DALLAS--(BUSINESS WIRE)--Aug. 6, 2014--
Matador Resources Company (NYSE: MTDR) (“Matador” or the “Company”), 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 and with a current focus on its Eagle Ford
operations in South Texas and its Permian Basin operations in Southeast
New Mexico and West Texas, today reported financial and operating
results for the three and six months ended June 30, 2014. Headlines
include:
For the quarter ended June 30, 2014:
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Record average daily oil equivalent production of 15,424 BOE, or
barrels of oil equivalent, per day, consisting of 8,809 Bbl of oil per
day and 39.7 MMcf of natural gas per day, a year-over-year BOE
increase of 46% from 10,582 BOE per day, consisting of 4,916 Bbl of
oil per day and 34.0 MMcf of natural gas per day, for the quarter
ended June 30, 2013, and a sequential increase of 30% from 11,904 BOE
per day, consisting of 7,344 Bbl of oil per day and 27.4 MMcf of
natural gas per day, for the quarter ended March 31, 2014.
-
Record quarterly oil production of 802,000 Bbl, a year-over-year
increase of 79% from 447,000 Bbl produced in the quarter ended
June 30, 2013, and a sequential increase of 21% from 661,000 Bbl
produced in the quarter ended March 31, 2014.
-
Record oil and natural gas revenues of $99.1 million, a
year-over-year increase of 70% from $58.2 million reported for the
quarter ended June 30, 2013, and a sequential increase of 25% from
$78.9 million reported for the quarter ended March 31, 2014.
-
Record Adjusted EBITDA, or earnings before interest, taxes,
depletion, depreciation, amortization and other items, of $69.5
million, a year-over-year increase of 70% from $40.8 million reported
for the quarter ended June 30, 2013, and a sequential increase of 23%
from $56.3 million reported for the quarter ended March 31, 2014.
For the six months ended June 30, 2014:
-
Record average daily oil equivalent production of 13,673 BOE per
day, consisting of 8,080 Bbl of oil per day and 33.6 MMcf of natural
gas per day, a year-over-year BOE increase of 27% from 10,739 BOE per
day, consisting of 5,015 Bbl of oil per day and 34.3 MMcf of natural
gas per day, for the six months ended June 30, 2013, and a sequential
increase of 7% from 12,723 BOE per day, consisting of 6,658 Bbl of oil
per day and 36.4 MMcf of natural gas per day, for the six months ended
December 31, 2013.
-
Record total oil production of 1,463,000 Bbl, a year-over-year
increase of 61% from 908,000 Bbl produced in the six months ended
June 30, 2013, and a sequential increase of 19% from 1,225,000 Bbl
produced in the six months ended December 31, 2013.
-
Record oil and natural gas revenues of $178.0 million, a
year-over-year increase of 51% from $117.5 million reported for the
six months ended June 30, 2013, and a sequential increase of 17% from
$151.5 million reported for the six months ended December 31, 2013.
-
Record Adjusted EBITDA of $125.8 million, a year-over-year increase
of 54% from $81.4 million reported for the six months ended June 30,
2013, and a sequential increase of 14% from $110.3 million reported
for the six months ended December 31, 2013.
Additional Highlights:
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Total proved oil and natural gas reserves of 57.2 million BOE at
June 30, 2014, including 18.6 million Bbl of oil and 231.4 Bcf of
natural gas, with a PV-10 of $826.0 million (Standardized Measure of
$723.0 million). Total proved oil and natural gas reserves increased
47% from 38.9 million BOE at June 30, 2013 and 11% from 51.7 million
BOE at December 31, 2013. PV-10 increased 58% from $522.3 million at
June 30, 2013 and 26% from $655.2 million at December 31, 2013. Proved
oil reserves increased 54% to 18.6 million Bbl at June 30, 2014, as
compared to 12.1 million Bbl at June 30, 2013, and increased 14%, as
compared to 16.4 million Bbl at December 31, 2013.
-
On July 30, 2014, Matador announced the results of two of its most
recent wells completed, tested and placed on production in the
Delaware Basin.
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In the Wolf prospect area in Loving County, Texas, the Norton
Schaub #1H well, a Wolfcamp “A” test, flowed 1,026 BOE per day,
consisting of 706 Bbl of oil per day and 1,922 Mcf of natural gas
per day (69% oil) at 3,000 psi flowing surface pressure on a 22/64th
inch choke during a 24-hour initial potential test in mid-July.
-
In the Ranger prospect area in Lea County, New Mexico, the
Pickard State 20-18-34 #1H well, a Second Bone Spring sand test,
flowed 592 BOE per day, including 535 Bbl of oil per day and 340
Mcf of natural gas per day (90% oil) at 750 psi flowing surface
pressure on a 22/64th inch choke during a
24-hour initial potential test in late July.
-
Added approximately 23,200 gross (17,200 net) acres in the Permian
Basin primarily in Loving County, Texas and Lea and Eddy Counties, New
Mexico between January 1 and August 6, 2014, bringing the Company’s
total acreage position in the Permian Basin to approximately 94,000
gross (62,000 net) acres.
-
In May 2014, Matador completed a public offering of 7.5 million
shares of common stock, raising net proceeds of approximately $181.3
million.
-
Reaffirmed its 2014 guidance metrics as revised upwards on May 6
and May 22, 2014, including (1) estimated capital expenditures of $570
million, (2) estimated natural gas production of 16.0 to 17.5 Bcf, (3)
estimated oil and natural gas revenues of $380 to $400 million and (4)
estimated Adjusted EBITDA of $270 to $290 million. Further, the
Company reaffirmed its guidance to the high end of its 2014 estimated
oil production range of 2.8 to 3.1 million Bbl.
Second Quarter and Year-to-Date 2014 Operating and Financial Results
Joseph Wm. Foran, Matador’s Chairman and CEO, commented, “This quarter
has been an exciting and a productive one for us. The Matador staff
again delivered record operating and financial results during the three
and six months ended June 30, 2014. Our total oil equivalent production,
oil production, oil and natural gas revenues and Adjusted EBITDA were
all the best results in our Company’s history during both respective
periods. During the second quarter of 2014, specifically, our average
daily oil equivalent production was 15,424 BOE per day, consisting of
8,809 Bbl of oil per day and 39.7 MMcf of natural gas per day, a
year-over-year BOE increase of 46% from 10,582 BOE per day during the
second quarter of 2013 and a sequential increase of 30% from 11,904 BOE
per day during the first quarter of 2014. Our quarterly oil production
of 802,000 Bbl, averaging 8,809 Bbl of oil per day, increased 79%
year-over-year, as compared to 447,000 Bbl, averaging 4,916 Bbl of oil
per day, during the second quarter of 2013, and increased 21%
sequentially, as compared to 661,000 Bbl, averaging 7,344 Bbl of oil per
day, during the first quarter of 2014. These record production results
are directly attributable not only to the continued execution of our
Eagle Ford development program but also to the positive,
better-than-expected results from our initial wells in the Permian
Basin. Notably, these results were achieved despite having as much as 10
to 15% of our total production capacity shut in or restricted at various
times during the second quarter while offsetting wells were drilled and
completed and pipeline connections were being made.
“Our oil and natural gas revenues of $99.1 million for the second
quarter of 2014 reflect a year-over-year increase of 70% from $58.2
million reported in the second quarter of 2013 and a 25% sequential
increase from $78.9 million reported in the first quarter of 2014. In
addition, we reported Adjusted EBITDA of $69.5 million for the second
quarter of 2014, an increase of 70%, as compared to $40.8 million
reported in the second quarter of 2013, and a 23% sequential increase
from $56.3 million reported for the first quarter of 2014. This growth
is also directly attributable to the growth in our oil and natural gas
production.
“Our leasehold position in the Permian Basin continues to grow in size
and importance as an exciting new operating area for Matador. Since
January 1, we have added approximately 23,200 gross (17,200 net) acres,
primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico,
that we believe to be prospective for the Wolfcamp and Bone Spring
plays, as well as other oil and liquids-rich targets, bringing our total
acreage position in the Permian Basin to approximately 94,000 gross
(62,000 net) acres. The growth by prospect area is detailed elsewhere in
this release. We have also acquired (or expect to acquire by the middle
of August) approximately 3,100 gross (2,900 net) acres in South Texas
prospective for the Eagle Ford shale in La Salle, Karnes and southern
Atascosa Counties since the first of the year. This acreage has the
potential to add up to 75 additional gross drilling locations to our
Eagle Ford development program — more than enough to replenish our
current-year drilling locations. We plan to continue our leasing and
acquisition efforts in each of our operating areas — Permian, Eagle Ford
and Haynesville — and anticipate we will acquire additional acreage as
opportunities are identified throughout the remainder of 2014.
“We were also pleased to announce last week the 24-hour initial
potential test results of two of our most recent wells completed in the
Delaware Basin, both of which have been producing fewer than 30 days. In
our Wolf prospect area in Loving County, Texas, the Norton Schaub #1H
well, a Wolfcamp ‘A’ completion, flowed 1,026 BOE per day, consisting of
706 Bbl of oil per day and 1,922 Mcf of natural gas per day (69% oil) at
3,000 psi flowing surface pressure on a 22/64th inch choke.
Along with the Dorothy White #1H well, this is our second successful
test of the Wolfcamp ‘A’ in the Wolf prospect area and further validates
our decision to operate one of our two Permian drilling rigs in this
area for the remainder of 2014. In the Ranger prospect area in Lea
County, New Mexico, the Pickard State 20-18-34 #1H well, a Second Bone
Spring sand test, flowed 592 BOE per day, including 535 Bbl of oil per
day and 340 Mcf of natural gas per day (90% oil) at 750 psi flowing
surface pressure on a 22/64th inch choke. Although early,
this well appears to be comparable to or better than the Ranger 33 State
Com #1H well. It is also a pleasure to announce today that the Pickard
State 20-18-34 #2H, a Wolfcamp ‘D’ test in the northern portion of the
Ranger prospect area, has been completed and is flowing oil. No initial
production test has been run yet as the well is still cleaning up
following stimulation, but its performance to-date is encouraging.
“In addition to these three most recent wells, the first three wells
Matador drilled in the Permian Basin continue to exhibit
better-than-expected performance. In the Wolf prospect area, the Dorothy
White #1H well, a Wolfcamp ‘A’ completion, has produced 175,000 BOE,
including 115,000 Bbl of oil (66% oil), in just seven months of
production and is currently producing over 500 Bbl of oil per day and
1.3 MMcf of natural gas per day at about 2,300 psi flowing surface
pressure. In the Ranger prospect area, the Ranger 33 State Com #1H has
produced 123,000 BOE, including 113,000 Bbl of oil (91% oil) after nine
months of production and continues to produce 350 to 400 Bbl of oil per
day. In the Rustler Breaks prospect area, the Rustler Breaks 12-24-27
#1H has produced 72,000 BOE in just over three months, including 32,000
Bbl of oil (45% oil) and is currently producing about 230 Bbl of oil and
1.8 MMcf of natural gas per day at 1,300 psi flowing surface pressure.
These results continue to encourage us about our growing opportunity set
and the overall growth potential ahead in the Permian Basin.
“Finally, in May, we successfully completed a public offering of 7.5
million shares of our common stock, raising net proceeds of
approximately $181.3 million. We have used this additional capital to,
among other items, increase our rig count from three to four drilling
rigs, including two rigs for the development of our properties in the
Eagle Ford and two rigs for the exploration and delineation of our
acreage in the Permian Basin, and to continue to acquire new leasehold
interests, primarily in the Permian Basin and the Eagle Ford shale. This
offering put the Company in a strong financial position heading into the
second half of 2014, and at August 6, 2014, we had approximately $200
million in cash and liquidity available under our revolving credit
facility, along with our increasing cash flows, to finance our
operations for the remainder of 2014 and into 2015. We expect this
liquidity to increase with our next borrowing base redetermination in
the third quarter of 2014 following the lenders’ review of our proved
oil and natural gas reserves at June 30, 2014.”
Production, Revenues, Adjusted EBITDA and Net Income
Production and Revenues
As noted earlier, quarterly production results for the three months
ended June 30, 2014 were the best in Matador’s history. Average daily
oil equivalent production increased 46% from 10,582 BOE per day (46%
oil) in the second quarter of 2013 to 15,424 BOE per day (57% oil) in
the second quarter of 2014, and increased 30% sequentially from 11,904
BOE per day (62% oil) in the first quarter of 2014. Oil production
increased 79% from 447,000 Bbl of oil, or 4,916 Bbl of oil per day, in
the second quarter of 2013, to 802,000 Bbl of oil, or 8,809 Bbl of oil
per day, in the second quarter of 2014, and increased 21% sequentially
from 661,000 Bbl of oil, or 7,344 Bbl of oil per day, in the first
quarter of 2014. These year-over-year and sequential increases in the
Company’s average daily oil equivalent production and, in particular,
the Company’s average daily oil production, are primarily attributable
to the success of the Company’s ongoing drilling operations in the Eagle
Ford shale, but also reflect the strong initial production performance
of the Company’s first horizontal wells in the Delaware portion of the
Permian Basin.
Natural gas production increased 17% from 3.1 Bcf, or 34.0 MMcf per day,
in the second quarter of 2013, to 3.6 Bcf, or 39.7 MMcf per day, in the
second quarter of 2014, and increased 47% sequentially from 2.5 Bcf, or
27.4 MMcf per day, in the first quarter of 2014. This increase in
natural gas production was attributable not only to drilling operations
in South Texas and the Permian Basin, but also to initial production
contributions from newly drilled non-operated wells in the Haynesville
shale in Northwest Louisiana during the three months ended June 30,
2014. The Company expects its natural gas production to grow sharply
beginning late in the third quarter and continuing throughout the fourth
quarter of 2014, as initial natural gas production from an anticipated
19 gross (4.2 net) Haynesville shale wells either in progress or
scheduled to be drilled, completed and placed on production in 2014 by
an affiliate of Chesapeake Energy Corporation (“Chesapeake”) on the
Company’s Elm Grove properties in Northwest Louisiana begins to come
online. Through the end of the second quarter of 2014, none of these Elm
Grove wells had been completed and placed on production due to
Chesapeake’s use of batch drilling operations. As a result of this
drilling program and its timing, Matador anticipates that its proved
developed reserves will grow substantially and that its average daily
natural gas production should more than double from the first quarter of
2014 to the end of the year, with most of this growth coming in the
fourth quarter.
Oil and natural gas revenues increased 70% from $58.2 million during the
second quarter of 2013 to $99.1 million in the second quarter of 2014,
and increased 25% sequentially from $78.9 million in the first quarter
of 2014. This increase in oil and natural gas revenues included an
increase in oil revenues of $33.9 million and an increase in natural gas
revenues of $7.0 million between the respective year-over-year periods.
Oil revenues increased 76% from $44.6 million for the three months ended
June 30, 2013 to $78.5 million for the three months ended June 30, 2014.
Natural gas revenues increased 52% from $13.5 million for the three
months ended June 30, 2013 to $20.6 million for the three months ended
June 30, 2014. The increase in oil revenues resulted primarily from the
79% increase in oil production from 447,000 Bbl of oil in the second
quarter of 2013 to 802,000 Bbl of oil in the second quarter of 2014. The
increase in natural gas revenues was attributable not only to the 17%
increase in natural gas production from 3.1 Bcf in the second quarter of
2013 to 3.6 Bcf in the second quarter of 2014, but also to a
significantly higher weighted average natural gas price of $5.69 per Mcf
realized in the second quarter of 2014, as compared to $4.38 per Mcf
realized in the second quarter of 2013. This increase in the weighted
average natural gas price reflects both the general improvement in
natural gas prices, as well as the higher percentage of liquids-rich
natural gas produced during the second quarter of 2014, as compared to
the second quarter of 2013. In the second quarter of 2014, approximately
54% of the Company’s natural gas production was liquids-rich natural
gas, primarily from the Eagle Ford shale, as compared to 31% in the
second quarter of 2013. As a two-stream reporting company, the economic
value of the natural gas liquids associated with the natural gas
produced by Matador is included in the natural gas revenues reported and
serves as an uplift to the estimated natural gas wellhead price on those
properties where the natural gas liquids are extracted and sold.
Production results from the six months ended June 30, 2014 were also the
best in Matador’s history. Average daily oil equivalent production
increased 27% from 10,739 BOE per day (47% oil) during the first six
months of 2013 to 13,673 BOE per day (59% oil) in the first six months
of 2014. Oil production increased 61% from 908,000 Bbl of oil, or 5,015
Bbl of oil per day, during the first six months of 2013, to
approximately 1.46 million Bbl of oil, or 8,080 Bbl of oil per day,
during the first six months of 2014, and increased 19% sequentially from
1.23 million Bbl of oil, or 6,658 Bbl of oil per day, during the six
months ended December 31, 2013. It is interesting to note that during
the first half of 2014, Matador produced more oil (1.46 million Bbl)
than the 1.21 million Bbl of oil the Company produced in all of 2012
just two years ago, and the Company has already produced almost 70% of
its 2013 total oil production of 2.13 million Bbl. These year-over-year
increases in the Company’s average daily oil equivalent production and,
in particular, the Company’s average daily oil production, are primarily
attributable to the success of the Company’s ongoing drilling operations
in the Eagle Ford shale, but also reflect the strong initial production
performance of the Company’s first horizontal wells in the Delaware
portion of the Permian Basin. Natural gas production remained
essentially flat between the periods, going from 6.2 Bcf, or 34.3 MMcf
per day, in the first six months of 2013, to 6.1 Bcf, or 33.6 MMcf per
day, during the first six months of 2014.
Oil and natural gas revenues increased 51% from $117.5 million during
the first six months of 2013 to $178.0 million in the first six months
of 2014, and increased 17% sequentially from $151.5 million for the six
months ended December 31, 2013. This increase in oil and natural gas
revenues included an increase in oil revenues of $48.9 million and an
increase in natural gas revenues of $11.6 million between the respective
periods. Oil revenues increased 52% from $93.3 million for the six
months ended June 30, 2013 to $142.2 million for the six months ended
June 30, 2014. Natural gas revenues increased 48% from $24.2 million for
the six months ended June 30, 2013 to $35.8 million for the six months
ended June 30, 2014. The increase in oil revenues was primarily
attributable to the 61% increase in oil production from 908,000 Bbl of
oil in the six months ended June 30, 2013 to 1.46 million Bbl of oil in
the six months ended June 30, 2014. The increase in natural gas revenues
was primarily attributable to a significantly higher weighted average
natural gas price of $5.90 per Mcf realized in the first six months of
2014, as compared to $3.89 per Mcf realized in the first six months of
2013. This increase in the weighted average natural gas price reflects
both the general improvement in natural gas prices, as well as the
higher percentage of liquids-rich natural gas produced during the first
six months of 2014, as compared to the first six months of 2013. In the
first six months of 2014, approximately 54% of the Company’s natural gas
production was liquids-rich natural gas, primarily from the Eagle Ford
shale, as compared to 29% in the first six months of 2013.
Adjusted EBITDA
Adjusted EBITDA, a non-GAAP financial measure, increased 70% from $40.8
million for the three months ended June 30, 2013 to $69.5 million for
the three months ended June 30, 2014. Sequentially, Adjusted EBITDA
increased 23%, as compared to $56.3 million reported for the first
quarter of 2014.
Adjusted EBITDA increased 54% from $81.4 million for the six months
ended June 30, 2013 to $125.8 million for the six months ended June 30,
2014. Sequentially, Adjusted EBITDA increased 14%, as compared to $110.3
million reported for the six months ended December 31, 2013.
For a definition of Adjusted EBITDA and a reconciliation of net
income (GAAP) and net cash provided by operating activities (GAAP) to
Adjusted EBITDA (non-GAAP), please see “Supplemental Non-GAAP Financial
Measures” below.
Net Income
For the quarter ended June 30, 2014, Matador reported net income of
$18.2 million and earnings of $0.26 per diluted common share, as
compared to net income of $25.1 million and earnings of $0.45 per
diluted common share for the quarter ended June 30, 2013, and as
compared to net income of $16.4 million and earnings of $0.25 per
diluted common share for the quarter ended March 31, 2014. The Company’s
earnings per share for the quarter ended June 30, 2014 were favorably
impacted by growth in oil and natural gas production and revenues and
continuing improvements in reducing lease operating expenses, among
other items, but were unfavorably impacted by a non-cash unrealized loss
on derivatives of $5.2 million recorded during the quarter, primarily
resulting from its hedging activities on oil. The Company’s earnings per
share for the quarter ended June 30, 2013 were favorably impacted by (1)
a non-cash unrealized gain on derivatives of $7.5 million, (2) no
deferred income tax provision being recorded during the quarter and (3)
19% fewer weighted average common shares outstanding. The Company had
weighted average common shares outstanding of 69.2 million on a diluted
basis at June 30, 2014, as compared to weighted average common shares
outstanding of 55.9 million on a diluted basis at June 30, 2013.
For the six months ended June 30, 2014, Matador reported net income of
$34.6 million and earnings of $0.51 per diluted common share, as
compared to net income of $9.6 million and earnings of $0.17 per diluted
common share for the six months ended June 30, 2013. The Company’s
earnings per share for the six months ended June 30, 2014 were favorably
impacted by its growth in oil and natural gas production and revenues
and continuing improvements in reducing lease operating expenses, but
were unfavorably impacted by a non-cash unrealized loss on derivatives
of $8.3 million recorded during the period, primarily resulting from the
Company’s hedging activities on oil. The Company’s earnings per share
for the six months ended June 30, 2013 were favorably impacted by (1) a
non-cash unrealized gain on derivatives of $2.7 million, (2) no deferred
income tax provision being recorded during the period and (3) 18% fewer
weighted average common shares outstanding, but such earnings per share
were unfavorably impacted by a full-cost ceiling test impairment of
$21.2 million recorded during the first quarter of 2013 that was
reflected in the Company’s condensed consolidated statement of
operations for the six months ended June 30, 2013.
Summary of Sequential Financial Results
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Average daily oil equivalent production increased 30% from 11,904 BOE
per day in the first quarter of 2014 to 15,424 BOE per day in the
second quarter of 2014.
-
Average daily oil equivalent production increased 7% from 12,723 BOE
per day for the six months ended December 31, 2013 to 13,673 BOE per
day for the six months ended June 30, 2014.
-
Oil production increased 21% from 661,000 Bbl, or 7,344 Bbl of oil per
day, in the first quarter of 2014 to 802,000 Bbl, or 8,809 Bbl of oil
per day, in the second quarter of 2014.
-
Oil production increased 19% from 1,225,000 Bbl for the six months
ended December 31, 2013 to 1,463,000 Bbl for the six months ended
June 30, 2014.
-
Natural gas production increased 47% from 2.5 Bcf, or 27.4 MMcf of
natural gas per day, in the first quarter of 2014 to 3.6 Bcf, or 39.7
MMcf of natural gas per day, in the second quarter of 2014.
-
Natural gas production decreased 9% from 6.7 Bcf for the six months
ended December 31, 2013 to 6.1 Bcf for the six months ended June 30,
2014.
-
Oil and natural gas revenues increased 25% from $78.9 million in the
first quarter of 2014 to $99.1 million in the second quarter of 2014.
The Company realized a weighted average oil price of $97.92 per Bbl
and a weighted average natural gas price of $5.69 per Mcf during the
second quarter of 2014, as compared to $96.34 per Bbl and $6.20 per
Mcf, respectively, during the first quarter of 2014.
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Oil and natural gas revenues increased 17% from $151.5 million for the
six months ended December 31, 2013 to $178.0 million for the six
months ended June 30, 2014. The Company realized a weighted average
oil price of $97.20 per Bbl and a weighted average natural gas price
of $5.90 per Mcf for the six months ended June 30, 2014, as compared
to $97.58 per Bbl and $4.78 per Mcf, respectively, for the six months
ended December 31, 2013.
-
Adjusted EBITDA increased 23% from $56.3 million in the first quarter
of 2014 to $69.5 million in the second quarter of 2014.
-
Adjusted EBITDA increased 14% from $110.3 million reported for the six
months ended December 31, 2013 to $125.8 million for the six months
ended June 30, 2014.
-
Net income increased 11% from $16.4 million in the first quarter of
2014 to $18.2 million in the second quarter of 2014. Net income
decreased 3% from $35.5 million reported for the six months ended
December 31, 2013 to $34.6 million reported for the six months ended
June 30, 2014.
Click
here for charts highlighting various aspects of Matador’s growth on a
sequential six-month basis.
Operating Expenses
Production Taxes and Marketing
Production taxes and marketing expenses increased from $4.5 million (or
$4.62 per BOE) for the three months ended June 30, 2013 to $9.1 million
(or $6.50 per BOE) for the three months ended June 30, 2014. This
increase was primarily due to the increase in oil and natural gas
revenues by approximately 70% during the three months ended June 30,
2014, as compared to the three months ended June 30, 2013. A large
portion of this increase on an absolute basis was attributable to
production taxes associated with the increase in oil production and
associated oil revenues during the three months ended June 30, 2014, as
compared to the three months ended June 30, 2013, resulting primarily
from drilling operations in the Eagle Ford shale, but also from initial
production contributions from the Company’s first operated wells in the
Permian Basin. Oil comprised 57% of the Company’s total production
volume in the second quarter of 2014, as compared to 46% in the second
quarter of 2013. The increase in production taxes and marketing expenses
during the second quarter of 2014, as compared to the second quarter of
2013, also reflected the higher percentage of Matador’s natural gas
production coming from the Eagle Ford shale in Texas, where natural gas
production taxes are higher than production taxes associated with the
Haynesville shale gas in Louisiana. The Company produced 48% of its
total natural gas volume from the Eagle Ford in the second quarter of
2014, as compared to only 31% in the second quarter of 2013. Production
taxes and marketing expenses for the three months ended June 30, 2014
also reflected some increased charges associated with non-operated
natural gas processing fees in South Texas. Production taxes and
marketing expenses increased from $8.5 million (or $4.40 per BOE) for
the six months ended June 30, 2013 to $15.1 million (or $6.11 per BOE)
for the six months ended June 30, 2014.
Lease Operating Expenses (“LOE”)
Lease operating expenses increased on an absolute basis, but
importantly, decreased 21% on a unit-of-production basis, from $10.1
million (or $10.53 per BOE) for the three months ended June 30, 2013 to
$11.7 million (or $8.34 per BOE) for the three months ended June 30,
2014. Between these respective periods, total oil and natural gas
production increased 46% from approximately 963,000 BOE to approximately
1.4 million BOE, including an increase in oil production of 79% from
447,000 Bbl to 802,000 Bbl. Oil production was 57% of total production
by volume in the second quarter of 2014, as compared to 46% of total
production by volume in the second quarter of 2013, which would
typically result in higher LOE on a per unit basis. The significant
(21%) decrease achieved in LOE on a per unit basis resulted from the
progress made in reducing LOE during the last twelve months, which was
primarily attributable to (1) the installation of permanent production
facilities on almost all Eagle Ford properties, alleviating the need for
the extended use of flowback equipment to produce newly completed Eagle
Ford wells, (2) the early use of gas lift on most newly completed Eagle
Ford wells and (3) a decrease in salt water disposal costs on a per Bbl
basis, as well as continued improvement in overall operational
processes, in the Company’s South Texas operations. For the six months
ended June 30, 2014, lease operating expenses were essentially flat on
an absolute basis, but decreased 21% on a unit-of-production basis, from
$21.0 million (or $10.82 per BOE) for the six months ended June 30, 2013
to $21.1 million (or $8.51 per BOE) for the six months ended June 30,
2014. Between these respective periods, total oil and natural gas
production increased 27% from approximately 1.9 million BOE to
approximately 2.5 million BOE, including an increase in oil production
of 61% from 908,000 Bbl to 1.46 million Bbl.
Depletion, depreciation and amortization (“DD&A”)
Due to Matador’s higher production volumes, depletion, depreciation and
amortization expenses increased 57% on an absolute basis from $20.2
million for the three months ended June 30, 2013 to $31.8 million for
the three months ended June 30, 2014. The 57% increase in total DD&A
expenses was primarily attributable to the 46% increase in total oil and
natural gas production from 963,000 BOE to approximately 1.4 million BOE
during the respective periods. On a unit-of-production basis, however,
DD&A expenses increased only 8% from $21.01 per BOE for the three months
ended June 30, 2013 to $22.66 per BOE for the three months ended
June 30, 2014. DD&A expenses increased 15% on an absolute basis from
$48.5 million for the six months ended June 30, 2013 to $55.8 million
for the six months ended June 30, 2014. Notably, on a unit-of-production
basis, DD&A expenses decreased 10% from $24.93 per BOE for the six
months ended June 30, 2013 to $22.56 per BOE for the six months ended
June 30, 2014.
General and administrative (“G&A”)
General and administrative expenses increased from $4.1 million (or
$4.31 per BOE) for the three months ended June 30, 2013 to $8.1 million
(or $5.77 per BOE) for the three months ended June 30, 2014. The
increase in G&A expenses for the three months ended June 30, 2014 was
largely attributable to additional payroll expenses associated with
personnel added between the respective periods to support increased
land, drilling, completion and production operations. The remaining
increase was due to an increase in stock-based compensation expense from
$1.0 million for the three months ended June 30, 2013 to $1.8 million
for the three months ended June 30, 2014. The increase in stock-based
compensation expense is attributable to the continued vesting of awards
granted in 2012 and 2013 and new awards granted in 2014, as well as the
increased fair value of liability-based stock options during the three
months ended June 30, 2014, resulting from an increase in the price per
share of Matador’s common stock from $24.49 to $29.28 during the second
quarter of 2014. These equity awards have helped Matador attract, retain
and incentivize its growing technical, operational, land and accounting
staff. The Company’s G&A expenses increased 34% on a unit-of-production
basis from $4.31 per BOE for the three months ended June 30, 2013 to
$5.77 per BOE for the three months ended June 30, 2014. General and
administrative expenses increased from $8.8 million (or $4.50 per BOE)
for the six months ended June 30, 2013 to $15.3 million (or $6.19 per
BOE) for the six months ended June 30, 2014.
Proved Reserves and PV-10
At June 30, 2014, Matador’s estimated total proved oil and natural gas
reserves were 57.2 million BOE, including 18.6 million Bbl of oil and
231.4 Bcf of natural gas, with a PV-10, a non-GAAP financial measure, of
$826.0 million (Standardized Measure of $723.0 million), as compared to
estimated total proved oil and natural gas reserves of 51.7 million BOE,
including 16.4 million Bbl of oil and 212.2 Bcf of natural gas, with a
PV-10 of $655.2 million (Standardized Measure of $578.7 million) at
December 31, 2013, and as compared to estimated total proved oil and
natural gas reserves of 38.9 million BOE, including 12.1 million Bbl of
oil and 160.8 Bcf of natural gas, with a PV-10 of $522.3 million
(Standardized Measure of $477.6 million) at June 30, 2013. Total proved
reserves of 57.2 million BOE at June 30, 2014 represented a 47%
year-over-year increase, as compared to 38.9 million BOE at June 30,
2013, and an 11% sequential six-month increase, as compared to 51.7
million BOE at December 31, 2013. The PV-10 of $826.0 million at
June 30, 2014 represented a 58% year-over-year increase, as compared to
$522.3 million at June 30, 2013, and a 26% sequential six-month
increase, as compared to $655.2 million at December 31, 2013.
Proved oil reserves increased 54% year-over-year to 18.6 million Bbl at
June 30, 2014, as compared to 12.1 million Bbl at June 30, 2013, and
increased 14% on a sequential six-month basis from 16.4 million Bbl at
December 31, 2013. Proved natural gas reserves increased 44%
year-over-year to 231.4 Bcf at June 30, 2014, as compared to 160.8 Bcf
at June 30, 2013, and increased 9% on a sequential six-month basis, as
compared to 212.2 Bcf at December 31, 2013. At June 30, 2014,
approximately 35% of the Company’s total proved reserves were proved
developed reserves, 33% were oil and 67% were natural gas. At
December 31, 2013, approximately 33% of the Company’s total proved
reserves were proved developed reserves, 32% were oil and 68% were
natural gas.
In comparing the Company’s reserves growth between periods, and
especially during the first six months of 2014, it is important to note
that, as a result of the Company’s drilling, completions and production
schedule and particularly its infill development plans in the Eagle Ford
shale, many of the wells drilled during the first six months of 2014
were identified as proved developed non-producing (“PDNP”) or proved
undeveloped (“PUD”) locations and reserves at December 31, 2013. Of the
21 gross (17.3 net) Eagle Ford wells drilled or participated in by the
Company in the first six months of 2014, 16 gross (13.4 net) of these
wells were included in the December 31, 2013 total proved reserves as
PUD or PDNP locations. In addition, all of the Company’s 22 gross (1.0
net) Haynesville shale wells, as well as one gross (0.95 net) of the
Company’s Permian Basin wells drilled and placed on production during
the first six months of 2014, were included in the December 31, 2013
total proved reserves as PUD or PDNP locations. The Company anticipates
that most of the wells it drills in the Eagle Ford shale during the
second half of 2014 will not be PUD locations as identified at December
31, 2013, as it moves to newer portions of its more developed Eagle Ford
properties, as well as certain of its recently acquired Eagle Ford
acreage where proved reserves have yet to be identified and included in
the Company’s total proved reserves. The Company anticipates drilling no
additional PUD locations in the Permian Basin for the remainder of 2014.
As noted earlier, Matador reports its production and estimated 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 Eagle Ford shale in South Texas and the
Permian Basin, the economic value of the natural gas liquids associated
with the natural gas is included as an uplift to the estimated natural
gas wellhead price on those properties where the natural gas liquids are
extracted and sold. The reserves estimates in all periods presented were
prepared by the Company’s internal engineering staff and audited by an
independent reservoir engineering firm, Netherland, Sewell & Associates,
Inc. These reserves estimates were prepared in accordance with the SEC’s
rules for oil and natural gas reserves reporting and do not include any
unproved reserves classified as probable or possible that might exist on
Matador’s properties. The unweighted arithmetic averages of
first-day-of-the-month oil and natural gas prices, respectively, used in
preparing these estimates were $96.75 per Bbl and $4.104 per MMBtu for
the period from July 2013 through June 2014, $93.42 per Bbl and $3.670
per MMBtu for the period from January 2013 through December 2013 and
$88.13 per Bbl and $3.444 per MMBtu for the period from July 2012
through June 2013. These prices were adjusted by property for quality,
energy content, regional price differentials, transportation fees,
marketing deductions and other factors affecting the oil and natural gas
prices received at the wellhead.
For a reconciliation of Standardized Measure (GAAP) to PV-10
(non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
Operations Update
Matador’s 2014 drilling activity continues to be focused on increasing
oil production and reserves in South Texas, primarily in the Eagle Ford
shale play, while expanding exploration and delineation efforts in the
Permian Basin in Southeast New Mexico and West Texas. At March 31, 2014,
the Company had two contracted drilling rigs operating on its Eagle Ford
acreage in South Texas and one contracted drilling rig operating in the
Permian Basin. In April 2014, the Company replaced the drilling rig
operating in the central portion of its Eagle Ford acreage in Karnes
County with a new “walking” rig. Due to a temporary contract overlap
resulting from initiating drilling operations with this second “walking”
rig, the Company moved the rig being replaced in the central Eagle Ford
in Karnes County to Loving County, Texas in order to provide Matador
with a second rig in the Permian Basin. The Company is using a portion
of the proceeds from its May 2014 equity offering (described below) to
keep this fourth rig operating full-time in the Permian Basin, primarily
in the Wolf prospect area in Loving County, Texas. As a result, as of
August 6, 2014, the Company was operating four drilling rigs — two in
the Eagle Ford and two in the Permian Basin. Because of the timing of
the addition of this fourth drilling rig in the Permian Basin and the
Company’s projected drilling and completions schedule, Matador does not
expect this rig to materially impact anticipated 2014 oil and natural
gas production or anticipated 2014 oil and natural gas revenues. Rather,
Matador anticipates that the addition of this second rig in the Permian
Basin will start to have a material impact on operations and financial
results beginning in 2015. Matador expects to add at least one
additional rig in the Permian Basin at the beginning of 2015 and is
working with its drilling contractor to add custom features to this rig
specifically tailored to its planned drilling operations in the Permian
Basin.
Eagle Ford Shale - South Texas
Matador had two drilling rigs operating in South Texas during the second
quarter of 2014 as the Company continued to develop its Eagle Ford
acreage. During the second quarter of 2014, the Company completed and
began producing oil and natural gas from nine gross (6.2 net) Eagle Ford
wells, including six gross (5.4 net) operated and three gross (0.8 net)
non-operated Eagle Ford wells. Matador completed three operated Eagle
Ford wells on its Northcut lease and two wells on its Martin Ranch lease
in La Salle County and one well on its Lyssy lease in southern Wilson
County. The three non-operated wells were completed on its Troutt lease
in La Salle County. The Northcut wells began producing in mid-April, the
Martin Ranch wells began producing in mid-May and the Lyssy well began
producing in mid-June. As a result, these six wells did not contribute
fully to production volumes for the second quarter of 2014 or for the
first half of 2014. Due to the Company’s (1) batch drilling operations
and other operating practices aimed at cost savings, improving
operational efficiencies and increasing estimated ultimate recoveries,
(2) increased completion activity from industry in these areas, (3)
protection of producing wells during the drilling and completion of
offsetting wells by both the Company and other operators, and (4)
continuing strategy to manage bottomhole pressure through the practice
of producing wells on restricted choke sizes, Matador had as much as 10
to 15% of its production capacity shut in or restricted at various times
during the second quarter of 2014. For the six months ended June 30,
2014, Matador completed 21 gross (17.3 net) Eagle Ford wells, including
17 gross (16.2 net) operated wells and 4 gross (1.1 net) non-operated
wells. At August 6, 2014, Matador had two drilling rigs operating in the
Eagle Ford — one on its Lyssy lease in southern Wilson County and one on
its Pawelek lease in Karnes County.
The Company continues to execute its Eagle Ford development plan in
accordance with its original plans and expectations for 2014. In April
2014, the Company replaced the drilling rig operating in the central
portion of its acreage in Karnes and Wilson Counties with a newer
“walking” rig. The company now has two “walking” rigs in the Eagle Ford
and plans to conduct batch drilling and other developmental operations
on its properties using these two rigs for the balance of 2014. Matador
has already achieved significant improvements in both drilling times and
costs since employing the new “walking” rig on the Company’s central
Eagle Ford acreage in the last few months. On the first few wells
drilled with this new “walking” rig, Matador has reduced spud to spud
drilling cycle times by one to three days per well, as compared to
earlier wells drilled in this same area. Further, the Company estimates
that it has reduced well costs by $300,000 to $400,000 per well compared
to recent wells drilled without using the new “walking” rig. Matador has
been conducting batch drilling operations with a “walking” rig on its
western Eagle Ford acreage in La Salle County since August 2013 and has
achieved significant improvements in both drilling times and costs in
this area since that time too. Recent wells on the Company’s western
acreage (e.g., the Martin Ranch and Northcut wells) have drilling times,
from spud to total depth, of 8 to 10 days per well and total drilling
and completion costs near or below $6.0 million per well.
The Company’s downspacing efforts in the Eagle Ford shale have continued
to achieve results similar to those previously reported. In Karnes
County, the Company has drilled recent wells on its Sickenius, Pawelek
and Danysh leases with 40 to 50-acre spacing. Matador is pleased with
the results of the Company’s Generation 5, 6 and 7 fracture designs in
this area and in almost all cases the wells are outperforming the
previous 80-acre wells drilled on these properties using earlier
generation fracture treatments. The initial flow rates and flowing
pressures on these newer wells on comparable choke sizes have been
consistently better than those observed on the 80-acre wells, and the
flowing pressures observed on these wells suggest minimal depletion at
these locations from earlier wells. On the Company’s Northcut lease in
La Salle County, 40-acre infill wells have delivered comparable to
better initial results than the previous 80-acre wells drilled on this
lease using earlier generation fracture treatment designs, and initial
flowing pressures observed on these wells also suggest minimal pressure
depletion at these locations. On Matador’s Martin Ranch lease, there
have been more indications of pressure interference between wells,
especially for those 40-acre infill wells drilled near or between the
better wells in the center of the property, which includes most of the
Martin Ranch infill wells drilled thus far. Still, given the incremental
recovery associated with these infill wells and the significant
improvement in well costs currently being achieved which continues to
improve rates of return, the Company believes the continued development
of its Martin Ranch lease on 40-acre spacing using batch drilling and
Generation 7 or later fracture treatment designs will be the best way to
maximize oil recovery and overall project economics. Matador continues
to project rates of return of 30 to 40% or greater from these wells at
current drilling and completion costs and commodity prices. In addition,
as the Company drills new wells in the northern and western portions of
the Martin Ranch lease, there are fewer true infill wells to be drilled.
Matador expects these newer wells to encounter essentially original
reservoir pressure and to be stimulated with Generation 7 or later
fracture treatment designs tailored to its 40-acre development plans.
The Company will also continue to test 40 to 50-acre spacing on its
other properties in northwest La Salle County throughout the remainder
of 2014.
Permian Basin - Southeast New Mexico and West Texas
Matador had two contracted drilling rigs operating in the Permian Basin
during the majority of the second quarter of 2014 — one in Loving
County, Texas and the other in Lea County, New Mexico. Due to the timing
of drilling, completion and production operations, the Company did not
complete and place on production any new Permian Basin wells during the
second quarter; however, three new Permian wells were completed and
began producing in mid-to-late July — the Norton Schaub #1H well in
Loving County and the Pickard State 20-18-34 #1H and Pickard State
20-18-34 #2H wells in Lea County, New Mexico, with results as noted
below. At August 6, 2014, the Company continues to have two drilling
rigs operating in the Permian Basin — one drilling the Johnson
44-02S-B53 WF #204H well, a Wolfcamp “A” test in the Wolf prospect area
in Loving County, Texas and one drilling the Jim Rolfe 22-18S-34E RN
#131H, the Company’s first Third Bone Spring sand test in the northern
part of its Ranger prospect area in Lea County, New Mexico. The Arno #1H
well, a Wolfcamp “A” test in the Wolf prospect area, has been drilled
and completion operations on that well should begin in mid-August.
Matador was pleased to announce last week the 24-hour initial potential
test results from the Norton Schaub #1H, a Wolfcamp “A” test, and the
Pickard State 20-18-34 #1H, a Second Bone Spring test, both of which
have been producing fewer than 30 days. First, in the Wolf prospect area
of Loving County, Texas, the Norton Schaub #1H well flowed 1,026 BOE per
day, including 706 Bbl of oil per day and 1,922 Mcf of natural gas per
day (69% oil), at 3,000 psi flowing surface pressure on a 22/64th
inch choke during its 24-hour initial potential test in mid-July 2014.
This well was completed in the upper portion of the Wolfcamp formation,
the Wolfcamp “A,” at approximately 10,800 feet true vertical depth.
Matador drilled a 4,700-ft horizontal lateral in the Norton Schaub #1H
and stimulated this well with approximately 200,000 Bbl of fluid and 9.8
million pounds of sand. This is the Company’s second successful test of
the Wolfcamp “A” formation in its Wolf prospect. The Norton Schaub #1H
was drilled near and to the northwest of Matador’s original well on the
Wolf prospect, the Dorothy White #1H. The Dorothy White #1H was also
completed in the Wolfcamp “A” formation and has continued to exhibit
very strong performance since being placed on production in January
2014. In only about seven months on production, including its initial
cleanup phase, the Dorothy White #1H well has produced 175,000 BOE,
including almost 115,000 Bbl of oil. The Dorothy White #1H well
continues to exhibit a much shallower decline than expected, which means
its ultimate recovery should be higher than originally estimated.
Currently, the Dorothy White #1H is still producing over 500 Bbl of oil
per day and 1.3 MMcf of natural gas per day at about 2,300 psi flowing
surface pressure. The Arno #1H well, a third “Wolfcamp A” test in the
southwest portion of the Wolf prospect area, has been drilled and will
be completed in mid-August. Based on the success of these two initial
wells, Matador intends to operate one of its two Permian drilling rigs
full time in the Loving County area throughout the remainder of 2014.
In the Ranger prospect area in Lea County, New Mexico, the Pickard State
20-18-34 #1H (Second Bone Spring test) and #2H (Wolfcamp “D” test) wells
were drilled from a single surface pad and then completed back-to-back,
with the Pickard State 20-18-34 #1H being put on production first after
completion. The Pickard State 20-18-34 #1H was completed in the Second
Bone Spring sand at approximately 9,900 feet true vertical depth.
Matador drilled a 4,100-ft horizontal lateral in the Pickard State
20-18-34 #1H and stimulated this well with approximately 167,000 Bbl of
fluid and 7.3 million pounds of sand. This well flowed 592 BOE per day,
including 535 Bbl of oil per day and 340 Mcf of natural gas per day (90%
oil) at 750 psi flowing surface pressure on a 22/64th inch
choke during its 24-hour initial potential test in late July 2014. This
well is the Company’s second positive test of the Second Bone Spring
sand in the Ranger prospect area, and early indications are that this
well may be comparable to or better than Matador’s initial Second Bone
Spring well, the Ranger 33 State Com #1H. The Pickard State 20-18-34 #1H
well flowed oil at higher rates and at higher flowing pressures on a
comparable choke much earlier than the Ranger 33 State Com #1H.
Meanwhile, the Ranger 33 State Com #1H has continued to exhibit strong
performance and a shallower decline than expected, despite its slow
initial clean up following stimulation, producing 123,000 BOE, including
113,000 Bbl of oil after nine months of production and continues to
produce 350 to 400 Bbl of oil per day. The Ranger 33 State Com #1H well
has been produced successfully with gas lift assist designed and
implemented early in its life, and Matador intends to use gas lift
assist on the Pickard State 20-18-34 #1H as well.
The Pickard State 20-18-34 #2H, also in the Ranger prospect area, was
completed in the Wolfcamp “D” formation at approximately 12,000 feet
true vertical depth. To the Company’s knowledge, this test of the
Wolfcamp “D” formation may be the northernmost horizontal test of the
Wolfcamp formation in the Delaware Basin. In this well, Matador drilled
a 4,300-ft horizontal lateral in the Pickard State 20-18-34 #2H and
stimulated this well with 183,000 Bbl of fluid and 8.2 million pounds of
sand. At August 6, 2014, the Pickard State 20-18-34 #2H was still in the
flowback period of its completion operations. The well is flowing oil
and natural gas (85 to 90% oil) but still cleaning up following
stimulation, and has yet to have its initial potential test. The initial
flowback results of this exploratory test are encouraging and confirm
the ability to produce oil from the organically rich source rocks in the
Wolfcamp “D” bench in the northern Delaware Basin. Matador expects to
report additional results from this well, the Arno #1H well and perhaps
other well results from its other current drilling activities in the
Permian Basin later in the third quarter.
Finally, the Company is pleased to report that the Rustler Breaks
12-24-27 #1H, a Wolfcamp “B” completion in its Rustler Breaks prospect
area in Eddy County, New Mexico, has now produced 72,000 BOE in just
over three months, including 32,000 Bbl of oil, and is currently
producing about 230 Bbl of oil and 1.8 MMcf of natural gas per day at
1,300 psi flowing surface pressure. This well’s early performance
continues to exceed the Company’s initial expectations and, to the
Company’s knowledge and based on publicly available completion records,
the Rustler Breaks 12-24-27 #1H well appears to be outperforming other
Wolfcamp “B” wells in the area. The Company attributes the
outperformance of this well, and others of its initial Permian wells, to
the effectiveness of the larger stimulation treatments performed on
these wells. The Company plans to keep its second Permian drilling rig
operating in Lea and Eddy Counties, New Mexico throughout the remainder
of 2014, with the possible exception of a one-well test of its Howard
County acreage in the Midland Basin being considered for later in the
third quarter.
Haynesville Shale - Northwest Louisiana and East Texas
During the first quarter of 2014, Matador was notified by Chesapeake of
its intent to drill up to a total of 30 gross (6.3 net) Haynesville
wells on Matador’s Elm Grove acreage in southern Caddo Parish, Louisiana
during 2014. The Company retains the right to participate for up to a
25% working interest in all wells drilled on this property, with its
working interest proportionately reduced to the leasehold position in
any individual drilling unit. Chesapeake began actively drilling on
these properties during the second quarter of 2014, and, at August 6,
2014, is currently operating four drilling rigs on these properties.
These wells are being drilled and completed in a multi-well batch mode,
and as a result, the Company does not expect to see significant
contributions from these wells to its natural gas production until late
in the third quarter and perhaps even into the fourth quarter of 2014.
At August 6, 2014, the Company had agreed to participate in 21 gross
(4.4 net) wells in progress or proposed on this acreage, with an
estimated total capital commitment of $37.4 million. Nineteen gross (4.2
net) of these wells are currently anticipated to be completed and placed
on production prior to the end of the year, with most coming on line in
the fourth quarter of 2014. Should Chesapeake elect to drill all 30
gross wells on this acreage in 2014, Matador’s working interest would be
equivalent to approximately 6.3 net wells at an estimated capital
expenditure of approximately $50.0 million. These capital expenditures
are included as part of the Company’s 2014 estimated capital
expenditures budget of $570 million.
Matador notes that this Elm Grove acreage in southern Caddo Parish is
relatively proven and is located in the core of the play where some of
the best Haynesville wells have been drilled. The Company anticipates
estimated ultimate recoveries of 8 to 12 Bcf per well in this area. As a
result, Matador believes its participation in these Chesapeake-operated
wells should generate very favorable returns at current natural gas
prices. Chesapeake has indicated it plans to drill these wells using
batch drilling techniques and drilling rigs equipped with “walking”
packages, similar to the Company’s operations in South Texas, to reduce
costs. Most of the upcoming wells drilled in this acreage will be
drilled as “cross-unit” horizontal wells, which should increase the
completed lateral length by up to 10%, as compared to the initial wells
in these sections. These longer laterals, along with improved
stimulation designs since the initial wells were drilled and completed
on these properties, are expected to improve the overall economic
returns from these wells. Matador’s economics are further enhanced by
the fact that the Company retained overriding royalty interests under
many of its leases covering this acreage as a result of its 2008
transaction with Chesapeake. As a result, the Company expects to have
effective net revenue interests of 85 to 90%, proportionately reduced to
its working interest, on many of these wells, which should further
improve returns. Finally, Matador recently began taking its natural gas
production in kind from these properties, and effective January 1, 2014,
the Company entered into a five-year natural gas gathering agreement for
this natural gas production. The Company believes taking its natural gas
production in kind and transporting through this gathering agreement
will further improve natural gas price realizations and reduce marketing
and transportation fees and other costs previously associated with this
production by an average of approximately $0.70 or more per MMBtu.
Matador participated in 13 gross (0.6 net) non-operated Haynesville
shale wells completed and placed on production during the second quarter
of 2014, but these wells did not include any of the 30 gross wells in
progress or proposed by Chesapeake on the Company’s Elm Grove properties
as described above.
Acreage Acquisitions
Matador began 2014 with approximately 70,800 gross (44,800 net) acres in
the Permian Basin in Southeast New Mexico and West Texas. Between
January 1 and August 6, 2014, Matador acquired an additional 23,200
gross (17,200 net) acres in this area, primarily in Lea and Eddy
Counties, New Mexico and Loving County, Texas. Including these acreage
acquisitions, at August 6, 2014, Matador’s total Permian Basin acreage
position is approximately 94,000 gross (62,000 net) acres. This
leasehold position includes 11,200 gross (7,200 net) acres in the Loving
County, Texas area (including a few small tracts in Reeves and Ward
Counties), 14,600 gross (10,200 net) acres in the Ranger/Querecho Plains
prospect area in Lea County, New Mexico, 18,100 gross (13,400 net) acres
in the Rustler Breaks/Indian Draw prospect area in Eddy County, New
Mexico, 37,700 gross (26,400 net) acres in the Twin Lakes prospect area
in Lea County, New Mexico, and an additional approximately 4,000 gross
(3,400 net) acres in Howard and Dawson Counties, Texas. Matador has
effectively doubled its leasehold position in the Loving County area
since January 1, 2014, including the addition of 1,800 gross (1,700 net)
acres adjacent to its Wolf prospect area, and has increased its overall
position in the Permian Basin by more than one-third.
Matador has also been actively acquiring additional Eagle Ford acreage
in South Texas. Between January 1 and August 6, 2014, the Company has
acquired (or expects to acquire by the middle of August) approximately
3,100 gross (2,900 net) acres in South Texas prospective for the Eagle
Ford shale in La Salle, Karnes and southern Atascosa Counties. This
newly acquired acreage has the potential to add up to 75 additional
gross drilling locations to the Eagle Ford development program. Matador
plans to maintain leasing efforts in each of its three operating areas —
Permian, Eagle Ford and Haynesville — as opportunities arise throughout
the remainder of 2014.
Liquidity Update
In May 2014, Matador successfully completed a public offering of 7.5
million shares of its common stock, raising net proceeds of
approximately $181.3 million. The Company has used the net proceeds from
this offering to fund a portion of its capital expenditures, including
to operate a fourth rig in the Permian Basin throughout the remainder of
2014, allowing the Company to operate two rigs for the development of
its Eagle Ford acreage and two rigs for the exploration and delineation
of its Permian Basin acreage. The Company has used and expects to
continue to use portions of the net proceeds from the equity offering to
fund targeted acquisitions of additional acreage in the Permian Basin,
as well as in the Eagle Ford shale and the Haynesville shale, for its
participation in the Haynesville shale wells proposed by Chesapeake on
its Elm Grove properties in Northwest Louisiana and for other working
capital needs. Pending such uses, the Company repaid $180.0 million in
outstanding borrowings under its revolving credit facility in May 2014,
which amounts may be reborrowed in accordance with the terms of that
facility.
At June 30, 2014, the borrowing base under the Company’s revolving
credit facility was $385.0 million, based on the lenders’ review of
Matador’s proved oil and natural gas reserves at December 31, 2013. At
June 30, 2014, Matador had cash on hand totaling approximately $14.6
million, $150.0 million of outstanding long-term borrowings and
approximately $0.6 million in outstanding letters of credit. During the
three months ended June 30, 2014, these borrowings bore interest at an
average effective interest rate of 3.6% per annum. The Company expects
to be able to access future borrowings under its revolving credit
facility to fund portions of its remaining 2014 capital expenditure
requirements in excess of amounts available from the Company’s operating
cash flows. Subsequent to June 30, 2014, the Company borrowed an
additional $45.0 million to fund a portion of its working capital
requirements and to fund the acquisition of additional leasehold
interests. At August 6, 2014, the Company had $195.0 million in
borrowings outstanding under its revolving credit facility and
approximately $0.6 million in outstanding letters of credit, and these
borrowings bore interest at an effective interest rate of 2.8% per
annum. The Company’s liquidity position, balance sheet and debt metrics
remain strong, with a debt to projected 2014 Adjusted EBITDA ratio of
less than 0.7 at August 6, 2014. The Company also anticipates receiving
an increase to its borrowing base during the third quarter of 2014
following its lenders’ review of Matador’s proved oil and natural gas
reserves at June 30, 2014.
Hedging Positions
From time to time, Matador uses derivative financial instruments to
mitigate its exposure to commodity price risk associated with oil,
natural gas and natural gas liquids prices and to protect its cash flows
and borrowing capacity.
At August 6, 2014, Matador had the following hedges in place, in the
form of costless collars and swaps, for the remainder of 2014.
-
Approximately 1.1 million Bbl of oil at a weighted average floor price
of $88 per Bbl and a weighted average ceiling price of $99 per Bbl.
-
Approximately 4.4 Bcf of natural gas at a weighted average floor price
of $3.50 per MMBtu and a weighted average ceiling price of $4.93 per
MMBtu.
-
Approximately 3.2 million gallons of natural gas liquids at a weighted
average price of $1.25 per gallon.
At August 6, 2014, Matador had the following hedges in place, in the
form of costless collars and swaps, for 2015.
-
Approximately 1.2 million Bbl of oil at a weighted average floor price
of $83 per Bbl and a weighted average ceiling price of $101 per Bbl.
-
Approximately 9.0 Bcf of natural gas at a weighted average floor price
of $3.77 per MMBtu and a weighted average ceiling price of $4.79 per
MMBtu.
-
Approximately 3.8 million gallons of natural gas liquids at a weighted
average price of $1.02 per gallon.
2014 Guidance Affirmation
Matador reaffirms its full year 2014 guidance as revised upwards on May
6 and May 22, 2014 for (1) estimated capital expenditures of $570
million, (2) estimated total natural gas production of 16.0 to 17.5 Bcf,
(3) estimated total oil and natural gas revenues of $380 to $400 million
and (4) estimated Adjusted EBITDA of $270 to $290 million. Further, the
Company reaffirms its guidance to the high end of its 2014 estimated oil
production range of 2.8 to 3.1 million Bbl.
In reaffirming these guidance metrics, Matador cautions that its growth
for the remainder of 2014 will be uneven as a result of batch drilling,
timing of completion operations and planned shut-ins of certain of its
producing Eagle Ford and Haynesville wells while Matador and its
non-operating partners conduct hydraulic fracturing operations on
multi-well pads. In addition, as noted previously, the Company does not
expect to see the first significant contributions from the Haynesville
wells being drilled on its Elm Grove properties until late in the third
quarter and into the fourth quarter of 2014. Further, due to the timing
of the fourth drilling rig added in the Permian Basin, the addition of
this rig is not expected to materially impact anticipated 2014 oil and
natural gas production and revenues.
As a result of these factors, Matador anticipates that its oil
equivalent production will increase about 6 to 8% during the third
quarter of 2014, with oil production expected to grow somewhat more
slowly and natural gas production to be up by about 10%. Matador notes
that its natural gas production growth in the third and fourth quarters
of 2014 will be significantly impacted by the timing of Chesapeake’s
completion activities on the Haynesville wells it is currently drilling
on the Company’s Elm Grove properties in Northwest Louisiana. Matador’s
natural gas production forecasts for the remainder of 2014 include its
best estimates of the timing of these wells being placed on production
and their initial natural gas production rates as a result of the
Company’s ongoing communications and discussions with Chesapeake, but
are subject to change and not within the Company’s control. For these
reasons, Matador also suggests referring to its six-month sequential
results as a more representative view of its ongoing growth and progress
than the applicable quarter-to-quarter comparisons.
Click
here for charts highlighting various aspects of Matador’s growth on a
sequential six-month basis.
Conference Call Information
The Company will host a conference call on Thursday, August 7, 2014, at
9:00 a.m. Central Daylight Time to discuss the second quarter 2014
financial and operational results. To access the conference call,
domestic participants should dial (866) 543-6403 and international
participants should dial (617) 213-8896. The participant passcode is
49110829. The conference call will also be available through the
Company’s website at www.matadorresources.com
on the Presentations & Webcasts page under the Investors tab. Domestic
participants accessing the telephonic replay should dial (888) 286-8010
and international participants should dial (617) 801-6888. The
participant passcode is 79228151. The replay for the event will also be
available on the Company’s website at www.matadorresources.com
through Friday, August 29, 2014.
About 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 Eagle Ford shale play in
South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin
in Southeast New Mexico and West Texas. Matador also operates in the
Haynesville shale and Cotton Valley plays in Northwest Louisiana and
East Texas.
For more information, visit Matador Resources Company at www.matadorresources.com.
Forward-Looking Statements
This press release includes “forward-looking statements” within the
meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended.
“Forward-looking statements” are statements related to future, not past,
events. Forward-looking statements are based on current expectations and
include any statement that does not directly relate to a current or
historical fact. In this context, forward-looking statements often
address expected future business and financial performance, and often
contain words such as “could,” “believe,” “would,” “anticipate,”
“intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,”
“predict,” “potential,” “project” and similar expressions that are
intended to identify forward-looking statements, although not all
forward-looking statements contain such identifying words. Actual
results and future events could differ materially from those anticipated
in such statements, and such forward-looking statements may not prove to
be accurate. These forward-looking statements involve certain risks and
uncertainties, including, but not limited to, the following risks
related to financial and operational performance: general economic
conditions; the Company’s ability to execute its 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; its 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; its ability to make acquisitions on economically acceptable
terms; availability of sufficient capital to execute its business plan,
including from future cash flows, increases in its borrowing base and
otherwise; weather and environmental conditions; and other important
factors which could cause actual results to differ materially from those
anticipated or implied in the forward-looking statements. For further
discussions of risks and uncertainties, you should refer to Matador’s
SEC filings, including the “Risk Factors” section of Matador’s most
recent Annual Report on Form 10-K and any subsequent Quarterly Reports
on Form 10-Q. Matador undertakes no obligation and does not intend to
update these forward-looking statements to reflect events or
circumstances occurring after the date of this press release, except as
required by law, including the securities laws of the United States and
the rules and regulations of the SEC. You are cautioned not to place
undue reliance on these forward-looking statements, which speak only as
of the date of this press release. All forward-looking statements are
qualified in their entirety by this cautionary statement.
|
|
|
|
|
|
|
|
|
|
Matador Resources Company and Subsidiaries
|
|
|
|
CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except par value and share data)
|
|
|
|
June 30,
2014
|
|
|
December 31,
2013
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
Cash
|
|
|
|
$
|
14,635
|
|
|
|
$
|
6,287
|
|
|
Accounts receivable
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues
|
|
|
|
33,493
|
|
|
|
25,823
|
|
|
Joint interest billings
|
|
|
|
9,925
|
|
|
|
4,785
|
|
|
Other
|
|
|
|
1,594
|
|
|
|
1,066
|
|
|
Derivative instruments
|
|
|
|
22
|
|
|
|
19
|
|
|
Deferred income taxes
|
|
|
|
4,294
|
|
|
|
1,636
|
|
|
Lease and well equipment inventory
|
|
|
|
954
|
|
|
|
785
|
|
|
Prepaid expenses
|
|
|
|
2,427
|
|
|
|
1,771
|
|
|
Total current assets
|
|
|
|
67,344
|
|
|
|
42,172
|
|
|
Property and equipment, at cost
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, full-cost method
|
|
|
|
|
|
|
|
|
Evaluated
|
|
|
|
1,278,003
|
|
|
|
1,090,656
|
|
|
Unproved and unevaluated
|
|
|
|
277,949
|
|
|
|
194,306
|
|
|
Other property and equipment
|
|
|
|
32,219
|
|
|
|
29,910
|
|
|
Less accumulated depletion, depreciation and amortization
|
|
|
|
(524,822
|
)
|
|
|
(468,995
|
)
|
|
Net property and equipment
|
|
|
|
1,063,349
|
|
|
|
845,877
|
|
|
Other assets
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
|
|
171
|
|
|
|
173
|
|
|
Other assets
|
|
|
|
2,577
|
|
|
|
2,108
|
|
|
Total other assets
|
|
|
|
2,748
|
|
|
|
2,281
|
|
|
Total assets
|
|
|
|
$
|
1,133,441
|
|
|
|
$
|
890,330
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
|
$
|
18,541
|
|
|
|
$
|
25,358
|
|
|
Accrued liabilities
|
|
|
|
105,129
|
|
|
|
63,987
|
|
|
Royalties payable
|
|
|
|
13,687
|
|
|
|
7,798
|
|
|
Derivative instruments
|
|
|
|
10,264
|
|
|
|
2,692
|
|
|
Income taxes payable
|
|
|
|
3,219
|
|
|
|
404
|
|
|
Other current liabilities
|
|
|
|
88
|
|
|
|
88
|
|
|
Total current liabilities
|
|
|
|
150,928
|
|
|
|
100,327
|
|
|
Long-term liabilities
|
|
|
|
|
|
|
|
|
Borrowings under Credit Agreement
|
|
|
|
150,000
|
|
|
|
200,000
|
|
|
Asset retirement obligations
|
|
|
|
9,723
|
|
|
|
7,309
|
|
|
Derivative instruments
|
|
|
|
1,025
|
|
|
|
253
|
|
|
Deferred income taxes
|
|
|
|
30,942
|
|
|
|
10,929
|
|
|
Other long-term liabilities
|
|
|
|
3,581
|
|
|
|
2,588
|
|
|
Total long-term liabilities
|
|
|
|
195,271
|
|
|
|
221,079
|
|
|
Shareholders’ equity
|
|
|
|
|
|
|
|
|
Common stock - $0.01 par value, 80,000,000 shares authorized;
74,657,951 and 66,958,867 shares issued; and 73,327,906 and
65,652,690 shares outstanding, respectively
|
|
|
|
747
|
|
|
|
670
|
|
|
Additional paid-in capital
|
|
|
|
732,587
|
|
|
|
548,935
|
|
|
Retained earnings
|
|
|
|
64,673
|
|
|
|
30,084
|
|
|
Treasury stock, at cost, 1,330,045 and 1,306,177 shares, respectively
|
|
|
|
(10,765
|
)
|
|
|
(10,765
|
)
|
|
Total shareholders’ equity
|
|
|
|
787,242
|
|
|
|
568,924
|
|
|
Total liabilities and shareholders’ equity
|
|
|
|
$
|
1,133,441
|
|
|
|
$
|
890,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Matador Resources Company and Subsidiaries
|
|
|
|
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per share data)
|
|
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
2014
|
|
2013
|
|
|
2014
|
|
2013
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues
|
|
|
|
$
|
99,054
|
|
|
$
|
58,179
|
|
|
|
$
|
177,986
|
|
|
$
|
117,498
|
|
|
Realized (loss) gain on derivatives
|
|
|
|
(2,913
|
)
|
|
254
|
|
|
|
(4,756
|
)
|
|
646
|
|
|
Unrealized (loss) gain on derivatives
|
|
|
|
(5,234
|
)
|
|
7,526
|
|
|
|
(8,342
|
)
|
|
2,701
|
|
|
Total revenues
|
|
|
|
90,907
|
|
|
65,959
|
|
|
|
164,888
|
|
|
120,845
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes and marketing
|
|
|
|
9,116
|
|
|
4,451
|
|
|
|
15,122
|
|
|
8,548
|
|
|
Lease operating
|
|
|
|
11,704
|
|
|
10,140
|
|
|
|
21,055
|
|
|
21,040
|
|
|
Depletion, depreciation and amortization
|
|
|
|
31,797
|
|
|
20,234
|
|
|
|
55,827
|
|
|
48,466
|
|
|
Accretion of asset retirement obligations
|
|
|
|
123
|
|
|
80
|
|
|
|
241
|
|
|
161
|
|
|
Full-cost ceiling impairment
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
21,229
|
|
|
General and administrative
|
|
|
|
8,100
|
|
|
4,149
|
|
|
|
15,319
|
|
|
8,751
|
|
|
Total expenses
|
|
|
|
60,840
|
|
|
39,054
|
|
|
|
107,564
|
|
|
108,195
|
|
|
Operating income
|
|
|
|
30,067
|
|
|
26,905
|
|
|
|
57,324
|
|
|
12,650
|
|
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss on asset sales and inventory impairment
|
|
|
|
—
|
|
|
(192
|
)
|
|
|
—
|
|
|
(192
|
)
|
|
Interest expense
|
|
|
|
(1,616
|
)
|
|
(1,609
|
)
|
|
|
(3,012
|
)
|
|
(2,880
|
)
|
|
Interest and other income
|
|
|
|
409
|
|
|
47
|
|
|
|
447
|
|
|
115
|
|
|
Total other expense
|
|
|
|
(1,207
|
)
|
|
(1,754
|
)
|
|
|
(2,565
|
)
|
|
(2,957
|
)
|
|
Income before income taxes
|
|
|
|
28,860
|
|
|
25,151
|
|
|
|
54,759
|
|
|
9,693
|
|
|
Income tax provision
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
1,539
|
|
|
32
|
|
|
|
2,814
|
|
|
78
|
|
|
Deferred
|
|
|
|
9,095
|
|
|
—
|
|
|
|
17,356
|
|
|
—
|
|
|
Total income tax provision
|
|
|
|
10,634
|
|
|
32
|
|
|
|
20,170
|
|
|
78
|
|
|
Net income
|
|
|
|
$
|
18,226
|
|
|
$
|
25,119
|
|
|
|
$
|
34,589
|
|
|
$
|
9,615
|
|
|
Earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
$
|
0.27
|
|
|
$
|
0.45
|
|
|
|
$
|
0.52
|
|
|
$
|
0.17
|
|
|
Diluted
|
|
|
|
$
|
0.26
|
|
|
$
|
0.45
|
|
|
|
$
|
0.51
|
|
|
$
|
0.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
68,531
|
|
|
55,839
|
|
|
|
67,108
|
|
|
55,729
|
|
|
Diluted
|
|
|
|
69,220
|
|
|
55,937
|
|
|
|
67,771
|
|
|
55,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Matador Resources Company and Subsidiaries
|
|
|
|
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
2014
|
|
|
2013
|
|
Operating activities
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
$
|
34,589
|
|
|
|
$
|
9,615
|
|
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
Unrealized loss (gain) on derivatives
|
|
|
|
8,342
|
|
|
|
(2,701
|
)
|
|
Depletion, depreciation and amortization
|
|
|
|
55,827
|
|
|
|
48,466
|
|
|
Accretion of asset retirement obligations
|
|
|
|
241
|
|
|
|
161
|
|
|
Full-cost ceiling impairment
|
|
|
|
—
|
|
|
|
21,229
|
|
|
Stock-based compensation expense
|
|
|
|
3,629
|
|
|
|
1,524
|
|
|
Deferred income tax provision
|
|
|
|
17,356
|
|
|
|
—
|
|
|
Net loss on asset sales and inventory impairment
|
|
|
|
—
|
|
|
|
192
|
|
|
Changes in operating assets and liabilities
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
|
(13,338
|
)
|
|
|
1,763
|
|
|
Lease and well equipment inventory
|
|
|
|
(36
|
)
|
|
|
280
|
|
|
Prepaid expenses
|
|
|
|
(656
|
)
|
|
|
(215
|
)
|
|
Other assets
|
|
|
|
(468
|
)
|
|
|
(117
|
)
|
|
Accounts payable, accrued liabilities and other current liabilities
|
|
|
|
(517
|
)
|
|
|
4,615
|
|
|
Royalties payable
|
|
|
|
5,890
|
|
|
|
(206
|
)
|
|
Advances from joint interest owners
|
|
|
|
—
|
|
|
|
(1,515
|
)
|
|
Income taxes payable
|
|
|
|
2,814
|
|
|
|
78
|
|
|
Other long-term liabilities
|
|
|
|
(198
|
)
|
|
|
743
|
|
|
Net cash provided by operating activities
|
|
|
|
113,475
|
|
|
|
83,912
|
|
|
Investing activities
|
|
|
|
|
|
|
|
|
Oil and natural gas properties capital expenditures
|
|
|
|
(234,335
|
)
|
|
|
(173,989
|
)
|
|
Expenditures for other property and equipment
|
|
|
|
(1,884
|
)
|
|
|
(2,081
|
)
|
|
Purchases of certificates of deposit
|
|
|
|
—
|
|
|
|
(61
|
)
|
|
Maturities of certificates of deposit
|
|
|
|
—
|
|
|
|
230
|
|
|
Net cash used in investing activities
|
|
|
|
(236,219
|
)
|
|
|
(175,901
|
)
|
|
Financing activities
|
|
|
|
|
|
|
|
|
Repayments of borrowings under Credit Agreement
|
|
|
|
(180,000
|
)
|
|
|
—
|
|
|
Borrowings under Credit Agreement
|
|
|
|
130,000
|
|
|
|
95,000
|
|
|
Proceeds from issuance of common stock
|
|
|
|
181,875
|
|
|
|
—
|
|
|
Cost to issue equity
|
|
|
|
(504
|
)
|
|
|
—
|
|
|
Proceeds from stock options exercised
|
|
|
|
6
|
|
|
|
—
|
|
|
Taxes paid related to net share settlement of stock-based
compensation
|
|
|
|
(285
|
)
|
|
|
(1
|
)
|
|
Net cash provided by financing activities
|
|
|
|
131,092
|
|
|
|
94,999
|
|
|
Increase in cash
|
|
|
|
8,348
|
|
|
|
3,010
|
|
|
Cash at beginning of period
|
|
|
|
6,287
|
|
|
|
2,095
|
|
|
Cash at end of period
|
|
|
|
$
|
14,635
|
|
|
|
$
|
5,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Matador Resources Company and Subsidiaries
|
|
|
|
SELECTED OPERATING DATA - UNAUDITED
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
|
|
Six Months Ended
June 30,
|
|
|
|
|
2014
|
|
|
2013
|
|
|
|
2014
|
|
|
2013
|
|
Net Production Volumes:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)(2) |
|
|
|
802
|
|
|
447
|
|
|
|
1,463
|
|
|
908
|
|
Natural gas (Bcf)(3) |
|
|
|
3.6
|
|
|
3.1
|
|
|
|
6.1
|
|
|
6.2
|
|
Total oil equivalent (MBOE)(4) |
|
|
|
1,403
|
|
|
963
|
|
|
|
2,475
|
|
|
1,944
|
|
Average daily production (BOE/d)(5) |
|
|
|
15,424
|
|
|
10,582
|
|
|
|
13,673
|
|
|
10,739
|
|
Average Sales Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, with realized derivatives (per Bbl)
|
|
|
|
$
|
94.47
|
|
|
$
|
99.26
|
|
|
|
$
|
94.67
|
|
|
$
|
102.27
|
|
Oil, without realized derivatives (per Bbl)
|
|
|
|
$
|
97.92
|
|
|
$
|
99.77
|
|
|
|
$
|
97.20
|
|
|
$
|
102.78
|
|
Natural gas, with realized derivatives (per Mcf)
|
|
|
|
$
|
5.65
|
|
|
$
|
4.53
|
|
|
|
$
|
5.72
|
|
|
$
|
4.07
|
|
Natural gas, without realized derivatives (per Mcf)
|
|
|
|
$
|
5.69
|
|
|
$
|
4.38
|
|
|
|
$
|
5.90
|
|
|
$
|
3.89
|
|
Operating Expenses (per BOE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes and marketing
|
|
|
|
$
|
6.50
|
|
|
$
|
4.62
|
|
|
|
$
|
6.11
|
|
|
$
|
4.40
|
|
Lease operating
|
|
|
|
$
|
8.34
|
|
|
$
|
10.53
|
|
|
|
$
|
8.51
|
|
|
$
|
10.82
|
|
Depletion, depreciation and amortization
|
|
|
|
$
|
22.66
|
|
|
$
|
21.01
|
|
|
|
$
|
22.56
|
|
|
$
|
24.93
|
|
General and administrative
|
|
|
|
$
|
5.77
|
|
|
$
|
4.31
|
|
|
|
$
|
6.19
|
|
|
$
|
4.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Production volumes and proved reserves reported in two streams:
oil and natural gas, including both dry and liquids-rich natural
gas.
|
|
(2)
|
|
One thousand barrels of oil equivalent.
|
|
(3)
|
|
One billion cubic feet of natural gas.
|
|
(4)
|
|
One thousand barrels 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED ESTIMATED PROVED RESERVES DATA - UNAUDITED
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2014
|
|
|
December 31,
2013
|
|
|
June 30,
2013
|
|
Estimated proved reserves:(1)(2) |
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)(3) |
|
|
|
18,627
|
|
|
|
16,362
|
|
|
|
12,128
|
|
|
Natural Gas (Bcf)(4) |
|
|
|
231.4
|
|
|
|
212.2
|
|
|
|
160.8
|
|
|
Total (MBOE)(5) |
|
|
|
57,202
|
|
|
|
51,729
|
|
|
|
38,931
|
|
|
Estimated proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)(3) |
|
|
|
9,917
|
|
|
|
8,258
|
|
|
|
6,591
|
|
|
Natural Gas (Bcf)(4) |
|
|
|
60.0
|
|
|
|
53.5
|
|
|
|
57.8
|
|
|
Total (MBOE)(5) |
|
|
|
19,917
|
|
|
|
17,168
|
|
|
|
16,221
|
|
|
Percent developed
|
|
|
|
34.8
|
%
|
|
|
33.2
|
%
|
|
|
41.7
|
%
|
|
Estimated proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)(3) |
|
|
|
8,711
|
|
|
|
8,104
|
|
|
|
5,537
|
|
|
Natural Gas (Bcf)(4) |
|
|
|
171.4
|
|
|
|
158.7
|
|
|
|
103.0
|
|
|
Total (MBOE)(5) |
|
|
|
37,285
|
|
|
|
34,561
|
|
|
|
22,710
|
|
|
PV-10 (in millions)
|
|
|
|
$
|
826.0
|
|
|
|
$
|
655.2
|
|
|
|
$
|
522.3
|
|
|
Standardized Measure (in millions)
|
|
|
|
$
|
723.0
|
|
|
|
$
|
578.7
|
|
|
|
$
|
477.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Numbers in table may not total due to rounding.
|
|
(2)
|
|
Production volumes and proved reserves reported in two streams:
oil and natural gas, including both dry and liquids-rich natural
gas.
|
|
(3)
|
|
One thousand barrels of oil.
|
|
(4)
|
|
One billion cubic feet of natural gas.
|
|
(5)
|
|
One thousand barrels of oil equivalent, estimated using a
conversation ratio of one Bbl of oil per six Mcf of natural gas.
|
|
|
|
|
Supplemental Non-GAAP Financial Measures
Adjusted EBITDA
This press release 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 industry 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 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 inventory
impairment. Adjusted EBITDA is not a measure of net income (loss) or net
cash provided by operating activities as determined by GAAP.
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 forward-looking 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 the forward-looking Adjusted EBITDA
numbers included in this press release 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Three Months Ended
March 31,
|
|
Six Months Ended
June 30,
|
|
Six Months Ended
December 31,
|
|
(In thousands)
|
|
|
|
2014
|
|
2013
|
|
2014
|
|
2014
|
|
2013
|
|
2013
|
|
Unaudited Adjusted EBITDA Reconciliation to Net Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
$
|
18,226
|
|
$
|
25,119
|
|
|
$
|
16,363
|
|
$
|
34,589
|
|
$
|
9,615
|
|
|
$
|
35,479
|
|
Interest expense
|
|
|
|
1,616
|
|
1,609
|
|
|
1,396
|
|
3,012
|
|
2,880
|
|
|
2,806
|
|
Total income tax provision
|
|
|
|
10,634
|
|
32
|
|
|
9,536
|
|
20,170
|
|
78
|
|
|
9,619
|
|
Depletion, depreciation and amortization
|
|
|
|
31,797
|
|
20,234
|
|
|
24,030
|
|
55,827
|
|
48,466
|
|
|
49,929
|
|
Accretion of asset retirement obligations
|
|
|
|
123
|
|
80
|
|
|
117
|
|
241
|
|
161
|
|
|
186
|
|
Full-cost ceiling impairment
|
|
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
21,229
|
|
|
—
|
|
Unrealized loss (gain) on derivatives
|
|
|
|
5,234
|
|
(7,526
|
)
|
|
3,108
|
|
8,342
|
|
(2,701
|
)
|
|
9,933
|
|
Stock-based compensation expense
|
|
|
|
1,834
|
|
1,032
|
|
|
1,795
|
|
3,629
|
|
1,524
|
|
|
2,373
|
|
Net loss on asset sales and inventory impairment
|
|
|
|
—
|
|
192
|
|
|
—
|
|
—
|
|
192
|
|
|
—
|
|
Adjusted EBITDA
|
|
|
|
$
|
69,464
|
|
$
|
40,772
|
|
|
$
|
56,345
|
|
$
|
125,810
|
|
$
|
81,444
|
|
|
$
|
110,325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Three Months Ended
March 31,
|
|
Six Months Ended
June 30,
|
|
Six Months Ended
December 31,
|
|
(In thousands)
|
|
|
|
2014
|
|
2013
|
|
2014
|
|
2014
|
|
2013
|
|
2013
|
|
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
|
$
|
81,530
|
|
|
$
|
51,684
|
|
|
$
|
31,945
|
|
$
|
113,475
|
|
$
|
83,912
|
|
|
$
|
95,558
|
|
Net change in operating assets and liabilities
|
|
|
|
(15,221
|
)
|
|
(12,553
|
)
|
|
21,729
|
|
6,509
|
|
(5,426
|
)
|
|
11,635
|
|
Interest expense
|
|
|
|
1,616
|
|
|
1,609
|
|
|
1,396
|
|
3,012
|
|
2,880
|
|
|
2,806
|
|
Current income tax provision
|
|
|
|
1,539
|
|
|
32
|
|
|
1,275
|
|
2,814
|
|
78
|
|
|
326
|
|
Adjusted EBITDA
|
|
|
|
$
|
69,464
|
|
|
$
|
40,772
|
|
|
$
|
56,345
|
|
$
|
125,810
|
|
$
|
81,444
|
|
|
$
|
110,325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10
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 the Company’s properties. Matador 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. PV-10 may be reconciled to the
Standardized Measure of discounted future net cash flows at such dates
by reducing PV-10 by the discounted future income taxes associated with
such reserves.
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
At June 30,
2014
|
|
At December 31,
2013
|
|
At June 30,
2013
|
|
PV-10
|
|
|
|
$
|
826.0
|
|
|
$
|
655.2
|
|
|
$
|
522.3
|
|
|
Discounted future income taxes
|
|
|
|
(103.0
|
)
|
|
(76.5
|
)
|
|
(44.7
|
)
|
|
Standardized Measure
|
|
|
|
$
|
723.0
|
|
|
$
|
578.7
|
|
|
$
|
477.6
|
|
Photos/Multimedia Gallery Available: http://www.businesswire.com/multimedia/home/20140806006352/en/
Source: Matador Resources Company
Matador Resources Company
Mac Schmitz, 972-371-5225
mschmitz@matadorresources.com
