The following discussion and analysis of our financial condition and results of
operations should be read in conjunction with our interim unaudited condensed
consolidated financial statements and related notes thereto contained herein and
the consolidated financial statements and related notes thereto contained in our
Annual Report on Form 10-K for the year ended December 31, 2020 (the "Annual
Report") filed with the Securities and Exchange Commission (the "SEC") on
February 26, 2021, along with Management's Discussion and Analysis of Financial
Condition and Results of Operations contained in the Annual Report. The Annual
Report is accessible on the SEC's website at www.sec.gov and on our website at
www.matadorresources.com. Our discussion and analysis includes forward-looking
information that involves risks and uncertainties and should be read in
conjunction with the "Risk Factors" section of the Annual Report and the section
entitled "Cautionary Note Regarding Forward-Looking Statements" below for
information about the risks and uncertainties that could cause our actual
results to be materially different than our forward-looking statements.
In this Quarterly Report on Form 10-Q (this "Quarterly 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, collectively with
its subsidiaries. For certain oil and natural gas terms used in this Quarterly
Report, please see the "Glossary of Oil and Natural Gas Terms" included with the
Annual Report.
Cautionary Note Regarding Forward-Looking Statements
Certain statements in this Quarterly 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;
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 San Mateo's Black River
cryogenic natural gas processing plant; the timing and operating results of the
buildout by San Mateo of oil, natural gas and water gathering and transportation
systems and the drilling of any additional salt water disposal wells; and the
other factors discussed below and elsewhere in this Quarterly Report and in
other documents that we file with or furnish to 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, completion 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;
•our drilling of wells;
                                       21
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•our ability to negotiate and consummate acquisition and divestiture
opportunities;
•government regulation and taxation of the oil and natural gas industry;
•our marketing of oil and natural gas;
•our exploitation projects or property acquisitions;
•the integration of acquisitions with our business;
•our ability and the ability of San Mateo to construct and operate midstream
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 San Mateo to attract third-party volumes;
•our costs and timing 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;
•counterparty credit risk;
•regulatory risk;
•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 Quarterly
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 Quarterly 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.
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.
Second Quarter Highlights
For the three months ended June 30, 2021, our total oil equivalent production
was 8.5 million BOE, and our average daily oil equivalent production was 93,200
BOE per day, of which 53,400 Bbl per day, or 57%, was oil and 239.1 MMcf per
day, or 43%, was natural gas. Our average daily oil production of 53,400 Bbl per
day for the three months ended June 30, 2021 increased 24% year-over-year from
43,100 Bbl per day for the three months ended June 30, 2020. Our average daily
natural gas production of 239.1 MMcf per day for the three months ended June 30,
2021 increased 32% year-over-year from 181.4 MMcf per day for the three months
ended June 30, 2020.
For the second quarter of 2021, we reported net income attributable to Matador
shareholders of $105.9 million, or $0.89 per diluted common share, on a
generally accepted accounting principles in the United States ("GAAP") basis, as
compared to a net loss attributable to Matador shareholders of $353.4 million,
or ($3.04) per diluted common share, for the second quarter of 2020. For the
second quarter of 2021, our Adjusted EBITDA attributable to Matador shareholders
("Adjusted EBITDA"), a non-GAAP financial measure, was $261.0 million, as
compared to Adjusted EBITDA of $107.6 million during the second
                                       22
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quarter of 2020. 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 "-Liquidity and Capital Resources-Non-GAAP Financial Measures."
For more information regarding our financial results for the three months ended
June 30, 2021, see "-Results of Operations" below.
For the six months ended June 30, 2021, we reported net income attributable to
Matador shareholders of $166.6 million, or $1.40 per diluted common share, on a
GAAP basis, as compared to a net loss attributable to Matador shareholders of
$227.7 million, or ($1.96) per diluted common share, for the six months ended
June 30, 2020. For the six months ended June 30, 2021, our Adjusted EBITDA, a
non-GAAP financial measure, was $459.1 million, as compared to Adjusted EBITDA
of $248.2 million during the six months ended June 30, 2020. 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 "-Liquidity and Capital
Resources-Non-GAAP Financial Measures." For more information regarding our
financial results for the six months ended June 30, 2021, see "-Results of
Operations" below.
Operations Update
We operated four drilling rigs in the Delaware Basin during the second quarter
of 2021. At July 27, 2021, two of these rigs were drilling in the Stateline
asset area in Eddy County, New Mexico. These two rigs recently completed
drilling 13 additional Boros wells in the eastern portion of the Stateline asset
area and at July 27, 2021 were drilling 11 new Voni wells in the western portion
of that asset area. The other two rigs have been drilling 13 wells in the
southern portion of the Arrowhead asset area (the "Greater Stebbins Area"), nine
of which were still in progress at July 27, 2021. Four of these wells, all
Second Bone Spring completions, were recently turned to sales. When we complete
drilling the nine wells in progress in the Greater Stebbins Area, we plan to use
these two rigs to drill two additional wells in the Ranger asset area in Lea
County, New Mexico and several additional Rodney Robinson wells in the western
portion of the Antelope Ridge asset area in Lea County.
We turned to sales a total of 24 gross (15.6 net) wells in the Delaware Basin
during the second quarter of 2021, including 15 gross (14.6 net) operated wells
and nine gross (1.0 net) non-operated wells. During the second quarter of 2021,
we turned to sales 13 gross (12.7 net) operated wells in the Stateline asset
area; four were Wolfcamp A-Lower completions, four were Wolfcamp A-XY
completions, four were Second Bone Spring completions and one was a First Bone
Spring completion. In the Wolf asset area, we turned to sales two gross (1.9
net) operated wells, both of which were Second Bone Spring completions. We also
participated in five gross (0.3 net) non-operated wells turned to sales in the
Antelope Ridge asset area, two gross (0.7 net) non-operated wells in the
Arrowhead asset area and two gross (less than 0.1 net) non-operated wells in the
Rustler Breaks asset area.
Our average daily oil equivalent production in the Delaware Basin for the second
quarter of 2021 was 87,500 BOE per day, consisting of 51,700 Bbl of oil per day
and 214.7 MMcf of natural gas per day, a 33% increase from 66,000 BOE per day,
consisting of 41,500 Bbl of oil per day and 146.9 MMcf of natural gas per day,
in the second quarter of 2020. The Delaware Basin contributed approximately 97%
of our daily oil production and approximately 90% of our daily natural gas
production in the second quarter of 2021, as compared to approximately 96% of
our daily oil production and approximately 81% of our daily natural gas
production in the second quarter of 2020.
During the second quarter of 2021, we did not complete and turn to sales any
operated wells on our leasehold properties in the Eagle Ford shale play in South
Texas or in the Haynesville shale and Cotton Valley plays in Northwest
Louisiana, but we did participate in four gross (less than 0.1 net) non-operated
wells in the Haynesville shale.
2021 Capital Expenditure Budget
At July 27, 2021, our 2021 estimated capital expenditures for drilling,
completing and equipping wells ("D/C/E capital expenditures") remained $525 to
$575 million, as originally estimated. As a result of savings on our operated
D/C/E capital expenditures in the first half of 2021, a faster drilling and
completions pace and an anticipated decrease in non-operated D/C/E capital
expenditures in the second half of 2021, we intend to advance the next 11 Voni
well completions in the Stateline asset area forward into the fourth quarter of
2021 and expect to be able to do so without increasing our estimates for D/C/E
capital expenditures for full year 2021.
At July 27, 2021, we increased our anticipated 2021 midstream capital
expenditures from $20 to $30 million to $35 to $45 million, primarily to
accommodate several new midstream opportunities for San Mateo with producers in
Eddy County, New Mexico and to accelerate the installation of compression
facilities and other infrastructure prior to the end of 2021 in order to be
prepared for the additional volumes from the accelerated Voni completions noted
above. Previously, these Voni-related capital expenditures were scheduled for
early 2022. The anticipated total 2021 midstream capital expenditures of $35 to
$45 million primarily reflect our proportionate share of San Mateo's estimated
2021 capital expenditures.
                                       23
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Capital Resources Update
Our Board of Directors (the "Board") declared a quarterly cash dividend of
$0.025 per share of common stock in both the first and second quarters of 2021,
which were paid on March 31, 2021 and June 3, 2021, respectively. In July 2021,
the Board declared a quarterly cash dividend of $0.025 per share of common stock
payable on September 3, 2021 to shareholders of record as of August 12, 2021.
During each of the first and second quarters of 2021, we had net repayments of
$100.0 million in borrowings under our third amended and restated credit
agreement (the "Credit Agreement"). Our outstanding borrowings under our Credit
Agreement at June 30, 2021 were $240.0 million.
In April 2021, the lenders under our Credit Agreement completed their review of
our proved oil and natural gas reserves, and, as a result, the borrowing base
was reaffirmed at $900.0 million. The Company elected to keep the borrowing
commitment at $700.0 million, the maximum facility amount remained $1.5 billion
and no material changes were made to the terms of the Credit Agreement. This
April 2021 redetermination constituted the regularly scheduled May 1
redetermination. Borrowings under the Credit Agreement are limited to the lowest
of the borrowing base, the maximum facility amount and the elected borrowing
commitment.
In June 2021, San Mateo's revolving credit facility (the "San Mateo Credit
Facility") was amended 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 certain covenants) and the borrowing rate for a base rate loan
or Eurodollar loan under such facility was increased 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.
Critical Accounting Policies
There have been no changes to our critical accounting policies and estimates
from those set forth in the Annual Report.
Recent Accounting Pronouncements
There are no recent accounting pronouncements that are expected to have a
material impact on our financial statements.
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Results of Operations
Revenues
The following table summarizes our unaudited revenues and production data for
the periods indicated:
                                                               Three Months Ended                     Six Months Ended
                                                                    June 30,                              June 30,
                                                            2021                2020               2021               2020
Operating Data
Revenues (in thousands)(1)
Oil                                                     $  315,114          $  94,174          $ 528,393          $ 263,759
Natural gas                                                 96,960             24,593            199,914             52,922
Total oil and natural gas revenues                         412,074            118,767            728,307            316,681
Third-party midstream services revenues                     19,850             14,668             35,288             30,498
Sales of purchased natural gas                              10,918             13,981             15,428             24,525
Lease bonus - mineral acreage                                    -              4,062                  -              4,062
Realized (loss) gain on derivatives                        (42,611)            44,110            (68,524)            54,977
Unrealized (loss) gain on derivatives                      (42,804)          (132,668)           (86,227)             3,762
Total revenues                                          $  357,427          $  62,920          $ 624,272          $ 434,505
Net Production Volumes(1)
Oil (MBbl)(2)                                                4,855              3,920              8,594              7,617
Natural gas (Bcf)(3)                                          21.8               16.5               39.3               33.2
Total oil equivalent (MBOE)(4)                               8,482              6,670             15,140             13,146
Average daily production (BOE/d)(5)                         93,210             73,302             83,650             72,232
Average Sales Prices
Oil, without realized derivatives (per Bbl)             $    64.90          $   24.03          $   61.49          $   34.63
Oil, with realized derivatives (per Bbl)                $    56.13          $   35.28          $   53.49          $   41.85
Natural gas, without realized derivatives (per Mcf)     $     4.46          $    1.49          $    5.09          $    1.60
Natural gas, with realized derivatives (per Mcf)        $     4.46          $    1.49          $    5.09          $    1.60

_________________


(1)We report our production volumes in two streams: oil and natural gas,
including both dry and liquids-rich natural gas. Revenues associated with
natural gas liquids are included with our natural gas revenues.
(2)One thousand Bbl of oil.
(3)One billion cubic feet of natural gas.
(4)One thousand Bbl of oil equivalent, estimated using a conversion ratio of one
Bbl of oil per six Mcf of natural gas.
(5)Barrels of oil equivalent per day, estimated using a conversion ratio of one
Bbl of oil per six Mcf of natural gas.
Three Months Ended June 30, 2021 as Compared to Three Months Ended June 30, 2020
Oil and natural gas revenues. Our oil and natural gas revenues increased $293.3
million, or 247%, to $412.1 million for the three months ended June 30, 2021, as
compared to $118.8 million for the three months ended June 30, 2020. Our oil
revenues increased $220.9 million, or 235%, to $315.1 million for the three
months ended June 30, 2021, as compared to $94.2 million for the three months
ended June 30, 2020. This increase in oil revenues resulted from a 170% increase
in the weighted average oil price realized for the three months ended June 30,
2021 to $64.90 per Bbl, as compared to $24.03 per Bbl for the three months ended
June 30, 2020, and from a 24% increase in our oil production to 4.9 million Bbl
for the three months ended June 30, 2021, as compared to 3.9 million Bbl for the
three months ended June 30, 2020. Our natural gas revenues increased $72.4
million, or 294%, to $97.0 million for the three months ended June 30, 2021, as
compared to $24.6 million for the three months ended June 30, 2020. The increase
in natural gas revenues resulted from an approximately three-fold increase in
the weighted average natural gas price realized for the three months ended June
30, 2021 to $4.46 per Mcf, as compared to a weighted average natural gas price
of $1.49 per Mcf realized for the three months ended June 30, 2020, and from a
32% increase in our natural gas production to 21.8 Bcf for the three months
ended June 30, 2021, as compared to 16.5 Bcf for the three months ended June 30,
2020.
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Third-party midstream services revenues. Our third-party midstream services
revenues increased $5.2 million, or 35%, to $19.9 million for the three months
ended June 30, 2021, as compared to $14.7 million for the three months ended
June 30, 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 $10.3 million for the three months ended June 30, 2021, as compared
to $6.3 million for the three months ended June 30, 2020, (ii) an increase in
our third-party produced water gathering and disposal revenues to $7.0 million
for the three months ended June 30, 2021, as compared to $6.2 million for the
three months ended June 30, 2020, and (iii) an increase in our third-party oil
gathering and transportation revenues to $2.6 million for the three months ended
June 30, 2021, as compared to $2.1 million for the three months ended June 30,
2020.
Sales of purchased natural gas. Our sales of purchased natural gas decreased
$3.1 million, or 22%, to $10.9 million for the three months ended June 30, 2021,
as compared to $14.0 million for the three months ended June 30, 2020. This
decrease was primarily the result of a decrease in purchased natural gas volumes
sold during the three months ended June 30, 2021. Sales of purchased natural gas
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 San Mateo's
cryogenic natural gas processing plant in Eddy County, New Mexico (the "Black
River Processing Plant") and subsequently sell the residue gas and natural gas
liquids ("NGL") 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 interim unaudited condensed consolidated statements of operations.
Lease bonus - mineral acreage. 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. We did not lease any of our mineral acreage to third parties during
the three months ended June 30, 2021. Our lease bonus - mineral acreage revenues
were $4.1 million for the three months ended June 30, 2020.
Realized (loss) gain on derivatives. Our realized net loss on derivatives was
$42.6 million for the three months ended June 30, 2021, as compared to a
realized net gain of $44.1 million for the three months ended June 30, 2020. We
realized a net loss of $42.6 million related to our oil costless collar and oil
and oil basis swap contracts for the three months ended June 30, 2021, resulting
primarily from oil prices that were above the ceiling prices of certain of our
oil costless collar contracts and above the strike prices of certain of our oil
and oil basis swap contracts. We realized an average loss on our oil derivatives
of approximately $8.77 per Bbl produced during the three months ended June 30,
2021, as compared to an average gain of approximately $11.25 per Bbl produced
during the three months ended June 30, 2020.
Unrealized (loss) gain on derivatives. Our unrealized net loss on derivatives
was $42.8 million for the three months ended June 30, 2021, as compared to an
unrealized net loss of $132.7 million for the three months ended June 30, 2020.
During the three months ended June 30, 2021, the aggregate net fair value of our
open oil and natural gas derivative contracts decreased to a net liability of
$122.1 million from a net liability of $79.3 million at March 31, 2021,
resulting in an unrealized loss on derivatives of $42.8 million for the three
months ended June 30, 2021. During the three months ended June 30, 2020, the
aggregate net fair value of our open oil and natural gas derivative contracts
decreased to a net liability of $0.1 million at June 30, 2020 from a net asset
of $132.6 million at March 31, 2020, resulting in an unrealized loss on
derivatives of $132.7 million for the three months ended June 30, 2020.
Six Months Ended June 30, 2021 as Compared to Six Months Ended June 30, 2020
Oil and natural gas revenues. Our oil and natural gas revenues increased $411.6
million, or 130%, to $728.3 million for the six months ended June 30, 2021, as
compared to $316.7 million for the six months ended June 30, 2020. Our oil
revenues increased $264.6 million, or 100%, to $528.4 million for the six months
ended June 30, 2021, as compared to $263.8 million for the six months ended June
30, 2020. This increase in oil revenues resulted from a 78% increase in the
weighted average oil price realized for the six months ended June 30, 2021 to
$61.49 per Bbl, as compared to $34.63 per Bbl for the six months ended June 30,
2020, and from a 13% increase in our oil production to 8.6 million Bbl for the
six months ended June 30, 2021, as compared to 7.6 million Bbl for the six
months ended June 30, 2020. Our natural gas revenues increased by $147.0
million, or 278%, to $199.9 million for the six months ended June 30, 2021, as
compared to $52.9 million for the six months ended June 30, 2020. The increase
in natural gas revenues resulted from a more than three-fold increase in the
weighted average natural gas price realized for the six months ended June 30,
2021 to $5.09 per Mcf, as compared to a weighted average natural gas price of
$1.60 per Mcf for the six months ended June 30, 2020, and from an 18% increase
in our natural gas production to 39.3 Bcf for the six months ended June 30,
2021, as compared to 33.2 Bcf for the six months ended June 30, 2020.
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Third-party midstream services revenues. Our third-party midstream services
revenues increased $4.8 million, or 16%, to $35.3 million for the six months
ended June 30, 2021, as compared to $30.5 million for the six months ended June
30, 2020. This increase was primarily attributable to (i) an increase in our
third-party natural gas gathering, transportation and processing revenues to
$17.1 million for the six months ended June 30, 2021, as compared to $13.4
million for the six months ended June 30, 2020, (ii) an increase in our
third-party oil gathering and transportation revenues to $4.7 million for the
six months ended June 30, 2021, as compared to $4.2 million for the six months
ended June 30, 2020, and (iii) an increase in our third-party produced water
gathering and disposal revenues to $13.5 million for the six months ended June
30, 2021, as compared to $12.9 million for the six months ended June 30, 2020.
Sales of purchased natural gas. Our sales of purchased natural gas decreased
$9.1 million, or 37%, to $15.4 million for the six months ended June 30, 2021,
as compared to $24.5 million for the six months ended June 30, 2020. This
decrease was primarily the result of a decrease in natural gas volumes sold
during the six months ended June 30, 2021.
Lease bonus - mineral acreage. We did not lease any of our mineral acreage to
third parties during the six months ended June 30, 2021. Our lease bonus -
mineral acreage revenues were $4.1 million for the six months ended June 30,
2020.
Realized (loss) gain on derivatives. Our realized net loss on derivatives was
$68.5 million for the six months ended June 30, 2021, as compared to a realized
net gain of $55.0 million for the six months ended June 30, 2020. We realized a
net loss of $68.7 million related to our oil costless collar and oil and oil
basis swap contracts for the six months ended June 30, 2021, resulting primarily
from oil prices that were above the ceiling prices of certain of our oil
costless collar contracts and above the strike prices of certain of our oil and
oil basis swap contracts. We realized a net gain of $0.2 million related to our
natural gas costless collar contracts for the six months ended June 30, 2021,
resulting primarily from natural gas prices that were below the floor prices of
certain of our natural gas costless collar contracts. We realized an average
loss on our oil derivatives of approximately $8.00 per Bbl produced during the
six months ended June 30, 2021, as compared to an average gain of $7.22 per Bbl
produced during the six months ended June 30, 2020.
Unrealized (loss) gain on derivatives. Our unrealized net loss on derivatives
was $86.2 million for the six months ended June 30, 2021, as compared to an
unrealized net gain of $3.8 million for the six months ended June 30, 2020.
During the period from December 31, 2020 through June 30, 2021, the aggregate
net fair value of our open oil and natural gas derivative contracts decreased to
a net liability of $122.1 million from a net liability of $35.9 million,
resulting in an unrealized loss on derivatives of $86.2 million for the six
months ended June 30, 2021. During the period from December 31, 2019 through
June 30, 2020, the aggregate net fair value of our open oil and natural gas
derivative contracts increased to a net liability of $0.1 million from a net
liability of $3.9 million, resulting in an unrealized gain on derivatives of
$3.8 million for the six months ended June 30, 2020.
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  Table of Conte    nts
Expenses
The following table summarizes our unaudited operating expenses and other income
(expense) for the periods indicated:
                                                                 Three Months Ended                      Six Months Ended
                                                                      June 30,                               June 30,
(In thousands, except expenses per BOE)                       2021               2020                2021               2020

Expenses


Production taxes, transportation and processing           $  43,843

$ 18,797 $ 78,017 $ 40,513 Lease operating

                                              28,752              26,162             54,691              57,072
Plant and other midstream services operating                 13,746               9,780             27,409              19,744
Purchased natural gas                                         9,628              10,922             12,483              18,980
Depletion, depreciation and amortization                     91,444              93,350            166,307             184,057
Accretion of asset retirement obligations                       511                 495              1,011                 971
Full-cost ceiling impairment                                      -             324,001                  -             324,001
General and administrative                                   24,397              14,723             46,585              30,945
Total expenses                                              212,321             498,230            386,503             676,283
Operating income (loss)                                     145,106            (435,310)           237,769            (241,778)
Other income (expense)
Net loss on asset sales and impairment                            -              (2,632)                 -              (2,632)
Interest expense                                            (17,940)            (18,297)           (37,590)            (38,109)

Other income (expense)                                           14                 473               (661)              1,793
Total other expense                                         (17,926)            (20,456)           (38,251)            (38,948)
Income (loss) before income taxes                           127,180            (455,766)           199,518            (280,726)
Income tax provision (benefit)                                5,349            (109,823)             8,189             (69,866)

Net income attributable to non-controlling interest in subsidiaries

                                                (15,926)             (7,473)           (24,779)            (16,827)

Net income (loss) attributable to Matador Resources Company shareholders

$ 105,905

$ (353,416) $ 166,550 $ (227,687) Expenses per BOE Production taxes, transportation and processing

$    5.17

$ 2.82 $ 5.15 $ 3.08 Lease operating

$    3.39

$ 3.92 $ 3.61 $ 4.34 Plant and other midstream services operating

$    1.62

$ 1.47 $ 1.81 $ 1.50 Depletion, depreciation and amortization

$   10.78

$ 14.00 $ 10.98 $ 14.00 General and administrative

$    2.88

$ 2.21 $ 3.08 $ 2.35




Three Months Ended June 30, 2021 as Compared to Three Months Ended June 30, 2020
Production taxes, transportation and processing. Our production taxes and
transportation and processing expenses increased $25.0 million, or 133%, to
$43.8 million for the three months ended June 30, 2021, as compared to $18.8
million for the three months ended June 30, 2020. On a unit-of-production basis,
our production taxes and transportation and processing expenses increased 83% to
$5.17 per BOE for the three months ended June 30, 2021, as compared to $2.82 per
BOE for the three months ended June 30, 2020. These increases were primarily due
to (i) a $22.5 million increase in production taxes to $31.1 million for the
three months ended June 30, 2021, as compared to $8.6 million for the three
months ended June 30, 2020, primarily due to the significant increase in the
weighted average oil and natural gas prices realized between the two periods,
and (ii) a $2.5 million increase in transportation and processing expenses to
$12.7 million for the three months ended June 30, 2021, as compared to $10.2
million for the three months ended June 30, 2020, primarily due to the 32%
increase in our natural gas production of 21.8 Bcf for the three months ended
June 30, 2021, as compared to 16.5 Bcf for the three months ended June 30, 2020.
Lease operating. Our lease operating expenses increased $2.6 million, or 10%, to
$28.8 million for the three months ended June 30, 2021, as compared to $26.2
million for the three months ended June 30, 2020. This increase was primarily
attributable to increases in expenses associated with workovers, chemicals and
other expenses of $3.4 million, which were attributable to servicing an
increased number of operated wells at June 30, 2021, as compared to June 30,
2020. This increase
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  Table of Conte    nts
was partially offset by a decrease in produced water trucking and disposal
expenses of $1.1 million as more of our operated wells have been connected to
produced water pipelines during three months ended June 30, 2021, as compared to
the three months ended June 30, 2020. Our lease operating expenses on a
unit-of-production basis decreased 14% to $3.39 per BOE for the three months
ended June 30, 2021, as compared to $3.92 per BOE for the three months ended
June 30, 2020, primarily due to the 27% increase in our total oil equivalent
production for the three months ended June 30, 2021, as compared to the three
months ended June 30, 2020.
Plant and other midstream services operating. Our plant and other midstream
services operating expenses increased $4.0 million, or 41%, to $13.7 million for
the three months ended June 30, 2021, as compared to $9.8 million for the three
months ended June 30, 2020. This increase was primarily attributable to (i)
increased expenses associated with our expanded commercial produced water
disposal operations of $6.6 million for the three months ended June 30, 2021, as
compared to $5.4 million for the three months ended June 30, 2020, (ii)
increased expenses associated with our expanded pipeline operations of $3.7
million for the three months ended June 30, 2021, as compared to $2.0 million
for the three months ended June 30, 2020, and (iii) increased expenses
associated with operating the expanded Black River Processing Plant of $3.5
million for the three months ended June 30, 2021, as compared to $2.5 million
for the three months ended June 30, 2020.
Depletion, depreciation and amortization. Our depletion, depreciation and
amortization expenses decreased $1.9 million, or 2%, to $91.4 million for the
three months ended June 30, 2021, as compared to $93.4 million for the three
months ended June 30, 2020. On a unit-of-production basis, our depletion,
depreciation and amortization expenses decreased 23% to $10.78 per BOE for the
three months ended June 30, 2021, as compared to $14.00 per BOE for the three
months ended June 30, 2020. These decreases were attributable to the increase in
our estimated total proved oil and natural gas reserves, as well as the decrease
in unamortized property costs resulting from the full-cost ceiling impairments
recorded in 2020. The decrease in our depletion, depreciation and amortization
expenses was partially offset by a $2.8 million increase in depreciation
expenses attributable to our midstream segment to $7.8 million for the three
months ended June 30, 2021, as compared to $5.0 million for the three months
ended June 30, 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 three months ended June 30,
2021. At June 30, 2020, the net capitalized costs of our oil and natural gas
properties less related deferred income taxes exceeded the full-cost ceiling by
$243.9 million. As a result, we recorded an impairment charge of $324.0 million
to the net capitalized costs of our oil and natural gas properties and a
deferred income tax benefit of $80.1 million. This full-cost ceiling impairment
of $324.0 million is reflected in our interim unaudited condensed consolidated
statement of operations for the three months ended June 30, 2020.
General and administrative. Our general and administrative expenses increased
$9.7 million, or 66%, to $24.4 million for the three months ended June 30, 2021,
as compared to $14.7 million for the three months ended June 30, 2020. Our
general and administrative expenses increased 30% on a unit-of-production basis
to $2.88 per BOE for the three months ended June 30, 2021, as compared to $2.21
per BOE for the three months ended June 30, 2020. These increases were largely
attributable to employee compensation costs, including a $5.2 million increase
in stock-based compensation expense we recorded primarily associated with our
cash-settled stock awards, the values of which are remeasured at each reporting
period. The share price of our common stock increased by 54% from $23.45 at
March 31, 2021 to $36.01 at June 30, 2021. The remainder of the increase for the
three months ended June 30, 2021, as compared to the three months ended June 30,
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 three months ended June 30, 2021, we incurred total
interest expense of $19.8 million. We capitalized $1.9 million of our interest
expense on certain qualifying projects for the three months ended June 30, 2021
and expensed the remaining $17.9 million to operations. For the three months
ended June 30, 2020, we incurred total interest expense of $20.1 million. We
capitalized $1.8 million of our interest expense on certain qualifying projects
for the three months ended June 30, 2020 and expensed the remaining $18.3
million to operations.
Income tax provision (benefit). Our income tax provision was $5.3 million for
the three months ended June 30, 2021. Our effective tax rate for the three
months ended June 30, 2021 was 5%, which differed from amounts computed by
applying the U.S. federal statutory rate to the pre-tax income due to recording
the net deferred tax liability for state taxes, primarily in New Mexico, and
continuing to recognize a valuation allowance against our U.S. federal net
deferred tax assets. As a result of the full-cost ceiling impairments recorded
in 2020, we recognized a valuation allowance against our net deferred tax assets
for the year ended December 31, 2020. The valuation allowance will continue to
be recognized until the future deferred tax benefits are more likely than not to
become utilized. We recorded an income tax benefit of $109.8 million for the
three months ended June 30, 2020, and our effective tax rate for the three
months ended June 30, 2020 was 24%, which differed from amounts computed by
applying the U.S. federal statutory rate to the pre-tax income due to the impact
of permanent differences between book and tax income, as well as state taxes,
primarily in New Mexico.
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  Table of Conte    nts
Six Months Ended June 30, 2021 as Compared to Six Months Ended June 30, 2020
Production taxes, transportation and processing. Our production taxes and
transportation and processing expenses increased $37.5 million, or 93%, to $78.0
million for the six months ended June 30, 2021, as compared to $40.5 million for
the six months ended June 30, 2020. On a unit-of-production basis, our
production taxes and transportation and processing expenses increased 67% to
$5.15 per BOE for the six months ended June 30, 2021, as compared to $3.08 per
BOE for the six months ended June 30, 2020. These increases were primarily due
to (i) a $32.1 million increase in production taxes to $54.8 million for the six
months ended June 30, 2021, as compared to $22.7 million for the six months
ended June 30, 2020, primarily due to the significant increase in the weighted
average oil and natural gas prices realized between the two periods, and (ii) a
$5.4 million increase in transportation and processing expenses to $23.2 million
for the six months ended June 30, 2021, as compared to $17.8 million for the six
months ended June 30, 2020, primarily due to the 18% increase in our natural gas
production to 39.3 Bcf for the six months ended June 30, 2021, as compared to
33.2 Bcf for the six months ended June 30, 2020.
Lease operating. Our lease operating expenses decreased $2.4 million, or 4%, to
$54.7 million for the six months ended June 30, 2021, as compared to $57.1
million for the six months ended June 30, 2020. Our lease operating expenses on
a unit-of-production basis decreased 17% to $3.61 per BOE for the six months
ended June 30, 2021, as compared to $4.34 per BOE for the six months ended June
30, 2020. These decreases were largely attributable to (i) a decrease in
produced water trucking and disposal expenses of $1.7 million as more of our
operated wells have been connected to produced water pipelines, (ii) a decrease
in repairs and maintenance and equipment rentals of $3.1 million and (iii) a
decrease in compressor rental charges of $1.1 million. These decreases were
partially offset by increases associated with workovers and chemical expenses of
$3.3 million, which were attributable to servicing an increased number of
operated wells at June 30, 2021, as compared to June 30, 2020.
Plant and other midstream services operating. Our plant and other midstream
services operating expenses increased $7.7 million, or 39%, to $27.4 million for
the six months ended June 30, 2021, as compared to $19.7 million for the six
months ended June 30, 2020. This increase was primarily attributable to (i)
increased expenses associated with our expanded commercial produced water
disposal operations of $14.2 million for the six months ended June 30, 2021, as
compared to $10.5 million for the six months ended June 30, 2020, (ii) increased
expenses associated with our expanded pipeline operations of $7.0 million for
the six months ended June 30, 2021, as compared to $4.0 million for the six
months ended June 30, 2020, and (iii) increased expenses associated with
operating the expanded Black River Processing Plant of $6.2 million for the six
months ended June 30, 2021, as compared to $5.2 million for the six months ended
June 30, 2020.
Depletion, depreciation and amortization. Our depletion, depreciation and
amortization expenses decreased $17.8 million, or 10%, to $166.3 million for the
six months ended June 30, 2021, as compared to $184.1 million for the six months
ended June 30, 2020. On a unit-of-production basis, our depletion, depreciation
and amortization expenses decreased 22% to $10.98 per BOE for the six months
ended June 30, 2021, as compared to $14.00 per BOE for the six months ended June
30, 2020. These decreases were attributable to the increase in our estimated
total proved oil and natural gas reserves, as well as the decrease in
unamortized property costs resulting from the full-cost ceiling impairments
recorded in 2020. The decrease in our depletion, depreciation and amortization
expenses was partially offset by a $5.8 million increase in depreciation
expenses attributable to our midstream segment to $15.6 million for the six
months ended June 30, 2021 as compared to $9.8 million for the six months ended
June 30, 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 six months ended June 30,
2021. At June 30, 2020, the net capitalized costs of our oil and natural gas
properties less related deferred income taxes exceeded the full-cost ceiling by
$243.9 million. As a result, we recorded an impairment charge of $324.0 million
to the net capitalized costs of our oil and natural gas properties and a
deferred income tax benefit of $80.1 million. This full-cost ceiling impairment
of $324.0 million is reflected in our interim unaudited condensed consolidated
statement of operations for the six months ended June 30, 2020.
General and administrative. Our general and administrative expenses increased
$15.6 million, or 51%, to $46.6 million for the six months ended June 30, 2021,
as compared to $30.9 million for the six months ended June 30, 2020. Our general
and administrative expenses increased 31% on a unit-of-production basis to $3.08
per BOE for the six months ended June 30, 2021, as compared to $2.35 per BOE for
the six months ended June 30, 2020. These increases were largely attributable to
employee compensation costs, including an $11.0 million increase in stock-based
compensation expense we recorded primarily associated with our cash-settled
stock awards, the values of which are remeasured at each reporting period. The
share price of our common stock increased approximately three-fold from $12.06
at December 31, 2020 to $36.01 at June 30, 2021. The remainder of the increase
for the six months ended June 30, 2021, as compared to the six months ended June
30, 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.
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  Table of Conte    nts
Interest expense. For the six months ended June 30, 2021, we incurred total
interest expense of $40.1 million. We capitalized $2.5 million of our interest
expense on certain qualifying projects for the six months ended June 30, 2021
and expensed the remaining $37.6 million to operations. For the six months ended
June 30, 2020, we incurred total interest expense of $41.3 million. We
capitalized $3.2 million of our interest expense on certain qualifying projects
for the six months ended June 30, 2020 and expensed the remaining $38.1 million
to operations.
Income tax provision (benefit). Our income tax provision was $8.2 million for
the six months ended June 30, 2021. Our effective tax rate for the six months
ended June 30, 2021 was 5%, which differed from amounts computed by applying the
U.S. federal statutory rate to the pre-tax income due to recording the net
deferred tax liability for state taxes, primarily in New Mexico, and continuing
to recognize a valuation allowance against our U.S. federal net deferred tax
assets. As a result of the full-cost ceiling impairments recorded in 2020, we
recognized a valuation allowance against our net deferred tax assets for the
year ended December 31, 2020. The valuation allowance will continue to be
recognized until the future deferred tax benefits are more likely than not to
become utilized. We recorded an income tax benefit of $69.9 million for the six
months ended June 30, 2020, and our effective tax rate for the six months ended
June 30, 2020 was 23%, which differed from amounts computed by applying the U.S.
federal statutory rate to the pre-tax income due to the impact of permanent
differences between book and tax income, as well as 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
the remainder of 2021 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 the remainder of 2021 primarily through a
combination of cash on hand, operating cash flows and performance incentives
paid to us by a subsidiary of Five Point Energy LLC, our joint venture partner,
in connection with San Mateo. If capital expenditures were to exceed our
operating cash flows during the remainder of 2021, 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 June 30, 2021, we had cash totaling $44.6 million and restricted cash
totaling $34.6 million, which was 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. During each of the first and second quarters of 2021, we had net
repayments of $100.0 million in borrowings under the Credit Agreement. In
addition, the Board declared our first two quarterly cash dividends of $0.025
per share of common stock, which were paid on March 31, 2021 and June 3, 2021.
In July 2021, the Board declared a quarterly cash dividend of $0.025 per share
of common stock payable on September 3, 2021 to shareholders of record as of
August 12, 2021.
At June 30, 2021, we had (i) $1.05 billion of outstanding 5.875% senior notes
due September 2026 (the "Notes"), (ii) $240.0 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 April 2021, the lenders under our Credit Agreement completed their review of
our proved oil and natural gas reserves, and, as a result, the borrowing base
was reaffirmed at $900.0 million. We elected to keep the borrowing commitment at
$700.0 million, the maximum facility amount remained $1.5 billion and no
material changes were made to the terms of the Credit Agreement. This April 2021
redetermination constituted the regularly scheduled May 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 covenant noted below). The Credit Agreement matures in
October 2023. The Credit Agreement requires the Company to maintain a debt to
EBITDA ratio, which is defined as debt outstanding (net of up to $50.0 million
of cash or cash equivalents), divided by a rolling four quarter EBITDA
calculation, of 4.0 or less. We believe that we were in compliance with the
terms of the Credit Agreement at June 30, 2021.
At June 30, 2021, San Mateo had $352.5 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. Between June
30, 2021 and July 27, 2021, San Mateo repaid $25.0 million of borrowings under
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 includes an accordion feature, which, after the
aforementioned amendment, provides for potential increases in lender
                                       31
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  Table of Conte    nts
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 5.0 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 2.5 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 June 30, 2021.
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. For a discussion of such loan, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations-Liquidity and Capital
Resources" in the Annual Report.
During the six months ended June 30 and through July 2021, the oil and natural
gas industry has experienced continued improvement in commodity prices as
compared to 2020, primarily resulting from (i) improvements in oil demand as the
impact from COVID-19 has begun to abate and (ii) actions taken by the
Organization of Petroleum Exporting Countries, Russia and certain other
oil-exporting countries ("OPEC+") to reduce the worldwide supply of oil through
coordinated production cuts. As a result, West Texas Intermediate ("WTI") oil
prices have increased from $48.52 per barrel at December 31, 2020 to as high as
$74.05 per barrel in late June 2021. While oil prices have improved in 2021, the
general outlook for the oil and natural gas industry for the remainder of the
year remains uncertain, and we can provide no assurances as to when or to what
extent economic disruptions resulting from COVID-19 and the corresponding
decreases in oil demand may improve further. These economic disruptions have
also impacted our ability to access the capital markets on reasonably similar
terms as were available prior to 2020. Prices for natural gas and NGLs were also
much higher during the six months ended June 30 and through July 2021 as
compared to 2020.
We expect that development of our Delaware Basin assets will be the primary
focus of our operations and capital expenditures for the remainder of 2021. We
operated four drilling rigs in the Delaware Basin during the second quarter of
2021. At July 27, 2021, two of these rigs were drilling in the Stateline asset
area in Eddy County, New Mexico. These two rigs recently completed drilling 13
additional Boros wells in the eastern portion of the Stateline asset area and at
July 27, 2021 were drilling 11 new Voni wells in the western portion of that
asset area. The other two rigs have been drilling 13 wells in the Greater
Stebbins Area, nine of which were still in progress at July 27, 2021. Four of
these wells, all Second Bone Spring completions, were recently turned to sales.
When we complete drilling the nine wells in progress in the Greater Stebbins
Area, we plan to use these two rigs to drill two additional wells in the Ranger
asset area in Lea County, New Mexico and several additional Rodney Robinson
wells in the western portion of the Antelope Ridge asset area in Lea County.
At July 27, 2021, our 2021 estimated capital expenditures for D/C/E capital
expenditures remained $525 to $575 million, as originally estimated. As a result
of savings on our operated D/C/E capital expenditures in the first half of 2021,
a faster drilling and completions pace and an anticipated decrease in
non-operated D/C/E capital expenditures in the second half of 2021, we intend to
advance the next 11 Voni well completions in the Stateline asset area forward
into the fourth quarter of 2021 and expect to be able to do so without
increasing our estimates for D/C/E capital expenditures for full year 2021.
At July 27, 2021, we increased our anticipated 2021 midstream capital
expenditures from $20 to $30 million to $35 to $45 million, primarily to
accommodate several new midstream opportunities for San Mateo with producers in
Eddy County, New Mexico and to accelerate the installation of compression
facilities and other infrastructure prior to the end of 2021 in order to be
prepared for the additional volumes from the accelerated Voni completions noted
above. Previously, these Voni-related capital expenditures were scheduled for
early 2022. The anticipated total 2021 midstream capital expenditures of $35 to
$45 million primarily reflect our proportionate share of San Mateo's estimated
2021 capital expenditures.
Substantially all of these 2021 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
2021 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 higher percentage of
longer horizontal wells in 2021, including 98% with anticipated completed
lateral lengths of two miles or greater. We have built significant optionality
into our drilling program, which should generally allow us to increase or
decrease the number of rigs we operate as necessary based on changing commodity
prices and other factors.
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  Table of Conte    nts
We may divest portions of our non-core assets, particularly in the Eagle Ford
shale in South Texas and the Haynesville shale and Cotton Valley plays 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 acreage and mineral interests, principally in
the Delaware Basin, during the remainder of 2021. 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 2021 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 acreage and mineral acquisitions
for 2021.
Our 2021 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 the remainder of 2021 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 the remainder of 2021 and the hedges we currently
have in place. For further 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 7 to the
interim unaudited condensed consolidated financial statements in this Quarterly
Report for a summary of our open derivative financial instruments.
Our unaudited cash flows for the six months ended June 30, 2021 and 2020 are
presented below:
                                                                                 Six Months Ended
                                                                                     June 30,
(In thousands)                                                               2021                2020

Net cash provided by operating activities                                $  427,595          $  210,385
Net cash used in investing activities                                      (251,122)           (458,761)
Net cash (used in) provided by financing activities                        (188,648)            226,756
Net change in cash and restricted cash                                   $  (12,175)         $  (21,620)
Adjusted EBITDA attributable to Matador Resources Company
shareholders(1)                                                          $  459,081          $  248,170


__________________
(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 $217.2 million to $427.6
million for the six months ended June 30, 2021 from $210.4 million for the six
months ended June 30, 2020. Excluding changes in operating assets and
liabilities, net cash provided by operating activities increased $221.7 million
to $457.4 million for the six months ended June 30, 2021 from $235.7 million for
the six months ended June 30, 2020, primarily attributable to significantly
higher realized oil and natural gas prices and higher oil and natural gas
production for the six months ended June 30, 2021, as compared to the six months
ended June 30, 2020. Changes in our operating assets and liabilities between the
two periods resulted in a net decrease of approximately $4.5 million in net cash
provided by operating activities for the six months ended June 30, 2021, as
compared to the six months ended June 30, 2020.
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  Table of Conte    nts
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. Furthermore, 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 during 2020.
These factors are beyond our control and are difficult to predict. We use
commodity derivative financial instruments at times to mitigate our exposure to
fluctuations in oil, natural gas and NGL prices.
Cash Flows Used in Investing Activities
Net cash used in investing activities decreased $207.6 million to $251.1 million
for the six months ended June 30, 2021 from $458.8 million for the six months
ended June 30, 2020. This decrease in net cash used in investing activities was
primarily due to (i) a decrease of $98.2 million in midstream capital
expenditures, (ii) a decrease of $72.6 million in D/C/E capital expenditures and
(iii) a decrease of $36.4 million in expenditures related to acquisition of oil
and natural gas properties for the six months ended June 30, 2021, as compared
to the six months ended June 30, 2020. Cash used for D/C/E capital expenditures
for the six months ended June 30, 2021 and 2020 was primarily attributable to
our operated and non-operated drilling and completion activities in the Delaware
Basin. Cash used for midstream capital expenditures for the six months ended
June 30, 2020 was primarily attributable to the expansion of the Black River
Processing Plant and midstream facilities in the Greater Stebbins Area and the
Stateline asset area, which were completed in 2020.
Cash Flows (Used in) Provided by Financing Activities
Net cash used in financing activities was $188.6 million for the six months
ended June 30, 2021, a significant change from net cash provided by financing
activities of $226.8 million for the six months ended June 30, 2020. During the
six months ended June 30, 2021, our primary uses of cash related to financing
activities were for the net repayment of $200.0 million in borrowings under our
Credit Agreement and the payment of our first two quarterly dividends. These
payments were partially offset by net borrowings under the San Mateo Credit
Facility of $18.5 million. During the six months ended June 30, 2020, our
primary sources of cash from financing activities included borrowings under our
Credit Agreement of $130.0 million, borrowings under the San Mateo Credit
Facility of $32.0 million and net contributions related to the formation of San
Mateo and from non-controlling interest owners in less-than-wholly-owned
subsidiaries of $59.8 million.
See Note 4 to the interim unaudited condensed consolidated financial statements
in this Quarterly 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 June 30, 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.
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  Table of Conte    nts
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.

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