Matador Resources Company Reports Second Quarter 2014 Results and Provides Operational Update

DALLAS--()--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:

  • 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:

  • 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.
    • 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

  • 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.
  • 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  

Contacts

Matador Resources Company
Mac Schmitz, 972-371-5225
mschmitz@matadorresources.com

Charts highlighting various aspects of Matador's growth on a sequential six-month basis. (Graphic: Business Wire)

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Release Summary

Matador Resources Company (NYSE: MTDR) today reported financial and operating results for the three and six months ended June 30, 2014.

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Contacts

Matador Resources Company
Mac Schmitz, 972-371-5225
mschmitz@matadorresources.com