Exhibit 99.1
MATADOR RESOURCES COMPANY REPORTS FOURTH QUARTER AND
FULL YEAR 2015 RESULTS AND PROVIDES OPERATIONAL UPDATE
DALLAS, Texas, February 24, 2016 -- 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, with an emphasis on oil and natural gas shale and other unconventional plays and with a current focus on its Delaware Basin operations in Southeast New Mexico and West Texas, today reported financial and operating results for the three months and year ended December 31, 2015.
Matador was particularly pleased with its 2015 operating and financial results despite the challenging commodity price environment, especially considering the reduction in its drilling program from five rigs to two rigs during the first quarter of 2015, returning to three rigs during the third quarter and for the balance of the year. Matador’s 2015 production was at the upper end of its 2015 guidance range as raised twice during the year, despite the impact of winter storms in the Delaware Basin at year end and the deferral by the operator of initial natural gas production from nine gross (1.9 net) non-operated Haynesville shale wells from the fourth quarter of 2015 to January 2016. As noted in previous earnings releases, because the third drilling rig was not added until the third quarter of 2015, most of the initial production impact from this rig begins in 2016.
Year-over-year twelve-month-period comparisons of selected financial and operating items are shown in the following table:

|  | Year Ended
|  | December 31, |  | December 31, |  | December 31,
|  | 2015 |  | 2014 |  | 2013
Oil production (MBbl) |  | 4,492 |  |  | 3,320 |  |  | 2,133 |
Natural gas production (Bcf) |  | 27.7 |  |  | 15.3 |  |  | 12.9 |
Average daily oil equivalent production (BOE/d) |  | 24,955 |  |  | 16,082 |  |  | 11,740 |
Average daily oil production (Bbl/d) |  | 12,306 |  |  | 9,095 |  |  | 5,843 |
Average daily natural gas production (MMcf/d) |  | 75.9 |  |  | 41.9 |  |  | 35.4 |
Oil and natural gas revenues (in millions) |  | $ | 278.3 |  |  | $ | 367.7 |  |  | $ | 269.0 |
Average realized oil price, $/Bbl |  | $ | 45.27 |  |  | $ | 87.37 |  |  | $ | 99.79 |
Average realized natural gas price, $/Mcf |  | $ | 2.71 |  |  | $ | 5.08 |  |  | $ | 4.35 |
Adjusted EBITDA(1) (in millions) |  | $ | 223.2 |  |  | $ | 262.9 |  |  | $ | 191.8 |
(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, please see “Supplemental Non-GAAP Financial Measures” below.

Summary of key operating results and comparisons for the year ended December 31, 2015:

• | Record oil production of 4.492 million barrels in 2015, a 35% year-over-year increase from 3.320 million barrels produced in 2014, and an increase of 111% from 2.133 million barrels produced in 2013.

• | Record natural gas production of 27.7 billion cubic feet in 2015, an 81% year-over-year increase from 15.3 billion cubic feet produced in 2014, and an increase of 114% from 12.9 billion cubic feet produced in 2013.

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• | Record average daily oil equivalent production of 24,955 barrels of oil equivalent (“BOE”) per day for the year ended December 31, 2015 (consisting of 12,306 barrels of oil per day and 75.9 million cubic feet of natural gas per day), a 55% year-over-year BOE increase from 16,082 BOE per day (consisting of 9,095 barrels of oil per day and 41.9 million cubic feet of natural gas per day) produced in 2014, and an increase of 113% from 11,740 BOE per day (consisting of 5,843 barrels of oil per day and 35.4 million cubic feet of natural gas per day) produced in 2013.

• | A 24% year-over-year decrease in oil and natural gas revenues from $367.7 million reported for the year ended December 31, 2014 to $278.3 million for the year ended December 31, 2015, and a 3% increase from $269.0 million reported for the year ended December 31, 2013. The weighted average oil and natural gas prices of $45.27 per barrel and $2.71 per thousand cubic feet, respectively, realized for the year ended December 31, 2015 were significantly lower than the weighted average oil and natural gas prices of $87.37 per barrel and $5.08 per thousand cubic feet, respectively, realized in 2014 and $99.79 per barrel and $4.35 per thousand cubic feet, respectively, realized in 2013, as shown in the table above.

• | A 15% year-over-year decrease in Adjusted EBITDA, a non-GAAP financial measure, from $262.9 million reported for the year ended December 31, 2014 to $223.2 million for the year ended December 31, 2015, and a 16% increase from $191.8 million reported for the year ended December 31, 2013. The Adjusted EBITDA of $223.2 million reported for 2015 was the second best Adjusted EBITDA result in Matador’s history, surpassed only by the record Adjusted EBITDA of $262.9 million reported for 2014.

• | Cash operating expenses per BOE, a non-GAAP financial measure, decreased 24%, or $4.47 per BOE, to $14.47 per BOE for the year ended December 31, 2015 from $18.94 per BOE for the year ended December 31, 2014, and decreased 19%, or $3.40 per BOE, from $17.87 per BOE for the year ended December 31, 2013.

Sequential and year-over-year quarterly comparisons of selected financial and operating items are shown in the following table:

|  | Three Months Ended
|  | December 31, |  | September 30, |  | December 31,
|  | 2015 |  | 2015 |  | 2014
Oil production (MBbl) |  | 1,062 |  |  | 1,161 |  |  | 1,018 |
Natural gas production (Bcf) |  | 6.6 |  |  | 7.5 |  |  | 5.4 |
Average daily oil equivalent production (BOE/d) |  | 23,556 |  |  | 26,137 |  |  | 20,807 |
Average daily oil production (Bbl/d) |  | 11,547 |  |  | 12,617 |  |  | 11,062 |
Average daily natural gas production (MMcf/d) |  | 72.1 |  |  | 81.1 |  |  | 58.5 |
Oil and natural gas revenues (in millions) |  | $ | 56.2 |  |  | $ | 71.8 |  |  | $ | 93.1 |
Average realized oil price, $/Bbl |  | $ | 38.55 |  |  | $ | 43.21 |  |  | $ | 69.09 |
Average realized natural gas price, $/Mcf |  | $ | 2.30 |  |  | $ | 2.90 |  |  | $ | 4.24 |
Adjusted EBITDA(1) (in millions) |  | $ | 48.3 |  |  | $ | 58.0 |  |  | $ | 70.3 |
(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, please see “Supplemental Non-GAAP Financial Measures” below.

Summary of key operating results and comparisons for the three months ended December 31, 2015:
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• | Oil production of 1.062 million barrels for the three months ended December 31, 2015, a 4% year-over-year increase from 1.018 million barrels produced in the three months ended December 31, 2014, and a sequential decrease of 9% from 1.161 million barrels produced in the three months ended September 30, 2015, due to the impact of winter storms and rig reductions.

• | Natural gas production of 6.6 billion cubic feet for the three months ended December 31, 2015, a 23% year-over-year increase from 5.4 billion cubic feet produced in the three months ended December 31, 2014, and a sequential decrease of 11% from 7.5 billion cubic feet produced in the three months ended September 30, 2015, due to the deferral by the operator of initial natural gas production from several non-operated Haynesville shale wells from the fourth quarter of 2015 to January 2016.

• | Average daily oil equivalent production of 23,556 BOE per day for the three months ended December 31, 2015 (consisting of 11,547 barrels of oil per day and 72.1 million cubic feet of natural gas per day), a 13% year-over-year BOE increase from 20,807 BOE per day (consisting of 11,062 barrels of oil per day and 58.5 million cubic feet of natural gas per day) for the three months ended December 31, 2014, and a sequential decrease of 10% from 26,137 BOE per day (consisting of 12,617 barrels of oil per day and 81.1 million cubic feet of natural gas per day) for the three months ended September 30, 2015.

• | A 40% year-over-year decrease in oil and natural gas revenues from $93.1 million reported for the fourth quarter of 2014 to $56.2 million for the fourth quarter of 2015, and a sequential decrease of 22% from $71.8 million reported in the third quarter of 2015. The weighted average oil and natural gas prices of $38.55 per barrel and $2.30 per thousand cubic feet, respectively, realized in the fourth quarter of 2015 were significantly lower than the weighted average oil and natural gas prices of $69.09 per barrel and $4.24 per thousand cubic feet, respectively, realized in the fourth quarter of 2014 and $43.21 per barrel and $2.90 per thousand cubic feet, respectively, realized in the third quarter of 2015, as shown in the table above.

• | A 31% year-over-year decrease in Adjusted EBITDA, a non-GAAP financial measure, from $70.3 million reported for the fourth quarter of 2014 to $48.3 million reported for the fourth quarter of 2015, and a sequential decrease of 17% from $58.0 million reported in the third quarter of 2015.

• | Cash operating expenses per BOE, a non-GAAP financial measure, decreased 13%, or $2.39 per BOE, to $15.33 per BOE for the three months ended December 31, 2015, as compared to $17.72 per BOE for the three months ended December 31, 2014. Sequentially, cash operating expenses per BOE increased 7%, or $0.95 per BOE, as compared to $14.38 per BOE for the three months ended September 30, 2015.

Additional Highlights:

• | Total proved oil and natural gas reserves of 85.1 million BOE (consisting of 45.6 million barrels of oil and 236.9 billion cubic feet of natural gas) at December 31, 2015, a 24% year-over-year BOE increase from 68.7 million BOE (consisting of 24.2 million barrels of oil and 267.1 billion cubic feet of natural gas) at December 31, 2014, and an 89% year-over-year increase in Matador’s proved oil reserves at December 31, 2015 as compared to December 31, 2014. The PV-10 of the Company’s total proved reserves, a non-GAAP financial measure, decreased 48% year-over-year to $541.6 million at December 31, 2015, as compared to $1.04 billion at December 31, 2014, as a result of lower commodity prices used to estimate proved reserves at year-end 2015 as compared to year-end 2014. The average oil and natural gas prices used in preparing these estimates, as further adjusted for those factors affecting the oil and natural gas prices received at the wellhead, were $46.79 per barrel and $2.59 per million British Thermal Units (“MMBtu”), respectively, at December 31, 2015, as compared to $91.48 per barrel and $4.35 per MMBtu, respectively, at December 31, 2014.

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• | Matador reaffirmed its full year 2016 guidance estimates, based on a three-rig drilling program, as provided at its Analyst Day on February 3, 2016, including (1) capital expenditures of $325 million, (2) oil production of 4.9 to 5.1 million barrels, (3) natural gas production of 26.0 to 28.0 billion cubic feet, (4) total oil equivalent production of 9.2 to 9.8 million BOE and (5) Adjusted EBITDA of $120 to $130 million based on estimated average realized prices of $34.00 per barrel for oil (West Texas Intermediate average oil price of $37.00 per barrel, less $3.00 per barrel of estimated price differentials, using the forward strip for oil prices as of late January 2016) and $2.37 per thousand cubic feet for natural gas (NYMEX Henry Hub average natural gas price using the forward strip for natural gas prices as of late January 2016 and assuming regional price differentials and uplifts from natural gas processing roughly offset).

A short slide presentation summarizing the highlights of Matador’s fourth quarter and full year 2015 earnings release is also included on the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab.
Management Comments
Joseph Wm. Foran, Matador’s Chairman and CEO, commented, “Despite a challenging commodity price environment, 2015 was another excellent year for Matador—one of the best in my 32 years in the business. As noted above, Matador reported record oil production of 4.5 million barrels, record natural gas production of 27.7 billion cubic feet and record total oil equivalent production of 9.1 million BOE in 2015, all of which were at or near the top of our 2015 production guidance as revised upwards on two occasions during 2015. Our proved oil and natural gas reserves also increased by 24% year-over-year to 85.1 million BOE at December 31, 2015, including an increase of 89% in our proved oil reserves to 45.6 million barrels.
“The Board, the staff and I were very pleased with our 2015 operating and financial results given the operating climate and especially considering the reduction in our drilling program from five rigs to two rigs during the first quarter of 2015, returning to three rigs during the third quarter for the balance of the year. Because this third drilling rig was not added until the third quarter, we did not expect to realize a significant contribution to production from wells drilled with this rig in 2015; rather, the production contribution associated with the initial wells drilled with the third rig should be realized in 2016.
“We also concluded several transformative transactions in 2015, including our merger with Harvey E. Yates Company (“HEYCO”) which added significantly to our Delaware Basin acreage position, our first issuance of senior unsecured notes, a follow-on equity offering and the sale of a portion of our midstream assets in Loving County, Texas to an affiliate of EnLink Midstream Partners, LP (“EnLink”). These transactions increased our operational flexibility and further enhanced our already strong balance sheet. Notably, our debt metrics continue to be among the very best in the industry for small- and mid-cap oil and natural gas companies.
“As a result of these transactions and the continued success of our Delaware Basin operations in 2015, our balance sheet and overall financial position entering 2016, as well as our properties and drilling opportunities, are perhaps the best in Matador’s history. That said, 2016 will likely be an even more challenging operating and commodity price environment than we have faced in many years. We must and we will focus in 2016 on execution and those things we can control in our operations, while remaining flexible and open to the special opportunities that may come our way in these times. The Board and I have challenged the staff to continue to deliver ‘better wells for less money,’ and we are confident we will work together to meet this challenge and to add value as we have done so many times before, especially through continued technical innovation and project management.
“As we reported during our recent Analyst Day presentation in Dallas on February 3, 2016, we are operating three state-of-the-art drilling rigs in the Delaware Basin today, and almost all of our 2016 anticipated capital investments
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are directed toward our operations in the Delaware Basin. We plan to run three rigs in the Delaware Basin throughout 2016. Running the third rig should positively impact our production and proved reserves as well as improve our ability to validate and hold acreage, including our ability to hold additional future well locations with the potential for millions of oil equivalent barrels in place. Nevertheless, should oil prices drop and remain below $30.00 per barrel, we have the flexibility to reduce our drilling program to two rigs, either for a short time or for the remainder of 2016. From a financial perspective, we began 2016 with approximately $61 million in cash and $375 million in undrawn borrowing capacity under our revolving credit facility, which provides us with more than sufficient liquidity to fund our 2016 capital program. As we work through 2016 to preserve our liquidity position and manage our debt profile, however, we will also consider the sale of certain assets, particularly in the midstream area of our business, to cover some or all of the anticipated outspend in our 2016 capital plan.
“The Matador Board, staff and I are proud of our accomplishments in 2015 and believe we start 2016 in a very strong position to address the challenges and opportunities that lie ahead. We realize that it will not be easy, but we are confident in the ability of the Matador team to improve our operating results throughout the year and to continue to deliver value for our shareholders.”
Fourth Quarter and Full Year 2015 Operating and Financial Results
The table below provides selected sequential and year-over-year operating data and unit cost comparisons for the periods shown.

|  | Three Months Ended |  | Year Ended December 31, |
| December 31, 2015 |  | September 30, 2015 |  | December 31, 2014 |  | 2015 |  | 2014 |  | 2013 |
Net Production Volumes:(1) |  |  |  |  |  |  |  |  |  |  |  |  |
Oil (MBbl)(2) |  | 1,062 |  |  | 1,161 |  |  | 1,018 |  |  | 4,492 |  |  | 3,320 |  |  | 2,133 |  |
Natural gas (Bcf)(3) |  | 6.6 |  |  | 7.5 |  |  | 5.4 |  |  | 27.7 |  |  | 15.3 |  |  | 12.9 |  |
Total oil equivalent (MBOE)(4) |  | 2,167 |  |  | 2,405 |  |  | 1,914 |  |  | 9,109 |  |  | 5,870 |  |  | 4,285 |  |
Average daily production (BOE/d)(5) |  | 23,556 |  |  | 26,137 |  |  | 20,807 |  |  | 24,955 |  |  | 16,082 |  |  | 11,740 |  |
Average Sales Prices: |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, with realized derivatives (per Bbl) |  | $ | 57.61 |  |  | $ | 57.90 |  |  | $ | 78.67 |  |  | $ | 59.13 |  |  | $ | 88.94 |  |  | $ | 98.67 |  |
Oil, without realized derivatives (per Bbl) |  | $ | 38.55 |  |  | $ | 43.21 |  |  | $ | 69.09 |  |  | $ | 45.27 |  |  | $ | 87.37 |  |  | $ | 99.79 |  |
Natural gas, with realized derivatives (per Mcf) |  | $ | 3.01 |  |  | $ | 3.28 |  |  | $ | 4.37 |  |  | $ | 3.24 |  |  | $ | 5.06 |  |  | $ | 4.47 |  |
Natural gas, without realized derivatives (per Mcf) |  | $ | 2.30 |  |  | $ | 2.90 |  |  | $ | 4.24 |  |  | $ | 2.71 |  |  | $ | 5.08 |  |  | $ | 4.35 |  |
Operating Expenses (per BOE): |  |  |  |  |  |  |  |  |  |  |  |  |
Production taxes and marketing |  | $ | 4.12 |  |  | $ | 3.86 |  |  | $ | 4.93 |  |  | $ | 3.90 |  |  | $ | 5.65 |  |  | $ | 4.89 |  |
Lease operating |  | $ | 7.05 |  |  | $ | 6.20 |  |  | $ | 8.68 |  |  | $ | 6.39 |  |  | $ | 8.75 |  |  | $ | 9.04 |  |
Depletion, depreciation and amortization |  | $ | 16.32 |  |  | $ | 18.81 |  |  | $ | 22.86 |  |  | $ | 19.63 |  |  | $ | 22.95 |  |  | $ | 22.96 |  |
General and administrative(6) |  | $ | 5.34 |  |  | $ | 5.05 |  |  | $ | 4.56 |  |  | $ | 5.50 |  |  | $ | 5.48 |  |  | $ | 4.85 |  |
Total(7) |  | $ | 32.83 |  |  | $ | 33.92 |  |  | $ | 41.03 |  |  | $ | 35.42 |  |  | $ | 42.83 |  |  | $ | 41.74 |  |
Cash operating expenses(8) |  | $ | 15.33 |  |  | $ | 14.38 |  |  | $ | 17.72 |  |  | $ | 14.47 |  |  | $ | 18.94 |  |  | $ | 17.87 |  |
(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. |
(3) One billion cubic feet of natural gas. |
(4) One thousand barrels of oil equivalent, estimated using a conversion ratio of one barrel of oil per six thousand cubic feet of natural gas. |
(5) Barrels of oil equivalent per day, estimated using a conversion ratio of one barrel of oil per six thousand cubic feet of natural gas. |
(6) Includes approximately $1.18, $0.73 and $0.45 per BOE of non-cash, stock-based compensation expenses in the fourth quarter of 2015, the third quarter of 2015 and the fourth quarter of 2014, respectively, and $1.04, $0.94 and $0.91 per BOE of non-cash, stock-based compensation for the years ended December 31, 2015, 2014 and 2013, respectively. |
(7) Total does not include the impact of full-cost ceiling impairment charges or immaterial accretion expenses. |
(8) Cash operating expenses per BOE is a non-GAAP financial measure. For a definition of cash operating expenses per BOE and a reconciliation of cash operating expenses per BOE (non-GAAP) to operating expenses per BOE (GAAP), please see “Supplemental Non-GAAP Financial Measures.” |

Production and Revenues
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Total oil production and average daily oil production for the year ended December 31, 2015 were the best in Matador’s history. Average daily oil production increased 35% from 9,095 barrels of oil per day during the year ended December 31, 2014 to 12,306 barrels of oil per day for the year ended December 31, 2015. This increase in oil production was primarily the result of Matador’s ongoing delineation and development operations in the Delaware Basin.
Total natural gas production and average daily natural gas production for the year ended December 31, 2015 were also the best in Matador’s history. Average daily natural gas production increased 81% from 41.9 million cubic feet per day for the year ended December 31, 2014 to 75.9 million cubic feet per day for the year ended December 31, 2015. This increase in natural gas production was primarily attributable to new, non-operated Haynesville shale wells completed and placed on production on Matador’s Elm Grove properties in Northwest Louisiana in late 2014 and throughout 2015, as well as the increased natural gas production associated with its Delaware Basin operations.
Average daily oil equivalent production was also at record levels, increasing 55% from 16,082 BOE per day for the year ended December 31, 2014 to 24,955 BOE per day for the year ended December 31, 2015. Oil production comprised 49% of total production (using a conversion ratio of one barrel of oil per six thousand cubic feet of natural gas) for the year ended December 31, 2015, as compared to 57% for the year ended December 31, 2014.
Oil and natural gas revenues decreased 24% from $367.7 million for the year ended December 31, 2014 to $278.3 million for the year ended December 31, 2015. Oil revenues decreased 30% from $290.0 million for the year ended December 31, 2014 to $203.4 million for the year ended December 31, 2015. Natural gas revenues decreased 3% from $77.7 million for the year ended December 31, 2014 to $75.0 million for the year ended December 31, 2015. Despite a 35% increase in oil production during 2015 as compared to 2014, oil revenues declined by 30% due to a significantly lower weighted average oil price of $45.27 per barrel realized in 2015, as compared to $87.37 per barrel realized in 2014. The 3% decrease in natural gas revenues in 2015 as compared to 2014 was attributable to a significantly lower weighted average natural gas price of $2.71 per thousand cubic feet realized in 2015, as compared to $5.08 per thousand cubic feet realized in 2014, which was offset by the 81% year-over-year increase in natural gas production.
Total oil production increased 4% from 1.018 million barrels of oil, or 11,062 barrels of oil per day, during the fourth quarter of 2014 to 1.062 million barrels of oil, or 11,547 barrels of oil per day, during the fourth quarter of 2015. This increase in oil production was primarily the result of Matador’s ongoing delineation and development operations in the Delaware Basin. Total natural gas production increased 23% from 5.4 billion cubic feet of natural gas during the fourth quarter of 2014 to 6.6 billion cubic feet of natural gas produced during the fourth quarter of 2015. This increase in natural gas production was primarily attributable to new, non-operated Haynesville shale wells completed and placed on production on Matador’s Elm Grove properties in Northwest Louisiana in late 2014 and throughout 2015, as well as the increased natural gas production associated with its Delaware Basin operations. Average daily oil equivalent production increased 13% from 20,807 BOE per day (53% oil by volume) in the fourth quarter of 2014 to 23,556 BOE per day (49% oil by volume) during the fourth quarter of 2015.
Oil and natural gas revenues decreased 40% from $93.1 million in the fourth quarter of 2014 to $56.2 million in the fourth quarter of 2015. Oil revenues decreased 42% from $70.3 million during the fourth quarter of 2014 to $40.9 million during the fourth quarter of 2015. Natural gas revenues decreased 33% from $22.8 million during the fourth quarter of 2014 to $15.3 million during the fourth quarter of 2015. Weighted average realized oil prices declined 44% from $69.09 per barrel realized in the fourth quarter of 2014 to $38.55 per barrel realized in the fourth quarter of 2015. Weighted average realized natural gas prices declined 46% from $4.24 per thousand cubic feet realized during the fourth quarter of 2014 to $2.30 per thousand cubic feet realized during the fourth quarter of 2015.
Adjusted EBITDA
Adjusted EBITDA, a non-GAAP financial measure, decreased 15% from $262.9 million for the year ended December 31, 2014 to $223.2 million for the year ended December 31, 2015. This decrease was primarily
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attributable to the sharp decline in commodity prices during the year ended December 31, 2015 (weighted average realized oil and natural gas prices of $45.27 per barrel and $2.71 per thousand cubic feet, respectively), as compared to the year ended December 31, 2014 (weighted average realized oil and natural gas prices of $87.37 per barrel and $5.08 per thousand cubic feet, respectively), as discussed in the previous section. These sharp commodity price declines were partially mitigated by the 55% increase in Matador’s total oil equivalent production and an increase of $72.1 million in realized gain on derivatives between the respective periods, as well as a 24% decrease in the Company’s cash operating expenses per BOE, a non-GAAP financial measure, from $18.94 per BOE for the year ended December 31, 2014 to $14.47 for the year ended December 31, 2015. The Adjusted EBITDA of $223.2 million reported for 2015 was the second best Adjusted EBITDA result in Matador’s history, surpassed only by the record Adjusted EBITDA of $262.9 million reported for 2014.
Adjusted EBITDA, a non-GAAP financial measure, decreased 31% from $70.3 million during the fourth quarter of 2014 to $48.3 million in the fourth quarter of 2015. This decrease in Adjusted EBITDA was primarily attributable to the sharp decline in commodity prices during the fourth quarter of 2015 (weighted average realized oil and natural gas prices of $38.55 per barrel and $2.30 per thousand cubic feet, respectively), as compared to the fourth quarter of 2014 (weighted average realized oil and natural gas prices of $69.09 per barrel and $4.24 per thousand cubic feet, respectively), as discussed in the previous section. These sharp commodity price declines were partially mitigated by the 13% increase in Matador’s total oil equivalent production and an increase of $14.5 million in realized gain on derivatives between the respective periods, as well as a 13% decrease in the Company’s cash operating expenses per BOE, a non-GAAP financial measure, from $17.72 per BOE during the fourth quarter of 2014 to $15.33 per BOE during the fourth quarter of 2015.
For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA (non-GAAP) to net income (GAAP) and net cash provided by operating activities (GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
For a definition of Cash Operating Expenses per BOE and a reconciliation of Cash Operating Expenses per BOE (non-GAAP) to Operating Expenses per BOE (GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
Net Income (Loss) and Earnings (Loss) Per Share
For the full year ended December 31, 2015, Matador reported adjusted net income of approximately $9.8 million and adjusted earnings of $0.12 per diluted common share, each as adjusted on a non-GAAP basis to exclude a non-cash, unrealized loss on derivatives of $39.3 million, a non-cash, full-cost ceiling impairment of $801.2 million, exclusive of tax effect, non-recurring costs associated with the HEYCO merger of $2.5 million and the impact of the gain on asset sales, primarily the EnLink transaction.
For the year ended December 31, 2015, Matador reported a net loss of approximately $679.8 million and a loss of $8.34 per diluted common share on a GAAP basis, as compared to a net income of approximately $110.8 million and earnings of $1.56 per diluted common share for the year ended December 31, 2014.
Matador’s net loss per diluted common share (GAAP basis) for the year ended December 31, 2015 was unfavorably impacted by (1) lower realized commodity prices, (2) a non-cash, unrealized loss on derivatives of $39.3 million and (3) a non-cash, full-cost ceiling impairment of $801.2 million, exclusive of tax effect. Matador’s net loss per diluted common share for the year ended December 31, 2015 was favorably impacted and mitigated by (1) significantly higher oil and natural gas production, (2) a realized gain on derivatives of $77.1 million and (3) improvements in operating expenses on a unit-of-production basis.
For the fourth quarter of 2015, Matador reported adjusted net income of approximately $2.4 million and adjusted earnings of $0.03 per diluted common share, each as adjusted on a non-GAAP basis to exclude a non-cash, unrealized loss on derivatives of $13.9 million, a non-cash, full-cost ceiling impairment of $219.3 million, exclusive of tax effect, and the impact of the EnLink transaction.
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For the fourth quarter of 2015, Matador reported a net loss of approximately $230.4 million and a loss of $2.72 per diluted common share on a GAAP basis, as compared to net income of approximately $46.6 million and earnings of $0.63 per diluted common share in the fourth quarter of 2014.
Matador’s loss per diluted common share (GAAP basis) for the fourth quarter of 2015 was unfavorably impacted by (1) lower realized commodity prices, (2) a non-cash, unrealized loss on derivatives of $13.9 million and (3) a non-cash, full-cost ceiling impairment of $219.3 million, exclusive of tax effect. Matador’s net loss per diluted common share for the fourth quarter of 2015 was favorably impacted and mitigated by (1) higher oil and natural gas production, (2) a realized gain on derivatives of $24.9 million and (3) improvements in operating expenses on a unit-of-production basis.
For a reconciliation of adjusted net income (non-GAAP) and adjusted earnings (loss) per diluted common share (non-GAAP) to net income (GAAP) and earnings (loss) per common share (GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
Sequential Production and Financial Results
Year Ended December 31, 2015 as Compared to Year Ended December 31, 2014

• | Oil production increased 35% from 3.320 million, or 9,095 barrels of oil per day, in 2014 to 4.492 million barrels, or 12,306 barrels of oil per day, in 2015.

• | Natural gas production increased 81% from 15.3 billion cubic feet, or 41.9 million cubic feet per day, in 2014 to 27.7 billion cubic feet, or 75.9 million cubic feet per day, in 2015.

• | Oil equivalent production increased 55% from 5.870 million BOE, or 16,082 BOE per day, in 2014 to 9.109 million BOE, or 24,955 BOE per day, in 2015.

• | Oil and natural gas revenues decreased 24% from $367.7 million in 2014 to $278.3 million in 2015.

• | Adjusted EBITDA decreased 15% from $262.9 million reported in 2014 to $223.2 million reported in 2015.

Three Months Ended December 31, 2015 as Compared to Three Months Ended September 30, 2015

• | Oil production decreased 9% from 1.161 million barrels, or 12,617 barrels of oil per day, in the third quarter of 2015 to 1.062 million barrels, or 11,547 barrels of oil per day, in the fourth quarter of 2015.

• | Natural gas production decreased 11% from 7.5 billion cubic feet, or 81.1 million cubic feet per day, in the third quarter of 2015 to 6.6 billion cubic feet, or 72.1 million cubic feet per day, in the fourth quarter of 2015.

• | Oil equivalent production decreased 10% from 2.405 million BOE, or 26,137 BOE per day, in the third quarter of 2015 to 2.167 million BOE, or 23,556 BOE per day, in the fourth quarter of 2015.

• | Oil and natural gas revenues decreased 22% from $71.8 million in the third quarter of 2015 to $56.2 million in the fourth quarter of 2015.

• | Adjusted EBITDA decreased 17% from $58.0 million in the third quarter of 2015 to $48.3 million in the fourth quarter of 2015.

Operating Expenses
Production Taxes and Marketing
Production taxes and marketing expenses increased 7% on an absolute basis, but decreased 31% on a unit-of-production basis, from $33.2 million (or $5.65 per BOE) for the year ended December 31, 2014 to $35.5 million (or $3.90 per BOE) for the year ended December 31, 2015. The increase in production taxes and marketing expenses
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on an absolute basis was primarily attributable to higher natural gas marketing expenses due to the 81% increase in natural gas production between the respective periods. This increase was partially offset by a decrease in production taxes in 2015 due primarily to the 30% decrease in oil revenues for the year ended December 31, 2015, as compared to the year ended December 31, 2014.
Lease Operating Expenses (“LOE”)
Total lease operating expenses increased 13% on an absolute basis, but decreased 27% on a unit-of-production basis, from $51.4 million (or $8.75 per BOE) for the year ended December 31, 2014 to $58.2 million (or $6.39 per BOE) for the year ended December 31, 2015. The increase in total LOE was primarily attributable to the increase in total oil and natural gas production between the respective periods. The decrease on a unit-of-production basis was attributable to several key factors, including (1) no clean-out operations on offsetting producing wells as a result of fracturing operations on newly drilled Eagle Ford wells as compared to the same period in 2014, (2) a decrease in salt water disposal costs on a per barrel basis, particularly in the Delaware Basin, (3) reduced service costs impacting lease operating expenses and (4) a higher percentage of natural gas production, including a significant increase in Haynesville natural gas production, which typically has lower operating costs due to its lack of associated oil and water production. A joint venture controlled by Matador drilled, completed and began injecting salt water into a new disposal well in the Wolf prospect area in Loving County, Texas in January 2015, which has reduced salt water disposal costs in this area. A second salt water disposal well has been drilled and tested in the Wolf prospect area and began disposing of salt water in the fourth quarter of 2015. This well is currently operating with temporary facilities, but is expected to be fully operational with permanent facilities later in the first quarter of 2016.
Depletion, Depreciation and Amortization (“DD&A”)
Depletion, depreciation and amortization expenses increased 33% on an absolute basis, but decreased 15% on a unit-of-production basis, from $134.7 million (or $22.95 per BOE) for the year ended December 31, 2014 to $178.8 million (or $19.63 per BOE) for the year ended December 31, 2015. The increase in total DD&A expenses was primarily attributable to the 55% increase in total oil equivalent production between the respective periods. The decrease in unit-of-production DD&A expenses resulted from the 24% increase in total proved oil and natural gas reserves from 68.7 million BOE at December 31, 2014 to 85.1 million BOE at December 31, 2015, which reserves were added at a lower cost per BOE, as well as from the decrease in unamortized property costs resulting from full-cost ceiling impairments in 2015. The increase in total proved oil and natural gas reserves was primarily attributable to Matador’s continued delineation and development of its acreage position in the Delaware Basin.
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Full-cost ceiling impairment
Matador uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, the net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling,” defined as (1) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (4) income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation.
Due to the sharp decline in commodity prices since mid-year 2014, the unweighted arithmetic average oil and natural gas prices that exploration and production companies are required to use in estimating total proved reserves and PV-10, a non-GAAP financial measure, have also declined significantly. At December 31, 2015, these average oil and natural gas prices were $46.79 per barrel and $2.59 per MMBtu, respectively, as compared to $91.48 per barrel and $4.35 per MMBtu at December 31, 2014. This decline in the arithmetic average commodity prices of approximately $45 per barrel of oil and $1.76 per MMBtu of natural gas had a significant impact on the discounted value of the Company’s proved oil and natural gas reserves. Thus, although Matador’s total proved oil and natural gas reserves grew by 24% in 2015 as compared to 2014, the PV-10 of its proved reserves decreased by 48% from $1.04 billion at December 31, 2014 to $541.6 million at December 31, 2015. As a result, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling at December 31, 2015. Matador recorded a non-cash impairment charge of $801.2 million to its unaudited consolidated statement of operations related to the full-cost ceiling limitation for the year ended December 31, 2015. Given current oil and natural gas prices at February 24, 2016, Matador anticipates additional full-cost ceiling impairments may be dictated in future periods.
As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheet, as well as the corresponding consolidated shareholders’ equity, but it has no impact on the Company’s consolidated cash flows or Adjusted EBITDA as reported.
For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
General and Administrative (“G&A”)
General and administrative expenses increased 56% on a total basis, but were essentially flat on a unit-of-production basis, from $32.2 million (or $5.48 per BOE) for the year ended December 31, 2014 to $50.1 million (or $5.50 per BOE) for the year ended December 31, 2015. The increase in G&A expenses was primarily attributable to increased payroll expenses associated with additional personnel joining the Company during the year ended December 31, 2015 to support increased land, geoscience, drilling, completion, production, accounting and administration functions, including the addition of 29 new employees in Roswell, New Mexico as a result of the HEYCO merger in late February 2015. Overall, the Company’s staff increased from 99 full-time employees at December 31, 2014 to 151 full-time employees at December 31, 2015. The remaining increase in G&A expenses is largely due to a $4.0 million increase in non-cash stock-based compensation expense to $9.5 million for the year ended December 31, 2015, as compared to $5.5 million for the year ended December 31, 2014.
Proved Reserves and PV-10
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The following table summarizes Matador’s estimated total proved oil and natural gas reserves at December 31, 2015, 2014 and 2013.

| At December 31,
| 2015 |  | 2014 |  | 2013
Estimated proved reserves:(1)(2) |  |  |  |  |
Oil (MBbl)(3) | 45,644 |  |  | 24,184 |  |  | 16,362 |
Natural Gas (Bcf)(4) | 236.9 |  |  | 267.1 |  |  | 212.2 |
Total (MBOE)(5) | 85,127 |  |  | 68,693 |  |  | 51,729 |
Estimated proved developed reserves: |  |  |  |  |
Oil (MBbl)(3) | 17,129 |  |  | 14,053 |  |  | 8,258 |
Natural Gas (Bcf)(4) | 101.4 |  |  | 102.8 |  |  | 53.5 |
Total (MBOE)(5) | 34,037 |  |  | 31,185 |  |  | 17,168 |
Percent developed | 40.0 | % |  | 45.4 | % |  | 33.2 | %
Estimated proved undeveloped reserves: |  |  |  |  |
Oil (MBbl)(3) | 28,515 |  |  | 10,131 |  |  | 8,104 |
Natural Gas (Bcf)(4) | 135.5 |  |  | 164.3 |  |  | 158.7 |
Total (MBOE)(5) | 51,090 |  |  | 37,508 |  |  | 34,561 |
PV-10 (in millions)(6) | $ | 541.6 |  |  | $ | 1,043.4 |  |  | $ | 655.2 |
Standardized Measure (in millions) | $ | 529.2 |  |  | $ | 913.3 |  |  | $ | 578.7 |
(1) Numbers in table may not total due to rounding.
(2) Production volumes and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the period from January through December 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas, for the period from January through December 2014 were $91.48 per Bbl for oil and $4.35 per MMBtu for natural gas and for the period from January through December 2013 were $93.42 per Bbl for oil and $3.67 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead.
(3) One thousand barrels of oil.
(4) One billion cubic feet of natural gas.
(5) One thousand barrels of oil equivalent, estimated using a conversion ratio of one barrel of oil per six thousand cubic feet of natural gas.
(6) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.

Matador’s estimated total proved oil and natural gas reserves were 85.1 million BOE at December 31, 2015 (consisting of 45.6 million barrels of oil and 236.9 billion cubic feet of natural gas) with a PV-10, a non-GAAP financial measure, of $541.6 million (Standardized Measure of $529.2 million), as compared to estimated total proved oil and natural gas reserves of 68.7 million BOE at December 31, 2014 (consisting of 24.2 million barrels of oil and 267.1 billion cubic feet of natural gas) with a PV-10 of $1.04 billion (Standardized Measure of $913.3 million). Total proved reserves of 85.1 million BOE at December 31, 2015 represented a 24% year-over-year increase, as compared to 68.7 million BOE at December 31, 2014, and a 65% increase, as compared to 51.7 million BOE at December 31, 2013. At December 31, 2015, Matador’s proved oil and natural gas reserves were 40% proved developed reserves, as compared to 45% and 33% at December 31, 2014 and 2013, respectively.
The unweighted arithmetic averages of the first-day-of-the-month prices for the year ended December 31, 2015 were $46.79 per barrel for oil and $2.59 per MMBtu for natural gas, a decrease of 49% and 40%, respectively, as compared to an average oil price of $91.48 per barrel and an average natural gas price of $4.35 per MMBtu for the year ended December 31, 2014, and a decrease of 50% and 29%, respectively, as compared to an average oil price of $93.42 per barrel and an average natural gas price of $3.67 per MMBtu for the year ended December 31, 2013. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the prices received at the wellhead. Matador reports proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the
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natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.
Proved oil reserves increased 89% to 45.6 million barrels at December 31, 2015, as compared to 24.2 million barrels at December 31, 2014, and increased almost three-fold, as compared to 16.4 million barrels at December 31, 2013. Including Matador’s 2015 total oil production of approximately 4.5 million barrels, Matador effectively doubled its proved oil reserves year-over-year, despite an almost 50% decline in the oil price used to estimate proved oil reserves at December 31, 2015. Further, Matador added proved oil reserves of approximately 26.0 million barrels in 2015, an almost six-fold replacement rate, as compared to its 2015 oil production of approximately 4.5 million barrels. Matador’s proved oil reserves in the Delaware Basin increased almost four-fold to 31.4 million barrels at December 31, 2015, as compared to 8.1 million barrels at December 31, 2014, resulting from the Company’s ongoing delineation and development operations in the Delaware Basin. Proved oil reserves comprised 54% of the Company’s total proved reserves at December 31, 2015, as compared to 35% and 32% at December 31, 2014 and 2013, respectively.
Proved natural gas reserves decreased 11% to 236.9 billion cubic feet at December 31, 2015, as compared to 267.1 billion cubic feet at December 31, 2014. The decline in year-over-year natural gas reserves resulted principally from the reclassification of proved undeveloped natural gas reserves to contingent resources, primarily in the Haynesville shale, as a result of the decline in natural gas prices during 2015. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by Matador or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. Matador’s natural gas reserves comprised 46% of Matador’s total proved reserves at December 31, 2015, as compared to 65% and 68% at December 31, 2014 and 2013, respectively.
For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
Operations Update
Delaware Basin - Southeast New Mexico and West Texas
During 2015, and particularly after the first quarter of 2015, Matador focused most of its efforts on the continued exploration, delineation and development of its Delaware Basin acreage in Loving County, Texas and Lea and Eddy Counties, New Mexico. Matador completed and began producing oil and natural gas from 41 gross (25.0 net) wells in this area in 2015, including 27 gross (23.7 net) operated and 14 gross (1.3 net) non-operated wells. Matador (or the operator in the case of non-operated wells) completed and placed on production 15 gross (14.0 net) wells in the Wolf and Jackson Trust prospect areas, 13 gross (6.3 net) wells in the Rustler Breaks prospect area, and 12 gross (4.5 net) wells in the Ranger and Arrowhead prospect areas. Matador has now tested 12 different intervals in its Delaware Basin acreage from the Brushy Canyon through the Wolfcamp D, although most of its delineation and development efforts have focused on multiple completion targets between the Second Bone Spring and the Wolfcamp B. As a result of its continued efforts in the Delaware Basin, at December 31, 2015, Matador had identified up to 3,543 gross (1,417 net) potential locations for future drilling on its Delaware Basin acreage, including 2,263 gross (1,284 net) locations that it may potentially operate. This well inventory does not yet include any locations for Matador’s Twin Lakes prospect area. At December 31, 2015, only 118 gross (71.1 net) of these locations, or about 5%, had been assigned proved undeveloped reserves.
At February 24, 2016, Matador is operating three drilling rigs in the Delaware Basin—two in Loving County, Texas on its Wolf prospect and one in Eddy County, New Mexico on its Rustler Breaks prospect. Matador plans to operate three rigs in the Delaware Basin throughout 2016, although should oil prices drop and remain below $30.00 per barrel, the Company has the flexibility to reduce its drilling program to two rigs, either for a short time or for the remainder of 2016, beginning early in the second quarter. Matador intends to direct 97% of its 2016 anticipated
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capital investments of $325 million (in a three-rig program) to its Delaware Basin activities, including $260 million for continued delineation and development operations throughout its acreage in the Delaware Basin, $40 million principally for the completion of new midstream facilities currently being constructed in the Rustler Breaks prospect area and $25 million for the acquisition of additional leasehold interests and seismic data, primarily in the Delaware Basin. Assuming the Company operates three rigs throughout 2016, Matador anticipates it will complete and begin production from 54 gross (36.5 net) wells, including 41 gross (34.6 net) operated wells. The vast majority of these wells are anticipated to be completed in the Wolfcamp A and B formations in 2016, primarily in the Company’s Wolf and Rustler Breaks prospect areas.
Matador’s Delaware Basin assets have become an increasingly important component of the Company’s portfolio. In 2015, Matador’s Delaware Basin production grew 3.6-fold from an average total production of 1,790 BOE per day (consisting of 1,314 barrels of oil per day and 2.9 million cubic feet of natural gas per day) in 2014 to an average total production of 6,518 BOE per day (consisting of 4,648 barrels of oil and 11.2 million cubic feet of natural gas per day) in 2015. The Company’s total Delaware Basin production increased from 2,629 BOE per day (consisting of 1,893 barrels of oil per day and 4.4 million cubic feet of natural gas per day) in the fourth quarter of 2014 to 8,720 BOE per day (consisting of 6,117 barrels of oil per day and 15.6 million cubic feet of natural gas per day) in the fourth quarter of 2015, comprising 37% of Matador’s average total production for the fourth quarter of 2015. Matador’s Delaware Basin proved oil and natural gas reserves were 47.1 million BOE (consisting of 31.4 million barrels of oil and 94.4 billion cubic feet of natural gas), or 55% of the Company’s total proved reserves, at December 31, 2015. Both oil and natural gas production and proved reserves from Matador’s Delaware Basin properties are expected to grow significantly in 2016.
Matador continues to make significant progress with its midstream operations in the Delaware Basin as well. On October 1, 2015, Matador closed the sale of its cryogenic natural gas processing plant in Loving County, Texas with approximately 35 million cubic feet per day of inlet capacity and approximately six miles of high-pressure gathering pipeline to EnLink for cash consideration of approximately $143 million, excluding customary purchase price adjustments. Matador retained its in-field natural gas gathering system up to a central delivery point and its other midstream assets in the Wolf prospect area, including oil and water gathering systems. Matador also retained its interest in a commercial salt-water disposal facility in Loving County, operated by a joint venture controlled by the Company. The joint venture entity has disposed of over 5.5 million barrels of salt water since it began operations in January 2015, with a total savings to Matador of approximately $6.5 million in salt water disposal costs. In addition, the joint venture entity began disposing of third-party salt water on a commercial basis in the fourth quarter of 2015.
Given its recent drilling success in the Rustler Breaks prospect area in Eddy County, New Mexico (see below) coupled with the sale of its natural gas processing facility in Loving County, Texas, Matador began construction of a new cryogenic natural gas processing plant, as well as the associated natural gas gathering system, in the Rustler Breaks area in late 2015 to support its future development efforts there. The Rustler Breaks natural gas processing plant will be larger than the Loving County plant with an inlet capacity of approximately 60 million cubic feet of natural gas per day. Matador incurred approximately $25 million in capital expenditures for the construction of the Rustler Breaks natural gas processing facility and associated natural gas gathering infrastructure in late 2015 and has budgeted an additional $40 million in 2016 principally for the completion of these midstream assets. Matador expects the Rustler Breaks natural gas processing plant to become operational during the third quarter of 2016.
Wolf Prospect Area - Loving County, Texas
Matador is currently operating two drilling rigs in its Wolf prospect area and expects to run at least one rig in this area throughout 2016. At February 24, 2016, one of these rigs is drilling a four-well pad in “batch” mode (the Dick Jay pad), testing the Wolfcamp A-XY (two horizontals), the Wolfcamp A-Lower and the Second Bone Spring. The second rig is drilling a three-well pad in “batch” mode on the Company’s Dorothy White leasehold, each well testing the Wolfcamp A-XY. The Company expects to complete these wells late in the first quarter or early in the second quarter of 2016, following the drilling of all wells on each pad; as a result, these wells will not contribute
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much, if at all, to Matador’s first quarter production, but should have a significant impact on the Company’s second quarter production.
Matador continues to be pleased with its progress in reducing drilling times and well costs for both Wolfcamp and Bone Spring horizontal wells in the Wolf prospect area. In the Wolfcamp, drilling times (spud to total depth) have been reduced from 43 days in 2014 to as low as 18 days on a recent well. In the Second Bone Spring, Matador drilled its most recent well in the Wolf area without setting a second intermediate casing string, saving both time and up to $500,000 in well costs versus its previous Second Bone Spring test in the area. Drilling wells in “batch” mode is also saving time and money on these wells—for example, Matador estimates it is saving $400,000 per well associated with the four-well Dick Jay pad currently being drilled. Through a combination of both drilling and completion efficiencies, coupled with service cost reductions of varying amounts, Matador has continued to reduce overall well costs significantly. Recent Wolfcamp wells in the Wolf prospect area have been drilled and completed for approximately $6.5 million, including production facilities and other related infrastructure costs. The Company estimates that it may be able to reduce Wolfcamp drilling and completion costs by up to another 20% during 2016 due to continued improvements in drilling and completion efficiencies, as well as to anticipated further declines in services costs, particularly stimulation costs.
In a three-rig program for 2016, Matador expects to complete and place on production 17 gross (15.2 net) wells in its Wolf prospect area in 2016, including 14 Wolfcamp A-XY wells, one Wolfcamp A-Lower well and two Second Bone Spring wells. Many of these wells will be drilled and completed in a portion of the Wolf prospect area between the Dorothy White and Norton Schaub properties, where initial Wolfcamp A-XY wells have estimated ultimate recoveries at or above one million BOE. Both the Dorothy White #1H and the Norton Schaub 84-TTT-B33 WF #201H continue to be excellent wells. As of January 31, 2016, the Dorothy White #1H had produced approximately 480,000 BOE (69% oil) in its first two years of production, and the Norton Schaub #201H had produced 360,000 BOE (68% oil) in its first 18 months of production. The Dorothy White #1H is still flowing naturally after two years of production and is still producing between 400 and 500 BOE per day. The Norton Schaub #201H produces on electric submersible pump (“ESP”) to assist in lifting the wellbore fluids and is still producing between 600 and 700 BOE per day.
In late October 2015, Matador tested the use of a fracture stimulation diverting agent in one of its Billy Burt completions in the northwest portion of the Wolf prospect—the Billy Burt 90-TTT-B33 WF #201H. The Billy Burt #201H well was a Wolfcamp A-Y test and has a completed lateral length of 6,725 feet. The diverting agent was used in an effort to improve the efficiency of each fracturing stage and to ensure as many perforation clusters were treated as possible, while simultaneously improving well costs. Breakdown pressures monitored during the fracture treatments on the Billy Burt #201H well indicated that additional perforations were opened and new hydraulic fractures were created after the diverting agent was pumped in various stages of the fracturing operation. The Billy Burt #201H well initially tested about 1,100 BOE per day (68% oil), consisting of about 750 barrels of oil per day and 2.1 million cubic feet of natural gas per day at about 2,500 psi on a 24/64-inch choke. More importantly, however, early production from the well over its initial ninety days has been about 27% higher than the immediate 80-acre offsetting well having a similar lateral length, but where no diverting agent was used. After its initial ninety days of production, the Billy Burt #201H well was still flowing about 933 BOE per day (75% oil), consisting of 688 barrels of oil per day and 1.5 million cubic feet of natural gas per day. Matador plans to continue to refine and improve its fracture treatment designs, including the use of both existing technologies and new technologies as they become available and are determined to be beneficial, in an effort to improve the overall recovery from its Delaware Basin wells.
During the third quarter of 2015, Matador drilled a three-well stacked horizontal lateral test in “batch” mode on its Jackson Trust C Unit in northeast Loving County, Texas. These three wells targeted, from deepest to shallowest, the Second Bone Spring, Avalon and Brushy Canyon formations. These were Matador’s first tests of each of these formations on its Jackson Trust acreage, and all three wells were completed in the fourth quarter of 2015. During a 24-hour initial potential test, the Jackson Trust C12-TTT-C24 NL #121H well, the Second Bone Spring completion, flowed 815 BOE per day (71% oil), consisting of 580 barrels of oil per day and 1.4 million cubic feet of natural gas per day, at 900 psi surface pressure on a 36/64-inch choke. The initial behavior of this Second Bone Spring
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completion and the way that it flowed back after stimulation were consistent with Matador’s expectations for the Second Bone Spring in the Loving County area.
In comparison to the Second Bone Spring, however, the Avalon and Brushy Canyon completions have been slower to clean up following stimulation. This was largely expected as both reservoirs are normally pressured and Matador anticipated that both wells would require some form of artificial lift in order to more fully clean up the fracturing fluid before any significant oil and natural gas production was established. Initially, Matador experimented with gas lift assist in both wells, but ultimately determined that another form of artificial lift may allow the wells to clean up faster. As a result, Matador installed an ESP in the Jackson Trust C12-TTT-C24 NL #101H well, the Avalon completion. Upon installation of the ESP, the total fluid recovery from the well increased significantly as expected, and at its February 3, 2016 Analyst Day presentation, Matador reported that the Avalon completion was producing 331 BOE per day and improving. Today, Matador is pleased to announce that the Avalon completion has continued to improve, and this well is currently producing 776 BOE per day (66% oil), consisting of 526 barrels of oil per day and approximately 1.5 million cubic feet of natural gas per day. Matador is very encouraged by this improvement in the Avalon completion since installing the ESP, and is preparing to install an ESP in the Jackson Trust C12-TTT-C24 NL #021H, the Brushy Canyon completion, during the first quarter of 2016 to further assist in the cleanup of that well.
Rustler Breaks Prospect Area - Eddy County, New Mexico
At February 24, 2016, Matador is operating one drilling rig in its Rustler Breaks prospect area in Eddy County, New Mexico and expects to run at least one rig in this area throughout 2016. This rig is drilling a two-well pad in “batch” mode (the Jimmy Kone pad) testing the Wolfcamp A-XY and the Wolfcamp B intervals. These wells will also be completed late in the first quarter or early in the second quarter of 2016 and will not contribute much, if at all, to Matador’s first quarter 2016 production. In a three-rig program for 2016, Matador expects to complete and place on production 18 gross (14.5 net) wells in its Rustler Breaks prospect area during 2016, including eight Wolfcamp A-XY wells and ten Wolfcamp B wells. Matador plans to focus on the Wolfcamp A-XY and Wolfcamp B formations at Rustler Breaks in 2016, not only because these wells are capable of providing satisfactory economic returns in this low commodity price environment, but also because Wolfcamp wells have the potential to hold more acreage and more up-hole future drilling opportunities than shallower wells. For example, drilling a single Wolfcamp B horizontal well typically holds 320 surface acres in the Rustler Breaks prospect area and preserves up to 15 additional drilling locations containing millions of oil equivalent barrels in place for potential future drilling opportunities in both the Wolfcamp and other up-hole horizons.
In the Rustler Breaks prospect, where the Wolfcamp formation is shallower, Matador has reduced Wolfcamp drilling times from an average of 32 days in 2014 to as low as 15 days on recent wells. In addition, Matador’s most recent Second Bone Spring horizontal well at Rustler Breaks was drilled from spud to total depth in 12 days, making it the fastest horizontal Second Bone Spring well the Company has drilled to date. As a result of both increased operational efficiencies and continuing service cost declines, Wolfcamp A-XY and Wolfcamp B wells in the Rustler Breaks area should be drilled and completed for $6.0 to $6.5 million in the first quarter of 2016, including production facilities and other related infrastructure costs, and, as in the Wolf prospect area, Matador estimates that it may be able to reduce Wolfcamp drilling and completion costs by up to another 20% during 2016. The Company’s most recent Second Bone Spring well in this area was drilled and completed for approximately $4 million.
The delineation of the Rustler Breaks prospect area delivered strong production results in both the Wolfcamp A-XY and Wolfcamp B formations in 2015, and this trend has continued with wells drilled and placed on production in the fourth quarter of 2015. During the fourth quarter of 2015, Matador completed and placed on production the Janie Conner 13-24S-28E RB #224H well in the Wolfcamp B formation. Of particular note, the Janie Conner #224H well was stimulated with increased sand concentrations of up to 3,000 pounds per foot of completed lateral to observe the impact of higher sand concentrations on well performance; Matador had pumped about 2,000 pounds per foot of completed lateral in its earlier Wolfcamp completions. The Janie Conner #224H tested 1,703 BOE per day (59% oil), consisting of 1,005 barrels of oil per day and 4.2 million cubic feet of natural gas per day, at 3,000 psi on a
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30/64-inch choke. This was the highest 24-hour initial potential test rate recorded for any of Matador’s Wolfcamp B wells in the Rustler Breaks area. In fact, this was the best 24-hour initial potential test of any well drilled by Matador thus far in the Delaware Basin. Early production from this well is currently tracking above Matador’s one million BOE Wolfcamp B type curve for the Rustler Breaks area, as is the production from the Tiger 14-24S-28E RB #224H well, which was drilled and completed in the Wolfcamp B formation in April 2015.
During the fourth quarter of 2015, Matador also completed and placed on production the Dr. K 24-23S-27E RB #203H well in the Wolfcamp A-XY formation. This well was also stimulated with increased sand concentrations up to 3,000 pounds per foot of completed lateral and 40 barrels of fracturing fluid per foot of completed lateral. This well is located closer to the center of Matador’s Rustler Breaks prospect area, northwest of the Guitar 10-24S-28E RB #202H and Tiger 14-24S-28E RB #204H wells, but south of the Scott Walker State 36-22S-27E RB #204H well. The Dr. K #203H well tested 1,241 BOE per day (69% oil), consisting of 856 barrels of oil per day and 2.3 million cubic feet of natural gas per day, at 1,890 psi on a 32/64-inch choke. This 24-hour initial potential test was comparable to the 1,274 BOE per day (79% oil) tested on the Guitar #202H well to the southeast and further established the prospectivity of the Wolfcamp A-XY formation across Matador’s Rustler Breaks acreage. The Guitar #202H well and the Tiger #204H well, Matador’s initial Wolfcamp A-XY completions at Rustler Breaks, continue to perform very well. Both wells continue to track above Matador’s 800,000 BOE Wolfcamp A-XY type curve for the Rustler Breaks area. The majority of Matador’s 2016 drilling program at Rustler Breaks is expected to be conducted to the south and southeast of the Dr. K #203H well.
Ranger Prospect Area - Lea County, New Mexico and Arrowhead Prospect Area - Eddy County, New Mexico
Matador is not currently drilling in either of its Ranger or Arrowhead prospect areas. (Note: Most of the acreage acquired by Matador in early 2015 as part of its merger with HEYCO is now included in Matador’s Arrowhead prospect area in northern Eddy County, New Mexico.) In a three-rig program, Matador expects to return to drilling in these areas during the second half of 2016 and anticipates completing and placing on production five gross (3.9 net) wells, consisting of two Second Bone Spring and three Third Bone Spring wells. The Third Bone Spring wells are scheduled to be approximately 7,500-foot laterals.
During the fourth quarter of 2015, Matador completed and placed on production two Second Bone Spring wells in the northern portion of its Ranger prospect area - the Conine 03-20S-35E RN #121H and the Hibiscus State 08-19S-35E RN #124H wells. The Conine #121H well tested 578 BOE per day (91% oil), consisting of 525 barrels of oil per day and 319 thousand cubic feet of natural gas per day. This well has continued to perform very well on ESP and as of mid-February 2016 was still producing between 400 and 500 barrels of oil per day. The Hibiscus #124H well is still cleaning up following its completion and is currently awaiting the installation of an ESP to assist with the cleanup operations. Second Bone Spring wells in this northern area of the Delaware Basin are normally pressured and, given their high oil cuts, typically require some form of artificial lift soon after being placed on production. Matador has been using both gas-lift and ESPs to provide the initial artificial lift for these wells depending on the particular producing characteristics of each well; both methods are proving to be successful in improving the initial productivity of these Second Bone Spring wells.
Eagle Ford Shale - South Texas
Matador completed and began producing oil and natural gas from 18 gross (17.3 net) wells in the Eagle Ford shale in 2015, all in the early portion of the year, including 17 gross (17.0 net) operated wells and one gross (0.3 net) non-operated well. During the second quarter of 2015, Matador concluded its planned drilling and completion operations for 2015 and did not drill or complete any additional operated wells in the Eagle Ford shale for the remainder of 2015.
Matador does not plan to drill or complete any operated wells in the Eagle Ford shale during 2016. At December 31, 2015, approximately 90% of the Company’s acreage in the Eagle Ford shale was either held by production or not subject to expirations before 2017. Matador has allocated approximately $5.6 million (less than 2%) of its 2016
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estimated capital expenditures to the Eagle Ford shale to allow for the installation of pumping units on certain properties and for lease extensions and acquisitions, as and if desired.
Haynesville Shale - Northwest Louisiana and East Texas
Matador participated in 22 gross (1.9 net) non-operated wells in the Haynesville shale in 2015, including nine gross (1.6 net) wells that were completed and placed on production by an affiliate of Chesapeake Energy Corporation (“Chesapeake”) on Matador’s Elm Grove properties in Northwest Louisiana. No new Haynesville shale wells were placed on production during the fourth quarter of 2015, as Chesapeake deferred first production until early January 2016 from nine gross (1.9 net) Haynesville shale wells drilled and completed in the latter portion of 2015. This deferral of first production from these nine new Haynesville shale wells was primarily responsible for the decline in Matador’s natural gas production during the fourth quarter of 2015.
As of December 31, 2015, Chesapeake had largely completed the infill drilling program at Elm Grove it was executing over the past couple of years. As a result, Matador expects to participate in only a few non-operated Haynesville shale wells in 2016. The Company has allocated $4.4 million (just over 1%) of its 2016 estimated capital expenditures to the Haynesville shale to allow for its participation in an anticipated five gross (0.6 net) non-operated wells.
Delaware (Permian) Basin Acreage Update
At February 24, 2016, Matador held approximately 158,100 gross (89,000 net) acres in the Permian Basin, primarily in the Delaware Basin in Lea and Eddy Counties, New Mexico and Loving County, Texas. These acreage totals included approximately 32,400 gross (19,400 net) acres in Matador’s Ranger area in Lea County, 47,400 gross (16,900 net) acres in its Arrowhead area in Eddy County, 21,500 gross (13,700 net) acres in its Rustler Breaks area in Eddy County, 12,200 gross (7,500 net) acres in its Wolf and Jackson Trust areas in Loving County and 42,300 gross (29,900 net) acres in its Twin Lakes area in Lea County. Matador plans to continue its leasing and acquisition efforts in the Delaware Basin during 2016, and may also consider acquiring additional acreage in the Eagle Ford shale and Haynesville shale as strategic opportunities are identified.
Liquidity Update
At December 31, 2015, the borrowing base under the Company’s revolving credit facility was $375.0 million, based on the lenders’ review of Matador’s proved oil and natural gas reserves as of June 30, 2015. At December 31, 2015, Matador had cash on hand totaling approximately $61 million and no outstanding borrowings under the Company’s revolving credit facility and approximately $0.6 million in outstanding letters of credit. At February 24, 2016, the Company continued to have no outstanding borrowings and approximately $0.6 million in outstanding letters of credit under its revolving credit facility.
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 February 24, 2016, Matador had the following hedges in place, in the form of costless collars, for the remainder of 2016.

• | Approximately 2.0 million barrels of oil at a weighted average floor price of $44 per barrel and a weighted average ceiling price of $65 per barrel.

• | Approximately 10.0 billion cubic feet of natural gas at a weighted average floor price of $2.60 per MMBtu and a weighted average ceiling price of $3.53 per MMBtu.

Matador estimates that it has approximately 44% of its anticipated oil production and approximately 44% of its anticipated natural gas production hedged for the remainder of 2016 based on the midpoint of its production guidance as provided at its Analyst Day on February 3, 2016 (see below).
At February 24, 2016, Matador had the following hedges in place, in the form of costless collars, for 2017.

• | Approximately 7.2 billion cubic feet of natural gas at a weighted average floor price of $2.25 per MMBtu and a weighted average ceiling price of $3.57 per MMBtu.

2016 Guidance Affirmation
At February 24, 2016, Matador affirms its 2016 guidance as initially provided at its Analyst Day on February 3, 2016. This guidance is based on Matador running three operated drilling rigs in the Delaware Basin throughout 2016, although, as previously noted, Matador will consider reducing its Delaware Basin program to two operated drilling rigs as early as the second quarter of 2016 should oil prices drop and remain below $30.00 per barrel.
As a result of additional pad drilling operations in 2016, Matador estimates that its production growth profile will be somewhat uneven in 2016. As noted earlier, due to multi-well pad drilling operations ongoing in the first quarter in its Wolf and Rustler Breaks prospect areas, seven to nine wells being drilled in the first quarter will not be stimulated and placed on production until late in the first quarter or early in the second quarter. As a result, Matador estimates that its first quarter oil production may be down approximately 3% and that its total production will be relatively flat, as compared to the fourth quarter of 2015. Should Matador continue with its three-rig program, the Company estimates that its oil production should increase in the second quarter of 2016, remain relatively flat for several months and then increase again in the fourth quarter of 2016, with fourth quarter 2016 oil production being as much as one-third higher compared to the fourth quarter of 2015. Natural gas production is expected to decline slightly in the latter half of 2016, as increasing natural gas production in the Delaware Basin partially offsets the anticipated declines in natural gas production resulting from essentially no drilling activity in the Eagle Ford and Haynesville shale during 2016. From January 1 to mid-February 2016, Matador’s oil equivalent production has averaged approximately 24,000 BOE per day (consisting of approximately 11,300 barrels of oil per day and 76.0 million cubic feet of natural gas per day).
Key elements of the Company’s 2016 guidance, based on the three-rig drilling program, are as follows.

• | 2016 capital expenditures of $325 million, including $260 million for drilling, completions, facilities and infrastructure costs, $40 million for midstream activities in the Delaware Basin and $25 million for discretionary land and seismic data;

• | 2016 oil production guidance of 4.9 to 5.1 million barrels, an increase of approximately 11% from 2015 actual oil production of 4.5 million barrels to the midpoint of 2016 production guidance;

• | 2016 natural gas production guidance of 26.0 to 28.0 billion cubic feet, a decrease of approximately 3% from 2015 actual natural gas production of 27.7 billion cubic feet to the midpoint of 2016 production guidance;

• | 2016 total oil equivalent production guidance of 9.2 to 9.8 million BOE, an increase of approximately 4% from 2015 actual oil equivalent production of 9.1 million BOE at the midpoint of 2016 production guidance; and

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• | 2016 Adjusted EBITDA guidance of $120 to $130 million, a decrease of approximately 44% from 2015 Adjusted EBITDA of $223.2 million based on estimated average oil prices of $34.00 per barrel for oil (West Texas Intermediate average oil price of $37.00 per barrel, less $3.00 per barrel of estimated price differentials, using the forward strip for oil prices in late January 2016) and $2.37 per thousand cubic feet for natural gas (NYMEX Henry Hub average natural gas price using the forward strip for natural gas prices in late January 2016 and assuming regional price differentials and uplifts from natural gas processing roughly offset). These estimated 2016 realized prices compare to 2015 realized oil and natural gas prices of $45.27 per barrel and $2.71 per thousand cubic feet, respectively.

Conference Call Information
The Company will host a live conference call on Thursday, February 25, 2016, at 9:00 a.m. Central Time to discuss its fourth quarter and full year 2015 financial and operational results. To access the live conference call, domestic participants should dial (855) 875-8781 and international participants should dial (720) 634-2925. The participant passcode is 50554612. The live conference call will also be available through the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab. The replay for the event will also be available on the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab through Thursday, March 31, 2016.
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 Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. Matador also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana 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,” “hypothetical,” “forecasted” 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 its 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; its ability to integrate acquisitions, including the HEYCO merger; 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
18

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.
Contact Information
Mac Schmitz
Capital Markets Coordinator
(972) 371-5225
mschmitz@matadorresources.com
19

Matador Resources Company and Subsidiaries
CONSOLIDATED BALANCE SHEETS - UNAUDITED

(In thousands, except par value and share data) |  | December 31,
|  |  | 2015 |  | 2014
| ASSETS |  |  |  |
| Current assets |  |  |  |
| Cash |  | $ | 16,732 |  |  | $ | 8,407 |
| Restricted cash |  | 44,357 |  |  | 609 |
| Accounts receivable |  |  |  |
| Oil and natural gas revenues |  | 16,616 |  |  | 28,976 |
| Joint interest billings |  | 16,999 |  |  | 6,925 |
| Other |  | 10,794 |  |  | 9,091 |
| Derivative instruments |  | 16,284 |  |  | 55,549 |
| Lease and well equipment inventory |  | 2,022 |  |  | 1,212 |
| Prepaid expenses and other assets |  | 3,203 |  |  | 1,649 |
| Total current assets |  | 127,007 |  |  | 112,418 |
| Property and equipment, at cost |  |  |  |
| Oil and natural gas properties, full-cost method |  |  |  |
| Evaluated |  | 2,122,174 |  |  | 1,617,913 |
| Unproved and unevaluated |  | 387,504 |  |  | 264,419 |
| Other property and equipment |  | 86,387 |  |  | 43,472 |
| Less accumulated depletion, depreciation and amortization |  | (1,583,659 | ) |  | (603,732 | )
| Net property and equipment |  | 1,012,406 |  |  | 1,322,072 |
| Other assets |  |  |  |
| Other assets |  | 1,448 |  |  | — |
| Total other assets |  | 1,448 |  |  | — |
| Total assets |  | $ | 1,140,861 |  |  | $ | 1,434,490 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY |  |  |  |
| Current liabilities |  |  |  |
| Accounts payable |  | $ | 10,966 |  |  | $ | 17,526 |
| Accrued liabilities |  | 92,369 |  |  | 107,356 |
| Royalties payable |  | 16,493 |  |  | 14,461 |
| Amounts due to affiliates |  | 5,670 |  |  | 2,146 |
| Advances from joint interest owners |  | 700 |  |  | — |
| Deferred gain on plant sale |  | 4,830 |  |  | — |
| Amounts due to joint ventures |  | 2,793 |  |  | — |
| Income taxes payable |  | 2,848 |  |  | 444 |
| Other current liabilities |  | 161 |  |  | 103 |
| Total current liabilities |  | 136,830 |  |  | 142,036 |
| Long-term liabilities |  |  |  |
| Borrowings under Credit Agreement |  | — |  |  | 338,199 |
| Senior unsecured notes payable |  | 391,254 |  |  | — |
| Asset retirement obligations |  | 15,166 |  |  | 11,640 |
| Amounts due to joint ventures |  | 3,956 |  |  | — |
| Deferred income taxes |  | — |  |  | 73,534 |
| Deferred gain on plant sale |  | 102,506 |  |  | — |
| Other long-term liabilities |  | 2,190 |  |  | 2,540 |
| Total long-term liabilities |  | 515,072 |  |  | 425,913 |
| Shareholders’ equity |  |  |  |
| Common stock — $0.01 par value, 120,000,000 and 80,000,000 shares authorized; 85,567,021 and 73,373,744 shares issued; 85,564,435 and 73,342,777 shares outstanding, respectively |  | 856 |  |  | 734 |
| Additional paid-in capital |  | 1,026,077 |  |  | 724,819 |
| Retained (deficit) earnings |  | (538,930 | ) |  | 140,855 |
| Total Matador Resources Company shareholders’ equity |  | 488,003 |  |  | 866,408 |
| Non-controlling interest in subsidiaries |  | 956 |  |  | 133 |
| Total shareholders’ equity |  | 488,959 |  |  | 866,541 |
| Total liabilities and shareholders’ equity |  | $ | 1,140,861 |  |  | $ | 1,434,490 |

20

Matador Resources Company and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED

(In thousands, except per share data) | For the Years Ended December 31,
|  | 2015 |  | 2014 |  | 2013
| Revenues |  |  |  |  |
| Oil and natural gas revenues | $ | 278,340 |  |  | $ | 367,712 |  |  | $ | 269,030 |
| Realized gain (loss) on derivatives | 77,094 |  |  | 5,022 |  |  | (909 | )
| Unrealized (loss) gain on derivatives | (39,265 | ) |  | 58,302 |  |  | (7,232 | )
| Total revenues | 316,169 |  |  | 431,036 |  |  | 260,889 |
| Expenses |  |  |  |  |
| Production taxes and marketing | 35,535 |  |  | 33,172 |  |  | 20,973 |
| Lease operating | 58,193 |  |  | 51,353 |  |  | 38,720 |
| Depletion, depreciation and amortization | 178,847 |  |  | 134,737 |  |  | 98,395 |
| Accretion of asset retirement obligations | 734 |  |  | 504 |  |  | 348 |
| Full-cost ceiling impairment | 801,166 |  |  | — |  |  | 21,229 |
| General and administrative | 50,105 |  |  | 32,152 |  |  | 20,779 |
| Total expenses | 1,124,580 |  |  | 251,918 |  |  | 200,444 |
| Operating (loss) income | (808,411 | ) |  | 179,118 |  |  | 60,445 |
| Other income (expense) |  |  |  |  |
| Net gain (loss) on asset sales and inventory impairment | 908 |  |  | — |  |  | (192 | )
| Interest expense, net of amounts capitalized | (21,754 | ) |  | (5,334 | ) |  | (5,687 | )
| Interest and other income | 2,365 |  |  | 1,345 |  |  | 225 |
| Total other expense | (18,481 | ) |  | (3,989 | ) |  | (5,654 | )
| (Loss) income before income taxes | (826,892 | ) |  | 175,129 |  |  | 54,791 |
| Income tax provision (benefit) |  |  |  |  |
| Current | 2,959 |  |  | 133 |  |  | 404 |
| Deferred | (150,327 | ) |  | 64,242 |  |  | 9,293 |
| Total income tax (benefit) provision | (147,368 | ) |  | 64,375 |  |  | 9,697 |
| Net (loss) income | (679,524 | ) |  | 110,754 |  |  | 45,094 |
| Net (income) loss attributable to non-controlling interest in subsidiaries | (261 | ) |  | 17 |  |  | — |
| Net (loss) income attributable to Matador Resources Company shareholders | $ | (679,785 | ) |  | $ | 110,771 |  |  | $ | 45,094 |
| Earnings (loss) per common share |  |  |  |  |
| Basic | $ | (8.34 | ) |  | $ | 1.58 |  |  | $ | 0.77 |
| Diluted | $ | (8.34 | ) |  | $ | 1.56 |  |  | $ | 0.77 |
| Weighted average common shares outstanding |  |  |  |  |
| Basic | 81,537 |  |  | 70,229 |  |  | 58,777 |
| Diluted | 81,537 |  |  | 70,906 |  |  | 58,929 |

21

Matador Resources Company and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED

(In thousands) |  | For the Years Ended December 31, |
|  |  | 2015 |  | 2014 |  | 2013 |
| Operating activities |  |  |  |  |  |  |
| Net (loss) income |  | $ | (679,524 | ) |  | $ | 110,754 |  |  | $ | 45,094 |  |
| Adjustments to reconcile net (loss) income to net cash provided by operating activities |  |  |  |  |  |  |
| Unrealized loss (gain) on derivatives |  | 39,265 |  |  | (58,302 | ) |  | 7,232 |  |
| Depletion, depreciation and amortization |  | 178,847 |  |  | 134,737 |  |  | 98,395 |  |
| Accretion of asset retirement obligations |  | 734 |  |  | 504 |  |  | 348 |  |
| Full-cost ceiling impairment |  | 801,166 |  |  | — |  |  | 21,229 |  |
| Stock-based compensation expense |  | 9,450 |  |  | 5,524 |  |  | 3,897 |  |
| Deferred income tax (benefit) provision |  | (150,327 | ) |  | 64,242 |  |  | 9,293 |  |
| Amortization of debt issuance costs and discounts |  | 852 |  |  | — |  |  | — |  |
| Net (gain) loss on asset sales and inventory impairment |  | (908 | ) |  | — |  |  | 192 |  |
| Changes in operating assets and liabilities |  |  |  |  |  |  |
| Accounts receivable |  | 3,633 |  |  | (13,318 | ) |  | (2,160 | ) |
| Lease and well equipment inventory |  | (180 | ) |  | (211 | ) |  | 243 |  |
| Prepaid expenses |  | (544 | ) |  | (783 | ) |  | (668 | ) |
| Other assets |  | (552 | ) |  | 1,212 |  |  | (548 | ) |
| Accounts payable, accrued liabilities and other current liabilities |  | 1,375 |  |  | 607 |  |  | (3,638 | ) |
| Royalties payable |  | 1,654 |  |  | 6,663 |  |  | 1,257 |  |
| Advances from joint interest owners |  | 700 |  |  | — |  |  | (1,515 | ) |
| Income taxes payable |  | 2,405 |  |  | 39 |  |  | 404 |  |
| Other long-term liabilities |  | 489 |  |  | (187 | ) |  | 415 |  |
| Net cash provided by operating activities |  | 208,535 |  |  | 251,481 |  |  | 179,470 |  |
| Investing activities |  |  |  |  |  |  |
| Proceeds from sale of assets |  | 139,836 |  |  | 79 |  |  | — |  |
| Oil and natural gas properties capital expenditures |  | (432,715 | ) |  | (560,849 | ) |  | (363,192 | ) |
| Expenditures for other property and equipment |  | (64,499 | ) |  | (9,152 | ) |  | (3,977 | ) |
| Business combination, net of cash acquired |  | (24,028 | ) |  | — |  |  | — |  |
| Maturities of certificates of deposit, net of purchases |  | — |  |  | — |  |  | 230 |  |
| Restricted cash |  | (43,098 | ) |  | — |  |  | — |  |
| Restricted cash in less-than-wholly-owned subsidiaries |  | (650 | ) |  | (609 | ) |  | — |  |
| Net cash used in investing activities |  | (425,154 | ) |  | (570,531 | ) |  | (366,939 | ) |
| Financing activities |  |  |  |  |  |  |
| Repayments of borrowings under Credit Agreement |  | (476,982 | ) |  | (180,000 | ) |  | (130,000 | ) |
| Borrowings under Credit Agreement |  | 125,000 |  |  | 320,000 |  |  | 180,000 |  |
| Proceeds from issuance of common stock |  | 188,720 |  |  | 181,875 |  |  | 149,069 |  |
| Proceeds from issuance of senior unsecured notes |  | 400,000 |  |  | — |  |  | — |  |
| Costs to issue equity |  | (1,158 | ) |  | (590 | ) |  | (7,390 | ) |
| Cost to issue senior unsecured notes |  | (9,598 | ) |  | — |  |  | — |  |
| Proceeds from stock options exercised |  | 10 |  |  | 43 |  |  | — |  |
| Capital commitment from non-controlling interest owners of less-than-wholly-owned subsidiaries |  | 562 |  |  | 150 |  |  | — |  |
| Taxes paid related to net share settlement of stock-based compensation |  | (1,610 | ) |  | (308 | ) |  | (18 | ) |
| Net cash provided by financing activities |  | 224,944 |  |  | 321,170 |  |  | 191,661 |  |
| Increase in cash |  | 8,325 |  |  | 2,120 |  |  | 4,192 |  |
| Cash at beginning of year |  | 8,407 |  |  | 6,287 |  |  | 2,095 |  |
| Cash at end of year |  | $ | 16,732 |  |  | $ | 8,407 |  |  | $ | 6,287 |  |

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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 pro forma, forward-looking, preliminary or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. The Company could not provide such reconciliation without undue hardship because such Adjusted EBITDA numbers are estimations, approximations and/or ranges. In addition, it would be difficult for the Company to present a detailed reconciliation on account of many unknown variables for the reconciling items.

|  | Year Ended December 31, |  | Three Months Ended
(In thousands) | 2015 |  | 2014 |  | 2013 |  | December 31, 2015 |  | September 30, 2015 |  | December 31, 2014
Unaudited Adjusted EBITDA Reconciliation to Net (Loss) Income: |  |  |  |  |  |  |  |  |  |  |
Net (loss) income attributable to Matador Resources Company shareholders | $ | (679,785 | ) |  | $ | 110,771 |  |  | $ | 45,094 |  |  | $ | (230,401 | ) |  | $ | (242,059 | ) |  | $ | 46,563 |
Interest expense | 21,754 |  |  | 5,334 |  |  | 5,687 |  |  | 6,586 |  |  | 7,229 |  |  | 1,649 |
Total income tax (benefit) provision | (147,368 | ) |  | 64,375 |  |  | 9,697 |  |  | 1,677 |  |  | (33,305 | ) |  | 27,701 |
Depletion, depreciation and amortization | 178,847 |  |  | 134,737 |  |  | 98,395 |  |  | 35,370 |  |  | 45,237 |  |  | 43,767 |
Accretion of asset retirement obligations | 734 |  |  | 504 |  |  | 348 |  |  | 307 |  |  | 182 |  |  | 134 |
Full-cost ceiling impairment | 801,166 |  |  | — |  |  | 21,229 |  |  | 219,292 |  |  | 285,721 |  |  | — |
Unrealized loss (gain) on derivatives | 39,265 |  |  | (58,302 | ) |  | 7,232 |  |  | 13,909 |  |  | (6,733 | ) |  | (50,351 | )
Stock-based compensation expense | 9,450 |  |  | 5,524 |  |  | 3,897 |  |  | 2,564 |  |  | 1,755 |  |  | 857 |
Net (gain) loss on asset sales and inventory impairment | (908 | ) |  | — |  |  | 192 |  |  | (1,005 | ) |  | — |  |  | — |
Adjusted EBITDA |  | $ | 223,155 |  |  | $ | 262,943 |  |  | $ | 191,771 |  |  | $ | 48,299 |  |  | $ | 58,027 |  |  | $ | 70,320 |
|  | Year Ended December 31, |  | Three Months Ended
(In thousands) | 2015 |  | 2014 |  | 2013 |  | December 31, 2015 |  | September 30, 2015 |  | December 31, 2014
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities: |  |  |  |  |  |  |  |  |  |  |
Net cash provided by operating activities | $ | 208,535 |  |  | $ | 251,481 |  |  | $ | 179,470 |  |  | $ | 22,611 |  |  | $ | 72,535 |  |  | $ | 71,123 |
Net change in operating assets and liabilities | (8,980 | ) |  | 5,978 |  |  | 6,210 |  |  | 16,254 |  |  | (20,846 | ) |  | 56 |
Interest expense, net of non-cash portion | 20,902 |  |  | 5,334 |  |  | 5,687 |  |  | 6,285 |  |  | 6,678 |  |  | 1,649 |
Current income tax provision (benefit) | 2,959 |  |  | 133 |  |  | 404 |  |  | 3,254 |  |  | (295 | ) |  | (2,525 | )
Net (income) loss attributable to non-controlling interest in subsidiaries | (261 | ) |  | 17 |  |  | — |  |  | (105 | ) |  | (45 | ) |  | 17 |
Adjusted EBITDA |  | $ | 223,155 |  |  | $ | 262,943 |  |  | $ | 191,771 |  |  | $ | 48,299 |  |  | $ | 58,027 |  |  | $ | 70,320 |

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Adjusted Net Income and Adjusted Earnings Per Share
This press release includes the non-GAAP financial measures of adjusted net income and adjusted earnings per diluted common share. These non-GAAP items are measured as net income (loss) attributable to Matador Resources Company shareholders, adjusted for dollar and per share impact of certain items, including unrealized gains or losses on derivatives, the impact of full cost-ceiling impairment charges, if any, and nonrecurring gains or losses or transaction costs for certain acquisitions and divestitures along with the related tax effects for all periods. This non-GAAP financial information is provided as additional information for investors and is not in accordance with, or an alternative to, GAAP financial measures. Additionally, these non-GAAP financial measures may be different than similar measures used by other companies. The Company believes the presentation of adjusted net income and adjusted earnings per diluted common share provides useful information to investors, as it provides them an additional relevant comparison of the Company’s performance across periods and to the performance of the Company’s peers. In addition, these non-GAAP financial measures reflect adjustments for items of income and expense that are often excluded by securities analysts and other users of the Company’s financial statements in evaluating the Company’s performance. The table below reconciles adjusted net income and adjusted earnings per diluted common share to their most directly comparable GAAP measure of net income (loss) attributable to Matador Resources Company shareholders.

| Three Months Ended December 31, 2015 |  | Year Ended December 31, 2015 |
(In thousands, except per share data) |  |  |  |
Unaudited Adjusted Net Income and Adjusted Earnings Per Share Reconciliation to Net Loss: |  |  |  |
Net loss attributable to Matador Resources Company shareholders | $ | (230,401 | ) |  | $ | (679,785 | ) |
Total income tax provision (benefit) | 1,677 |  |  | (147,368 | ) |
Loss attributable to Matador Resources Company shareholders before taxes | (228,724 | ) |  | (827,153 | ) |
Less non-recurring and unrealized charges to net income before taxes: |  |  |  |
Full-cost ceiling impairment | 219,292 |  |  | 801,166 |  |
Unrealized loss on derivatives | 13,909 |  |  | 39,265 |  |
Net gain on asset sales and inventory impairment | (1,005 | ) |  | (908 | ) |
Non-recurring transaction costs associated with the HEYCO merger | — |  |  | 2,510 |  |
Adjusted income attributable to Matador Resources Company shareholders before taxes | 3,472 |  |  | 14,880 |  |
Income tax expense | 1,111 |  |  | 5,119 |  |
Adjusted net income attributable to Matador Resources Company shareholders | $ | 2,361 |  |  | $ | 9,761 |  |
Basic weighted average shares outstanding, without participating securities | 84,705 |  |  | 81,537 |  |
Dilutive effect of participating securities | 849 |  |  | 769 |  |
Weighted average shares outstanding, including participating securities - basic | 85,554 |  |  | 82,306 |  |
Dilutive effect of options, restricted stock units and preferred shares | 461 |  |  | 544 |  |
Weighted average common shares outstanding - diluted | 86,015 |  |  | 82,850 |  |
Adjusted earnings per share attributable to Matador Resources Company shareholders (non-GAAP) |  |  |  |
Basic | $ | 0.03 |  |  | $ | 0.12 |  |
Diluted | $ | 0.03 |  |  | $ | 0.12 |  |

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. Where
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references are hypothetical in nature, and not based on historical fact, the table does not provide a reconciliation. The Company could not provide such reconciliation without undue hardship because such amounts are estimations and/or approximations. In addition, it would be difficult for the Company to present a detailed reconciliation on account of many unknown variables for the reconciling items.

(in millions) | At December 31, 2015 |  | At December 31, 2014 |  | At December 31, 2013 |
PV-10 | $ | 541.6 |  |  | $ | 1,043.4 |  |  | $ | 655.2 |  |
Discounted future income taxes | (12.4 | ) |  | (130.1 | ) |  | (76.5 | ) |
Standardized Measure | $ | 529.2 |  |  | $ | 913.3 |  |  | $ | 578.7 |  |

Cash Operating Expenses per BOE
This press release includes the non-GAAP financial measure of cash operating expenses per BOE. This non-GAAP item is measured as operating expenses per BOE excluding non-cash DD&A expense, non-cash stock-based compensation expense and non-recurring transaction costs associated with the HEYCO merger, each as adjusted on a per BOE basis. This non-GAAP financial information is provided as additional information for investors and is not in accordance with, or an alternative to, GAAP financial measures. Additionally, this non-GAAP financial measure may be different than similar measures used by other companies. The Company believes the presentation of cash operating expenses per BOE provides useful information to investors and other users of the Company’s financial information in evaluating the Company’s operating performance. The following table reconciles cash operating expenses per BOE (non-GAAP) to operating expenses per BOE (GAAP).

| Three Months Ended |  | Year Ended |
| December 31, 2015 |  | September 30, 2015 |  | December 31, 2014 |  | December 31, 2015 |  | December 31, 2014 |  | December 31, 2013 |
Cash Operating Expenses per BOE Reconciliation to Operating Expenses per BOE: |  |  |  |  |  |  |  |  |  |  |  |
Total operating expenses (per BOE)(1) | $ | 32.83 |  |  | $ | 33.92 |  |  | $ | 41.03 |  |  | $ | 35.42 |  |  | $ | 42.83 |  |  | $ | 41.74 |  |
Depletion, depreciation and amortization expenses (per BOE) | (16.32 | ) |  | (18.81 | ) |  | (22.86 | ) |  | (19.63 | ) |  | (22.95 | ) |  | (22.96 | ) |
Non-cash stock-based compensation expense (per BOE) | (1.18 | ) |  | (0.73 | ) |  | (0.45 | ) |  | (1.04 | ) |  | (0.94 | ) |  | (0.91 | ) |
Non-recurring transaction costs (per BOE) | — |  |  | — |  |  | — |  |  | (0.28 | ) |  | — |  |  | — |  |
Cash operating expenses (per BOE) | $ | 15.33 |  |  | $ | 14.38 |  |  | $ | 17.72 |  |  | $ | 14.47 |  |  | $ | 18.94 |  |  | $ | 17.87 |  |
(1) Total does not include the impact of full-cost ceiling impairment charges or immaterial accretion expenses. |

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