.3
Bcf of natural gas, a 19% increase, as compared to 261.9 million BOE for the year ended December 31, 2020.
Our Delaware Basin proved reserves at December 31, 2021 comprised approximately 98% of our proved oil reserves
and 95% of our proved natural gas reserves, as compared to approximately 98% of our proved oil reserves and
96% of our proved natural gas reserves at December 31, 2020.
At December 31, 2021, we had identified 4,381 gross (1,534 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 2,204 gross (1,350 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 that location given our current acreage position. At December 31,
2021, 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, 2021, 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,
2021, 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, 2021, these potential future drilling locations included 358 gross (136 net) operated
and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in
the Brushy Canyon, Avalon and Delaware formations, to which we have assigned proved undeveloped reserves.
At December 31, 2021, we were operating five drilling rigs in the Delaware Basin. At February 22, 2022,
we had contracted a sixth drilling rig to begin drilling operations on recently acquired acreage in the western portion
of our Ranger asset area in Lea County, New Mexico. We expect to operate six drilling rigs across our various
Delaware Basin asset areas throughout the remainder of 2022, but these six drilling rigs are expected to have an
increased focus on our Rustler Breaks, Antelope Ridge and Ranger asset areas in 2022, as compared to 2021.
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
are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2022.
FORM 10-K PART I
12
MATADOR RESOURCES COMPANY
Antelope Ridge Asset Area - Lea County, New Mexico
At the end of the first quarter of 2021, we achieved the first of the five operational milestones we set for Matador
in 2021 when we turned to sales four gross (3.8 net) wells on the Rodney Robinson leasehold. These wells were
the second group of wells drilled on the Rodney Robinson leasehold, which was acquired in the BLM Acquisition.
We did not turn to sales any other operated wells in other portions of the Antelope Ridge asset area during 2021,
although we did participate in the drilling and completion of 20 gross (1.1 net) non-operated wells that were turned
to sales in the Antelope Ridge asset area during 2021.
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. The four Rodney Robinson wells, which included two Wolfcamp A-XY completions
and two Third Bone Spring completions, were turned to sales late in the first quarter of 2021 and were all two-mile
laterals. These four Rodney Robinson wells have produced in aggregate approximately 1.5 million BOE in approximately
11 months of production despite being produced on restricted chokes throughout their early producing lives. We
drilled nine additional Rodney Robinson wells in the fall of 2021, and these nine wells are expected to be turned to
sales late in the first quarter of 2022.
We turned to sales the initial six Rodney Robinson wells in the western portion of the Antelope Ridge asset area
in late March 2020. In aggregate, these six wells have produced approximately 4.3 million BOE in approximately
22 months of production.
Rustler Breaks Asset Area - Eddy County, New Mexico
In the Rustler Breaks asset area, we turned to sales 13 gross (0.9 net) non-operated wells during 2021. We
did not turn to sales any operated wells during 2021, but at December 31, 2021, we had drilled or were drilling six
operated wells in the Rustler Breaks asset area, all of which are expected to be turned to sales in the second
quarter of 2022. We expect the Rustler Breaks asset area to be an area of increased operational focus for Matador
throughout 2022.
Arrowhead Asset Area - Eddy County, New Mexico
In the Arrowhead asset area, we turned to sales 13 gross (11.5 net) operated wells and 14 gross (1.6 net) non-
operated wells during 2021.
During the third quarter of 2021, we achieved the third of the five operational milestones we set for Matador in
2021 when we turned to sales four wells, all of which were two-mile laterals completed in the Second Bone Spring
formation, in the Greater Stebbins Area. These four wells have produced in aggregate approximately 0.7 million BOE
in seven months of production. At the end of the fourth quarter of 2021, we achieved the fifth and final operational
milestone we set for Matador in 2021 when we turned to sales nine wells, all of which were two-mile laterals
completed in the Third Bone Spring, Wolfcamp A-XY and Wolfcamp B formations, in the Greater Stebbins Area in
December 2021.
Ranger and Twin Lakes Asset Areas - Lea County, New Mexico
In the Ranger asset area, we turned to sales two gross (1.3 net) operated wells and three gross (0.4 net) non-
operated wells. We did not turn to sales any operated or non-operated wells in the Twin Lakes asset area during 2021.
FORM 10-K PART I
2021 ANNUAL REPORT
13
We were pleased with the performance from the first two Uncle Ches wells turned to sales in the Second
Bone Spring in the Ranger asset area in the first quarter of 2021. In aggregate, these two wells tested 4,053 BOE
per day (90% oil) during 24-hour initial potential (“IP”) tests conducted after these wells were equipped with
electric submersible pumps (“ESP”). The high (90%) oil cut and low water cut (approximately one Bbl of water per
Bbl of oil produced) exhibited by these wells should enhance their economics. We drilled two additional Uncle Ches
wells in the Ranger asset area in the fall of 2021, also Second Bone Spring completions, which were turned to sales
in mid-January 2022.
Stateline Asset Area - Eddy County, New Mexico
We operated two drilling rigs in our Stateline asset area for the majority of 2021. In early September 2018, we
acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The
Stateline asset area includes approximately 2,900 gross and net leasehold acres prospective for multiple geologic
targets. The federal leases provide an 87.5% NRI. The large majority of the Stateline asset area acreage has shown
to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad
development. We have been developing this acreage block drilling two-mile laterals on the eastern side of the
leasehold and approximately 2.3-mile laterals on the western side of the leasehold. We began drilling operations in
the Stateline asset area just before the end of 2019 and, at the end of the third quarter of 2020, we turned to sales
our first 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area. In aggregate,
the first 13 Boros wells have produced approximately 7.2 million BOE in approximately 15 months of production.
After finishing drilling operations on the first 13 Boros wells in 2020, we began drilling operations on the Voni
tract in the western portion of the Stateline asset area, and in the second quarter of 2021, we achieved the second
of the five operational milestones we set for Matador in 2021 when we turned to sales our first 13 gross (12.7 net)
wells on the Voni tract in the western portion of the Stateline asset area. The 13 Voni wells had completed lateral
lengths of approximately 12,000 feet, or about 2.3-miles, making them the longest laterals Matador has completed
to date. The 13 Voni wells included one First Bone Spring completion, four Second Bone Spring completions, four
Wolfcamp A-XY completions and four Wolfcamp A-Lower completions. Of particular note, the Voni Federal #216H
well, a Wolfcamp A-Lower completion, tested 5,073 BOE per day (60% oil), which was the highest 24-hour IP
Matador has achieved to date in any formation in the Delaware Basin. These 13 Voni wells have produced in aggregate
approximately 5.2 million BOE in approximately eight months of production, despite a number of these wells being
produced on restricted chokes early in their producing lives.
After finishing drilling operations on the first 13 Voni wells, we began drilling operations on the next 13 Boros
wells, and in the third quarter of 2021, we achieved the fourth of the five operational milestones we set for Matador
in 2021 when we turned to sales our second group of 13 gross (13.0 net) wells on the Boros tract in the eastern
portion of the Stateline asset area. These 13 Boros wells have produced in aggregate approximately 2.2 million BOE
in five months of production. Drilling and completion costs for the 26 Stateline wells turned to sales during 2021
averaged $628 per completed lateral foot, the lowest costs we have achieved in any of our asset areas.
In addition, during 2021, we drilled and completed our second group of 11 wells on the Voni tract on the western
portion of the Stateline leasehold. These 11 Voni wells are expected to have completed lateral lengths of
approximately 12,000 feet and were turned to sales in the first quarter of 2022.
Wolf and Jackson Trust Asset Areas - Loving County, Texas
In the Wolf and Jackson Trust asset areas, we turned to sales two gross (1.9 net) operated wells during 2021.
At December 31, 2021, we were in the process of completing three two-mile lateral wells in the Second Bone Spring
formation, and these three wells were turned to sales in February 2022.
FORM 10-K PART I
14
MATADOR RESOURCES COMPANY
South Texas — Eagle Ford Shale and Other Formations
The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a
band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies
between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the
Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly
sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal
maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone,
and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition
between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich
natural gas with condensate.
At December 31, 2021, our properties included approximately 27,400 gross (25,100 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, 2021.
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, 2021. In fact, as of December 31, 2021, we had not completed
any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result, our average daily oil
equivalent production from the Eagle Ford shale decreased 12% 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, as compared to 2,412 BOE per day, including 1,840 Bbl
of oil per day and 3.4 MMcf of natural gas per day, during 2020. For the year ended December 31, 2021, 2% of
our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 3% for the year
ended December 31, 2020.
At December 31, 2021, approximately 2% of our estimated total proved oil and natural gas reserves, or 5.7 million
BOE, was attributable to the Eagle Ford shale, including approximately 4.1 million Bbl of oil and 9.1 Bcf of natural
gas. Our Eagle Ford total proved reserves comprised approximately 2% of our proved oil reserves and 1% of our
proved natural gas reserves at December 31, 2021, essentially unchanged from December 31, 2020.
At December 31, 2021, we had identified 208 gross (175 net) engineered locations for potential future drilling
on our Eagle Ford acreage, including 55 gross (55 net) engineered locations in Zavala County that were divested in
January 2022. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral
lengths ranging from one mile to almost two miles. These 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 producing Eagle Ford wells and other nearby wells based on available
public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated
drilling and completion costs, spacing and other rules established by regulatory authorities and surface
considerations, among other factors.
These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We
believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the
Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to
produce predominantly oil and liquids. In addition, we believe portions of our South Texas acreage may also be
prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly
oil and liquids. At December 31, 2021, we had not included any future drilling locations in the upper portion of
the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or
Buda formations, even though activity from other operators in these formations around our South Texas acreage
position has demonstrated the prospectivity of these intervals.
FORM 10-K PART I
2021 ANNUAL REPORT
15
Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations
The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and
Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad
region throughout Northwest Louisiana, including principally Bossier, Caddo, DeSoto and Red River Parishes in
Louisiana. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale
is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low
permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%.
We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest
Louisiana during 2021, although we did participate in the drilling and completion of seven gross (less than 0.1 net)
non-operated Haynesville shale wells that were turned to sales in 2021. In the first quarter of 2020, we leased
2,800 net acres of our minerals in the southern portion of our Pine Island asset area to a third party and retained
royalty interests ranging from 18% to 20%. This lessee turned to sales four Haynesville shale wells drilled on
these interests in the first half of 2021. We do not plan to drill any operated Haynesville shale or Cotton Valley
wells in 2022.
At December 31, 2021, we held approximately 19,100 gross (17,700 net) acres in Northwest Louisiana, including
16,700 gross (9,100 net) acres in the Haynesville shale play and 16,100 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 (4,800 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, 2021.
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
leasehold interests in Northwest Louisiana, while for the year ended December 31, 2020, approximately 7% of
our average daily oil equivalent production, or 5,241 BOE per day, including eight Bbl of oil per day and 31.4 MMcf of
natural gas per day, was attributable to our properties in Northwest Louisiana. 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 our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2020, approximately 17%
of our daily natural gas production, or 31.4 MMcf of natural gas per day, was attributable to these properties. At
December 31, 2021, approximately 2% of our estimated total proved reserves, or 5.7 million BOE, was attributable
to our properties in Northwest Louisiana.
At December 31, 2021, we had identified 161 gross (15 net) engineered locations for potential future drilling in
the Haynesville shale play and 154 gross (35 net) engineered locations for potential future drilling in the Cotton
Valley formation. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral
lengths ranging from one mile to two miles, with most being two miles. These 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 producing Haynesville and Cotton Valley wells
and other nearby wells based on available public data, drilling densities observed on properties of other operators,
including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules
established by regulatory authorities and surface conditions, among other factors.
FORM 10-K PART I
16
MATADOR RESOURCES COMPANY
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) 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 22, 2022, we had earned $58.8 million of the potential $73.5 million in performance incentives. Through
February 22, 2022, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018,
2019, 2020 and 2021, and we may earn up to the remaining $14.7 million in San Mateo performance incentives
over the next year relating to the formation of San Mateo. 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 over the next several years,
plus additional performance incentives for securing volumes from third-party customers. During the fourth quarter of
2020, we met the threshold requirements to begin earning the additional $150.0 million in performance incentives
from Five Point. At February 22, 2022, we had received $33.9 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, 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.
FORM 10-K PART I
2021 ANNUAL REPORT
17
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.
During the third quarter of 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, 2021, 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.
In September 2020, San Mateo completed and placed in service 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, 2021, 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, in early 2018, San Mateo completed a natural gas liquids (“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 the 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, 2021, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and
related compression and treating systems. During the year ended December 31, 2021, San Mateo gathered
approximately 86.1 Bcf of natural gas, an increase of 17%, as compared to 73.9 Bcf of natural gas gathered during
the year ended December 31, 2020. In addition, during the year ended December 31, 2021, San Mateo processed
approximately 77.6 Bcf of natural gas at the Black River Processing Plant, an increase of 28%, as compared to
60.8 Bcf of natural gas processed during the year ended December 31, 2020. Natural gas gathering and processing
volumes for the years ended December 31, 2021 and 2020 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.
FORM 10-K PART I
18
MATADOR RESOURCES COMPANY
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.
In 2020, San Mateo completed and placed into service (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, 2021, 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, 2021, 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, 2021, the San Mateo Oil Pipeline Systems had
throughput of approximately 14.9 million Bbl of oil, an increase of 28%, as compared to throughput of approximately
11.6 million Bbl of oil during the year ended December 31, 2020.
Produced Water Gathering and Disposal Assets
During 2021, 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 three. In
addition to its three commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at
February 22, 2022, 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 22, 2022, San Mateo had designed disposal capacity of approximately 370,000 Bbl
of produced water per day.
During the year ended December 31, 2021, San Mateo handled approximately 101.4 million Bbl of produced
water, an increase of 20%, as compared to approximately 84.8 million Bbl of produced water handled during the
year ended December 31, 2020.
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.
FORM 10-K PART I
OPERATING SUMMARY
The following table sets forth certain unaudited production and operating data for the years ended December 31,
2021 ANNUAL REPORT
19
2021, 2020 and 2019.
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,
2021
2020
2019
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
$
13,984
61.1
24,164
66,203
$ 54.34
$ 54.98
$ 2.17
$ 2.18
$ 3.82
$ 4.85
$ 1.52
$ 14.51
$ 3.31
(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, 2021 from our operating areas, which we consider to be distinct fields for purposes
of accounting for production.
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)
Southeast
New Mexico/
West Texas
South Texas
Northwest Louisiana
Delaware Basin Eagle Ford(1)
Haynesville Cotton Valley (2)
Total
17,279
72.7
29,395
93.4%
558
1.3
776
2.5%
—
7.3
1,217
3.9%
3
0.4
66
0.2%
17,840
81.7
31,454
100.0%
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
9
1.0
182
$ —
$ 3.19
$ 19.16
$ 64.40
$ 4.31
$ 27.81
48,876
223.8
86,176
$ 67.58
$ 6.06
$ 54.06
Production Costs(5)
Lease operating, transportation and processing (per BOE)
$ 4.49
$ 19.51
$ 4.84
$ 25.69
$ 4.92
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%
3
0.5
83
0.3%
15,931
69.5
27,514
100.0%
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
8
1.3
226
$28.77
$ 1.66
$ 9.94
$38.31
$ 1.69
$11.09
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.
FORM 10-K PART I
2021 ANNUAL REPORT
21
The following table sets forth information regarding our production volumes, sales prices and production costs
for the year ended December 31, 2019 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)
12,843
44.7
20,294
84.0%
35,184
122.5
55,599
$ 53.95
$ 2.11
$ 38.80
1,136
2.0
1,463
6.0%
—
13.9
2,316
9.6%
5
0.5
91
0.4%
13,984
61.1
24,164
100.0%
3,113
5.4
4,009
$ 58.71
$ 3.45
$ 50.22
—
38.1
6,345
15
1.4
250
$ —
$ 2.16
$12.99
$52.89
$ 2.17
$15.22
38,312
167.4
66,203
$ 54.34
$
2.17
$ 36.93
$ 5.22
$ 15.27
$ 4.36
$22.43
$
5.81
(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 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.
Our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020
increased 14% from our total oil equivalent production of approximately 24.2 million BOE for the year ended
December 31, 2019. This increased production was primarily due to our delineation and development operations in
the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales.
Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, as
compared to 66,203 BOE per day for the year ended December 31, 2019. Our average daily oil production for the
year ended December 31, 2020 was 43,526 Bbl of oil per day, an increase of 14% from 38,312 Bbl of oil per day
for the year ended December 31, 2019. Our average daily natural gas production for the year ended December 31,
2020 was 189.9 MMcf of natural gas per day, an increase of 13% from 167.4 MMcf of natural gas per day for
the year ended December 31, 2019.
FORM 10-K PART I
22
MATADOR RESOURCES COMPANY
PRODUCING WELLS
The following table sets forth information relating to producing wells at December 31, 2021. 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, 2021. 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
784
388.4
160
79.7
944
468.1
128
107.5
3
3.0
131
110.5
—
1
1
913
—
1.0
1.0
496.9
233
62
295
458
18.3
38.6
56.9
139.6
233
63
296
1,371
18.3
39.6
57.9
636.5
(1)
Includes 212 gross (67.5 net) vertical wells that were acquired in multiple transactions.
(2) 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.
(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, 2021, 2020 and
2019. 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
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.
2021 ANNUAL REPORT
23
At December 31,(1)
2021
2020
2019
181,306
852.5
323,397
159,949
662.3
270,332
102,233
546.2
193,262
69,647
323.2
123,507
147,991
627.2
252,531
59,667
276.3
105,710
59.8%
45.7%
41.9%
79,073
306.4
130,135
90,301
339.1
146,825
88,324
351.0
146,821
$ 4,375.4
$ 5,347.6
$ 1,584.4
$ 1,658.0
$ 2,034.0
$ 2,248.2
(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, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas, for
the 12 months ended December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas and for the 12 months ended
December 31, 2019 were $52.19 per Bbl for oil and $2.58 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, 2021, 2020 and 2019 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, 2021, 2020 and 2019 were, in millions, $972.2, $73.6 and $214.2, respectively.
Our estimated total 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. This increase in proved oil and natural gas reserves was primarily
attributable to (i) our delineation and development operations in the Delaware Basin during 2021 and (ii) the 75%
increase in oil prices and the 81% increase in natural gas prices used to estimate total proved reserves at
December 31, 2021, as compared to December 31, 2020. We added 33.1 million BOE in proved oil and natural gas
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 our 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 we continue to
develop our Delaware Basin assets, we may reclassify some or all of this 16.3 million BOE to proved reserves at a
FORM 10-K PART I
24
MATADOR RESOURCES COMPANY
future date. We realized approximately 41.9 million BOE in net upward revisions to prior estimates, 96% of which
were 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 our properties. We also had small upward
revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain
of our properties. In addition, we realized 9.5 million BOE in net upward revisions to our proved oil and natural gas
reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021.
Our proved oil reserves grew 13% from approximately 159.9 million Bbl at December 31, 2020 to approximately
181.3 million Bbl at December 31, 2021. Our proved natural gas reserves increased 29% from 662.3 Bcf at
December 31, 2020 to 852.5 Bcf at December 31, 2021. Our proved reserves to production ratio at December 31,
2021 was 10.3, an increase of 5% from 9.8 at December 31, 2020.
The Standardized Measure of our total proved oil and natural gas reserves increased 176% from $1.58 billion at
December 31, 2020 to $4.38 billion at December 31, 2021. The PV-10 of our total proved oil and natural gas
reserves increased 223% from $1.66 billion at December 31, 2020 to $5.35 billion at December 31, 2021. The
increases in our Standardized Measure and PV-10 are primarily a result of the significantly higher weighted average
oil and natural gas prices used to estimate proved reserves at December 31, 2021, as compared to December 31,
2020, but also due to the 20% increase in our total proved oil and natural gas reserves at December 31, 2021, as
compared to December 31, 2020. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas
prices used to estimate proved reserves at December 31, 2021 were $63.04 per Bbl and $3.60 per MMBtu, an
increase of 75% and 81%, respectively, as compared to average oil and natural gas prices of $36.04 per Bbl and $1.99
per MMBtu used to estimate proved reserves at December 31, 2020. Our total proved reserves were made up of
56% oil and 44% natural gas at December 31, 2021 and 59% oil and 41% natural gas at December 31, 2020. 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, 2021.
As of December 31, 2020
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, 2021
(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
Proved
Developed
Reserves
(MBOE)(1)
123,507
22,427
4,907
33,804
(31,454)
40,071
193,262
Our proved developed oil and natural gas reserves increased 56% from 123.5 million BOE at December 31,
2020 to 193.3 million BOE at December 31, 2021. We added 22.4 million BOE in proved developed reserves
through extensions and discoveries during 2021, which resulted from new well locations drilled during 2021 to
establish proved reserves. We realized approximately 33.8 million BOE in net upward revisions to prior estimates,
97% 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 our producing properties.
We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated
operating costs on certain of our producing properties. In addition, we converted 40.1 million BOE of our proved
undeveloped reserves to proved developed reserves through our development activities in the Delaware Basin
FORM 10-K PART I
2021 ANNUAL REPORT
25
during 2021, primarily in our Stateline asset area, in the Greater Stebbins Area and in the Rodney Robinson
leasehold in the Antelope Ridge asset area. In addition, we realized 4.9 million BOE in net upward revisions to our
proved developed reserves at December 31, 2021 as a result of property acquisitions and divestitures completed
during 2021. These cumulative net upward revisions of 101.2 million BOE to our proved developed reserves exceeded
by 3.2 times our total oil and natural gas production of 31.5 million BOE in 2021.
Our proved developed oil reserves increased 47% from 69.6 million Bbl at December 31, 2020 to 102.2 million
Bbl at December 31, 2021. Our proved developed natural gas reserves increased 69% from 323.2 Bcf at
December 31, 2020 to 546.2 Bcf at December 31, 2021. Proved developed reserves constituted 60% of our total
proved oil and natural gas reserves at December 31, 2021, as compared to 46% at December 31, 2020.
The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2021.
As of December 31, 2020
Extensions and discoveries
Net acquisitions of minerals-in-place
Revisions of prior estimates
Conversion of proved undeveloped to proved developed
As of December 31, 2021
(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
Proved
Undeveloped
Reserves
(MBOE)(1)
146,825
10,647
4,622
8,112
(40,071)
130,135
Our proved undeveloped oil and natural gas reserves decreased 11% from 146.8 million BOE at December 31,
2020 to 130.1 million at December 31, 2021. We added 26.9 million BOE in proved undeveloped reserves through
extensions and discoveries during 2021, which resulted primarily from new proved undeveloped locations identified
as a result of drilling activities on our 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 the properties in the Delaware Basin. We realized approximately 8.1 million BOE in net upward
revisions to our prior estimates of proved undeveloped reserves, 90% 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 our proved undeveloped locations. We also had small upward revisions
to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our
proved undeveloped locations. In addition, we realized 4.6 million BOE in net upward revisions to our proved
undeveloped reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during
2021. During 2021, we also converted 40.1 million BOE of our proved undeveloped reserves to proved developed
reserves through our development activities in the Delaware Basin during 2021, primarily in our Stateline asset area,
in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area.
FORM 10-K PART I
26
MATADOR RESOURCES COMPANY
At December 31, 2021, 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, 2021 within five years of booking these
reserves. The following table sets forth, since 2018, proved undeveloped reserves converted to proved developed
reserves during each year and the investments associated with these conversions (dollars in thousands).
2018
2019
2020
2021
Total
Proved Undeveloped Reserves
Converted to
Proved Developed Reserves
Oil
(MBbl)
16,009
13,832
16,256
23,965
70,062
Natural Gas
Total
(Bcf)
(MBOE)(1)
61.7
58.8
76.1
96.6
293.2
26,283
23,629
28,944
40,071
118,927
Investment in Conversion
of Proved Undeveloped
Reserves to Proved
Developed Reserves
$ 356,830
318,609
257,590
240,664
$1,173,693
(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
The following table sets forth additional summary information by operating area with respect to our estimated
net proved reserves at December 31, 2021.
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)
177,137
809.3
312,018
$ 4,268.7
$ 5,217.2
4,146
9.1
5,663
78.8
96.2
—
23
23
181,306
29.1
5.0
34.1
852.5
4,848
868
5,716
323,397
26.3
1.6
27.9
$ 4,375.4
32.2
2.0
34.2
$ 5,347.6
(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, 2021 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, 2021 were approximately $972.2 million.
(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 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.
(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
FORM 10-K PART I
2021 ANNUAL REPORT
27
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.
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 Reserves Manager was primarily responsible for overseeing the preparation of our reserves
estimates in 2021. 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 nine
years of industry experience. Our Reserves Manager works under the direct supervision of our Senior 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 14 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 U.S. generally accepted accounting
principles (“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.
FORM 10-K PART I
28
MATADOR RESOURCES COMPANY
ACREAGE SUMMARY
The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at
December 31, 2021.
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
184,000
93,000
53,200
31,800
237,200
124,800
27,400
25,100
—
—
27,400
25,100
16,700
16,100
19,100
230,500
9,100
14,900
17,700
135,800
—
—
—
53,200
—
—
—
31,800
16,700
16,100
19,100
283,700
9,100
14,900
17,700
167,600
(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.
UNDEVELOPED ACREAGE EXPIRATION
The following table sets forth the approximate number of gross and net undeveloped acres at December 31,
2021 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 2027 and beyond totals 6,700 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, 2021.
Acres Expiring 2022
Acres Expiring 2023
Acres Expiring 2024
Acres Expiring 2025
Acres Expiring 2026
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Southeast New Mexico/
West Texas:
Delaware Basin(1)
Total
24,100
24,100
11,100
11,100
5,500
5,500
5,300
5,300
8,900
8,900
3,100
3,100
2,900
2,900
2,800
2,800
5,200
5,200
2,800
2,800
(1) Approximately 65% 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, 2021, 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, 2021, less than 2% of our proved oil and natural gas reserves would
be impacted by the expirations of this undeveloped acreage.
FORM 10-K PART I
DRILLING RESULTS
The following table summarizes our drilling activity for the years ended December 31, 2021, 2020 and 2019.
2021 ANNUAL REPORT
29
Development Wells
Productive
Dry
Exploration Wells
Productive
Dry
Total Wells
Productive
Dry
Year Ended December 31,
2021
2020
2019
Gross
Net
Gross
Net
Gross
Net
96
—
8
—
104
—
40.2
—
8.0
—
48.2
—
89
—
4
—
44.5
—
3.3
—
147
—
25
—
93
—
47.8
—
172
—
62.0
—
13.3
—
75.3
—
(1) At December 31, 2021, we had a total of 31 gross (27.0 net) development wells and two gross (1.1 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 or third parties’ processing facilities to
extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids 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 and natural gas production fluctuate widely. Factors that, directly or indirectly,
cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of
Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”), weather conditions,
including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin, oil and natural gas
storage levels, transportation and refinery capacity constraints, domestic and foreign governmental regulations,
price and availability of alternative fuels, political conditions in oil and natural gas producing regions, including Russia,
Ukraine, China and the Middle East, domestic or global health concerns such as COVID-19, the domestic and
foreign supply of oil and natural gas, the price of foreign imports and overall 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 and natural gas. Low oil and natural gas 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.”
FORM 10-K PART I
30
MATADOR RESOURCES COMPANY
The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark
prices, such as the NYMEX West Texas Intermediate (“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, 2021, 2020 and 2019, we had three, two and two significant purchasers,
respectively, that accounted for approximately 72%, 65% and 67%, 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.”
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 at December 31, 2021, the impact of 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.
FORM 10-K PART I
2021 ANNUAL REPORT
31
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.
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.”
FORM 10-K PART I
32
MATADOR RESOURCES COMPANY
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.
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 Bureau of Land Management (“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”). In 2019, 2020 and 2021, an environmental
group filed three 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, but the appeal was voluntarily dismissed in 2021. 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. The BLM has
not announced when it will complete the additional NEPA review, and the outcome of that review with regard to
the leases at issue and any related drilling permits is uncertain.
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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 gas leasing and permitting decisions by the BLM. In
February 2022, the Louisiana federal district court issued an injunction prohibiting the federal government, including
the Department of Interior and BLM, from utilizing the challenged social cost of greenhouse gases factor as a part of
NEPA reviews. Subsequent to that decision, the federal government submitted filings in the federal district court
indicating that the court’s injunction could, among other things, result in an indefinite delay of future lease sales and
permit approvals due to inconsistencies between the NEPA analyses and the court’s ruling.
Although some of the restrictions in the Biden Administrative Federal Lease Orders have lapsed at December 31,
2021, the impact of federal actions related to the oil and natural gas industry, including those in response to the Lease
Sale Litigation and Social Cost of Carbon 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.
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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
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, 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. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids
(i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017,
the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but
not yet published, be immediately withdrawn for further review. 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.”
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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.
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 gas exploration and development, and any
such changes could negatively affect our financial condition, results of operations, and cash flows. The Build Back
Better Act (H.R. 5376) was passed by the U.S. House of Representatives on November 19, 2021 and contains
certain U.S. federal income tax changes and certain additional taxes and fees.
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 regulators (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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MATADOR RESOURCES COMPANY
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 (the “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, however, and promulgated the Navigable Waters Protection Rule (the “NWPR”) in
2020. The NWPR defined what waters qualify as navigable waters of the United States and are under CWA
jurisdiction. This new rule has generally been viewed as narrowing the scope of WOTUS as compared to the 2015
rule, but there is currently litigation in multiple federal district courts challenging the rescission of the 2015 rule and
the promulgation of the NWPR.
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 U.S. Fish and Wildlife Service (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. The Corps has now issued a new set of NWPs, which would
replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017,
but has not elected not to consult with the USFWS. The re-issued NWPs have similarly been subject to the same
legal challenges based on the lack of a formal ESA consultation.
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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MATADOR RESOURCES COMPANY
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, which set
greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the
Paris Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to
rejoin the Paris Agreement. In April 2021, President Biden set a new goal for the United States 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. 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 New Mexico
Oil Conservation Division (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”) has also proposed similar rules and regulations.
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, recent scientific studies have suggested that emissions of certain gases, commonly referred to as
“greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s
atmosphere. Based on these 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.”
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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 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 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. In addition, 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. 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.
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
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MATADOR RESOURCES COMPANY
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 an 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.
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. 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
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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, 2021, 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 an 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
an 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. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon
Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden
Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these 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, 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.
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MATADOR RESOURCES COMPANY
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.”
OFFICE LOCATION
Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240.
HUMAN CAPITAL
At December 31, 2021, we had 286 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 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 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 2020, for example, our employees completed approximately 15,000 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
2021, we estimate our employees have worked approximately 2.7 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.
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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.
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 and results of operations. You should read this summary together with the more detailed
risk factors contained below.
Risks Related to our Financial Condition
• Our success is dependent on the prices of oil and natural gas, the volatility of which may adversely affect
our financial condition.
• We face numerous risks related to the COVID-19 global pandemic, including its impact on global oil demand.
• 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 may not reflect the actual volumes we will recover, and
we may be required to write down the carrying value of our proved properties under accounting rules.
• 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.
• Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses.
• 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 financial condition.
• A component of our growth may come through acquisitions, which we may be unable to complete or which
may require us to incur certain liabilities, risks or title deficiencies.
• Our ability to complete dispositions of assets may be subject to factors beyond our control, and in certain
cases we may be required to retain liabilities for certain matters.
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MATADOR RESOURCES COMPANY
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 indebtedness impose significant operating and financial
restrictions.
• Our credit rating may be downgraded, which could reduce our financial flexibility and increase interest expense.
• 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.
Risks Related to our Operations
• Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational,
geological and financial risk, and insurance against all such risks is not available to us.
• 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.
• 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, and multi-well pad drilling may result in volatility in our
operating results.
• 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.
• The unavailability or high cost of 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 unable to 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 the manner we have been.
• 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 our plans.
Risks Related to Third Parties
• We depend upon several significant purchasers for the sale of most of our production, and financial
difficulties encountered by such purchasers, other operators or 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.
• Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s
long-term success depends on its ability to obtain new sources of products.
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• 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.
• Competition in our industry is intense, making it more difficult for us to acquire properties, market
production, provide midstream services and secure trained personnel, and our competitors may use superior
technology and data resources.
• We have limited control over activities on properties we do not operate.
Risks Related to Laws and Regulations
• As of December 31, 2021, 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 environmental laws, which could require significant
expenditures.
• We are subject to tax laws, and changes thereto could eliminate or reduced certain federal income tax
deductions or net operating loss carryforwards currently available.
• Legislative and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and
climate change could result in increased costs, operating restrictions or delays.
• We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations,
and the rates of our regulated assets are subject to oversight by regulators, which could adversely affect
our revenues.
• Derivatives legislation adopted by Congress could limit our ability to hedge commodity price risks.
Risks Relating to Our Common Stock
• The price of our common stock is volatile 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 our stock price.
• Our directors and executive officers own a significant percentage of our equity, which could give them
influence in transactions and other matters, and their interests could differ from other shareholders.
• 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.
General Risk Factors
• We may have difficulty managing growth in our business.
• Our success depends on our ability to retain our key personnel.
•
If we fail to maintain effective internal control over financial reporting, our ability to accurately report our
financial results could be adversely affected.
• 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 that could have an adverse
effect on our results of operations and financial condition.
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MATADOR RESOURCES COMPANY
RISKS RELATED TO OUR FINANCIAL CONDITION
Our success is dependent on the prices of oil and natural gas. Low oil and natural gas 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 and natural gas 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 and natural gas 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 and natural gas have been volatile and will likely continue to be volatile in
the future. For the year ended December 31, 2021, oil prices averaged $68.11 per Bbl, as compared to $39.34
per Bbl in 2020, ranging from a low of $47.62 per Bbl at the start of the year to a high of $84.65 per Bbl in October,
based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2021,
natural gas prices averaged $3.71 per MMBtu, as compared to $2.13 per MMbtu in 2020, based upon the NYMEX
Henry Hub natural gas futures contract price for the earliest delivery date. During 2021, natural gas prices ranged
from a low of $2.45 per MMBtu in January to a high of $6.31 per MMBtu in October before finishing the year at
$3.73 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 and natural gas;
the actions of OPEC+ and state-controlled oil companies relating to oil price and production controls;
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;
• 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 China;
• 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;
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•
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 and natural gas 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 and natural gas prices do not necessarily
fluctuate in direct relation to each other.
Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and
natural gas that we can produce economically and could reduce the amount we may borrow under our Credit
Agreement. Should oil or natural gas 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.
We face numerous risks related to the COVID-19 global pandemic, which has had and is likely to 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 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. The extent to which COVID-19 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 outbreak and responsive measures, additional or modified government actions,
new information that may emerge concerning the severity of COVID-19 and the effectiveness of vaccines and
other actions taken to contain COVID-19 or treat its impact now or in the future, among others.
Some impacts of the COVID-19 pandemic that could have an 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;
•
•
further 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;
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 due to curtailed or shut-in production by Matador or other of
San Mateo’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;
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MATADOR RESOURCES COMPANY
•
•
•
•
•
•
•
•
•
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 and other critical midstream infrastructure
to be adversely impacted by outbreaks of COVID-19 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.
The COVID-19 outbreak continues to evolve, and the extent to which the outbreak 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.
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;
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•
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.
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 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.
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MATADOR RESOURCES COMPANY
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.
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 our 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 44% of our total proved reserves at December 31, 2021 consisted of undeveloped and
developed non-producing reserves, and those reserves may not ultimately be developed or produced.
At December 31, 2021, approximately 40% of our total proved reserves were undeveloped and approximately
4% 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.
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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. 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
FORM 10-K PART I
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MATADOR RESOURCES COMPANY
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.
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, 2021.
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.
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 could
turn negative and widen again 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. We have limited oil basis hedges in
place to mitigate our exposure to oil price differentials during 2022, and we have no derivative contracts in place to
mitigate our exposure to natural gas price differentials.
FORM 10-K PART I
2021 ANNUAL REPORT
53
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.
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. 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 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.
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MATADOR RESOURCES COMPANY
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
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
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.
FORM 10-K PART I
2021 ANNUAL REPORT
55
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,
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 22, 2022, the maximum facility amount under the Credit Agreement was $1.50 billion, the
borrowing base was $1.35 billion and our elected borrowing commitment was $700.0 million. 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 covenants noted below). At February 22, 2022, we had available
borrowing capacity of approximately $554.2 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 cash or 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.
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MATADOR RESOURCES COMPANY
As of February 22, 2022, the facility amount under the San Mateo Credit Facility was $450.0 million, and
San Mateo had available borrowing capacity of approximately $56.0 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 $700.0 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.
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 22,
2022, our borrowing base was $1.35 billion, our elected borrowing commitment was $700.0 million, the maximum
facility amount under the Credit Agreement was $1.50 billion and we had $100.0 million in outstanding borrowings
under, and approximately $45.8 million in outstanding letters of credit issued pursuant to, the Credit Agreement.
At February 28, 2022, we had repaid an additional $25.0 million, resulting in $75.0 million in borrowings outstanding
under 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
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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
Eurodollar loan. 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 daily adjusting LIBOR rate (as defined in the Credit Agreement), 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 Eurodollar loan, such borrowings will bear interest at a rate equal
to (x) the reserve adjusted LIBOR rate (as defined in the Credit Agreement) 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.
Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar
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 LIBO Rate (as defined in the San Mateo Credit Facility)
plus 1.00% plus, in each case, an amount ranging from 1.00% to 2.00% 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 Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen
interest period plus (y) an amount ranging from 2.00% to 3.00% 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.
As noted above, under the Credit Agreement and the San Mateo Credit Facility, borrowings in the form of
Eurodollar loans currently accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected
to be discontinued. Each of the Credit Agreement and the San Mateo Credit Facility specify that the use of LIBOR
as a global reference rate will, upon the occurrence of certain events, transition to a rate based on the Secured
Overnight Financing Rate (“SOFR”) plus a credit spread adjustment. As a result, the interest rate for borrowings
under the Credit Agreement and the San Mateo Credit Facility may be higher than an interest rate based solely on
LIBOR. Each of the Credit Agreement and the San Mateo Credit Facility also specify that in the event that LIBOR
and SOFR cannot be determined or other conditions exist with respect to LIBOR and SOFR, a replacement interest
rate that gives due consideration to the then-prevailing market convention for determining a rate of interest for
syndicated loans in the United States at such time may be established by the respective administrative agents, in
consultation with us. If such an event occurs and we are unable to agree upon a replacement interest rate with
our respective administrative agents, we could be unable to make borrowings in the form of Eurodollar loans and
would have to borrow funds at the higher base rate, which could increase our cost of capital. Furthermore, the
overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR or the use of SOFR
as a replacement for LIBOR. An increase in our cost of capital or a disruption in the financial market could have an
adverse effect on our business and financial condition.
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MATADOR RESOURCES COMPANY
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.
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 cash
or 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, 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 adversely affect our ability to finance future operations or capital needs or to engage
in other business activities.
FORM 10-K PART I
2021 ANNUAL REPORT
59
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 and to “B1” in September 2021. S&P Global Ratings
upgraded our corporate credit rating to “B” in June 2021 and “B+” in January 2022. In September 2021, Fitch Ratings
assigned us a corporate credit rating of “B+.” As of February 22, 2022, our corporate credit ratings from
S&P Global Ratings, Moody’s Investors Service and Fitch Ratings remained “B+,” “B1” and “B+,” 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.
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.
Our Board of Directors declared a quarterly dividend of $0.025 per share of common stock in each of the first
three quarters of 2021 and, in October 2021, the Board amended our dividend policy to increase the quarterly
dividend and declared a quarterly cash dividend of $0.05 per share of common stock. We intend to continue to
pay a quarterly dividend in the future pursuant to a 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.
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MATADOR RESOURCES COMPANY
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,
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.
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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 2021, 98% of the operated wells we turned to
sales had lateral lengths of two miles or greater. In 2022, we anticipate that 90% of the operated wells we turn
to sales should have lateral lengths of two miles or greater. 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.
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;
•
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
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MATADOR RESOURCES COMPANY
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.
There are also significant risks associated with the operation of cryogenic natural gas processing plants such as
the Black River Processing Plant owned by San Mateo and operated by us. Natural gas and NGLs are volatile and
explosive and may include carcinogens. Damage to or improper operation of the Black River 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 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 costs to access and transport on these third-party
pipelines significantly increase, its 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 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.
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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 93% of our total oil and natural gas production for 2021 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 2022 will continue to be in the
Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville
shale positions to maintain and extend leases and to participate in certain non-operated well opportunities.
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, 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 financial condition, results of operations and cash flows.
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MATADOR RESOURCES COMPANY
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.
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 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,
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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.
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 an 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.
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MATADOR RESOURCES COMPANY
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 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, 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. In addition, the BLM has indicated that the Lease
Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits.
Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31,
2021, the impact of these 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, 2021, we had leasehold interests in approximately 25,100 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 2027. 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
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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.
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, 2021, 2020 and 2019, we had three, two and two significant purchasers, respectively, that collectively
accounted for approximately 72%, 65% and 67%, 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 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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MATADOR RESOURCES COMPANY
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 2022. 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 the Delaware Basin 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,
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69
and we may be required to increase our level of financial commitment or 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 financial condition, results of
operations and cash flows.
Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s
long-term success depends on its ability to obtain new sources of products, which depends on certain
factors beyond San Mateo’s control. Any decrease in supplies to its midstream facilities could adversely
affect San Mateo’s business and operating results.
San Mateo’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
gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new
sources of products. San Mateo’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 has no control over the level of activity in the areas of its
operations, the amount of reserves associated with the wells or the rate at which production from a well will decline.
In addition, San Mateo has 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, 2021, our long-term contractual obligations under agreements with
minimum volume commitments totaled approximately $987.6 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,
depends in part on our ability to compete with other midstream service companies to attract third-party customers
to our midstream facilities. 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. 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, 2021, Matador held approximately 124,800 net leasehold and mineral acres in the Delaware
Basin in Eddy and Lea Counties, New Mexico and in Loving County, Texas, of which approximately 38,600 net
acres, or about 31%, were 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 an 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 an 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. In addition, the BLM has indicated that the Lease Sale
Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although
some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021,
the impact of these 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 an
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, has the potential to delay or even halt development of future oil and natural
gas projects with NEPA applicability.
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. The change in the presidential administration 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,
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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 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).
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. Furthermore, we participate in candidate conservation agreements for the lesser
prairie-chicken, 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. Participation in such agreements or the designation of
previously unprotected species as threatened or endangered species could prohibit drilling or other operations
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MATADOR RESOURCES COMPANY
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 an 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.
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
(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 Build Back Better Act (H.R.
5376) was passed by the U.S. House of Representatives on November 19, 2021 and contains certain U.S. federal
income tax changes, including a 15% corporate minimum tax imposed on net taxable income of 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. 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. These rules were rescinded by rule in December 2017; however, in January
2018, California and a coalition of environmental groups filed a lawsuit in the Northern District of California to
challenge the BLM’s rescission of the rules. The Northern District of California upheld the rescission in 2020, but
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this decision was then appealed to the Ninth Circuit Court of Appeals. However, in October 2020, the U.S. District
Court for the District of Wyoming found that the BLM exceeded its statutory authority and acted arbitrarily in
promulgating the 2016 Waste Prevention Rule. The court ordered that the rule be vacated, except for certain
severable provisions. This decision has been appealed to the Tenth Circuit Court of Appeals.
Various policymakers, regulatory agencies and political candidates at the federal, state and local levels have
proposed restrictions on hydraulic fracturing, including its outright prohibition. At various times during his presidential
campaign, President Biden indicated support for prohibitions of hydraulic fracturing on federal lands or outright.
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 at the local, state or federal
level could limit our operations.
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 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 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
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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 our
operations and could lead to operational delays or increased operating costs. Additional regulation and attention
given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities.
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.
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 nationally determined
contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the
United States exited the Paris Agreement in November 2020, effective February 19, 2021, President Biden caused
the United States to rejoin the Paris Agreement. In April 2021, President Biden set a new goal for the United States
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. 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
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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 also proposed similar
rules and regulations. 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.
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. 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 an 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. In addition, the BLM has indicated that the Lease Sale Litigation and
the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the
restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of
these 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 Congress, 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 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 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, the Department of the Interior
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 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. However, in October 2020, the U.S. District Court for the District of Wyoming found that the BLM exceeded
its statutory authority and acted arbitrarily in promulgating the 2016 Waste Prevention Rule. The court ordered that
the rule be vacated, except for certain severable provisions. This decision has been appealed to the Tenth Circuit
Court of Appeals. If not withdrawn or significantly revised, these 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 to reduce methane and other pollutants from the oil and gas industry. 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.
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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 proposed rulemaking that would expand existing
integrity management requirements to natural gas transmission and gathering lines in areas with medium population
densities. 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.
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
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MATADOR RESOURCES COMPANY
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.
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.
The 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.
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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.
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 2021,
our stock price fluctuated between a high of $47.23 and a low of $12.02. 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;
•
the realization of any of the risk factors presented in this Annual Report;
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MATADOR RESOURCES COMPANY
•
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.
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.
FORM 10-K PART I
2021 ANNUAL REPORT
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Our directors and executive officers own a significant percentage of our equity, which could give them
influence in corporate transactions and other matters, and the interests of our directors and executive
officers could differ from other shareholders.
As of February 22, 2022, our directors and executive officers beneficially owned approximately 6.5% 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.
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 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
FORM 10-K PART I
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MATADOR RESOURCES COMPANY
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.
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.
If we fail to maintain effective internal control over financial reporting in the future, our ability to accurately
report our financial results could be adversely affected.
As a public company with listed equity securities, we are required to comply with laws, regulations and
requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of
the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is
difficult and costly and occupies a significant amount of time of our Board of Directors and management.
Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over financial reporting. Our
efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls
over our financial processes and reporting in the future and comply with the certification and reporting obligations
under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls
and disclosure controls will prevent all possible error or all fraud. Any failure to maintain effective controls could
result in material misstatements that are not prevented or detected and corrected on a timely basis, which could
potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective
internal controls could also cause investors to lose confidence in our reported financial information and adversely
affect our business and our stock price.
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. We depend on 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 supervisory control and data acquisition (SCADA) systems, control important processes and facilities
that are critical to our operations. 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 and the inability to engage in any of the aforementioned
activities. Any such consequence could have a material adverse effect on our business.
FORM 10-K PART I
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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
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 or financial loss.
As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and
enhance our protective systems or to investigate and remediate any vulnerabilities.
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 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 an 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 an 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.
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MATADOR RESOURCES COMPANY
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 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
2021 ANNUAL REPORT
87
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 22, 2022, we had 118,043,776 shares of common stock outstanding held by approximately 335 record
holders, excluding shareholders for whom shares are held in “nominee” or “street” name.
EQUITY COMPENSATION PLAN INFORMATION
The following table presents the securities authorized for issuance under our equity compensation plans as of
December 31, 2021.
Plan Category
Equity compensation plans approved by security holders(1)(2)
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
2,248,984
—
2,248,984
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
$ 22.92
—
$ 22.92
Number of Shares
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
1,571,972
—
1,571,972
(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.
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MATADOR RESOURCES COMPANY
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
180
160
140
120
100
80
60
40
20
0
12/31/16
06/30/17
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
MTDR
Russell 2000
Russell 2000 Energy
FORM 10-K PART I I
2021 ANNUAL REPORT
89
REPURCHASE OF EQUITY BY THE COMPANY OR AFFILIATES
During the quarter ended December 31, 2021, 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, 2021 to October 31, 2021
November 1, 2021 to November 30, 2021
December 1, 2021 to December 31, 2021
Total
—
2,051
4,321
6,372
$ —
39.55
38.26
$ 38.68
—
—
—
—
—
—
—
—
(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
90
MATADOR RESOURCES COMPANY
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 impact of the worldwide spread 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, 2020 and December 31, 2019,
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, 2020, filed with the SEC on February 26, 2021.
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, primarily through San Mateo, 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.
2021 Operational Highlights
We began 2021 operating three drilling rigs in the Delaware Basin, as we continued to focus on the exploration,
delineation and development of our Delaware Basin acreage in Lea and Eddy Counties, New Mexico and Loving
County, Texas. In March 2021, we added a fourth rig to our operated drilling program, and in August 2021, we began
operating a fifth drilling rig on behalf of San Mateo for the purpose of drilling an additional salt water disposal well
in the southern part of the Arrowhead asset area in Eddy County, New Mexico (the “Greater Stebbins Area”). In
October 2021, following the conclusion of drilling operations on the salt water disposal well, we moved this rig to
the Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area in Lea County, New Mexico.
We operated five drilling rigs in the Delaware Basin during the remainder of 2021. Despite the addition of the
fifth operated drilling rig and the acceleration of 11 Voni well completions forward into the fourth quarter of 2021,
FORM 10-K PART I I
2021 ANNUAL REPORT
91
we were able to achieve D/C/E capital expenditures for 2021 of $513 million, which was below our original estimated
range for 2021 D/C/E capital expenditures of $525 to $575 million as provided on February 23, 2021 and our revised
estimated range for 2021 D/C/E capital expenditures of $535 to $565 million as provided on October 26, 2021.
During the year ended December 31, 2021, we completed and began producing oil and natural gas from 47 gross
(44.2 net) operated and 50 gross (4.0 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
2021, although we did participate in the drilling and completion of seven gross (less than 0.1 net) non-operated
Haynesville shale wells that began producing in 2021.
The vast majority of our 2021 capital expenditures was directed to (i) the delineation and development of our
leasehold position in the Delaware Basin, (ii) the development of certain midstream assets to support our operations
there, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin 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 remaining capital expenditures were primarily directed to the
installation of pumping units and other facilities on certain of our Eagle Ford shale wells in South Texas and to our
participation in several non-operated wells drilled and completed in the Haynesville shale in Northwest Louisiana
throughout 2021.
Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day,
including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, an increase of 15%, as compared to
75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, for the year ended
December 31, 2020. Our average daily oil production in 2021 of 48,876 Bbl of oil per day increased 12% from
43,526 Bbl of oil per day in 2020. 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 223.8 MMcf per day in 2021 increased 18% from 189.9 MMcf per day in 2020. This increase
in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in
the Delaware Basin, which offset declining natural gas production in the Haynesville shale where we had
significantly less non-operated activity in 2020 and 2021 as compared to 2019. Oil production comprised 57% of
our total production for the year ended December 31, 2021, as compared to 58% in 2020.
For the year ended December 31, 2021, our oil and natural gas revenues were $1.70 billion, an increase of
128% from oil and natural gas revenues of $744.5 million for the year ended December 31, 2020. Our oil revenues
increased 102% to $1.21 billion, as compared to $595.5 million for the year ended December 31, 2020. The
increase in oil revenues resulted from a significantly higher weighted average realized oil price of $67.58 per Bbl in
2021, as compared to $37.38 per Bbl in 2020, as well as the 12% increase in oil production for the year ended
December 31, 2021 noted above. Our natural gas revenues increased 232% to $494.9 million, as compared to
$149.0 million for the year ended December 31, 2020. The increase in natural gas revenues resulted from an almost
three-fold increase in our weighted average realized natural gas price of $6.06 per Mcf in 2021, as compared to
$2.14 per Mcf in 2020, and the 18% increase in our natural gas production noted above.
We reported net income attributable to Matador shareholders of approximately $585.0 million, or $4.91 per
diluted common share, on a GAAP basis for the year ended December 31, 2021, as compared to a net loss of
$593.2 million, or ($5.11) per diluted common share, for the year ended December 31, 2020. Adjusted EBITDA for
the year ended December 31, 2021 was $1.05 billion, as compared to Adjusted EBITDA of $519.3 million for the
year ended December 31, 2020. 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
92
MATADOR RESOURCES COMPANY
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. At December 31, 2020, our estimated total proved oil and natural gas reserves were 270.3 million
BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, with a Standardized Measure of $1.58 billion
and a PV-10 of $1.66 billion. Our estimated total proved reserves of 323.4 million BOE at December 31, 2021
represented a 20% year-over-year increase, as compared to 270.3 million BOE at December 31, 2020. Our estimated
proved oil reserves of 181.3 million Bbl at December 31, 2021 increased 13%, as compared to 159.9 million Bbl
at December 31, 2020, and our estimated proved natural gas reserves of 852.5 Bcf at December 31, 2021 increased
29%, as compared to 662.3 Bcf at December 31, 2020. Proved oil reserves comprised 56% of our total proved
reserves at December 31, 2021, as compared to 59% at December 31, 2020. At December 31, 2021, 60% of our
total proved reserves were proved developed reserves, as compared to 46% at December 31, 2020.
Our proved oil and natural gas reserves in the Delaware Basin increased 19% to 312.0 million BOE at
December 31, 2021, as compared to 261.9 million BOE at December 31, 2020, primarily as a result of our ongoing
delineation and development operations there. At December 31, 2021, approximately 96% 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 13% to 177.1 million Bbl at December 31, 2021, as compared to 156.3 million Bbl at
December 31, 2020, and our proved natural gas reserves in the Delaware Basin increased 28% to 809.3 Bcf, as
compared to 633.5 Bcf at December 31, 2020. Proved oil reserves comprised 57% of our Delaware Basin total
proved reserves at December 31, 2021, as compared to 60% at December 31, 2020.
At both December 31, 2021 and December 31, 2020, 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.”
2021 Midstream Highlights
San Mateo achieved strong operating results in 2021, 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 2020. Volumes for the years
ended December 31, 2021 and 2020 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,
2021 and 2020. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.
During 2021, 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.
FORM 10-K PART I I
2021 ANNUAL REPORT
93
At December 31, 2021, 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
90 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: 14 commercial salt water disposal wells and associated facilities with designed
produced water disposal capacity of 370,000 Bbl per day and approximately 130 miles of produced water
gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
2022 Capital Expenditure Budget
We expect that development of our Delaware Basin assets will be the primary focus of our operations and
capital expenditures in 2022. In the second half of 2021, we added a fifth operated drilling rig in the Delaware Basin
to drill a salt water disposal well on behalf of San Mateo. In October 2021, following the conclusion of drilling
operations on the salt water disposal well, we began drilling oil and natural gas wells with this rig, and we plan to
operate these five contracted drilling rigs in the Delaware Basin throughout 2022. In addition, at February 22, 2022,
we had contracted a sixth operated drilling rig to begin drilling operations immediately on recently acquired
acreage in western Lea County, New Mexico in our Ranger asset area. We expect to operate this sixth rig on the
newly acquired acreage throughout the remainder of 2022. We have built significant optionality into our 2022 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 2022 estimated capital expenditure budget consists of
$640.0 to $710.0 million for D/C/E capital expenditures and $50.0 to $60.0 million for midstream capital expenditures,
which primarily reflects our proportionate share of San Mateo’s estimated 2022 capital expenditures. Substantially
all of these 2022 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, with the exception of amounts
allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases
and to participate in certain non-operated well opportunities. Our 2022 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 2022, including 90%
with anticipated completed lateral lengths of two miles or greater.
At December 31, 2021, we had $48.1 million in cash (excluding restricted cash) and $554.2 million in undrawn
borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our
elected borrowing commitment of $700.0 million). Excluding any possible significant acquisitions, we expect to
fund our 2022 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 2022, we expect to fund any such excess capital expenditures 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 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.
FORM 10-K PART I I
94
MATADOR RESOURCES COMPANY
We may divest portions of our non-core assets, particularly in the Haynesville shale and in our South Texas position
(as we did in 2020, 2021 and early 2022), 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 2022. 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 2022 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 acquisitions of producing properties, acreage and mineral
interests and midstream assets for 2022. The aggregate amount of capital we 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.
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,
2021
2020
2019
$ 1,205,608
494,934
1,700,542
75,499
86,034
—
(220,105)
21,011
$ 1,662,981
$595,507
148,954
744,461
64,932
41,742
4,062
38,937
(32,008)
$862,126
$759,811
132,514
892,325
59,110
74,769
1,711
9,482
(53,727)
$983,670
17,840
81.7
31,454
86,176
15,931
69.5
27,514
75,175
13,984
61.1
24,164
66,203
$
$
$
$
67.58
56.70
6.06
5.74
$
$
$
$
37.38
39.83
2.14
2.14
$
$
$
$
54.34
54.98
2.17
2.18
(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.
FORM 10-K PART I I
2021 ANNUAL REPORT
95
Year Ended December 31, 2021 as Compared to Year Ended December 31, 2020
Oil and natural gas revenues. Our oil and natural gas revenues increased $956.1 million, or 128%, to $1.70 billion
for the year ended December 31, 2021, as compared to $744.5 million for the year ended December 31, 2020.
Our oil revenues increased $610.1 million, or 102%, to $1.21 billion for the year ended December 31, 2021, as
compared to $595.5 million for the year ended December 31, 2020. This increase in oil revenues resulted from an
81% increase in the weighted average oil price realized for the year ended December 31, 2021 to $67.58 per Bbl,
as compared to $37.38 per Bbl realized for the year ended December 31, 2020, and the 12% increase in our oil
production to 17.8 million Bbl of oil for the year ended December 31, 2021, as compared to 15.9 million Bbl of oil
for the year ended December 31, 2020. 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
$346.0 million, or 232%, to $494.9 million for the year ended December 31, 2021, as compared to $149.0 million
for the year ended December 31, 2020. The increase in natural gas revenues was primarily attributable to the
almost three-fold increase in the weighted average natural gas price realized for the year ended December 31, 2021
to $6.06 per Mcf, as compared to $2.14 per Mcf realized for the year ended December 31, 2020, and the 18%
increase in our natural gas production to 81.7 Bcf for the year ended December 31, 2021, as compared to 69.5 Bcf
for the year ended December 31, 2020. The increase in natural gas production was primarily attributable to our
ongoing delineation and development drilling activities in the Delaware Basin, which offset declining natural gas
production from our properties in the Haynesville shale.
Third-party midstream services revenues. Our third-party midstream services revenues increased $10.6 million,
or 16%, to $75.5 million for the year ended December 31, 2021, as compared to $64.9 million for the year ended
December 31, 2020. 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 $37.6 million
for the year ended December 31, 2021, as compared to $30.1 million for the year ended December 31, 2020, (ii) an
increase in our third-party oil gathering and transportation revenues to $10.2 million for the year ended December 31,
2021, as compared to $9.4 million for the year ended December 31, 2020, and (iii) an increase in third-party
produced water handling revenues to $27.6 million for the year ended December 31, 2021, as compared to
$25.5 million for the year ended December 31, 2020.
Sales of purchased natural gas. Our sales of purchased natural gas increased $44.3 million, or 106%, to
$86.0 million for the year ended December 31, 2021, as compared to $41.7 million for the year ended December 31,
2020. 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, 2021. 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 the 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.
FORM 10-K PART I I
96
MATADOR RESOURCES COMPANY
Lease bonus - mineral acreage. We did not lease any of our mineral acreage to third parties during the year
ended December 31, 2021. Our lease bonus - mineral acreage revenues were $4.1 million for the year ended
December 31, 2020. Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or
extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests.
Realized (loss) gain on derivatives. Our realized net loss on derivatives was $220.1 million for the year ended
December 31, 2021, as compared to a realized net gain of approximately $38.9 million for the year ended
December 31, 2020. 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 a net gain of $35.1 million related to our oil costless collar, put
and swap contracts for the year ended December 31, 2020, resulting primarily from oil prices that were below
the floor prices of certain of our oil costless collar contracts and below the strike price of certain of our oil put and
swap contracts. We realized a net gain of $3.8 million from our oil basis swap contracts for the year ended
December 31, 2020, 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 $10.88 per Bbl of oil produced
during the year ended December 31, 2021, as compared to an average gain of $2.45 per Bbl of oil produced during
the year ended December 31, 2020. We realized 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, as compared to no gain or loss
on our natural gas derivatives during the year ended December 31, 2020. Our total oil volumes hedged for the
year ended December 31, 2021 represented 61% of our total oil production, as compared to 77% of our total oil
production for the year ended December 31, 2020. Our total natural gas volumes hedged for the year ended
December 31, 2021 represented 62% of our total natural gas production, as compared to 10% of our total natural
gas production for the year ended December 31, 2020.
Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $21.0 million for
the year ended December 31, 2021, as compared to an unrealized loss of $32.0 million for the year ended
December 31, 2020. During the year ended December 31, 2021, the aggregate net fair value of our open oil and
natural gas derivatives and oil basis swap contracts increased 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. During the year ended December 31, 2020, 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 $3.9 million to a net liability of $35.9 million, resulting in an unrealized loss on derivatives of approximately
$32.0 million for the year ended December 31, 2020.
FORM 10-K PART I I
2021 ANNUAL REPORT
97
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
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
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,
2021
2020
2019
$ 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
(55,668)
$ 584,968
$
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)
(39,645)
$ (593,205)
5.69
$
3.46
$
1.95
$
$ 10.97
3.06
$
$
$
$
$
$
3.39
3.81
1.51
13.15
2.27
$ 92,273
117,305
36,798
69,398
350,540
1,822
—
80,054
748,190
235,480
(967)
(73,873)
(2,126)
(76,966)
158,514
35,532
(35,205)
$ 87,777
$
$
$
$
$
3.82
4.85
1.52
14.51
3.31
Year Ended December 31, 2021 as Compared to Year Ended December 31, 2020
Production taxes, transportation and processing. Our production taxes and transportation and processing
expenses increased $85.6 million, or 92%, to $179.0 million for the year ended December 31, 2021, as compared to
$93.3 million for the year ended December 31, 2020. On a unit-of-production basis, our production taxes and
transportation and processing expenses increased 68% to $5.69 per BOE for the year ended December 31, 2021,
as compared to $3.39 per BOE for the year ended December 31, 2020. These increases were primarily attributable
to the $76.5 million increase in our production taxes to $129.8 million for the year ended December 31, 2021, as
compared to $53.4 million for the year ended December 31, 2020, resulting from the $956.1 million increase in oil
and natural gas revenues for the year ended December 31, 2021, as compared to the year ended December 31,
2020 and the $9.2 million increase in transportation and processing expenses to $49.2 million for the year ended
December 31, 2021, as compared to $40.0 million for the year ended December 31, 2020, primarily resulting from
the 14% increase in total oil equivalent production between the respective periods.
FORM 10-K PART I I
98
MATADOR RESOURCES COMPANY
Lease operating expenses. Our lease operating expenses increased $4.0 million, or 4%, to $109.0 million for
the year ended December 31, 2021, as compared to $105.0 million for the year ended December 31, 2020. This
increase in our lease operating expenses for the year ended December 31, 2021 was attributable to an increase in
workover expenses of $4.0 million, which resulted from additional well maintenance operations conducted during
the year-ended December 31, 2021, as compared to 2020. On a unit-of-production basis, our lease operating
expenses decreased 9% to $3.46 per BOE for the year ended December 31, 2021, as compared to $3.81 per BOE
for the year ended December 31, 2020, primarily resulting from the 14% increase in total oil equivalent production
between the respective periods.
Plant and other midstream services operating. Our plant and other midstream services operating
expenses increased $20.0 million, or 48%, to $61.5 million for the year ended December 31, 2021, as compared
to $41.5 million for the year ended December 31, 2020. This increase was primarily attributable to (i) increased
expenses associated with our expanded commercial produced water disposal operations of $30.8 million for the
year ended December 31, 2021, as compared to $21.8 million for the year ended December 31, 2020, (ii) increased
expenses associated with our expanded pipeline operations of $17.5 million for the year ended December 31, 2021,
as compared to $10.0 million for the year ended December 31, 2020, and (iii) increased expenses associated with
operating the Black River Processing Plant of $13.1 million for the year ended December 31, 2021, as compared to
$9.7 million for the year ended December 31, 2020.
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased
$16.9 million, or 5%, to $344.9 million for the year ended December 31, 2021, as compared to $361.8 million
for the year ended December 31, 2020. On a unit-of-production basis, our depletion, depreciation and amortization
expenses decreased 17% to $10.97 per BOE for the year ended December 31, 2021, as compared to $13.15
per BOE for the year ended December 31, 2020. These decreases were primarily attributable to the decrease in
unamortized property costs resulting from the full-cost ceiling impairments recorded during the year ended
December 31, 2020. These decreases were partially offset by (i) the 14% increase in total oil equivalent production
to 31.5 million BOE for the year ended December 31, 2021, as compared to 27.5 million BOE for the year
ended December 31, 2020, and (ii) increased depreciation expenses attributable to our midstream segment of
approximately $31.5 million for the year ended December 31, 2021, as compared to $23.3 million for the year
ended December 31, 2020.
Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no
corresponding charge resulting from a full-cost ceiling impairment were recorded for the year ended December 31,
2021. Due to the sharp decline in oil and natural gas prices used to estimate proved oil and natural gas reserves in
2020, at June 30, 2020, September 30, 2020 and December 31, 2020, the net capitalized costs of our oil and
natural gas properties less related deferred income taxes exceeded the full-cost ceiling. As a result, we recorded an
impairment charge of $684.7 million, exclusive of tax effect, to our net capitalized costs. This full-cost ceiling
impairment is reflected in our consolidated statement of operations for the year ended December 31, 2020, with
the related deferred income tax credit recorded net of a valuation allowance.
General and administrative. Our general and administrative expenses increased $33.8 million, or 54%, to
$96.4 million for the year ended December 31, 2021, as compared to $62.6 million for the year ended December 31,
2020. Our general and administrative expenses on a unit-of-production basis increased 35% to $3.06 per BOE
for the year ended December 31, 2021, as compared to $2.27 per BOE for the year ended December 31, 2020.
These increases were largely attributable to employee compensation costs, including a $16.1 million increase
in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which
are remeasured at each reporting period based upon our share price at the end of each reporting period. The
share price of our common stock increased from $12.06 at December 31, 2020 to $36.92 at December 31, 2021.
FORM 10-K PART I I
2021 ANNUAL REPORT
99
The remainder of the increase for the year ended December 31, 2021, as compared to December 31, 2020,
resulted primarily from the reinstatement of employee compensation beginning in March 2021, which had been
previously reduced beginning in March 2020 in response to the significantly lower oil and natural gas price
environment at that time.
Interest expense. For the year ended December 31, 2021, we incurred total interest expense of approximately
$79.5 million. We capitalized approximately $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. For the year ended
December 31, 2020, we incurred total interest expense of approximately $82.2 million. We capitalized $5.5 million
of our interest expense on certain qualifying projects for the year ended December 31, 2020 and expensed the
remaining $76.7 million to operations.
Total income tax provision (benefit). At December 31, 2020, our deferred tax assets exceeded our deferred
tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2020. As a result, we
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 our significant net income in 2021, our federal valuation allowance was
reversed at September 30, 2021 as the deferred tax assets were determined to be more likely than not to be
utilized. As a portion of our 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. We recorded a total income tax provision of $74.7 million for the year ended December 31, 2021. Our
effective tax rate was 11.3% for the year ended December 31, 2021, which differed from amounts computed by
applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of reversing the valuation
allowance, but also due to permanent differences between book and taxable income and state taxes, primarily
in New Mexico. We recorded a total income tax benefit of $45.6 million for the year ended December 31, 2020. Our
effective tax rate was 7.6% for the year ended December 31, 2020, which differed from amounts computed by
applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of the valuation allowance,
but also due 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 2022 and for the foreseeable
future, for the acquisition, exploration and development of oil and natural gas properties and for midstream
investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditures for 2022
primarily 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 2022,
we expect to fund any such excess capital expenditures 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 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.
At December 31, 2021, we had cash totaling $48.1 million and restricted cash totaling $38.8 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.
FORM 10-K PART I I
100
MATADOR RESOURCES COMPANY
At December 31, 2021, we had (i) $1.05 billion of outstanding 5.875% senior notes due September 2026 (the
“Notes”), (ii) $100.0 million in borrowings outstanding under the Credit Agreement, (iii) approximately $45.8 million
in outstanding letters of credit issued pursuant to the Credit Agreement and (iv) $7.5 million outstanding under
an unsecured U.S. Small Business Administration (“SBA”) loan. In November 2021, the Company and lenders under
our Credit Agreement entered into a Fourth Amended and Restated Credit Agreement, under which the borrowing
base was increased to $1.35 billion. We elected to keep the borrowing commitment at $700.0 million, the maximum
facility amount remained $1.5 billion and certain modifications were made to the terms of the Credit Agreement.
These modifications include extending the maturity date to October 31, 2026, increasing the borrowing rate for
a base rate loan or a Eurodollar loan under such facility by 0.50% and updating the key financial covenants under the
Credit Agreement to require 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 total debt outstanding (net of up to $75.0 million of cash
or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less. This November 2021
update to the Credit Agreement took the place of the regularly scheduled November 1 redetermination. 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 above). We believe that we were in
compliance with the terms of the Credit Agreement at December 31, 2021. Between December 31, 2021 and
February 28, 2022, we repaid an additional $25.0 million of borrowings outstanding under the Credit Agreement.
At December 31, 2021, San Mateo had $385.0 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. The San Mateo Credit Facility matures December 19, 2023 and was amended in June 2021 to increase the
lender commitments under that facility from $375 million to $450 million (subject to San Mateo’s compliance
with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under
such facility by 0.50%. The San Mateo Credit Facility contains an accordion feature, which, after the aforementioned
amendment, provides for potential increases in lender commitments to up to $700.0 million. The San Mateo Credit
Facility is guaranteed by San Mateo’s subsidiaries, secured by substantially all of San Mateo’s assets, including
real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries. 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. We believe that San Mateo was in compliance with the terms of
the San Mateo Credit Facility at December 31, 2021. Between December 31, 2021 and February 22, 2022, we
repaid an additional $30.0 million of borrowings outstanding under the San Mateo Credit Facility.
FORM 10-K PART I I
2021 ANNUAL REPORT
101
On April 13, 2020, we executed a promissory note evidencing an unsecured loan in the amount of approximately
$7.5 million as part of the Paycheck Protection Program. The Paycheck Protection Program was established
under the Coronavirus Aid, Relief, and Economic Security Act and is administered by the SBA. The loan was issued
through Iberiabank, which is a lender under the Credit Agreement, matures on the second anniversary of the
funding date and bears interest at a fixed rate of 1.00% per annum. We used the proceeds of the loan for payroll,
including salaries, payroll taxes and employee medical benefits, as permitted by the program. The receipt of the
loan allowed us to avoid further reductions to employee headcount and salaries above those taken in March 2020.
The loan is eligible for forgiveness for the portion of the loan proceeds used for payroll costs and other
designated operating expenses, provided at least 60% of the loan’s proceeds are used for payroll costs. During
2021, we applied to the SBA for forgiveness of the Paycheck Protection Program loan, as all proceeds were
used for payroll costs.
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital
expenditures in 2022. In the second half of 2021, we added a fifth contracted drilling rig in the Delaware Basin and
plan to operate these five contracted drilling rigs in the Delaware Basin throughout 2022. In addition, at February 22,
2022, we had contracted a sixth operated drilling rig to begin drilling operations immediately on recently acquired
acreage in western Lea County, New Mexico in our Ranger asset area. We expect to operate this sixth rig on the
newly acquired acreage 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. Our 2022 estimated capital expenditure budget consists of
$640.0 to $710.0 million for D/C/E capital expenditures and $50.0 to $60.0 million for midstream capital expenditures,
which primarily reflects our proportionate share of San Mateo’s estimated 2022 capital expenditures. Substantially
all of these 2022 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, as well as amounts allocated
to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and
to participate in certain non-operated well opportunities. Our 2022 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 2022, including
90% with anticipated completed lateral lengths of two miles or greater.
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 well as consider monetizing other assets, such as certain mineral,
royalty and midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating
the opportunistic acquisition of producing properties, acreage and mineral interests, principally in the Delaware
Basin, during 2022. 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 2022 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 for 2022.
FORM 10-K PART I I
102
MATADOR RESOURCES COMPANY
Our 2022 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.
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 2022 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 2022 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, 2021. 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.”
FORM 10-K PART I I
2021 ANNUAL REPORT
103
Our cash flows for the years ended December 31, 2021, 2020 and 2019 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,
2021
2020
2019
$ 1,053,355
$ 477,582
(729,265)
(328,553)
(4,463)
$
(775,666)
324,339
$ 26,255
$ 552,042
(903,976)
333,078
$ (18,856)
Adjusted EBITDA attributable to Matador Resources Company shareholders(1)
$ 1,051,973
$ 519,277
$ 610,756
(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.
Cash Flows Provided by Operating Activities
Net cash provided by operating activities increased by $575.8 million to $1.05 billion for the year ended
December 31, 2021, as compared to net cash provided by operating activities of $477.6 million for the year ended
December 31, 2020. Excluding changes in operating assets and liabilities, net cash provided by operating
activities increased to $1.05 billion for the year ended December 31, 2021 from $500.7 million for the year ended
December 31, 2020. This increase was primarily attributable to significantly higher realized oil and natural gas prices
for the year ended December 31, 2021, as compared to the year ended December 31, 2020, as well as the 14%
increase in total oil equivalent production during 2021, as compared to 2020. Changes in our operating assets and
liabilities between December 31, 2020 and December 31, 2021 resulted in a net increase of approximately
$22.1 million in net cash provided by operating activities for the year ended December 31, 2021, as compared to
the year ended December 31, 2020.
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-owned 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. 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 and natural gas. Low oil and natural gas 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 decreased by $46.4 million to $729.3 million for the year ended December 31,
2021 from $775.7 million for the year ended December 31, 2020. This decrease in net cash used in investing
activities was primarily attributable to a decrease of $40.0 million in D/C/E capital expenditures as compared to the
year ended December 31, 2020, and a decrease of approximately $171.0 million in expenditures for midstream
support equipment and facilities, resulting from completing the construction of the further expansion of the Black
River Processing Plant and associated infrastructure, additional salt water disposal wells and additional pipeline
infrastructure during 2020. These decreases were partially offset by an increase of $165.8 million in expenditures
primarily related to our acquisition of oil and natural gas properties in the Delaware Basin during 2021. Cash used for
D/C/E capital expenditures for the year ended December 31, 2021 was primarily attributable to our operated and
non-operated drilling and completion activities in the Delaware Basin.
FORM 10-K PART I I
104
MATADOR RESOURCES COMPANY
Cash Flows (Used in) Provided by Financing Activities
Net cash used in financing activities was $328.6 million for the year ended December 31, 2021, as compared
to net cash provided by financing activities of $324.3 million for the year ended December 31, 2020. The net cash
used in financing activities for the year ended December 31, 2021 was primarily attributable to (i) net repayments
under our Credit Agreement of $340.0 million, (ii) net borrowings under the San Mateo Credit Facility of $51.0 million,
(iii) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $13.4 million
and (iv) dividends paid of $14.6 million.
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, 2021, the Guarantor
Subsidiaries were 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. San Mateo and its subsidiaries are not guarantors 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
FORM 10-K PART I I
December 31, 2021
$ 305,712
$ 3,060,233
48,890
$
$ 461,013
$ 1,142,580
$ 138,010
Year Ended
December 31, 2021
$ 1,543,420
873,037
$ 670,383
(67,823)
(74,710)
$ 527,850
2021 ANNUAL REPORT
105
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
Consolidated Adjusted EBITDA
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
Adjusted EBITDA attributable to Matador Resources Company
shareholders
Year Ended December 31,
2021
2020
2019
$ 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)
$ 87,777
35,205
122,982
73,873
35,532
350,540
1,822
—
53,727
18,505
967
—
657,948
(47,192)
$ 1,051,973
$ 519,277
$610,756
FORM 10-K PART I I
106
MATADOR RESOURCES COMPANY
(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
Expense related to contingent consideration
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
Adjusted EBITDA attributable to Matador Resources Company shareholders
Year Ended December 31,
2021
2020
2019
$ 1,053,355
982
71,028
1,485
(74,877)
$ 1,051,973
$477,582
23,078
73,860
—
(55,243)
$519,277
$552,042
34,517
71,389
—
(47,192)
$610,756
For the year ended December 31, 2021, we reported net income attributable to Matador shareholders of
$585.0 million, as compared to a net loss attributable to Matador shareholders of $593.2 million for the year ended
December 31, 2020. This increase primarily resulted from (i) significantly higher realized oil and natural gas prices
and higher oil and natural gas production, for the year ended December 31, 2021, as compared to the year ended
December 31, 2020, and (ii) no full-cost ceiling impairment recorded for the year ended December 31, 2021, as
compared to $684.7 million recorded for the year ended December 31, 2020. These increases were partially offset
by a realized loss on derivatives of $220.1 million for the year ended December 31, 2021, as compared to a
realized gain on derivatives of $38.9 million for the year ended December 31, 2020, and an income tax provision of
$74.7 million for the year ended December 31, 2021, as compared to an income tax benefit of $45.6 million for
the year ended December 31, 2020.
Adjusted EBITDA, a non-GAAP financial measure, increased $532.7 million to $1.05 billion for the year ended
December 31, 2021, as compared to $519.3 million for the year ended December 31, 2020. 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, 2021, as compared to the year ended December 31, 2020.
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, 2021, 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
2021 ANNUAL REPORT
107
OBLIGATIONS AND COMMITMENTS
We had the following material contractual obligations and commitments at December 31, 2021.
(In thousands)
Contractual Obligations:
Borrowings, including letters of credit(1)
(2)
Office leases
Non-operated drilling and other capital
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
$ 547,273
1,050,000
18,483
$
—
—
4,123
$ 401,470
—
8,529
$ 145,803
1,050,000
5,831
$
—
—
—
65,414
10,835
41,959
45,614
10,835
270
19,800
—
5,074
—
—
1,518
—
—
35,097
disposal agreements with non-affiliates(6)
597,334
70,014
143,424
142,185
241,711
Transportation, gathering, processing and
disposal agreements with San Mateo(7)
Total contractual cash obligations
390,307
$ 2,721,605
—
$ 130,856
100,101
$ 678,398
182,740
107,466
$ 1,528,077 $ 384,274
The amounts included in the table above represent principal maturities only. At December 31, 2021, we had $100.0 million of borrowings
outstanding under the Credit Agreement, approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement
and $7.5 million in borrowings under the SBA loan. The Credit Agreement matures in October 2026. At December 31, 2021 San Mateo had
$385.0 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 in December 2023. Assuming the amounts outstanding
and interest rates of 1.85% and 2.11%, for the Credit Agreement and the San Mateo Credit Facility, respectively, at December 31, 2021, the
interest expense for such facilities is expected to be approximately $1.9 million and $8.2 million each year until maturity.
(2) The amounts included in the table above represent principal maturities only. Interest expense on the $1.05 billion of Notes that were outstanding
as of December 31, 2021 is expected to be approximately $61.7 million each year until maturity.
(3) At December 31, 2021, we had outstanding commitments to drill and complete and to participate in the drilling and completion of various
operated and 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, 2021.
(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 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, 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.
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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 and results of operations. Commodity prices are
affected by changes in market supply and demand, which are impacted by overall economic activity, political instability
in Russia, Ukraine, China and the Middle East, the actions of OPEC+, the worldwide spread of COVID-19, 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 revenue, profitability, cash flow available
for capital expenditures, access to capital 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 an adverse effect on our financial condition,
results of operations, cash flows and reserves and our ability to comply with the leverage ratio covenant under our
Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the
prices of oil and natural gas. Low oil and natural gas 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 first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and
significant decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April. This sudden
decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand
resulting from the worldwide spread of COVID-19 and (ii) the increase in global oil supply resulting from the actions
of OPEC+. The sudden decline in oil prices began to improve later in the second quarter of 2020 and generally
continued throughout the remainder of 2020.
During the year ended December 31, 2021 and through February 22, 2022, the oil and natural gas industry
experienced continued improvement in commodity prices, as compared to 2020, primarily resulting from
(x) improvements in oil demand as the impact from COVID-19 has begun to abate, (y) actions taken by OPEC+ to
reduce the worldwide supply of oil through coordinated production cuts and (z) changes in supply and demand
dynamics, particularly with respect to natural gas markets generally and, more recently, instability in Russia and
Ukraine. While oil and natural gas prices improved significantly in 2021 and early 2022, the general outlook for the
oil and natural gas industry for the remainder of 2022 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 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
and natural gas. Low oil and natural gas 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 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.
For the year ended December 31, 2021, oil prices averaged $68.11 per Bbl, as compared to $39.34 per Bbl in
2020, ranging from a low of $47.62 per Bbl in early January to a high of $84.65 per Bbl in late October, based upon
the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $67.58
per Bbl ($56.70 per Bbl including realized losses from oil derivatives) for our oil production for the year ended
December 31, 2021, as compared to $37.38 per Bbl ($39.83 per Bbl including realized gains from oil derivatives)
FORM 10-K PART I I
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for the year ended December 31, 2020. At February 22, 2022, the WTI oil futures contract price for the earliest
delivery date had increased from year-end 2021, closing at $92.35 per Bbl, and was higher compared to $61.49 per
Bbl on February 22, 2021. We are uncertain that oil prices will remain at these levels as noted above.
Natural gas prices also improved significantly during 2021. For the year ended December 31, 2021, natural gas
prices averaged $3.71 per MMBtu, as compared to $2.13 per MMBtu in 2020, ranging from a low of $2.45 per
MMBtu in late January to a high of $6.31 per MMBtu in early October. As a result of milder-than-expected winter
weather, natural gas prices declined over the course of the fourth quarter of 2021, finishing the year at $3.73 per
MMBtu. We realized a weighted average natural gas price of $6.06 per Mcf ($5.74 per Mcf including realized losses
from natural gas derivatives) for our natural gas production for the year ended December 31, 2021, as compared to
$2.14 per Mcf (with no realized gains or losses from natural gas derivatives) for the year ended December 31, 2020.
As a two-stream reporter, the revenues associated with our NGL production are included in the weighted average
natural gas price. At February 22, 2022, the NYMEX Henry Hub natural gas futures contract price for the earliest
delivery date had increased from year-end 2021, closing at $4.50 per MMBtu, and was higher as compared to $2.95
per MMBtu at February 22, 2021. We are uncertain that natural gas prices will remain at these levels, particularly
as we exit the winter heating season.
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, 2021, we incurred realized losses on our oil and natural derivative
contracts of approximately $220.1 million, primarily as a result of oil and natural 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 of our oil
swap and oil basis swap contracts. At February 22, 2022, almost all of the derivative contracts we had in place that
contributed to these realized losses on derivatives in 2021 had expired. At February 22, 2022, 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 2022, although there may be periods where we realize losses from
derivatives. At December 31, 2021, adjusted for derivative contracts entered into between January 1, 2022 and
February 22, 2022, we had derivative contracts in place for approximately 5.1 million Bbl of our anticipated full year
2022 oil production and approximately 54.7 Bcf of our anticipated full year 2022 natural gas production.
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, 2021, 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.
The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years but began 2020
slightly positive to the WTI oil price and remained positive through much of the first quarter. With the abrupt
decline in oil prices during the first quarter of 2020, however, the Midland-Cushing (Oklahoma) oil price differential
experienced significant volatility in April 2020, reaching ($6.00) per Bbl before becoming positive later in the
second quarter and improving throughout the rest of 2020 and 2021 and into early 2022. At February 22, 2022, this
oil price differential was approximately +$1.00 per Bbl. At February 22, 2022, we had derivative contracts in place
to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated full
year 2022 oil production.
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MATADOR RESOURCES COMPANY
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, including times in April 2019 when natural gas was
being sold at the Waha hub for negative prices as high as ($7.00) to ($9.00) per MMBtu. In early 2020, the Waha
basis differential remained significant at about ($1.20) per MMBtu and continued to deteriorate. Natural gas prices
at the Waha hub were negative again on certain days in April 2020. The Waha basis differential narrowed during
the remainder of the second quarter of 2020. During the third quarter of 2020 and, in particular, at the beginning of
October 2020, the Waha basis differential widened significantly again, including several days when natural gas was
being sold at the Waha hub for negative prices, due to seasonal pipeline maintenance and other factors that reduced
capacity out of the Waha hub. These capacity issues have been largely resolved and the Waha basis differential
improved during the remainder of 2020 and 2021. 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 22, 2022, this natural gas price differential was approximately
($0.60) per MMBtu.
A significant portion of our Delaware Basin natural gas production is sold at Houston Ship Channel pricing and
is not exposed to Waha pricing. During 2021, 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 11% of our reported natural gas production for the year ended December 31, 2021 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.
Although the natural gas price differentials have recently at times been positive or close to zero, these price
differentials could deteriorate in future periods. 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, we have no derivative
contracts in place to mitigate our exposure to these natural gas price differentials in 2022.
At February 22, 2022, we had not experienced material pipeline-related interruptions to our oil, natural gas or
NGL production. In certain periods over the last few years, 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.
As a result of the recent increases in oil and natural gas prices, we have begun to experience inflation in the
costs of certain oilfield services, including diesel, steel, labor, trucking, personnel and completion costs, among others.
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. We budgeted a 10 to 15% increase in oilfield service costs, as compared to the fourth quarter of 2021, in
preparing our full-year D/C/E and midstream capital expenditures for 2022. Should we experience service cost inflation
above 10 to 15% during 2022, we may be required to increase our 2022 estimated capital expenditure budget.
Further, in early 2022, supply chain disruptions 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.
FORM 10-K PART I I
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In addition, should oil and natural gas prices remain at their current levels throughout 2022, we may exhaust
our federal or state net operating loss carryforwards and become subject to federal and state income taxes in future
periods. At February 22, 2022, given our current projections, we do not expect to pay significant federal income
taxes, if any, in 2022, but may pay federal income taxes in 2023. We may pay state income taxes in 2022 and 2023,
however, in New Mexico and Texas.
Our oil and natural gas exploration, development, production, midstream and related operations are subject to
extensive federal, state and local laws, rules and regulations. 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 proposed 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 an adverse impact
on our business, financial condition, results of operations and cash flows. In January 2021, the Biden administration
issued the Biden Administration Federal Lease Orders. In addition, the BLM has indicated that the Lease Sale
Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits.
Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31,
2021, the impact of federal actions 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 2022 and 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
FORM 10-K PART I I
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MATADOR RESOURCES COMPANY
have been filed in some states 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. See “Risk Factors—Risks Related to
Laws and Regulations—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.”
Certain segments of the investor community have recently expressed negative sentiment towards investing in
the oil and natural gas industry. Equity returns in the sector prior to 2021 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, 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.
FORM 10-K PART I I
2021 ANNUAL REPORT
113
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, 2021.
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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MATADOR RESOURCES COMPANY
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 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 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, 2021.
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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MATADOR RESOURCES COMPANY
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, 2021, The
Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), PNC Bank and Royal Bank of Canada (or affiliates
thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the
counterparties in determining the fair value of our derivative financial instruments.
At December 31, 2021, we had entered into various costless collar contracts to mitigate our exposure to
fluctuations in oil and natural gas prices, each with an established price floor and ceiling. When the settlement price
is below the price floor established by one or more of these collars, 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 one or more of the costless collars,
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.
At December 31, 2021, we had entered into various swap contracts to mitigate our exposure to oil price
differences between NYMEX WTI Cushing and Argus WTI Midland crude oil. When the settlement price is below
the fixed price established by one or more of these basis swaps, we receive from the counterparty an amount
equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. When
the settlement price is above the fixed price established by one or more of these basis swaps, we pay to the
counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the
contract oil 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, 2021. Such information is incorporated herein by reference.
FORM 10-K PART I I
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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.”
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, 2021, we had outstanding borrowings
of $100.0 million at an interest rate of 1.85% per annum under our Credit Agreement, $1.05 billion in Notes
outstanding at a coupon rate of 5.875% per annum and $385.0 million of outstanding borrowings under the San Mateo
Credit Facility at an interest rate of 2.11% 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 is
subject to the credit risk of its customers. The inability or failure of our or San Mateo’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 counterparties on our derivative financial
instruments in place at February 22, 2022 were The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal),
PNC Bank, Royal Bank of Canada and Truist Bank (or affiliates thereof), and all but BMO Harris Financing were
lenders (or affiliates thereof) under our Credit Agreement, and we are likely to enter into any future derivative
instruments with such banks or other lenders (or affiliates thereof) party to the Credit Agreement.
Impact of Inflation. Inflation in the United States has been relatively low in recent years and did not have
a material impact on our results of operations for the years ended December 31, 2021, 2020 and 2019. Although
the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy
and has become much more significant in recent months, reaching its highest levels in approximately 40 years.
At February 22, 2022, we do not know how long these inflationary pressures may persist or the impact they
FORM 10-K PART I I
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MATADOR RESOURCES COMPANY
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 15% increase in oil field service costs, as
compared to the fourth quarter of 2021, in preparing our full year 2022 D/C/E and midstream capital expenditures
estimates. See “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.
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, 2021 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, 2021, 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.
FORM 10-K PART I I
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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, 2021 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.
FORM 10-K PART I I
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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, 2021, 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, 2021, based
on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
k
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the
related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the
years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial
statements), and our report dated February 28, 2022 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.
FORM 10-K PART I I
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121
Report of Independent Registered Public Accounting Firm
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
February 28, 2022
/s/ KPMG LLP
FORM 10-K PART I I
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MATADOR RESOURCES COMPANY
ITEM 9B. OTHER INFORMATION.
Not applicable.
FORM 10-K PART I I
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123
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 2022 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
roxy 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
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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, 2021 and 2020, Consolidated Statements of Operations
for the Years Ended December 31, 2021, 2020 and 2019, Consolidated Statements of Changes in
Shareholders’ Equity for the Years Ended December 31, 2021, 2020 and 2019 and Consolidated Statements
of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019.
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
2021 ANNUAL REPORT
125
Exhibit Index
Exhibit
Number Description
2.1
3.1
3.2
3.3
3.4
4.1
4.2
4.3
4.4
4.5
10.1†
10.2†
10.3†
10.4†
10.5†
10.6†
10.7†
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).*
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).
Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference
to Exhibit 10.4 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011).
Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference
to Exhibit 10.5 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).
First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster
(incorporated by reference to Exhibit 10.9 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 Matthew Hairford
(incorporated by reference to Exhibit 10.10 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).
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126
MATADOR RESOURCES COMPANY
Exhibit
Number Description
10.8†
10.9†
10.10†
10.11†
10.12†
10.13†
10.14†
10.15†
10.16†
10.17†
10.18†
10.19
10.20
10.21
Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster
(incorporated by reference to Exhibit 10.13 to Amendment No. 2 to the Registration Statement on Form S-1 filed on
December 30, 2011).
Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford
(incorporated by reference to Exhibit 10.14 to Amendment No. 2 to the Registration Statement on Form S-1 filed on
December 30, 2011).
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).
Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson
(incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).
First Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and
Bradley M. Robinson (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 2019).
Second Amendment to the Amended and Restated Employment Agreement between Matador Resources Company
and Bradley M. Robinson (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year
ended December 31, 2020).
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).
Third Amended and Restated Credit Agreement, dated as of September 28, 2012, 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
October 4, 2012).
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).
10.22
First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC
Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012).
FORM 10-K PART I V
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127
Exhibit
Number Description
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013).
Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013).
Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013).
Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among
MRC Energy Company, as Borrower, the Lenders party thereto 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 September 8, 2014).
Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015).
Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among
MRC Energy Company, as Borrower, the Lenders party thereto 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 October 21, 2015).
Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among
MRC Energy Company, as Borrower, the Lenders party thereto 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 2, 2016).
Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of
December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of
Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed
on December 9, 2016).
Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among
MRC Energy Company, as Borrower, the Lenders party thereto 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 May 4, 2017).
Eleventh Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2018, by and among
MRC Energy Company, as Borrower, the Lenders party thereto 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 August 9, 2018).
Limited Consent and Twelfth Amendment to Third Amended and Restated Credit Agreement, dated as of October 1,
2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of
Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed
on October 4, 2018).
Thirteenth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2018, by and
among MRC Energy Company, as Borrower, the Lenders party thereto 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 1, 2018).
Fourteenth Amendment to Third Amended and Restated Credit Agreement, dated as of February 27, 2020,
by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as
Administrative Agent (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year
ended December 31, 2019).
Fifteenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 23, 2021, by and among
MRC Energy Company, as Borrower, the Lenders party thereto 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 April 29, 2021).
FORM 10-K PART I V
128
MATADOR RESOURCES COMPANY
Exhibit
Number Description
10.37
10.38†
10.39†
10.40†
10.41†
10.42†
10.43†
10.44†
10.45†
10.46†
10.47†
10.48†
10.49†
10.50†
10.51†
10.52†
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).
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).
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 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).
FORM 10-K PART I V
2021 ANNUAL REPORT
129
Exhibit
Number Description
10.53†
10.54†
10.55†
10.56†
10.57†
10.58†
10.59†
10.60†
10.61†
21.1
23.1
23.2
31.1
31.2
32.1
32.2
99.1
101
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).
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 (filed herewith).
Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019
Long-Term Incentive Plan for employees without employment agreements (filed herewith).
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 (filed herewith).
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).
List of Subsidiaries of Matador Resources Company (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.
* Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the
SEC upon request.
FORM 10-K PART I V
130
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.
February 28, 2022
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
Date
/s/ JOSEPH WM. FORAN
Joseph Wm. Foran
Chairman and Chief Executive Officer
(Principal Executive Officer)
February 28, 2022
/s/ DAVID E. LANCASTER
David E. Lancaster
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
February 28, 2022
/s/ ROBERT T. MACALIK
Robert T. Macalik
Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)
February 28, 2022
Director
Director
Director
Director
Director
Director
Director
Director
February 28, 2022
February 28, 2022
February 28, 2022
February 28, 2022
February 28, 2022
February 28, 2022
February 28, 2022
February 28, 2022
/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
2021 ANNUAL REPORT
131
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
132
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.
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
2021 ANNUAL REPORT
133
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
134
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.
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
2021 ANNUAL REPORT
F-1
Consolidated Financial Statements
MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2021, 2020 and 2019
Contents
Page
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-2
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2021 and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019 . . . . . . . . . . .
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2021,
2020 and 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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, 2021 and 2020, 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,
2021, 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,
2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period
ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on
criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission, and our report dated February 28, 2022 expressed an unqualified
opinion on the effectiveness of the Company’s internal control over financial reporting.
k
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
2021 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, 2021, the Company recorded depletion expense of evaluated oil and natural gas properties of
$310.1 million. Additionally, as discussed in Note 3 to the consolidated financial statements, the Company recorded
$6.0 billion of gross evaluated oil and natural gas properties as of December 31, 2021. 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
February 28, 2022
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
Derivative instruments
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;
117,861,923 and 116,847,003 shares issued; and 117,850,233 and
116,844,768 shares outstanding, respectively
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost, 11,945 and 2,235 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,
2021
2020
$
48,135
38,785
$
57,916
33,467
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
85,098
34,823
17,212
6,727
10,584
15,802
261,629
5,295,931
902,133
841,695
29,561
(3,701,551)
3,367,769
—
34,163
$ 4,262,153
2,570
55,312
$ 3,687,280
$
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
$
13,982
119,158
66,049
4,934
45,186
4,191
37,436
290,936
440,000
334,000
1,040,998
37,919
—
30,402
1,883,319
1,179
2,077,592
(171,318)
(243)
1,907,210
220,178
2,127,388
$ 4,262,153
1,169
2,027,069
(741,705)
(3)
1,286,530
226,495
1,513,025
$ 3,687,280
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)
2021 ANNUAL REPORT
F-5
Year Ended December 31,
2021
2020
2019
$ 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
$ 892,325
59,110
74,769
1,711
9,482
(53,727)
983,670
178,987
108,964
61,459
77,126
344,905
2,068
—
96,396
869,905
793,076
93,338
104,953
41,500
32,734
361,831
1,948
684,743
62,578
1,383,625
(521,499)
92,273
117,305
36,798
69,398
350,540
1,822
—
80,054
748,190
235,480
(331)
(74,687)
(2,712)
(77,730)
715,346
(2,832)
(76,692)
1,864
(77,660)
(599,159)
(967)
(73,873)
(2,126)
(76,966)
158,514
Deferred
Total income tax provision (benefit)
74,710
74,710
640,636
Net income attributable to non-controlling interest in subsidiaries
(55,668)
Net income (loss) attributable to Matador Resources Company shareholders $ 584,968
Net income (loss)
(45,599)
(45,599)
(553,560)
(39,645)
$ (593,205)
35,532
35,532
122,982
(35,205)
$ 87,777
Earnings (loss) per common share
Basic
Diluted
Weighted average common shares outstanding
Basic
Diluted
$
$
5.00
4.91
$
$
(5.11)
(5.11)
$
$
0.75
0.75
116,999
116,068
116,555
119,163
116,068
117,063
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, 2021, 2020 and 2019
Common Stock
Shares Amount
Additional
paid-in
capital
Accumulated Treasury Stock
Shares Amount
deficit
Total
shareholders’
equity
attributable
to Matador
Resources
Company
Non-
controlling
interest
in
subsidiaries
Total
shareholders’
equity
116,375 $ 1,164
$ 1,924,408 $ (236,277) 21 $ (415) $ 1,688,880 $ 90,777 $ 1,779,657
(In thousands)
Balance at January 1, 2019
Issuance of common stock pursuant
to employee stock compensation plan
Issuance of common stock pursuant
240
2
(2)
—
—
—
—
—
—
—
—
—
—
—
—
—
to directors’ and advisors’ compensation plan
50
—
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
Restricted stock forfeited
Contribution related to formation of San Mateo,
net of tax of $3.1 million (See Note 6)
Contribution of property related to formation of
San Mateo II (See Note 6)
Contributions from non-controlling interest owners
of less-than-wholly-owned subsidiaries, 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
—
—
23,396
—
—
—
23,396
—
23,396
220
1
—
2
—
—
3,298
11
—
—
—
—
—
—
222
—
—
(3,691)
3,300
11
(3,691)
—
—
—
3,300
11
(3,691)
—
—
11,613
—
—
—
11,613
—
11,613
—
—
(506)
—
—
—
(506)
506
—
—
—
22,874
—
—
—
22,874
48,510
71,384
—
(242)
—
—
(2)
—
—
(4,078)
—
—
—
87,777
—
(242)
—
—
4,080
—
—
—
87,777
(39,200)
—
35,205
(39,200)
—
122,982
116,644
1,166
1,981,014
(148,500)
1
(26)
1,833,654
135,798
1,969,452
Balance at December 31, 2019
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
Contributions 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
244
85
2
1
(2)
(1)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
17,452
—
—
—
17,452
—
17,452
—
22
—
—
—
—
(24)
297
—
—
—
—
—
—
149
—
—
(1,489)
(24)
297
(1,489)
—
—
—
(24)
297
(1,489)
—
—
11,613
—
—
—
11,613
—
11,613
—
—
18,232
—
—
—
18,232
96,622
114,854
—
(148)
—
—
—
—
—
(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 $ 226,495 $ 1,513,025
(14,581)
(14,581)
—
—
768
81
7
1
(7)
(1)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12,113
—
—
—
12,113
—
12,113
312
—
3
—
(4,258)
—
—
—
—
156
—
(2,621)
(4,255)
(2,621)
—
—
(4,255)
(2,621)
—
—
45,056
—
—
—
45,056
—
45,056
—
(146)
—
—
(1)
—
—
(2,380)
—
—
—
584,968
—
(146)
—
—
2,381
—
—
—
584,968
(61,985)
—
55,668
(61,985)
—
640,636
Balance at December 31, 2021
117,862 $ 1,179
$ 2,077,592 $ (171,318) 12 $ (243) $ 1,907,210 $ 220,178 $ 2,127,388
The accompanying notes are an integral part of these consolidated financial statements.
FORM 10-K Consolidated Financial Statements
2021 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
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
Expenditures for other property and equipment
Proceeds from sale of assets
Net cash used in investing activities
Financing activities
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
Proceeds from stock options exercised
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
(Decrease) increase 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,
2021
2020
2019
$ 640,636
$ (553,560)
$ 122,982
(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)
1,335
(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)
45
—
14,700
53,727
350,540
1,822
—
18,505
35,532
2,484
967
(43,261)
4,777
(4,844)
678
(19,004)
20,417
3,869
2,851
552,042
(679,395)
(50,766)
(192,035)
(3,701)
21,921
(903,976)
(35,000)
250,000
—
68,000
(1,443)
3,300
—
14,700
—
119,700
77,330
(61,985)
(8,211)
(629)
(328,553)
(4,463)
91,383
$ 86,920
(45,570)
(1,556)
6,680
324,339
26,255
65,128
$ 91,383
(39,200)
(3,691)
(918)
333,078
(18,856)
83,984
$ 65,128
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Financial Statements FORM 10-K PART IV
F-8
MATADOR RESOURCES COMPANY
Notes to Consolidated Financial Statements
MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2021, 2020 and 2019
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 (collectively with its subsidiaries, “San Mateo”), 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
2021 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, San Mateo’s customers 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, 2021, three significant purchasers accounted for 72% of the Company’s total
oil, natural gas and NGL revenues: Plains Marketing, L.P. (29%), Exxon Mobil Corporation (33%) 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%). For the year ended December 31, 2019, two significant purchasers accounted for 67% of the Company’s total
oil, natural gas and NGL revenues: Plains Marketing, L.P. (53%) and BP America Production Company (14%). 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, 2021, 2020 and 2019, approximately 39%, 35% and 31%,
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 market 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 $38.4 million, $30.0 million and $31.1 million of its general and administrative costs into oil and natural
gas properties in 2021, 2020 and 2019, respectively. The Company capitalized $4.8 million, $5.0 million and
$7.6 million of its interest expense into oil and natural gas properties for the years ended December 31, 2021, 2020
and 2019, 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, 2021, 2020 and 2019,
the Company recorded depletion expense of $310.1 million, $334.8 million and $330.7 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
2021 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 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. For the period from January through December 2019, these average oil and
natural gas prices were $52.19 per Bbl and $2.58 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, 2021 and 2019, 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, 2021 and 2019.
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 $1.3 million, $1.8 million and $1.8 million of general and administrative
costs into midstream properties in 2021, 2020 and 2019, respectively. The Company did not capitalize any interest
expense into midstream properties for the year ended December 31, 2021. The Company capitalized $0.5 million
and $0.9 million of interest expense into midstream properties for the years ended December 31, 2020 and 2019.
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
2021 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 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, 2021, 2020 and 2019 (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,
2021
2020
2019
$ 1,862,075
—
(220,105)
21,011
$ 1,662,981
$ 851,135
4,062
38,937
(32,008)
$ 862,126
$1,026,204
1,711
9,482
(53,727)
$ 983,670
Year Ended December 31,
2021
2020
2019
$ 1,205,608
494,934
75,499
86,034
$ 1,862,075
$ 595,507
148,954
64,932
41,742
$ 851,135
$ 759,811
132,514
59,110
74,769
$1,026,204
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
2021 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, 2021, 2020 and
2019 include a stock-based compensation (non-cash) expense of $9.0 million, $13.6 million and $18.5 million,
respectively. This stock-based compensation expense includes common stock issuances and restricted stock units
expense totaling $0.9 million, $1.0 million and $1.4 million for the years ended December 31, 2021, 2020 and
2019, respectively, paid to independent members of the Board of Directors and advisors as compensation for their
services to the Company. The Company’s consolidated statement of operations for the years ended December 31,
2021, 2020 and 2019 also includes $20.4 million, $4.0 million and $3.2 million, respectively, related to liability-based
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, 2021, 2020 and 2019, 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, 2021,
2020 and 2019.
Allocation of Purchase Price in Business Combinations
As part of the Company’s business strategy, it periodically pursues the acquisition of 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, 2021, 2020 and 2019 (in
thousands, except per share data).
Year Ended December 31,
2021
2020
2019
Net income (loss) attributable to Matador Resources Company shareholders —
numerator
$ 584,968
$(593,205)
$ 87,777
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
116,999
2,164
119,163
116,068
—
116,068
116,555
508
117,063
$
$
5.00
4.91
$
$
(5.11)
(5.11)
$
$
0.75
0.75
A total of 2.5 million and 2.6 million options to purchase shares of Matador’s common stock were excluded
from the diluted weighted average common shares outstanding for the years ended December 31, 2020 and 2019,
respectively, 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 contracts at December 31, 2021 were with The Bank
of Nova Scotia, BMO Harris Financing, Inc. (Bank of Montreal), PNC Bank and Royal Bank of Canada (or affiliates
thereof), and all but BMO Harris Financing, Inc. (Bank of Montreal) were parties that are lenders (or affiliates
thereof) 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
2021 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,
2021 and 2020 (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,
2021
2020
$ 6,007,325
964,714
6,972,039
(3,933,355)
3,038,684
$ 5,295,931
902,133
6,198,064
(3,623,265)
2,574,799
900,979
(92,574)
808,405
841,695
(61,113)
780,582
10,923
8,225
10,975
30,123
(20,527)
9,596
$ 3,856,685
10,591
8,116
10,854
29,561
(17,173)
12,388
$ 3,367,769
The following table provides a breakdown of the Company’s unproved and unevaluated property costs not
subject to amortization as of December 31, 2021 and the year in which these costs were incurred (in thousands).
Description
Costs incurred for
Property acquisition
Exploration wells
Development wells
Total
2021
2020
2019
2018
2017 and prior
Total
$ 111,120
14,738
46,232
$ 172,090
$40,355
411
2,027
$42,793
$40,140
1,199
3,245
$44,584
$417,114
123
60
$417,297
$287,666
274
10
$287,950
$896,395
16,745
51,574
$964,714
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, 2021 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
$68.3 million at December 31, 2021. Of this total, $16.7 million was associated with exploration wells and
$51.6 million was associated with development wells. The Company anticipates that most of the $68.3 million
associated with these wells in progress at December 31, 2021 will be transferred to the amortization base during
2022. Unproved and unevaluated property costs for exploration and development wells incurred in years prior to
2021 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, 2021 were 2.73% and 1.99% 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
2021 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, 2021 and 2020, 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,
2021
2020
$ 11,393
36
3,645
15,074
11,234
4,037
37
15,308
566
138
704
$ 31,086
$12,994
28
3,698
16,720
12,890
5,689
47
18,626
747
123
870
$36,216
(1) Does not include gross payments related to drilling rig leases of $31.9 million and $33.6 million for the years ended December 31, 2021 and
2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets
at December 31, 2021 and 2020, 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 $61.7 million and $65.3 million for the
years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method”
in the consolidated balance sheets at December 31, 2021 and 2020, respectively.
The following table presents supplemental consolidated balance sheet information related to leases as of
December 31, 2021 and 2020, 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,
2021
2020
$ 29,519
$ 51,528
$ (19,649)
(15,340)
$ (34,989)
$(35,716)
(21,598)
$(57,314)
$ 5,914
(3,485)
$ 2,429
$
$
(378)
(45)
(423)
$ 3,673
(2,134)
$ 1,539
$
$
(621)
(256)
(877)
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
year ended December 31, 2021 and 2020, 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,
2021
2020
$ 14,430
$ 31,967
629
$
$ 18,454
$ 2,241
$ 15,664
$ 33,556
790
$
$ 12,474
996
$
The following table presents the maturities of lease liabilities at December 31, 2021 (in years).
Weighted-Average Remaining Lease Term
Operating leases
Financing leases
December 31,
2021
2.5
1.7
The following table presents a schedule of future minimum lease payments required under all lease agreements
as of December 31, 2021 (in thousands).
2022
2023
2024
2025
2026
Thereafter
Total lease payments
Less imputed interest
Total lease obligations
Less current obligations
Long-term lease obligations
December 31, 2021
Operating
Leases
Financing
Leases
$ 19,649
6,830
4,217
4,287
1,553
—
36,536
(1,547)
34,989
(19,649)
$ 15,340
$ 378
180
37
—
—
—
595
(172)
423
(378)
$ 45
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
2021 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, 2021 and 2020 (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 obligations
Year Ended December 31,
2021
2020
$ 38,542
2,294
(151)
86
(880)
2,068
41,959
(270)
$ 41,689
$36,211
2,548
(290)
(1,875)
—
1,948
38,542
(623)
$37,919
(1)
Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2021 and 2020.
NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES
Business Combination
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 and will
pay an additional $6.5 million, net of customary working capital adjustments, including adjusting for production,
revenues, operating expenses and capital expenditures from August 1, 2021 to closing. In addition, the Company
will increase 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, is greater than $75.00 per barrel. The Company recorded this
contingent consideration at fair value on the date of the business combination and will record the change in the fair
value in future periods as “Other income (expense)” in its consolidated statements of operations. The fair value
of the contingent consideration increased between December 14, 2021 and December 31, 2021 by $1.5 million,
which was recorded as “Other expense” for the year ended December 31, 2021. 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).
In addition, the Company acquired oil and natural gas production of approximately 3,500 BOE per day at the date
of acquisition, which increased the Company’s revenues and net income for the period from December 15, 2021
through December 31, 2021 by $4.0 million and $3.2 million, respectively. The pro forma impact of this business
combination to revenues and net income for the remainder of 2021 would not be material to the Company’s 2021
revenues and net income as reported.
Notes to Consolidated Financial Statements FORM 10-K
F-22
MATADOR RESOURCES COMPANY
NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued
The preliminary allocation of the consideration given related to this business combination was as follows (in
thousands). The Company anticipates that the allocation of the consideration given should be finalized during 2022
upon determination of the final customary purchase price adjustments.
Consideration given
Cash
Working capital adjustments to be paid in 2022
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
Joint Ventures
Allocation
$161,680
6,500
6,718
$174,898
$139,312
43,204
(360)
(6,865)
(393)
$174,898
At December 31, 2021, 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, 2021, Five Point owned the remaining 49% of San Mateo. The midstream assets include (i) the
Black River Processing Plant, (ii) 14 salt water disposal wells and associated commercial salt water disposal facilities
and (iii) approximately 370 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 agreement 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 December 31, 2021, the Company had earned $58.8 million of the
potential $73.5 million in performance incentives and Five Point had paid $14.7 million in performance incentives in
each of the first quarters of 2018, 2019, 2020 and 2021. The Company may earn up to the remaining $14.7 million
in performance incentives until January 31, 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 over the
next several years, plus additional performance incentives for securing volumes from third-party customers. During
the year ended December 31, 2021, Five Point paid $33.9 million in these additional performance incentives.
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).
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-23
NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued
During the years ended December 31, 2021 and 2020, San Mateo distributed $64.5 million and $47.4 million,
respectively, to the Company and $62.0 million and $45.6 million, respectively, to Five Point. During the year ended
December 31, 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. During the year
ended December 31, 2019, the Company contributed $24.2 million and Five Point contributed $77.3 million of cash
to San Mateo, of which $28.4 million was paid to carry Matador’s proportionate interest in San Mateo II and was
recorded in “Additional paid-in capital” in the consolidated balance sheet, net of the $5.9 million deferred tax impact
to Matador related to this equity contribution. In the first quarter of 2019, the Company also contributed $1.0 million
of property to San Mateo II. San Mateo II was merged with and into San Mateo effective October 1, 2020.
Divestitures
During 2021 and 2020, the Company converted approximately $4.2 million and $4.8 million, respectively, of
non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana.
NOTE 7 — DEBT
At December 31, 2021, the Company had (i) $1.05 billion of outstanding senior notes due 2026, (ii) $100.0 million
in borrowings outstanding under its reserves-based revolving credit facility, (iii) approximately $45.8 million in
outstanding letters of credit issued pursuant to its revolving credit facility and (iv) $7.5 million outstanding under an
unsecured U.S. Small Business Administration loan.
At December 31, 2021, San Mateo had $385.0 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 facility 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 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.
Notes to Consolidated Financial Statements FORM 10-K
F-24
MATADOR RESOURCES COMPANY
NOTE 7 — DEBT — Continued
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 November 2021, 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 $900.0 million to $1.35 billion. The Company elected to
keep the borrowing commitment at $700.0 million, and the maximum facility amount remained $1.5 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 $3.9 million at December 31, 2021, and these costs are being amortized over the
term of the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was 1.85% at
December 31, 2021. At December 31, 2021, the Company had $100.0 million in borrowings outstanding under the
Credit Agreement and approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit
Agreement. Between December 31, 2021 and February 28, 2022, the Company repaid $25.0 million of borrowings
outstanding under the Credit Agreement.
Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If MRC
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 Credit Agreement) on such day, plus
0.50%, and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% 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 MRC borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the
LIBOR Rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.75% to 2.75% per annum
depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar 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 cash or cash equivalents) divided
by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less.
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-25
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 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, 2021.
Notes to Consolidated Financial Statements FORM 10-K
F-26
MATADOR RESOURCES COMPANY
NOTE 7 — DEBT — Continued
San Mateo Midstream, LLC
On December 19, 2018, San Mateo entered into a $250.0 million credit facility with the lenders party thereto,
currently led by Truist Bank as administrative agent (the “San Mateo Credit Facility”). The San Mateo Credit Facility
matures December 19, 2023 and was amended in June 2021 to increase the lender commitments under the
revolving credit facility from $375.0 million to $450.0 million (subject to San Mateo’s compliance with the covenants
noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by
0.50%. The San Mateo Credit Facility includes an accordion feature, which, after the aforementioned amendment,
provides for potential increases in lender commitments to up to $700.0 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 $1.9 million at December 31, 2021, and these costs are being amortized over
the term of the San Mateo Credit Facility. San Mateo’s effective interest rate under the San Mateo Credit Facility
was 2.11% at December 31, 2021. At December 31, 2021, San Mateo had $385.0 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, 2021 and February 22, 2022, San Mateo repaid $30.0 million of borrowings
outstanding under the San Mateo Credit Facility.
Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar 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 LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0% plus,
in each case, an amount ranging from 1.00% to 2.00% 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 Eurodollar loan, such
borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an
amount ranging from 2.00% to 3.00% 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 the unused availability under the San Mateo
Credit Facility, 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,
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.
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-27
NOTE 7 — DEBT — Continued
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 subsidiaries.
If an event of default exists under the San Mateo Credit Facility, the lenders will be able to 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, 2021.
Senior Unsecured Notes
At December 31, 2021, the Company had $1.05 billion 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 guaranteed on a senior unsecured
basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and its subsidiaries are not Restricted
Subsidiaries (as defined in the Indenture) or Guarantors of the Notes.
Notes to Consolidated Financial Statements FORM 10-K
F-28
MATADOR RESOURCES COMPANY
NOTE 7 — DEBT — Continued
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
2021
2022
2023
2024 and thereafter
Redemption Price
104.406%
102.938%
101.469%
100.000%
Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s 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.
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.
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-29
NOTE 7 — DEBT — Continued
The outstanding borrowings of $100.0 million at December 31, 2021 under the Credit Agreement mature on
October 31, 2026. The outstanding borrowings of $385.0 million at December 31, 2021 under the San Mateo Credit
Facility mature on December 19, 2023. The $1.05 billion of outstanding Notes at December 31, 2021 mature on
September 15, 2026.
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, 2021
and 2020 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
Property and equipment
Less than wholly-owned subsidiaries
Lease right of use assets
Other
Total deferred tax liabilities
Net deferred tax (liabilities) assets
December 31,
2021
2020
$ 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)
$ 122,952
8,997
1,462
10,405
9,380
8,334
161,530
(110,681)
50,849
(11,879)
(26,564)
(9,380)
(2,684)
(50,507)
342
$
At December 31, 2021, the Company had net operating loss carryforwards of $555.2 million for federal income
tax purposes and $223.3 million for state income tax purposes available to offset future taxable income, as limited
by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss
carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024;
however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027.
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. The remaining net deferred
tax asset at December 31, 2020 relates to state taxes, for which the deferred taxes were determined to be more
likely than not to be utilized. 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.
Notes to Consolidated Financial Statements FORM 10-K
F-30
MATADOR RESOURCES COMPANY
NOTE 8 — INCOME TAXES — Continued
The current income tax provision and the deferred income tax provision for the years ended December 31, 2021,
2020 and 2019 were comprised of the following (in thousands).
Deferred income tax provision (benefit)
Federal income tax
State income tax
Net deferred income tax provision (benefit)
Year Ended December 31,
2021
2020
2019
$ 44,883
29,827
$ 74,710
$(25,675)
(19,924)
$(45,599)
$29,171
6,361
$35,532
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, 2021, 2020 and 2019 is as follows (in thousands).
Federal tax expense (benefit) at statutory rate(1)
State income tax
Permanent differences
Change in federal valuation allowance
Change in state valuation allowance
Net deferred income tax provision (benefit)
Total income tax provision (benefit)
Year Ended December 31,
2021
2020
2019
$ 150,223
26,646
(2,078)
(103,262)
3,181
74,710
$ 74,710
$ (125,823)
(20,607)
(3,114)
103,262
683
(45,599)
$ (45,599)
$ 33,441
6,141
(4,267)
—
217
35,532
$ 35,532
(1) The statutory federal tax rate was 21% for the years ended December 31, 2021, 2020 and 2019.
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 2018. The earliest tax year open for examination for the State of Texas
tax return is 2017.
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,
2021, the Company had not established any reserves for, nor recorded any unrecognized benefits related to,
uncertain tax positions.
NOTE 9 — STOCK-BASED COMPENSATION
Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards
In 2012, the Company’s Board of Directors 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.
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-31
NOTE 9 — STOCK-BASED COMPENSATION — Continued
In 2019, the Company’s Board of Directors adopted and shareholders approved the 2019 Incentive Plan. As of
December 31, 2021, the 2019 Incentive Plan provided for a maximum of 1,571,972 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 the 2019 Incentive Plan are administered by the independent members of the Board
of Directors, who, upon recommendation of the Strategic Planning and Compensation Committee of the Board
of Directors, 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.
During the years ended December 31, 2021, 2020 and 2019, 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.
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 weighted average grant date fair value for stock option awards granted under the 2019 Incentive Plan
was estimated using the following weighted average assumptions during the year ended December 31, 2019. The
Company did not grant stock option awards during the years ended December 31, 2021 and 2020.
Stock option pricing model
Expected option life
Risk-free interest rate
Volatility
Dividend yield
Estimated forfeiture rate
Weighted average fair value of stock option awards granted during the year
2019
Black Scholes Merton
4.00 years
1.46%
48.52%
—%
4.43%
$5.04
The Company estimated the future volatility of its common stock using the historical value of its stock for a
period of time commensurate with the expected term of the stock option. The expected term was estimated using
the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate was the rate for
constant yield U.S. Treasury securities with a term to maturity that was consistent with the expected term of
the award.
Notes to Consolidated Financial Statements FORM 10-K
F-32
MATADOR RESOURCES COMPANY
NOTE 9 — STOCK-BASED COMPENSATION — Continued
Summarized information about stock options outstanding at December 31, 2021 under the 2012 Incentive Plan
and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows.
Options outstanding at December 31, 2020
Options granted
Options exercised
Options forfeited
Options expired
Options outstanding at December 31, 2021
Number of
options
(in thousands)
Weighted
average
exercise price
2,473
—
(1,368)
(37)
(465)
603
$23.08
$ —
$ 25.37
$ 18.72
$ 16.90
$ 22.92
Range of exercise prices
$14.48 - $15.40
$26.86 - $29.68
Options outstanding at
December 31, 2021
Options exercisable at
December 31, 2021
Shares
outstanding
(in thousands)
Weighted average
remaining
contractual life
Weighted average
exercise price
Shares
exercisable
(in thousands)
Weighted
average
exercise price
240
363
3.66
1.59
$ 14.80
$ 28.28
82
363
$ 14.80
$ 28.28
At December 31, 2021, the aggregate intrinsic value for both outstanding and exercisable options was $4.9 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, 2021 was 1.97 years.
The total intrinsic value of options exercised during the years ended December 31, 2021, 2020 and 2019 was
$15.8 million, $0.3 million and $0.8 million, respectively. The tax related benefit realized from the exercise of stock
options totaled $16.8 million, $1.4 million and $2.8 million for the years ended December 31, 2021, 2020 and
2019, respectively.
At December 31, 2021, the total remaining unrecognized compensation expense related to unvested stock
options was approximately $0.5 million and the weighted average remaining requisite service period (vesting period)
of all unvested stock options was 0.66 years.
The fair value of options vested during 2021, 2020 and 2019 was $3.0 million, $6.7 million and $9.7 million,
respectively.
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 2021,
2020 and 2019 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 2021 and 2020 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, 2023 and 2022, respectively, as compared to a designated peer group, and will be
settled in equity.
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-33
NOTE 9 — STOCK-BASED COMPENSATION — Continued
Equity-Based
A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2021
is presented below (in thousands, except fair value).
Non-vested restricted stock
and restricted stock units
Non-vested at December 31, 2020
Granted
Vested(1)
Non-vested at December 31, 2021
Restricted Stock
Restricted Stock Units
Service Based
Service Based
Performance Based
Weighted
average
fair value
$20.01
$ 37.56
$ 27.14
$ 17.35
$ 24.59
Shares
682
283
(334)
(42)
589
Weighted
average
fair value
$ 8.85
$ 30.97
$ 9.02
$ —
$ 33.39
Shares
75
36
(78)
—
33
Weighted
average
fair value
$ 9.05
$ 50.53
$ 20.00
$ 9.33
$ 20.26
Shares
1,069
366
(397)
(75)
963
On December 31, 2021, 396,827 of the performance-based awards that were granted in 2019 vested. The vested units earned 200% for each
vested award representing 793,654 aggregate shares of common stock, which were issued on December 31, 2021.
Liability-Based
A summary of the non-vested liability-based restricted stock units as of December 31, 2021 is presented below
(in thousands).
Non-vested restricted stock units
Non-vested at December 31, 2020
Granted
Vested
Forfeited
Non-vested at December 31, 2021
Shares
1,319
357
(487)
(87)
1,102
The Company settled 487,252 liability-based awards for $12.4 million and 226,363 liability-based awards for
$2.4 million in cash for the years ended December 31, 2021 and 2020, respectively. The Company did not settle any
liability awards for the year ended December 31, 2019.
At December 31, 2021, the aggregate intrinsic value for the restricted stock and restricted stock units
outstanding was $99.2 million, of which $40.7 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.
At December 31, 2021, the total remaining unrecognized compensation expense related to unvested restricted
stock and restricted stock units was approximately $50.3 million, of which $24.0 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 2.0 years.
The fair value of restricted stock and restricted stock units vested during 2021, 2020 and 2019 was $51.9 million,
$8.4 million and $13.6 million, respectively.
Notes to Consolidated Financial Statements FORM 10-K
F-34
MATADOR RESOURCES COMPANY
NOTE 9 — STOCK-BASED COMPENSATION — Continued
Summary
During the years ended December 31, 2021, 2020 and 2019, the total expense attributable to stock options
was $1.0 million, $3.4 million and $6.4 million, respectively. During the years ended December 31, 2021, 2020
and 2019, the total expense attributable to restricted stock and restricted stock units was $36.3 million, $17.7 million
and $20.2 million, respectively. During the years ended December 31, 2021, 2020 and 2019, the Company
capitalized $7.2 million, $3.6 million and $5.0 million, respectively, related to stock-based compensation and
expensed the remaining $30.0 million, $17.6 million and $21.6 million, respectively.
The total tax benefit recognized for all stock-based compensation was $7.9 million, $4.5 million and $5.6 million
for the years ended December 31, 2021, 2020 and 2019, 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 $1.6 million, $1.4 million
and $1.4 million in 2021, 2020 and 2019, 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 $2.1 million, $1.8 million and $1.7 million in 2021, 2020 and 2019, respectively. The Company made no
additional contributions in any reporting period presented.
NOTE 11 — EQUITY
Common Stock Dividend
The Company’s Board of Directors (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 October 2021, the Board amended the Company’s
dividend policy to increase the quarterly dividend and declared a quarterly cash dividend of $0.05 per share of
common stock. Total cash dividends declared and paid totaled $14.6 million during the year ended December 31,
2021. There were no cash dividends declared or paid prior to 2021.
Treasury Stock
On October 21, 2021, October 22, 2020 and October 24, 2019, Matador’s Board of Directors canceled all of the
shares of treasury stock outstanding as of September 30, 2021, 2020 and 2019, 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, 2021, 2020 and 2019 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.
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-35
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, 2021, the Company had various costless collar and swap contracts open and in place to mitigate
its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity
(volume hedged) and price floor and ceiling for the collars and fixed price for the swaps. At December 31, 2021, each
contract was set to expire at varying times during 2022. The Company had no open contracts associated with NGL
prices at December 31, 2021.
The following is a summary of the Company’s open costless collar contracts for oil and natural gas at
December 31, 2021.
Commodity
Calculation Period
Notional
Quantity
(Bbl or MMBtu)
Weighted
Average
Price Floor
($/Bbl or $/MMBtu)
Weighted
Average
Price Ceiling
($/Bbl or $/MMBtu)
Fair Value
of Asset
(Liability)
(thousands)
Oil
Natural Gas
Total open costless collar
contracts
01/01/2022 - 12/31/2022
01/01/2022 - 03/31/2022
2,040,000
8,250,000
$ 50.00
$ 2.70
$ 67.85
$ 6.33
$ (16,652)
(151)
$ (16,803)
The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2021.
Commodity
Oil Basis
Total open basis swap contracts
Calculation Period
Notional
Quantity
(Bbl)
Fixed Price
($/Bbl)
01/01/2022 - 12/31/2022
5,520,000
$ 0.95
Fair Value
of Asset
(Liability)
(thousands)
1,925
$ 1,925
At December 31, 2021, the Company had an aggregate net liability value for open derivative financial instruments
of $14.9 million.
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.
Notes to Consolidated Financial Statements FORM 10-K
F-36
MATADOR RESOURCES COMPANY
NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued
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,
2021 and December 31, 2020 (in thousands).
Derivative Instruments
December 31, 2021
Current assets
Current liabilities
Total
December 31, 2020
Current assets
Other assets
Current liabilities
Long-term liabilities
Total
Gross amounts
recognized
Gross amounts
netted in the
consolidated
balance sheets
Net amounts
presented in
the consolidated
balance sheets
$ 215,145
(230,023)
$ (14,878)
$ (213,174)
213,174
—
$
$ 382,328
150,194
(420,787)
(147,624)
$ (35,889)
$ (375,601)
(147,624)
375,601
147,624
—
$
$ 1,971
(16,849)
$ (14,878)
$ 6,727
2,570
(45,186)
—
$(35,889)
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
2021
2020
2019
Derivative Instrument
Oil
Natural Gas
Realized (loss) gain on derivatives
Oil
Natural Gas
Revenues: Realized (loss) gain on derivatives
Revenues: Realized (loss) gain on derivatives
Revenues: Unrealized gain (loss) on derivatives
Revenues: Unrealized (loss) gain on derivatives
Unrealized gain (loss) on derivatives
Total
$ (194,058) $ 38,937
—
38,937
(37,703)
5,695
(32,008)
(26,047)
(220,105)
26,857
(5,846)
21,011
$ (199,094) $ 6,929
$ 9,026
456
9,482
(53,443)
(284)
(53,727)
$(44,245)
Year Ended December 31,
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.
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.
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-37
NOTE 13 — FAIR VALUE MEASUREMENTS — Continued
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, 2021
and 2020 (in thousands).
Description
Assets (Liabilities)
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)
$ —
—
(8,203)
$ (8,203)
$ (14,727)
(151)
(8,203)
$ (23,081)
Description
Assets (Liabilities)
Oil derivatives and basis swaps
Natural gas derivatives
Total
Fair Value Measurements at December 31, 2020 using
Level 1
Level 2
Level 3
Total
$ —
—
$ —
$ (41,584)
5,695
$ (35,889)
$ — $(41,584)
5,695
$ — $(35,889)
—
Additional disclosures related to derivative financial instruments are provided in Note 12.
Other Fair Value Measurements
At December 31, 2021 and 2020, 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, 2021 and 2020, 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, 2021 and 2020, the fair value of the Notes was $1.08 billion and $1.03 billion, respectively,
based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.
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 2021 and 2020.
Notes to Consolidated Financial Statements FORM 10-K
F-38
MATADOR RESOURCES COMPANY
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 $48.7 million and
$46.0 million for deliveries under these agreements during the years ended December 31, 2021 and 2020,
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, 2021, the total
deficiencies required to be paid by the Company under these agreements would be approximately $597.3 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, 2021 was approximately $390.3 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 $10.8 million at December 31, 2021.
At December 31, 2021, the Company had outstanding commitments to drill and complete and to participate in
the drilling and completion of various operated and 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 operated and non-operated wells were approximately $65.4 million at December 31, 2021. The Company
expects these costs to be incurred within the next three years.
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.
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-39
NOTE 15 — SUPPLEMENTAL DISCLOSURES
Accrued Liabilities
The following table summarizes the Company’s current accrued liabilities at December 31, 2021 and 2020
(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,
2021
2020
$ 128,598
7,799
32,182
18,232
270
17,460
11,284
37,458
$ 253,283
$ 44,012
12,776
24,276
18,315
623
7,407
418
11,331
$119,158
The following table provides supplemental disclosures of cash flow information for the years ended December 31,
2021, 2020 and 2019 (in thousands).
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
Increase (decrease) in liabilities for drilling, completion and equipping
capital expenditures
Increase (decrease) increase in liabilities for acquisition of oil and
natural gas properties
(Decrease) increase in liabilities for midstream capital expenditures
Stock-based compensation expense recognized as liability
Transfer of inventory (to) from oil and natural gas properties
Year Ended December 31,
2021
2020
2019
$ 74,843
$ 76,880
$ 75,525
$ 1,091
257
$
$
$
(208)
690
$ 2,912
$ 1,204
$ 80,255
$(26,126)
$(13,310)
$ 2,981
$ (4,478)
$ 24,494
(398)
$
$ (2,346)
$(33,609)
$ 3,702
608
$
$ (2,567)
$ 30,374
$ 3,170
$ 1,515
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,
2021
2020
2019
$ 48,135
38,785
$ 86,920
$ 57,916
33,467
$ 91,383
$ 40,024
25,104
$ 65,128
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). San Mateo and its subsidiaries are not guarantors of the
Notes or the Credit Agreement.
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.”
Exploration and
Production
Midstream
Corporate
Consolidations
and
Eliminations
Consolidated
Company
Year Ended December 31, 2021
Oil and natural gas revenues
Sales of purchased natural gas
Realized loss on derivatives
Unrealized gain on derivatives
Expenses(1)
Operating income(2)
(3)
(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
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.
FORM 10-K Notes to Consolidated Financial Statements
2021 ANNUAL REPORT
F-41
NOTE 16 — SEGMENT INFORMATION — Continued
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 (loss) income(2)
Total assets(3)
Capital expenditures(4)
Exploration and
Production
Midstream
Corporate
Consolidations
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.
Year Ended December 31, 2019
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
Consolidations
and
Eliminations
Consolidated
Company
$ 886,127
—
4,802
1,711
9,482
(53,727)
621,687
$ 226,708
$
6,198
135,953
69,967
—
—
—
130,612
$ 81,506
$
—
—
—
—
—
—
72,734
$(72,734)
$3,360,725
$ 647,937
$ 61,014
$ 718,712
$ 223,612
$ 3,701
$
—
(76,843)
—
—
—
—
(76,843)
$
$
$
—
—
—
$ 892,325
59,110
74,769
1,711
9,482
(53,727)
748,190
$ 235,480
$4,069,676
$ 946,025
(1)
Includes depletion, depreciation and amortization expenses of $331.7 million and $16.1 million for the exploration and production and
midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.7 million.
(2) Includes $35.2 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 $48.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and
$145.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.
Notes to Consolidated Financial Statements FORM 10-K
F-42
MATADOR RESOURCES COMPANY
Unaudited Supplementary Information
MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2021, 2020 and 2019
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, 2021, 2020 and 2019 (in thousands).
Property acquisition costs
Proved
Unproved and unevaluated
Exploration costs
Development costs
Total costs incurred(1)
Year Ended December 31,
2021
2020
2019
$ 145,759
104,582
51,534
476,316
$ 778,191
$
8,003
61,984
29,370
418,840
$518,197
$
3,767
39,595
109,439
570,290
$723,091
(1) Excludes midstream-related development and corporate costs of approximately $59.7 million, $203.6 million and $227.3 million for the years
ended December 31, 2021, 2020 and 2019, 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 year
ended December 31, 2021, approximately 58% of the Company’s property acquisition costs resulted from the
acquisition of proved properties, while for the years ended December 31, 2020 and 2019, most of the Company’s
property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold and mineral interests.
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. For the years ended December 31, 2021, 2020 and 2019, the Company capitalized
$7.5 million, zero and $2.9 million, respectively, of geological and geophysical costs, which are included as exploration
costs in the table above.
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 $1.4 million, a reduction of $0.2 million and an increase of $4.3 million for the
years ended December 31, 2021, 2020 and 2019, 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 $38.4 million, $30.0 million and $31.1 million of these internal costs for the years ended
December 31, 2021, 2020 and 2019, 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 $4.8 million, $5.0 million and $7.6 million of its interest expense for the years ended December 31, 2021,
2020 and 2019, respectively, excluding midstream-related capitalized interest expense.
FORM 10-K Unaudited Supplementary Information
2021 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, 2021, 2020 and 2019 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 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. For the period from January through December 2019, these average oil and natural gas prices
were $52.19 per Bbl and $2.58 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, 2018
Revisions of prior estimates
Net divestitures of minerals-in-place
Extensions and discoveries
Production
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
Proved Developed Reserves
December 31, 2018
December 31, 2019
December 31, 2020
December 31, 2021
Proved Undeveloped Reserves
December 31, 2018
December 31, 2019
December 31, 2020
December 31, 2021
Net Proved Reserves
Oil
(MBbl)
123,401
(605)
(298)
39,477
(13,984)
147,991
6,587
11
21,291
(15,931)
159,949
14,346
7,533
17,318
(17,840)
181,306
53,223
59,667
69,647
102,233
70,178
88,324
90,301
79,073
Natural
Gas
(MMcf)
551,474
34,062
(12,048)
114,833
(61,083)
627,238
19,444
1,078
84,043
(69,501)
662,302
165,423
11,976
94,532
(81,686)
852,547
246,229
276,258
323,160
546,173
305,245
350,980
339,142
306,374
Oil
Equivalent
(MBOE)
215,313
5,073
(2,307)
58,616
(24,164)
252,531
9,828
190
35,297
(27,514)
270,332
41,916
9,529
33,074
(31,454)
323,397
94,261
105,710
123,507
193,262
121,052
146,821
146,825
130,135
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, 2021, 2020 and 2019.
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
FORM 10-K Unaudited Supplementary Information
2021 ANNUAL REPORT
F-45
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued
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 developed oil and natural gas reserves increased 56% from 123.5 million BOE at
December 31, 2020 to 193.3 million BOE at December 31, 2021. The Company’s proved developed oil and natural
gas reserves increased by 101.2 million BOE and the Company produced 31.5 million BOE during the year ended
December 31, 2021, resulting in a net increase of 69.8 million BOE. The Company added 22.4 million BOE in proved
developed reserves through extensions and discoveries during 2021, which resulted from new well locations
drilled during 2021 to establish proved developed reserves. The Company realized approximately 33.8 million BOE in
net upward revisions to prior estimates, 97% 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 producing 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 producing properties. In addition,
the Company converted 40.1 million BOE of its proved undeveloped reserves to proved developed reserves
primarily through its development activities in the Delaware Basin during 2021, primarily in the Company’s Stateline
asset area, in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area.
In addition, the Company realized 4.9 million BOE in net upward revisions to its proved developed reserves at
December 31, 2021 as a result of property acquisitions and divestitures completed during 2021.
The Company’s proved undeveloped oil and natural gas reserves decreased 11% from 146.8 million BOE at
December 31, 2020 to 130.1 million BOE at December 31, 2021. The Company added 26.9 million BOE in proved
undeveloped reserves through extensions and discoveries during 2021, which 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 the properties in the Delaware Basin. The Company
realized approximately 8.1 million BOE in net upward revisions to its prior estimates of proved undeveloped
reserves, 90% 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 proved
undeveloped locations. The Company also had small upward revisions to prior estimates attributable to increased
working interests and lower estimated operating costs on certain of its proved undeveloped locations. In addition,
the Company realized 4.6 million BOE in net upward revisions to its proved undeveloped reserves at December 31,
2021 as a result of property acquisitions and divestitures completed during 2021. During 2021, the Company also
converted 40.1 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its
development activities in the Delaware Basin during 2021, as noted above.
At December 31, 2021, the Company’s proved reserves were comprised of 56% oil and 44% natural gas and
were approximately 60% proved developed and 40% proved undeveloped. This increase in the Company’s proved
developed reserves to 60% of its total proved reserves at December 31, 2021 reflected a significant change in
the Company’s percentage of proved developed reserves, as compared to 46% and 42% proved developed reserves
at December 31, 2020 and 2019, 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 to 270.3 million BOE at December 31, 2020 from
252.5 million BOE at December 31, 2019. 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.
The Company’s proved oil and natural gas reserves increased to 252.5 million BOE at December 31, 2019
from 215.3 million BOE at December 31, 2018. The Company’s proved oil and natural gas reserves increased by
61.4 million BOE and the Company produced 24.2 million BOE during the year ended December 31, 2019, resulting
in a net increase of 37.2 million BOE. The Company’s proved oil and natural gas reserves increased by 58.6 million
BOE during 2019 as a result of extensions and discoveries during the year, which were primarily attributable to drilling
operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West
Texas. The Company’s proved oil and natural gas reserves increased by 5.1 million BOE during 2019 as a result of
upward revisions of prior estimates, which were attributable to better-than-expected well performance from certain
wells, but which were also partially offset by downward revisions attributable to the lower weighted average oil
and natural gas prices used to estimate proved reserves in 2019, as compared to 2018. The Company’s proved oil
and natural gas reserves decreased 2.3 million BOE in 2019 as a result of net divestitures of minerals-in-place
primarily in the Eagle Ford Shale in South Texas and the Haynesville Shale in Northwest Louisiana. The Company’s
proved developed oil and natural gas reserves increased to 105.7 million BOE at December 31, 2019 from
94.3 million BOE at December 31, 2018, 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, 2019, the Company’s
proved reserves were made up of approximately 59% oil and 41% natural gas and were approximately 42% proved
developed and approximately 58% proved undeveloped.
FORM 10-K Unaudited Supplementary Information
2021 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 2021, the unweighted, arithmetic averages
of first-day-of-the-month 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. For the period from January through December 2019, the comparable average
oil and natural gas prices were $52.19 per Bbl and $2.58 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, 2021, 2020 and 2019 (in thousands).
Year Ended December 31,
2021
2020
2019
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
$ 15,174,065
$ 6,587,343
(4,588,677)
(1,251,581)
(1,836,009)
7,497,798
(3,122,373)
(2,606,956)
(1,075,317)
(228,848)
2,676,222
(1,091,823)
Standardized measure of discounted future net cash flows
$ 4,375,425
$ 1,584,399
$ 8,771,595
(3,087,142)
(1,638,744)
(479,011)
3,566,698
(1,532,715)
$ 2,033,983
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, 2021, 2020 and 2019 (in thousands).
Year Ended December 31,
2021
2020
2019
$ 1,584,399
$ 2,033,983
$2,250,613
3,347,910
(238,871)
(1,412,591)
178,695
620,235
786,061
240,664
165,799
1,737
(898,613)
(1,126,777)
177,074
(546,169)
1,803
296,617
93,066
253,165
240,728
16
160,893
$ 1,584,399
(622,710)
(284,748)
(682,747)
(28,849)
733,208
63,436
258,593
237,548
(4,861)
114,500
$2,033,983
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 (divestitures) 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
$ 4,375,425
FORM 10-K Unaudited Supplementary Information
2021 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.
February 28, 2022
/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, David E. Lancaster, 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.
February 28, 2022
/s/ David E. Lancaster
David E. Lancaster
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
FORM 10-K
2021 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, 2021 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.
February 28, 2022
/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, 2021 as filed with the Securities and Exchange Commission on the date hereof
(the “Form 10-K”), I, David E. Lancaster, Executive Vice President and Chief Financial 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.
February 28, 2022
/s/ David E. Lancaster
David E. Lancaster
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
FORM 10-K
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 (loss), 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 (loss) 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 (loss) 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 (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
Consolidated Adjusted EBITDA
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
Adjusted EBITDA attributable to Matador Resources Company shareholders
Year Ended
December 31, December 31,
2021
2020
$ 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
$(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)
$ 519,277
Additional Financial Information
ADJUSTED EBITDA RECONCILIATION — Continued
Year Ended
December 31, December 31,
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
Expense related to contingent consideration
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
Adjusted EBITDA attributable to Matador Resources Company shareholders
$ 1,053,355
982
71,028
1,485
(74,877)
$ 1,051,973
$477,582
23,078
73,860
—
(55,243)
$519,277
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
One-time plant payment and impairment
Adjusted EBITDA
(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
Year Ended
December 31, December 31,
December 31, December 31,
2021
2020
2019
2018
$ 113,607
30,522
8,434
247
1,500
$ 154,310
$ 80,910
22,485
7,884
200
1,261
$112,740
$
$
71,850
15,068
9,282
110
—
96,310
$ 52,158
9,459
333
61
—
$ 62,011
Year Ended
December 31, December 31,
December 31, December 31,
2021
2020
2019
2018
$ 143,744
1,689
7,377
1,500
$ 154,310
$ 96,334
9,206
7,200
—
$112,740
$ 106,650
(19,137)
8,797
—
96,310
$
$ 35,702
25,989
320
—
$ 62,011
Additional Financial Information
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 as 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 Reconciliation — 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,
2021
$ 1,053,355
982
(71,262)
48,626
1,031,701
431,136
63,359
376
78,515
(28,614)
544,772
$ 486,929
(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 immaterial
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,
2021
$ 143,744
1,689
145,433
62,111
(3,716)
58,395
$ 87,038
Additional Financial Information
MATADOR RESOURCES COMPANY
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MATADOR RESOURCES COMPANY
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MATADOR RESOURCES COMPANY
[PAGE INTENTIONALLY LEFT BLANK]
CORPORATE INFORMATION
STOCK EXCHANGE LISTING
New York Stock Exchange (NYSE): MTDR
CORPORATE HEADQUARTERS
Matador Resources Company
One Lincoln Centre
5400 LBJ Freeway, Suite 1500
Dallas, Texas 75240
(972) 371-5200
For more information, please visit
www.matadorresources.com.
For Employment Opportunities, please visit
www.matadorresources.com/careers
Email: careers@matadorresources.com
STOCK TRANSFER AGENT AND REGISTRAR
Please direct general questions about shareholder
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mailings to Matador Resources Company’s transfer agent:
Computershare Investor Services
462 South 4th Street, Suite 1600
Louisville, KY 40202
(800) 368-5948
www.computershare.com
FINANCIAL INFORMATION REQUESTS
To receive additional copies of our Annual Report
(cid:156)(cid:152)(cid:3)(cid:19)(cid:156)(cid:192)(cid:147)(cid:3)(cid:163)(cid:228)(cid:135)(cid:28)(cid:3)(cid:62)(cid:195)(cid:3)(cid:119)(cid:143)(cid:105)(cid:96)(cid:3)(cid:220)(cid:136)(cid:204)(cid:133)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)(cid:45)(cid:13)(cid:10)(cid:3)(cid:156)(cid:192)(cid:3)(cid:204)(cid:156)(cid:3)(cid:156)(cid:76)(cid:204)(cid:62)(cid:136)(cid:152)(cid:3)(cid:156)(cid:204)(cid:133)(cid:105)(cid:192)(cid:3)
Matador Resources Company information, please
contact Mac Schmitz, Capital Markets Coordinator,
at our corporate headquarters.
Phone: (972) 371-5225
Email: investors@matadorresources.com
OFFICER CERTIFICATIONS
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included herein, excluding all exhibits other than our
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by the CEO and CFO. We will send shareholders copies
of the exhibits to our Annual Report on Form 10-K and
any of our corporate governance documents, free of
charge, upon request.
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:83)(cid:86)(cid:86)(cid:82)(cid:80)(cid:85)(cid:78)(cid:3)(cid:90)(cid:91)(cid:72)(cid:91)(cid:76)(cid:84)(cid:76)(cid:85)(cid:91)(cid:90)(cid:3)(cid:72)(cid:89)(cid:76)(cid:3)(cid:88)(cid:92)(cid:72)(cid:83)(cid:80)(cid:196)(cid:76)(cid:75)(cid:3)(cid:80)(cid:85)(cid:3)(cid:91)(cid:79)(cid:76)(cid:80)(cid:89)(cid:3)(cid:76)(cid:85)(cid:91)(cid:80)(cid:89)(cid:76)(cid:91)(cid:96)(cid:3)(cid:73)(cid:96)(cid:3)(cid:91)(cid:79)(cid:80)(cid:90)(cid:3)(cid:74)(cid:72)(cid:92)(cid:91)(cid:80)(cid:86)(cid:85)(cid:72)(cid:89)(cid:96)(cid:3)(cid:90)(cid:91)(cid:72)(cid:91)(cid:76)(cid:84)(cid:76)(cid:85)(cid:91)(cid:21)
CELEBRATING 10 YEARS OF
BUILDING SHAREHOLDER VALUE
Matador’s average daily
total production was just
over 7,000 barrels of oil
equivalent per day in 2011,
and in the second quarter of
2022, we expect to average
more than 100,000 barrels of
oil equivalent per day. Even
more striking, in 2011, we
produced a total of 154,000
barrels of oil, or about 420
barrels of oil per day, while
in 2021, we produced 17.8
million barrels of oil, or
48,900 barrels of oil per
day—an increase of more
than 100-fold!
Matador has experienced tremendous growth in production, Adjusted EBITDA(1) and oil and natural
gas reserves over the past ten years.
10TOP
Ranked producer
for oil and natural
gas in the state
of New Mexico.
TOTAL PRODUCTION GROWTH
E
O
B
M
,
n
o
i
t
c
u
d
o
r
P
l
a
t
o
T
35,000
25,000
20,000
15,000
10,000
5,000
0
+28% CAGR
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during the past ten years. On February 2, 2012, we
began trading as a public company at $12.00 per
share. On March 25, 2022, just over ten years later,
Matador closed at an all-time high of $56.39 per
share, an increase of 4.7-fold.
20TOP
Largest E&P companies by
market capitalization having
(cid:86)(cid:143)(cid:136)(cid:147)(cid:76)(cid:105)(cid:96)(cid:3)(cid:195)(cid:136)(cid:125)(cid:152)(cid:136)(cid:119)(cid:86)(cid:62)(cid:152)(cid:204)(cid:143)(cid:222)(cid:3)(cid:62)(cid:147)(cid:156)(cid:152)(cid:125)(cid:3)(cid:204)(cid:133)(cid:105)(cid:3)
150 largest companies since
the time of Matador’s IPO in
February 2012.
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
ADJUSTED EBITDA(1) GROWTH
s
n
o
i
l
l
i
m
n
i
$
,
I
A
D
T
B
E
d
e
t
s
u
d
A
j
+36% CAGR
$1,200
$1,000
$800
$600
$400
$200
$0
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
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MATADOR RESOURCES COMPANY | 5400 LBJ Freeway, Suite 1500 | Dallas, Texas 75240 | (972) 371-5200 | www.matadorresources.com