8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 8-K

_________________________________

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of Earliest Event Reported) November 4, 2015

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Matador Resources Company

(Exact name of registrant as specified in its charter)

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Texas	001-35410	27-4662601
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

5400 LBJ Freeway, Suite 1500, Dallas, Texas	75240
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (972) 371-5200

Not Applicable

(Former name or former address, if changed since last report)

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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition.

Attached hereto as Exhibit 99.1 is a press release (the “Press Release”) issued by Matador Resources Company (the “Company”) on November 4, 2015, announcing its financial results for the three and nine months ended September 30, 2015. The Press Release includes an operational update at November 4, 2015 and provides updated guidance for 2015. In connection with the Press Release, the Company released a presentation summarizing the highlights of the Press Release (the “Presentation” and, collectively with the Press Release, the “Investor Materials”). The Presentation is attached hereto as Exhibit 99.2 and is also available on the Company’s website at www.matadorresources.com. The Investor Materials are incorporated by reference into this Item 2.02, and the foregoing descriptions of the Investor Materials are qualified in their entirety by reference to these exhibits.

The information furnished pursuant to this Item 2.02, including Exhibits 99.1 and 99.2, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended (the “Securities Act”), unless specifically identified therein as being incorporated therein by reference.

In the Investor Materials, the Company has included as “non-GAAP financial measures,” as defined in Item 10 of Regulation S-K of the Exchange Act, (i) 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”), (ii) present value discounted at 10% (pre-tax) of estimated total proved reserves (“PV-10”), (iii) adjusted net income and adjusted earnings per share and (iv) cash operating expenses per barrel of oil equivalent. In the Investor Materials, the Company has provided reconciliations of the non-GAAP financial measures to the most directly comparable financial measures calculated and presented in accordance with generally-accepted accounting principles (“GAAP”) in the United States. In addition, in the Investor Materials, the Company has provided the reasons why the Company believes those non-GAAP financial measures provide useful information to investors.

Item 7.01 Regulation FD Disclosure.

Item 2.02 above is incorporated herein by reference.

The information furnished pursuant to this Item 7.01, including Exhibits 99.1 and 99.2, shall not be deemed to be “filed” for the purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any filing under the Securities Act unless specifically identified therein as being incorporated therein by reference.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit No.	Description of Exhibit
99.1	Press Release, dated November 4, 2015.
99.2	Presentation.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	MATADOR RESOURCES COMPANY
Date: November 5, 2015	By:	/s/ Craig N. Adams
	Name:	Craig N. Adams
	Title:	Executive Vice President

Exhibit Index

Exhibit No.	Description of Exhibit
99.1	Press Release, dated November 4, 2015.
99.2	Presentation.

EX-99.1

Exhibit 99.1

MATADOR RESOURCES COMPANY REPORTS THIRD QUARTER 2015 RESULTS

AND PROVIDES OPERATIONAL UPDATE

DALLAS, Texas, November 4, 2015 -- 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 Permian (Delaware) Basin operations in Southeast New Mexico and West Texas, today reported financial and operating results for the three and nine months ended September 30, 2015.

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

	Three Months Ended
	September 30,		June 30,		September 30,
	2015		2015		2014
Oil production (MBbl)	1,161		1,260		839
Natural gas production (Bcf)	7.5		7.0		3.8
Average daily oil equivalent production (BOE/d)	26,137		26,601		16,096
Average daily oil production (Bbl/d)	12,617		13,847		9,123
Average daily natural gas production (MMcf/d)	81.1		76.5		41.8
Oil and natural gas revenues (in millions)	$	71.8	$	87.8	$	96.6
Average realized oil price, $/Bbl	$	43.21	$	54.37	$	92.39
Average realized natural gas price, $/Mcf	$	2.90	$	2.78	$	4.95
Adjusted EBITDA(1) (in millions)	$	58.0	$	66.7	$	66.8
(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 three months ended September 30, 2015:

• Oil production of 1.16 million barrels for the three months ended September 30, 2015, a 38% year-over-year increase as compared to 839,000 barrels for the three months ended September 30, 2014; oil production decreased 8% sequentially from 1.26 million barrels produced in the three months ended June 30, 2015.

• Record natural gas production resulting in a 94% year-over-year increase to 7.5 billion cubic feet for the three months ended September 30, 2015 as compared to 3.8 billion cubic feet produced in the three months ended September 30, 2014, and a sequential increase of 7% from 7.0 billion cubic feet produced in the three months ended June 30, 2015.

• Average daily oil equivalent production of 26,137 barrels of oil equivalent (“BOE”) per day for the three months ended September 30, 2015 (consisting of 12,617 barrels of oil per day and 81.1 million cubic feet of natural gas per day), a 62% year-over-year increase as compared to 16,096 BOE per day (consisting of 9,123 barrels of oil per day and 41.8 million cubic feet of natural gas per day) for the three months ended September 30, 2014, and a sequential decrease of 2% from 26,601 BOE per day (consisting of 13,847 barrels of oil per day and 76.5 million cubic feet of natural gas per day) for the three months ended June 30, 2015.

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• A 26% year-over-year decrease in oil and natural gas revenues from $96.6 million reported for the third quarter of 2014 to $71.8 million for the third quarter of 2015, and a sequential decrease of 18% from $87.8 million reported in the second quarter of 2015. The weighted average oil and natural gas prices of $43.21 per barrel and $2.90 per thousand cubic feet, respectively, realized in the third quarter of 2015 were significantly lower than the weighted average oil and natural gas prices of $92.39 per barrel and $4.95 per thousand cubic feet, respectively, realized in the third quarter of 2014, as shown in the table above.

• A 13% year-over-year decrease in Adjusted EBITDA, a non-GAAP financial measure, from $66.8 million reported for the third quarter of 2014 to $58.0 million reported for the third quarter of 2015, and a sequential decrease of 13% from $66.7 million reported in the second quarter of 2015.

• Cash operating expenses per BOE, a non-GAAP financial measure, declined 28%, or $5.46 per BOE, to $14.38 per BOE for the three months ended September 30, 2015 as compared to $19.84 per BOE for the three months ended September 30, 2014. Sequentially, cash operating expenses per BOE decreased 1%, or $0.12 per BOE, as compared to $14.50 per BOE reported for the three months ended June 30, 2015.

Year-over-year nine-month-period comparisons of selected financial and operating items are shown in the following table:

	Nine Months Ended
	September 30,		September 30,
	2015		2014
Oil production (MBbl)	3,429		2,302
Natural gas production (Bcf)	21.1		9.9
Average daily oil equivalent production (BOE/d)	25,427		14,490
Average daily oil production (Bbl/d)	12,562		8,432
Average daily natural gas production (MMcf/d)	77.2		36.3
Oil and natural gas revenues (in millions)	$	222.1	$	274.6
Average realized oil price, $/Bbl	$	47.36	$	95.45
Average realized natural gas price, $/Mcf	$	2.83	$	5.53
Adjusted EBITDA(1) (in millions)	$	174.9	$	192.6
(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 nine months ended September 30, 2015:

• Record oil production resulting in an increase of 49% year-over-year to 3.43 million barrels for the nine months ended September 30, 2015 as compared to 2.30 million barrels for the nine months ended September 30, 2014.

• Record natural gas production resulting in a 112% year-over-year increase from 9.9 billion cubic feet produced in the nine months ended September 30, 2014 to 21.1 billion cubic feet for the nine months ended September 30, 2015.

• Record average daily oil equivalent production resulting in a 75% year-over-year increase to 25,427 BOE per day for the nine months ended September 30, 2015 (consisting of 12,562 barrels of oil per day and 77.2 million cubic feet of natural gas per day) as compared to 14,490 BOE per day (consisting

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of 8,432 barrels of oil per day and 36.3 million cubic feet of natural gas per day) for the nine months ended September 30, 2014.

• A 19% year-over-year decrease in oil and natural gas revenues from $274.6 million reported during the nine months ended September 30, 2014 to $222.1 million for the nine months ended September 30, 2015. The weighted average oil and natural gas prices of $47.36 per barrel and $2.83 per thousand cubic feet, respectively, realized in the nine months ended September 30, 2015 were significantly lower than the weighted average oil and natural gas prices of $95.45 per barrel and $5.53 per thousand cubic feet, respectively, realized in the nine months ended September 30, 2014, as shown in the table above.

• A 9% year-over-year decrease in Adjusted EBITDA, a non-GAAP financial measure, from $192.6 million reported during the nine months ended September 30, 2014 to $174.9 million for the nine months ended September 30, 2015.

• Cash operating expenses per BOE, a non-GAAP financial measure, declined 27%, or $5.31 per BOE, to $14.21 per BOE for the nine months ended September 30, 2015, as compared to $19.52 per BOE for the nine months ended September 30, 2014.

Additional Highlights:

• Matador’s proved oil reserves have approximately doubled year-over-year since September 30, 2014, and as of September 30, 2015 comprise 49% of the Company’s total proved reserves, resulting primarily from its ongoing delineation and development drilling and completion operations in the Delaware Basin. Total proved oil and natural gas reserves were 87.1 million BOE at September 30, 2015 (consisting of 42.5 million barrels of oil and 267.5 billion cubic feet of natural gas), a year-over-year BOE increase of 43% from 61.0 million BOE (consisting of 21.5 million barrels of oil and 236.7 billion cubic feet of natural gas) at September 30, 2014 and a BOE increase of 27% 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. The PV-10 of Matador’s total proved reserves, a non-GAAP financial measure, decreased 34% from $1.04 billion at December 31, 2014 to $0.69 billion at September 30, 2015 and decreased 27% year-over-year from $0.95 billion at September 30, 2014, as a result of the decline in oil and natural gas prices since July 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 $55.73 per barrel and $3.06 per million British Thermal Unit (“MMBtu”), respectively, at September 30, 2015, as compared to $91.48 per barrel and $4.35 per MMBtu, respectively, at December 31, 2014, and $95.56 per barrel and $4.24 per MMBtu, respectively, at September 30, 2014.

• Increased full-year 2015 natural gas production guidance from 26.0 to 27.0 billion cubic feet to 27.0 to 28.0 billion cubic feet. Reaffirmed all other full-year 2015 guidance estimates as increased on August 4, 2015 including (1) capital expenditures of $425 million (excluding capital expenditures associated with the HEYCO merger), (2) oil production of 4.4 to 4.5 million barrels, (3) oil and natural gas revenues of $290 to $300 million and (4) Adjusted EBITDA of $220 to $230 million. Oil and natural gas revenues and Adjusted EBITDA guidance are based on estimated average realized oil and natural gas prices of $50.00 per barrel and $3.00 per thousand cubic feet for the final three months of 2015.

A short presentation summarizing the highlights of Matador’s third quarter 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

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Joseph Wm. Foran, Matador’s Chairman and CEO, commented, “It is a pleasure to report that Matador delivered another strong operating quarter for its shareholders in the third quarter of 2015, highlighted by better-than-expected production, lower costs and the sale of a portion of our midstream assets in Loving County, Texas to an affiliate of EnLink Midstream Partners, LP (“EnLink”) for cash consideration of approximately $143 million. These results further enhanced our strong balance sheet and asset base, leaving us with a Net Debt to trailing 12-month Adjusted EBITDA ratio of approximately 1.0 at the close of this transaction on October 1, 2015. Apart from the sale of a newly constructed natural gas processing plant, we retained our infield natural gas gathering system up to a central delivery point, as well as our other midstream assets in the Wolf prospect area in Loving County, Texas. These midstream assets include oil and water gathering systems as well as our interest in a commercial salt water disposal facility that a Matador-controlled joint venture entity owns. In addition to disposing of our own produced salt water, we began disposing of third-party salt water at this disposal facility early in the fourth quarter of 2015. Given our recent drilling success in the Rustler Breaks prospect area in Eddy County, New Mexico, coupled with the sale of our natural gas processing facility in Loving County, we now plan to construct another cryogenic natural gas processing plant and natural gas, oil and water gathering system in the Rustler Breaks area to support our future development plans there. These assets, along with our other midstream assets in the Eagle Ford and the Haynesville, continue to provide an ongoing source of revenue, cost reduction and, most importantly, shareholder value for Matador.

“Operationally and financially, we are pleased with our progress and results to date in 2015, yet we intend to remain very conscious of our capital spending for the remainder of 2015 and into 2016. At this time, we have not finalized our capital spending plans for 2016. We do expect to run three operated rigs in the Delaware Basin throughout the remainder of 2015 and into the first part of 2016, and if oil prices remain at current levels, below $50 per barrel, we would expect to stay with a three-rig program in 2016 absent further material cost reductions or material increases in our expected well recoveries. As a result, we estimate that our drilling, completions and facilities capital expenditures for this three-rig program would be in the range of $250 to $275 million, which also includes $20 to $25 million for participation in non-operated wells in both the Delaware Basin and the Haynesville shale in 2016. Further, the capital budget will likely include additional discretionary capital expenditures to construct new midstream facilities in our Rustler Breaks and Wolf areas, as well as monies for continuing to add to our acreage position in the Delaware Basin. We have not yet determined the optimal capital budget for these discretionary projects, but we expect the total capital budget for 2016 to be less than the $425 million budgeted for 2015 (excluding capital expenditures associated with the HEYCO merger). We are also working with our lenders to secure a separate credit facility for our midstream operations. Matador expects to refine our capital expenditure estimates and our drilling and completions, midstream and acreage acquisition plans throughout the fourth quarter of 2015 as we continue to observe market conditions. We currently plan to provide formal guidance and capital spending plans for 2016 in late January or early February at our annual Analyst Day presentation in Dallas, Texas.

“During the third quarter of 2015, we are pleased to report that Matador produced 2.41 million BOE, including 1.16 million barrels of oil and 7.5 Bcf of natural gas, at or above our expectations for the quarter and the second best quarter in Matador’s history following the second quarter of 2015. Through the first nine months of 2015, we delivered record oil production of 3.43 million barrels, record natural gas production of 21.1 billion cubic feet and record oil equivalent production of 6.94 million BOE. In fact, our oil, natural gas and total oil equivalent production for the first nine months of the year have now exceeded our oil, natural gas and total oil equivalent production for all of 2014, even though we are operating with a reduced rig count and in areas that require longer drilling times than in the Eagle Ford. Our Adjusted EBITDA of $58.0 million also exceeded our expectations for the third quarter and was achieved despite receiving lower-than-projected oil and natural gas prices in the quarter.

“Drilling times and overall well costs continue to improve in our Delaware Basin operations and are helping to mitigate the year’s oil price declines. In our Wolf and Rustler Breaks prospect areas, we have reduced our drilling times from spud to total depth in both the Wolfcamp and Second Bone Spring formations by 50% or more this year. In fact, the most recent Second Bone Spring well we drilled at Rustler Breaks recorded a drilling time of only 12 days from spud to total depth, making it the fastest horizontal well we have yet drilled in the Second Bone Spring. Well costs also continue to improve. For example, drilling and completion costs for this most recent Second Bone Spring well were approximately $4.0 million and recent drilling and completion costs for Wolfcamp wells at Rustler

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Breaks were in the range of $5.8 to $6.5 million. The two Wolfcamp wells we are currently drilling on our Johnson leasehold in our Wolf prospect area are anticipated to be the fastest and least expensive Wolfcamp wells we have drilled in this prospect to date. Our operating costs also continue to improve as reflected by our lease operating expenses of only $6.20 per BOE in the third quarter, very consistent with earlier reporting periods in 2015 and down 33% from the same period a year ago.

“In mid-October, we were pleased to announce that our lenders had unanimously reaffirmed our borrowing base at $375.0 million based on their review of our oil and natural gas reserves as June 30, 2015. Further, the maturity of our credit facility was extended five years to October 2020. With this reaffirmation of our borrowing base and the recent EnLink transaction, we now have almost $500 million in liquidity to continue the delineation and development of our Delaware Basin acreage. We believe we could add to this borrowing base if the need should arise.

“Despite the challenges of lower commodity prices in 2015, the Matador board, the staff and I are proud of our accomplishments so far this year. We have significantly improved the strength of our balance sheet throughout the year, and the transaction with EnLink has further enhanced our financial position. Through our merger with Harvey E. Yates Company (“HEYCO”) earlier this year and our continued efforts to add to our acreage position, we have grown our Permian Basin net acreage position by almost 40% in 2015 to a total of approximately 91,000 net acres today. Further, we have continued to delineate and develop this acreage successfully and have identified a number of new intervals for future development. We look forward to finishing 2015 strong and to preparing for the opportunities ahead in 2016 and beyond.”

Third Quarter 2015 Operating and Financial Results

The table below provides selected operating data and unit costs for the third quarter of 2015, the second quarter of 2015 and the third quarter of 2014.

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	Three Months Ended
	September 30, 2015		June 30, 2015		September 30, 2014
Net Production Volumes:(1)
Oil (MBbl)(2)	1,161		1,260		839
Natural gas (Bcf)(3)	7.5		7.0		3.8
Total oil equivalent (MBOE)(4)	2,405		2,421		1,481
Average daily production (BOE/d)(5)	26,137		26,601		16,096
Average Sales Prices:
Oil, with realized derivatives (per Bbl)	$	57.90	$	62.72	$	91.42
Oil, without realized derivatives (per Bbl)	$	43.21	$	54.37	$	92.39
Natural gas, with realized derivatives (per Mcf)	$	3.28	$	3.24	$	4.99
Natural gas, without realized derivatives (per Mcf)	$	2.90	$	2.78	$	4.95
Operating Expenses (per BOE):
Production taxes and marketing	$	3.86	$	4.24	$	5.82
Lease operating	6.20		6.18		9.25
Depletion, depreciation and amortization	18.81		21.39		23.73
General and administrative(6)	5.05		5.35		5.47
Total(7)	$	33.92	$	37.16	$	44.27
Cash operating expenses(8)	$	14.38	$	14.50	$	19.84
(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 $0.73, $1.16 and $0.70 per BOE of non-cash, stock-based compensation expenses in the third quarter of 2015, the second quarter of 2015 and the third quarter of 2014, 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

Three months ended September 30, 2015 as compared to three months ended September 30, 2014

Average daily oil equivalent production was up 62% from 16,096 BOE per day (57% oil by volume) in the third quarter of 2014 to 26,137 BOE per day (48% oil by volume) during the third quarter of 2015. Total oil production increased 38% from 839,000 barrels of oil, or 9,123 barrels of oil per day, during the third quarter of 2014 to 1.16 million barrels of oil, or 12,617 barrels of oil per day, during the third quarter of 2015. This increase in oil production was primarily a result of increased oil production from newly drilled and completed wells in the Delaware Basin, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Matador’s Delaware Basin oil production increased almost four-fold year-over-year from approximately 137,000 barrels, or 1,500 barrels of oil per day, in the third quarter of 2014 to about 505,000 barrels, or about 5,500 barrels of oil per day, in the third quarter of 2015.

Total natural gas production almost doubled from 3.8 billion cubic feet of natural gas, or 41.8 million cubic feet of natural gas per day, during the third quarter of 2014 to 7.5 billion cubic feet of natural gas, or 81.1 million cubic feet of natural gas per day, during the third quarter of 2015. This increase in natural gas production was primarily attributable to the increased natural gas production resulting from new, non-operated Haynesville shale wells completed and placed on production on Matador’s Elm Grove properties in Northwest Louisiana during the latter half of 2014 and throughout 2015, as well as increased natural gas production associated with Matador’s operations in both the Delaware Basin and the Eagle Ford shale. Matador’s Haynesville natural gas production increased 158% from 1.7 billion cubic feet of natural gas, or about 18.9 million cubic feet of natural gas per day, in the third quarter of 2014 to 4.5 billion cubic feet of natural gas, or approximately 48.7 million cubic feet of natural gas per day, in the third quarter of 2015.

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Oil and natural gas revenues decreased 26% from $96.6 million in the third quarter of 2014 to $71.8 million in the third quarter of 2015. Oil revenues decreased 35% from $77.5 million in the third quarter of 2014 to $50.2 million in the third quarter of 2015, despite the 38% increase in oil production from 839,000 barrels in the third quarter of 2014 to 1.16 million barrels in the third quarter of 2015. This lower oil revenue was attributable to a sharp decline of 53% in the weighted average oil price realized by the Company from $92.39 per barrel in the third quarter of 2014 to $43.21 per barrel realized in the third quarter of 2015. Natural gas revenues increased 13% from $19.1 million during the third quarter of 2014 to $21.6 million during the third quarter of 2015, despite a 41% decrease in the weighted average natural gas price realized from $4.95 per thousand cubic feet in the third quarter of 2014 to $2.90 per thousand cubic feet in the third quarter of 2015. This increase in natural gas revenues was attributed to a 94% increase in natural gas production from 3.8 billion cubic feet in the third quarter of 2014 to 7.5 billion cubic feet in the third quarter of 2015.

Matador’s oil and natural gas hedges further mitigated the decline in oil and natural gas revenues during the third quarter of 2015. Total realized revenues, including realized hedging gains and losses, but excluding unrealized, non-cash hedging gains and losses, decreased 4% year-over-year from $95.9 million in the third quarter of 2014 to $91.7 million in the third quarter of 2015. Realized hedging gains, primarily from oil and natural gas hedges, were $19.9 million in the third quarter of 2015, as compared to a realized hedging loss of $0.7 million in the third quarter of 2014. Including the impacts of realized hedging gains, Matador realized weighted average oil and natural gas prices of $57.90 per barrel and $3.28 per thousand cubic feet, respectively, during the third quarter of 2015.

Nine months ended September 30, 2015 as compared to nine months ended September 30, 2014

Average daily oil equivalent production was up 75% from 14,490 BOE per day (58% oil by volume) for the nine months ended September 30, 2014 to 25,427 BOE per day (49% oil by volume) for the nine months ended September 30, 2015. Total oil equivalent production of 6.94 million BOE for the nine months ended September 30, 2015 exceeded the total oil equivalent production of 5.87 million BOE for full-year 2014.

Total oil production increased 49% from 2.30 million barrels of oil, or 8,432 barrels of oil per day, for the nine months ended September 30, 2014 to 3.43 million barrels of oil, or 12,562 barrels of oil per day, for the nine months ended September 30, 2015. This increase in oil production was primarily a result of increased oil production from the Company’s newly drilled and completed wells in the Delaware Basin, as well as from newly drilled and completed wells in the Eagle Ford shale in early 2015. Matador’s Delaware Basin oil production increased almost four-fold year-over-year from approximately 305,000 barrels, or 1,100 barrels of oil per day, for the nine months ended September 30, 2014 to about 1.13 million barrels, or 4,150 barrels of oil per day, for the nine months ended September 30, 2015. Total oil production of 3.43 million barrels through the first nine months of 2015 has now exceeded total oil production of 3.32 million barrels produced in full-year 2014.

Total natural gas production more than doubled from 9.9 billion cubic feet of natural gas, or 36.3 million cubic feet of natural gas per day, for the nine months ended September 30, 2014 to 21.1 billion cubic feet of natural gas, or 77.2 million cubic feet of natural gas per day, for the nine months ended September 30, 2015. This increase in natural gas production was primarily attributable to the increased natural gas production resulting from new, non-operated Haynesville shale wells completed and placed on production on Matador’s Elm Grove properties in Northwest Louisiana during the latter half of 2014 and into 2015, and also included increased natural gas production associated with Matador’s operations in the Delaware Basin and the Eagle Ford shale. Matador’s Haynesville shale natural gas production increased more than three-fold from 4.0 billion cubic feet of natural gas, or about 14.6 million cubic feet of natural gas per day, for the nine months ended September 30, 2014 to 13.4 billion cubic feet of natural gas, or approximately 49.1 million cubic feet of natural gas per day, for the nine months ended September 30, 2015.

Oil and natural gas revenues decreased 19% from $274.6 million for the nine months ended September 30, 2014 to $222.1 million for the nine months ended September 30, 2015. Despite the 49% increase in oil production from 2.30 million barrels for the nine months ended September 30, 2014 to 3.43 million barrels for the nine months

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ended September 30, 2015, oil revenues decreased 26% from $219.7 million for the nine months ended September 30, 2014 to $162.4 million for the nine months ended September 30, 2015. This lower oil revenue was attributable to a sharp decline of 50% in the weighted average oil price realized by the Company from $95.45 per barrel for the nine months ended September 30, 2014 to $47.36 per barrel realized for the nine months ended September 30, 2015. Despite a similar 49% decrease in the weighted average natural gas price realized from $5.53 per thousand cubic feet for the nine months ended September 30, 2014 to $2.83 per thousand cubic feet for the nine months ended September 30, 2015, natural gas revenues increased 9% from $54.9 million for the nine months ended September 30, 2014 to $59.7 million for the nine months ended September 30, 2015 due to the 112% increase in natural gas production from 9.9 billion cubic feet for the nine months ended September 30, 2014 to 21.1 billion cubic feet for the nine months ended September 30, 2015.

Total realized revenues, including realized hedging gains and losses, but excluding unrealized, non-cash hedging gains and losses, increased 2% year-over-year from $269.1 million in the nine months ended September 30, 2014 to $274.3 million in the nine months ended September 30, 2015. Realized hedging gains, primarily from oil and natural gas hedges, were $52.1 million in the nine months ended September 30, 2015, as compared to a realized hedging loss of $5.5 million in the nine months ended September 30, 2014. Including the impacts of realized hedging gains, Matador realized weighted average oil and natural gas prices of $59.61 per barrel and $3.31 per thousand cubic feet, respectively, during the nine months ended September 30, 2015.

Adjusted EBITDA

Adjusted EBITDA, a non-GAAP financial measure, decreased 13% from $66.8 million during the third quarter of 2014 to $58.0 million in the third quarter of 2015. This decrease in Adjusted EBITDA was primarily attributable to the sharp decline in commodity prices during the third quarter of 2015 (weighted average realized oil and natural gas prices of $43.21 per barrel and $2.90 per thousand cubic feet, respectively), as compared to the third quarter of 2014 (weighted average realized oil and natural gas prices of $92.39 per barrel and $4.95 per thousand cubic feet, respectively), as discussed in the previous section. These sharp commodity price declines were mitigated significantly by the 62% increase in Matador’s total oil equivalent production year-over-year, its increased revenues attributable to hedging and the 28% decline in the Company’s cash operating expenses on a unit-of-production basis, a non-GAAP financial measure, from $19.84 per BOE during the third quarter of 2014 to $14.38 per BOE during the third quarter of 2015.

Adjusted EBITDA decreased 9% from $192.6 million during the nine months ended September 30, 2014 to $174.9 million in the nine months ended September 30, 2015. This decrease was primarily attributable to the sharp decline in commodity prices during the nine months ended September 30, 2015 (weighted average realized oil and natural gas prices of $47.36 per barrel and $2.83 per thousand cubic feet, respectively), as compared to the nine months ended September 30, 2014 (weighted average realized oil and natural gas prices of $95.45 per barrel and $5.53 per thousand cubic feet, respectively), as discussed in the previous section. These sharp commodity price declines were mitigated significantly by the 75% increase in Matador’s total oil equivalent production year-over-year, its increased revenues attributable to hedging and the 27% decline in the Company’s cash operating expenses on a unit-of-production basis from $19.52 per BOE during the nine months ended September 30, 2014 to $14.21 per BOE during the nine months ended September 30, 2015.

For a definition of Adjusted EBITDA and a reconciliation of net income (GAAP) and net cash provided by operating activities (GAAP) to Adjusted EBITDA (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.

Net Income (Loss) and Earnings (Loss) Per Share

For the third quarter of 2015, Matador reported adjusted net income of approximately $2.6 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 gain on derivatives of $6.7 million and a non-cash full-cost ceiling impairment of $252.4 million, net of tax effect.

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For the third quarter of 2015, Matador reported a net loss of approximately $242.1 million and a loss of $2.86 per diluted common share on a GAAP basis, as compared to net income of approximately $29.6 million and earnings of $0.40 per diluted common share in the third quarter of 2014.

Matador’s net loss per diluted common share (GAAP basis) for the third quarter of 2015 was unfavorably impacted by (1) lower realized commodity prices and (2) a non-cash, full-cost ceiling impairment of $252.4 million, net of tax effect. Matador’s net loss per diluted common share for the third quarter of 2015 was favorably impacted and mitigated by (1) significantly higher oil and natural gas production, (2) $19.9 million in realized gain on derivatives, (3) a non-cash, unrealized gain on derivatives of $6.7 million and (4) improvements in operating expenses on a unit-of-production basis.

For the nine months ended September 30, 2015, Matador reported adjusted net income of approximately $8.0 million and adjusted earnings of $0.10 per diluted common share, each as adjusted on a non-GAAP basis to exclude a non-cash, unrealized loss on derivatives of $25.4 million, a non-cash full-cost ceiling impairment of $441.5 million, net of tax effect, and non-recurring costs associated with the HEYCO merger of $2.5 million.

For the nine months ended September 30, 2015, Matador reported a net loss of approximately $449.4 million and a loss of $5.58 per diluted common share on a GAAP basis, as compared to a net income of approximately $64.2 million and earnings of $0.92 per diluted common share for the nine months ended September 30, 2014.

Matador’s net loss per diluted common share (GAAP basis) for the nine months ended September 30, 2015 was unfavorably impacted by (1) lower realized commodity prices, (2) a non-cash unrealized loss on derivatives of $25.4 million and (3) a non-cash, full-cost ceiling impairment of $441.5 million, net of tax effect. Matador’s net loss per diluted common share for the nine months ended September 30, 2015 was favorably impacted and mitigated by (1) significantly higher oil and natural gas production, (2) $52.1 million in realized hedging gains and (3) improvements in operating expenses on a unit-of-production basis.

For a reconciliation of net income (GAAP) and earnings (loss) per common share (GAAP) to adjusted net income (non-GAAP) and adjusted earnings (loss) per common share (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.

Sequential Production and Financial Results

Three months ended September 30, 2015 as compared to three months ended June 30, 2015

• Oil production decreased 8% from 1.26 million barrels, or 13,847 barrels of oil per day, in the second quarter of 2015 to 1.16 million barrels, or 12,617 barrels of oil per day, in the third quarter of 2015.

• Natural gas production increased 7% from 7.0 billion cubic feet, or 76.5 million cubic feet per day, in the second quarter of 2015 to 7.5 billion cubic feet, or 81.1 million cubic feet per day, in the third quarter of 2015.

• Total oil equivalent production decreased 1% from 2.42 million BOE, or 26,601 BOE per day, in the second quarter of 2015 to 2.41 million BOE, or 26,137 BOE per day, in the third quarter of 2015.

• Oil and natural gas revenues decreased 18% from $87.8 million in the second quarter of 2015 to $71.8 million in the third quarter of 2015.

• Total realized revenues, including the impacts of hedging, decreased 10% from $101.6 million in the second quarter of 2015 to $91.7 million in the third quarter of 2015.

• Adjusted EBITDA decreased 13% from $66.7 million in the second quarter of 2015 to $58.0 million in the third quarter of 2015.

• Total operating expenses per BOE declined 9% from $37.16 per BOE in the second quarter of 2015 to $33.92 per BOE in the third quarter of 2015. Year-over-year, total operating expenses declined 23% from

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$44.27 per BOE for the third quarter of 2014 to $33.92 per BOE in the third quarter of 2015. Total operating expenses per BOE exclude any impacts of the non-cash, full-cost impairment charges or immaterial non-cash accretion expenses recorded in any period.

Operating Expenses

Production Taxes and Marketing

Production taxes and marketing expenses increased 8% on an absolute basis, but decreased 34% on a unit-of-production basis, from $8.6 million, or $5.82 per BOE, for the three months ended September 30, 2014 to $9.3 million, or $3.86 per BOE, for the three months ended September 30, 2015. The increase in production taxes and marketing expenses on an absolute basis was primarily attributable to higher natural gas marketing expenses due to the 94%increase in natural gas production between respective periods. The decrease in production taxes and marketing expenses on a unit-of-production basis was primarily attributable to the 35%decrease in oil revenues leading to lower oil production taxes in the third quarter of 2015 as compared to the third quarter of 2014.

Production taxes and marketing expenses increased 12% on an absolute basis, but decreased 36% on a unit-of-production basis, from $23.7 million, or $6.00 per BOE, for the nine months ended September 30, 2014 to $26.6 million, or $3.83 per BOE, for the nine months ended September 30, 2015.

Lease Operating Expenses (“LOE”)

Lease operating expenses increased 9% on an absolute basis, but decreased 33% on a unit-of-production basis, from $13.7 million, or $9.25 per BOE, for the three months ended September 30, 2014 to $14.9 million, or $6.20 per BOE, for the three months ended September 30, 2015. On a unit-of-production basis, lease operating expenses were significantly lower than the Company’s goal of $7.25 per BOE for all of 2015. This marked the third consecutive quarter of significantly lower-than-expected lease operating expenses. The decrease achieved in LOE on a unit-of-production basis was attributable to several key factors including (i) no cleanout operations on producing wells as a result of fracturing operations on newly drilled Eagle Ford wells as compared to the same period in 2014, (ii) a decrease in salt water disposal costs on a per barrel basis, particularly in the Delaware Basin, (iii) reduced service costs impacting lease operating expenses and (iv) 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 water disposal costs in this area; additionally, a second salt water disposal well has been drilled and tested in the Wolf area and is expected to be fully operational during the first quarter of 2016.

Lease operating expenses increased 24% on an absolute basis, but decreased 30% on a unit-of-production basis, from $34.7 million, or $8.78 per BOE, for the nine months ended September 30, 2014 to $42.9 million, or $6.18 per BOE, for the nine months ended September 30, 2015.

Depletion, depreciation and amortization (“DD&A”)

Depletion, depreciation and amortization expenses increased 29% on an absolute basis, but decreased 21% on a unit-of-production basis, from $35.1 million, or $23.73 per BOE, for the three months ended September 30, 2014 to $45.2 million, or $18.81 per BOE, for the three months ended September 30, 2015. The increase in total DD&A expenses was primarily attributable to the 62% increase in total oil equivalent production between the respective periods. The decrease in unit-of-production DD&A expenses resulted from the 43% increase in estimated total proved oil and natural gas reserves from 61.0 million BOE at September 30, 2014 to 87.1 million BOE at September 30, 2015, as well as the decrease in unamortized property costs resulting from full-cost ceiling impairments in 2015. This increase in total proved oil and natural gas reserves was primarily attributable to Matador’s continued development of its acreage position in the Delaware Basin.

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Depletion, depreciation and amortization expenses increased 58% on an absolute basis, but decreased 10% on a unit-of-production basis, from $91.0 million, or $23.00 per BOE, for the nine months ended September 30, 2014 to $143.5 million, or $20.67 per BOE, for the nine months ended September 30, 2015.

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 need for a full-cost ceiling impairment is required to be assessed on a quarterly basis. 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 have also declined significantly. At September 30, 2015, these average oil and natural gas prices were $55.73 per barrel and $3.06 per MMBtu, respectively, as compared to $91.48 per barrel and $4.35 per MMBtu at December 31, 2014. This decline in the unweighted arithmetic average commodity prices of approximately $36 per barrel of oil and $1.29 per MMBtu of natural gas had a significant impact on the overall 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 27% in the first nine months of 2015, the PV-10 of its proved reserves decreased by 34% from $1.04 billion at December 31, 2014 to $0.69 billion at September 30, 2015. As a result, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $252.4 million at September 30, 2015. Matador recorded a non-cash impairment charge of $285.7 million to its net capitalized costs and a deferred income tax credit of $33.3 million related to the full-cost ceiling limitation for the three months ended September 30, 2015. These charges are reflected in the Company’s unaudited condensed consolidated statement of operations for the three months ended September 30, 2015. For the nine months ended September 30, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $441.5 million. Matador recorded a non-cash impairment charge of $581.9 million to its net capitalized costs and a deferred income tax credit of $140.3 million for the nine months ended September 30, 2015. It is important to note that this impairment charge reflects the sharp decline in commodity prices and had the weighted average oil and natural gas prices used to estimate total proved reserves remained unchanged since December 31, 2014, the PV-10 of Matador’s proved oil and natural gas reserves would have been approximately $1.7 billion, and no full-cost impairment would have been required. Given current commodity prices, the Company 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.

General and administrative (“G&A”)

General and administrative expenses increased 50% on an absolute basis, but decreased 8% on a unit-of-production basis, from $8.1 million, or $5.47 per BOE, for the three months ended September 30, 2014 to $12.2 million, or $5.05 per BOE, for the three months ended September 30, 2015. The increase in G&A expenses was largely attributable to increased payroll expenses associated with increases in the Company’s full-time staff by 46 employees between the respective periods to support increased land, geoscience, drilling, completion, production, accounting and administration functions. These 46 additional employees included the addition of 29 new employees in Roswell, New Mexico as a result of the HEYCO merger in late February. General and administrative expenses

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also included non-cash stock-based compensation expense of $1.8 million for the three months ended September 30, 2015, as compared to $1.0 million for the three months ended September 30, 2014. While general and administrative expenses increased 50% on an absolute basis, G&A expenses decreased by 8% on a unit-of-production basis, primarily as a result of the increased total oil equivalent production between the respective periods.

General and administrative expenses increased 65% on an absolute basis, but decreased 6% on a unit-of-production basis, from $23.4 million, or $5.92 per BOE, for the nine months ended September 30, 2014 to $38.5 million, or $5.55 per BOE, for the nine months ended September 30, 2015.

Proved Reserves and PV-10

The following table summarizes Matador’s estimated total proved oil and natural gas reserves at September 30, 2015, December 31, 2014 and September 30, 2014.

	September 30,   2015			December 31, 2014			September 30,   2014
Estimated proved reserves:(1)(2)
Oil (MBbl)(3)	42,531			24,184			21,519
Natural Gas (Bcf)(4)	267.5			267.1			236.7
Total (MBOE)(5)	87,109			68,693			60,969
Estimated proved developed reserves:
Oil (MBbl)(3)	17,413			14,053			12,192
Natural Gas (Bcf)(4)	97.7			102.8			78.3
Total (MBOE)(5)	33,685			31,185			25,242
Percent developed	38.7		%	45.4		%	41.4		%
Estimated proved undeveloped reserves:
Oil (MBbl)(3)	25,118			10,131			9,327
Natural Gas (Bcf)(4)	169.8			164.3			158.4
Total (MBOE)(5)	53,424			37,508			35,727
PV-10 (in millions)(6)	$	692.7		$	1,043.4		$	952.0
Standardized Measure (in millions)	$	673.8		$	913.3		$	835.1
(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 October 2014 through September 2015 were $55.73 per Bbl for oil and $3.06 per MMBtu for natural gas, for the period from January 2014 through December 2014 were $91.48 per Bbl for oil and $4.35 per MMBtu for natural gas and for the period from October 2013 through September 2014 were $95.56 per Bbl for oil and $4.24 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 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 87.1 million BOE at September 30, 2015, including 42.5 million barrels of oil and 267.5 billion cubic feet of natural gas, with a PV-10, a non-GAAP financial measure, of $0.69 billion (Standardized Measure of $0.67 billion), an increase of 27% as compared to estimated total proved oil and natural gas reserves of 68.7 million BOE at December 31, 2014, including 24.2 million barrels

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of oil and 267.1 billion cubic feet of natural gas, with a PV-10 of $1.04 billion (Standardized Measure of $0.91 billion), and an increase of 43% as compared to 61.0 million BOE at September 30, 2014, including 21.5 million barrels of oil and 236.7 billion cubic feet of natural gas, with a PV-10 of $0.95 billion (Standardized Measure of $0.84 billion).

Proved oil reserves increased 76% from 24.2 million barrels at December 31, 2014 to 42.5 million barrels at September 30, 2015, and approximately doubled year-over-year from 21.5 million barrels at September 30, 2014. At September 30, 2015, approximately 49% of the Company’s total proved reserves were oil and 51% were natural gas. By comparison, at September 30, 2014, approximately 35% of the Company’s total proved reserves were oil and 65% were natural gas. The proved developed component of Matador’s total proved reserves was 39% at September 30, 2015 as compared to 41% at September 30, 2014.

The PV-10 of $0.69 billion at September 30, 2015, based on SEC pricing, was a 27% year-over-year decrease as compared to $0.95 billion at September 30, 2014, which reflects the sharp decline in the unweighted arithmetic oil and natural gas prices used to estimate proved reserves between the respective periods. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used in preparing these estimates were $55.73 per barrel and $3.06 per MMBtu, respectively, for the 12 months ended September 30, 2015, as compared to $95.56 per barrel and $4.24 per MMBtu, respectively, for the 12 months ended September 30, 2014. The 43% increase in Matador’s total proved reserves over the past year served to mitigate the decline in commodity prices used to estimate these reserves. The PV-10 of $0.69 billion at September 30, 2015, based on SEC pricing, was a 34% decrease as compared to $1.04 billion at December 31, 2014. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used in preparing these estimates were $91.48 per barrel and $4.35 per MMBtu, respectively, for the 12 months ended December 31, 2014. These average oil and natural gas prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the oil and natural gas prices received at the wellhead. As a result of the sharp decline in commodity prices used to estimate proved reserves at September 30, 2015, certain of the Company’s proved undeveloped reserves, in particular, natural gas proved undeveloped reserves in portions of the Haynesville shale, were reclassified to contingent resources and are no longer considered proved reserves under SEC guidelines.

Matador reports its production and estimated proved reserves in two streams: an oil stream and a natural gas stream, which includes both dry natural gas and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, as it does in the Eagle Ford shale in South Texas and the Permian Basin in Southeast New Mexico and West Texas, the economic value of the natural gas liquids associated with the natural gas is included as an uplift to the estimated natural gas wellhead price on those properties where the natural gas liquids are extracted and sold. The reserves estimates in all periods presented were prepared by the Company’s internal engineering staff and audited by an independent reservoir engineering firm, Netherland, Sewell & Associates, Inc. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting and do not include any unproved reserves classified as probable or possible that might exist on Matador’s properties.

As a result of its drilling, completion and delineation activities in West Texas and Southeast New Mexico in 2014 and the first nine months of 2015, including the addition of the HEYCO properties in the first quarter of 2015, Matador’s Delaware Basin oil and natural gas reserves continue to become a more significant component of the Company’s total oil and natural gas reserves. Matador’s estimated Delaware Basin proved oil and natural gas reserves have increased over five-fold from 7.8 million BOE at September 30, 2014, or only 13% of the Company’s total proved oil and natural gas reserves, including 5.0 million barrels of oil and 16.7 billion cubic feet of natural gas, to 39.6 million BOE, or 46% of the Company’s total proved oil and natural gas reserves, including 25.6 million barrels of oil and 84.0 billion cubic feet of natural gas, at September 30, 2015.

For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.

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Operations Update

At the beginning of 2015, Matador was operating five drilling rigs, two rigs in the Eagle Ford and three rigs in the Permian (Delaware) Basin, but reduced the number of operated drilling rigs from five to two by the end of the first quarter of 2015. These two rigs are state-of-the-art and specially built for the Company for its Delaware Basin operations. In late July 2015, Matador took delivery of a third state-of-the-art, specially built drilling rig in the Delaware Basin which began batch drilling a series of three stacked, horizontal wells from a single pad in the Company’s Jackson Trust prospect area in northeast Loving County, Texas testing the Brushy Canyon, Avalon and Second Bone Spring formations. At November 4, 2015, these three wells had been drilled and just recently completed, but were not yet flowing back after stimulation.

At November 4, 2015, Matador continued to operate three rigs full-time in the Delaware Basin. One rig is currently drilling two Wolfcamp “A”/“X-Y” wells from a single pad on the Johnson lease in the Wolf prospect in Loving County, Texas. The second rig is drilling a Wolfcamp “A”/“Y” test near the center of the Company’s Rustler Breaks prospect in Eddy County, New Mexico. The third rig has just begun drilling a vertical pilot hole in Matador’s Twin Lakes prospect area in northern Lea County, New Mexico, where the Company will gather a full suite of openhole well logs and both whole core and rotary sidewall core samples in preparation for drilling a horizontal lateral in the Twin Lakes area during 2016.

Permian (Delaware) Basin - Southeast New Mexico and West Texas

During the third quarter of 2015, Matador completed and began producing oil and natural gas from 11 gross (4.7 net) wells in the Permian Basin, including 4 gross (4.0 net) operated wells and 7 gross (0.7 net) non-operated wells, throughout its various prospect areas. As of the end of the third quarter, Matador had drilled an additional five wells that were in the process of completion, including two Wolfcamp “A”/“Y” wells on the Billy Burt leasehold in its Wolf prospect area and the three-well batch at Jackson Trust mentioned above.

As a result of Matador’s ongoing drilling and completion operations in its various prospect areas, its Delaware Basin production has increased sharply over the past twelve months. Total Delaware Basin production for the third quarter of 2015 was 7,551 BOE per day (consisting of 5,489 barrels of oil per day and 12.4 million cubic feet of natural gas per day), an almost four-fold increase from production of 2,084 BOE per day (consisting of 1,486 barrels of oil per day and 3.6 million cubic feet of natural gas per day) in the third quarter of 2014. The Permian Basin contributed approximately 44% of Matador’s daily oil production and approximately 15% of daily natural gas production in the third quarter of 2015, as compared to only about 16% of daily oil production and approximately 9% of daily natural gas production in the third quarter of 2014.

Matador continues to be pleased with its progress in reducing drilling times and well costs for both Wolfcamp and Bone Spring horizontal wells. The Company’s focus on improving drilling times and operational efficiencies has cut drilling times by as much as 50% or more on recent Wolfcamp wells in the Wolf and Rustler Breaks prospect areas as compared to earlier wells drilled in these prospect areas. In the Wolf prospect area in Loving County, Texas, for example, Wolfcamp drilling times (spud to total depth) have been reduced from an average of 43 days in 2014 to as low as 22 days on recent wells. In the Rustler Breaks prospect area in Eddy County, New Mexico, where the Wolfcamp formation is shallower, Wolfcamp drilling times have been reduced from an average of 32 days in 2014 and early 2015 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 only 12 days, making it the fastest horizontal Second Bone Spring well the Company has drilled to date. These increased drilling efficiencies are the result of a number of factors such as Company-supported modifications to its contracted drilling rigs including 7,500 psi circulating systems, simultaneous operating capabilities, integrated equipment upgrades and other efficiency-related modifications, as well as more experienced personnel on each rig, improved bit designs and the ability to start drilling wells in “batch” mode in some areas. Matador believes not only that these efficiencies are sustainable, but also that it will continue to improve drilling times going forward, particularly as it moves into more of a development mode in these prospect areas.

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These increased drilling and completion efficiencies, coupled with service cost reductions of varying amounts, have continued to reduce overall well costs significantly. Recent Wolfcamp wells in the Wolf prospect area have been drilled and completed for approximately $7 to $8 million, as compared to $10 to $12 million in 2014 and early 2015. In the Rustler Breaks prospect area, Wolfcamp drilling and completion costs have been reduced to between $5.8 and $6.5 million per well, and the Company’s most recent Bone Spring well in this area was drilled and completed for approximately $4 million. These well costs are substantially reduced from those of initial wells drilled in these areas and are less than the well costs originally budgeted in early 2015 for many of these wells.

Matador also continues to make significant progress with its midstream operations. On September 15, 2015, Matador announced 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. 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 is currently disposing of about 20,000 barrels per day of salt water at this facility, with a total savings to Matador of more than $4 million in salt water disposal costs since it began operations in January 2015. In addition, the joint venture entity began disposing of third-party salt water on a commercial basis early in the fourth quarter of 2015.

Given its recent drilling success in the Rustler Breaks prospect area in Eddy County, New Mexico coupled with the sale of its natural gas processing facility in Loving County, Texas, Matador now plans to construct another cryogenic natural gas processing plant, as well as natural gas, oil and water gathering systems in the Rustler Breaks area to support its future development plans there. The Rustler Breaks natural gas processing plant is anticipated to be larger than the Loving County plant with a projected inlet capacity of approximately 60 million cubic feet of natural gas per day. Matador expects this facility to come on line during the third quarter of 2016.

Wolf/Loving Prospect Area - Loving County, Texas

Matador is currently operating one rig in its Wolf prospect area in Loving County, Texas and plans to continue operating at least one rig in this area for the remainder of 2015 and into 2016. Matador continues to be pleased with the results of its ongoing development efforts in the Wolfcamp “A”/“X” and “Y” sands and with the relative consistency of the estimated ultimate recoveries from these wells, typically in the range of 650,000 to 1.1 million BOE. During the third quarter of 2015, the Company completed and began producing oil and natural gas from two Wolfcamp wells in this prospect, both on its Barnett lease—the Barnett 90-TTT-B01 WF #202H, a Wolfcamp “A”/“X” completion and the Barnett 90-TTT-B01 WF #206H well, a Wolfcamp “A”/“Y” completion.

The Barnett wells were 80-acre offsets drilled from a single pad using batch mode drilling operations. The Barnett 90-TTT-B01 WF #202H well (Wolfcamp “A”/“X”) tested 1,047 BOE per day (54% oil) during a 24-hour initial potential test, consisting of 561 barrels of oil per day and 2.9 million cubic feet of natural gas per day at 3,200 psi on a 26/64-inch choke. The Barnett 90-TTT-B01 WF #206H well (Wolfcamp “A”/“Y”) tested 1,127 BOE per day (55% oil), consisting of 615 barrels of oil per day and 3.1 million cubic feet of natural gas per day at 3,400 psi on a 24/64-inch choke. These results were very consistent with the first two wells drilled and completed on the Barnett lease during the first quarter of 2015—the Barnett 90-TTT-B01 WF #201H, a Wolfcamp “A”/“X” completion, and the Barnett 90-TTT-B01 WF #205H well, a Wolfcamp “A”/“Y” completion.

In late October 2015, Matador completed and began producing oil and natural gas from two additional wells in the far northwest portion of its Wolf prospect—the Billy Burt 90-TTT-B33 WF #201H well and the Billy Burt 90-TTT-B33 WF #204H well. Both wells were drilled in the Wolfcamp “A”/“Y” sand and have completed lateral lengths of 6,725 feet and 4,775 feet respectively. These wells are flowing back and continuing to clean up following stimulation. The Billy Burt 90-TTT-B33 WF #201H well is testing 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 26/64-inch choke. The Billy Burt 90-TTT-B33 WF #204H well is testing about 750 BOE per day (67% oil), consisting of about 500 barrels of oil per day and 1.6 million cubic feet of natural gas per day at almost 2,500 psi on a 26/64-inch

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choke. Again, these results are very consistent with the two earlier wells completed on the Billy Burt lease—the Billy Burt 90-TTT-B33 WF #202H and the Billy Burt 90-TTT-B33 WF #203H wells, both of which were Wolfcamp “A”/“X” completions. Matador projects the estimated ultimate recovery from both Wolfcamp “A”/“X” wells at approximately 700,000 BOE as of the end of the third quarter of 2015.

In October 2015, Matador began drilling two additional wells on its Wolf prospect—the Johnson 44-02S-B53 WF #202H well and the Johnson 44-02S-B53 WF #206H well. These wells are 80-acre offset wells on a single drilling pad and are being drilled using batch-mode drilling operations. The Johnson 44-02S-B53 WF #202H well is targeting the Wolfcamp “A”/“X” sand, and Matador currently expects this well to be both the fastest and the least expensive Wolfcamp well it will have drilled in the Wolf prospect area. The Johnson 44-02S-B53 WF #206H well is targeting the Wolfcamp “A”/“Y” sand and is also drilling faster than expected to date. After these two Johnson wells are drilled and completed, Matador expects to begin drilling a series of four, stacked horizontal wells from a single pad (the Dick Jay wells) testing the Second Bone Spring, Wolfcamp “A”/“X”, Wolfcamp “A”/“Y” and a deeper, more organically-rich interval of the Wolfcamp “A”.

Rustler Breaks Prospect Area - Eddy County, New Mexico

Matador completed and began producing oil and natural gas from one well in the Rustler Breaks prospect area in Eddy County, New Mexico in the third quarter of 2015. The Company initially drilled the Scott Walker State 36-22S-27E RB #204H as a vertical pilot hole through the lower Wolfcamp formation to collect a full suite of openhole logs and then drilled and completed a horizontal lateral in the Wolfcamp “A”/“X-Y” sand. This well was located in the far northwestern portion of Matador’s Rustler Breaks prospect area and was completed using Matador’s “micro-coupled” Generation 2 Wolfcamp frac design with 2,000 pounds of sand per foot and 30 barrels of fracturing fluid per foot. The Scott Walker State 36-22S-27E RB #204H well tested 504 BOE per day (70% oil), consisting of 354 barrels of oil per day and 0.9 million cubic feet of natural gas per day at 1,100 psi on a 32/64-inch choke. Although this well did not test at rates as high as Matador’s Wolfcamp “A”/“X-Y” tests in the southeastern part of the Rustler Breaks area—the Guitar 10-24S-28E RB #204H and Tiger 14-24S-28E RB #204H wells—the Company is encouraged by these results as they establish the prospectivity of the Wolfcamp “A”/“X-Y” interval across its Rustler Breaks acreage position. To Matador’s knowledge, this is the northernmost horizontal test of the Wolfcamp “A”/“X-Y” sand to date in Eddy County, New Mexico.

Matador’s four previous Wolfcamp completions in the Rustler Breaks prospect, two Wolfcamp “A”/“X-Y” and two Wolfcamp “B” completions, all continue to perform very well. As of the end of the third quarter of 2015, Matador continued to estimate ultimate recoveries from these wells from 700,000 to just over 1.0 million BOE. In addition to these wells, Matador also participated in two non-operated Second Bone Spring wells drilled and completed by an affiliate of Chevron Corporation in the far southern portion of its Rustler Breaks prospect area during the third quarter of 2015. These two wells, the White City #5H and White City #6H wells, both tested between 1,100 and 1,200 BOE per day at an approximately 77% oil cut. Matador owns a 12.5% working interest in each of these wells.

At November 4, 2015, Matador had completed drilling two new wells in the Rustler Breaks prospect area which are just beginning to clean up and flow back following stimulation. The Janie Conner 13-24S-28E RB #224H and Janie Conner 13-24S-28E RB #124H wells are stacked laterals targeting the Wolfcamp “B” and Second Bone Spring, respectively. Of particular note, Matador stimulated the Janie Conner 13-24S-28E RB #224H well with increased sand concentrations of up to 3,000 pounds of sand per foot to observe the impact of higher sand concentrations on well performance; previously, Matador has pumped about 2,000 pounds per foot of completed lateral in its Wolfcamp completions. In addition, the Janie Conner 13-24S-28E RB #124H well was drilled through the Second Bone Spring in approximately 12 days from spud to total depth with a total measured depth of approximately 13,200 feet and a completable horizontal lateral length of approximately 4,500 feet. This is the fastest Second Bone Spring well drilled by Matador in this area to date, and the Company estimates total drilling and completion costs for this well at approximately $4 million, which is also the least expensive Second Bone Spring well drilled thus far on its Delaware Basin acreage.

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Ranger Prospect Area - Lea County, New Mexico and Arrowhead Prospect Area - Eddy County, New Mexico

During the third quarter of 2015, Matador did not drill and complete any operated wells in its Ranger or Arrowhead prospect areas in Lea and Eddy Counties, New Mexico, respectively. (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 early October 2015, however, Matador moved one rig from its Wolf/Loving prospect area in Loving County, Texas and a second rig from its Rustler Breaks prospect area in Eddy County, New Mexico to the Ranger prospect area in Lea County, New Mexico. In early November, the Company finished its drilling operations on both the Hibiscus 08-19S-35E RN State Com #124H well and the Conine 03-20S-35E RN #121H well—each of which are horizontal wells targeting the Second Bone Spring sand.

Matador has also participated in several recent non-operated horizontal wells in its Ranger and Arrowhead prospect areas. In the Ranger area during the third quarter of 2015, Matador participated in the Iggles 21-16 State Com #1H, a Second Bone Spring test operated by an affiliate of Concho Resources, Inc. (“Concho”) in the northern part of Matador’s Ranger acreage adjacent to its Pickard State 20-18S-34E RN #121H well. The Iggles 21-16 State Com #1H well had a completed lateral length of approximately 6,700 feet and tested between 1,200 and 1,300 BOE per day (90% oil) from the Second Bone Spring. Matador owns a 33% working interest in this well. At the time of its merger with HEYCO, Matador previously reported the results of two additional non-operated wells drilled by Concho in Matador’s Arrowhead prospect area. These wells, the CTA State Com #3H and #4H wells, were both Second Bone Spring completions and tested 992 BOE per day (84% oil) and 1,063 BOE per day (78% oil), respectively. Subsequent to these wells, Matador also participated in two additional Concho-operated wells in this area, the CTA State Com #5H and the CTA State Com #6H wells. These wells were also Second Bone Spring completions and tested 640 BOE per day (92% oil) and 1,130 BOE per day (88% oil), respectively. Matador owns an approximate 15% working interest in each of these four wells. Matador has also participated with Mewbourne Oil Company, Inc. in its Gobbler 5 B2PM #1H well in the Arrowhead prospect area. This well, a Second Bone Spring completion, tested 2,300 BOE per day (80% oil), and Matador owns a 6% working interest in this well. More importantly, Matador operates the section directly offsetting the Gobbler 5 B2PM #1H well to the west. Matador expects to begin drilling operated wells in this section and others in its Arrowhead prospect area during 2016, and results like these continue to illustrate the quality and prospectivity of the Company’s acreage in this area.

Eagle Ford Shale - South Texas

During the second quarter of 2015, Matador completed its planned Eagle Ford drilling and completion operations for 2015. The Company does not plan to drill or complete any additional wells in the Eagle Ford shale during the remainder of 2015. Matador did acquire approximately 385 gross (385 net) acres of additional leasehold in the Eagle Ford during the third quarter of 2015 adjacent to its Sickenius properties in Karnes County, Texas.

Haynesville Shale - Northwest Louisiana and East Texas

The Company participated in two gross (0.4 net) non-operated Haynesville shale 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 during the third quarter of 2015. Both wells came on production at 12 to 14 million cubic feet of natural gas per day (about 5.7 million cubic feet of natural gas per day net to Matador’s interest). Drilling and completion costs for these wells continued to be in the range of $7 to $7.5 million. Matador’s combined Haynesville and Cotton Valley natural gas production for the third quarter of 2015, primarily in Northwest Louisiana, was approximately 51.3 million cubic feet per day, a sequential increase of 1% from 50.5 million cubic feet per day in the second quarter of 2015 and a year-over-year increase of 137% from 21.6 million cubic feet per day in the third quarter of 2014. Matador continues to participate in ongoing, non-operated, Haynesville drilling and completion operations being conducted by Chesapeake in this area. At November 4, 2015, there are 12 gross (2.5 net) wells in progress in Matador’s Elm Grove area; these wells are scheduled to be completed and placed on production late in the fourth quarter of 2015 or early in the first quarter of 2016.

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Permian Basin Acreage Acquisitions

At December 31, 2014, Matador held 92,700 gross (66,100 net) acres in the Permian Basin, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. Between January 1 and November 4, 2015, the Company added approximately 66,000 gross (24,600 net) acres in Southeast New Mexico and West Texas, bringing Matador’s total Permian Basin acreage position to 158,700 gross (90,700 net) acres. At November 4, 2015, these acreage totals included approximately 32,300 gross (19,700 net) acres in Matador’s Ranger prospect area in Lea County, 47,400 gross (17,100 net) acres in its Arrowhead prospect in Eddy County, 20,700 gross (13,500 net) acres in its Rustler Breaks prospect area in Eddy County, 11,500 gross (7,300 net) acres in its Wolf and Jackson Trust prospect areas in Loving County and 42,900 gross (30,000 net) acres in its Twin Lakes prospect area in Lea County. Much of the acreage that Matador acquired in the merger with HEYCO in February 2015 (the “HEYCO merger”) that was previously included with the Company’s Rustler Breaks and Ranger prospect areas is now being included in the Company’s Arrowhead prospect area.

Liquidity Update

On September 15, 2015, Matador announced the sale of a portion of its midstream assets including certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas to EnLink for approximately $143 million in an all-cash transaction that closed on October 1, 2015. As a result of the closing of the EnLink transaction on October 1, the cash proceeds from the sale are not reflected in the Company’s financial statements for the three and nine months ended September 30, 2015.

At September 30, 2015, prior to the closing of the sale of its midstream assets in Loving County, Texas, the Company had cash totaling $13.9 million. At both September 30, 2015 and November 4, 2015, the Company had no borrowings outstanding and $0.6 million in outstanding letters of credit pursuant to its credit facility and $400.0 million of outstanding senior unsecured notes.

Effective October 16, 2015, Matador amended its revolving credit facility to extend the maturity date from December 29, 2016 to October 16, 2020. In connection with this amendment, Matador’s lenders unanimously reaffirmed the borrowing base under the revolving credit facility at $375.0 million, and the maximum facility amount remained unchanged at $500.0 million.

As of November 4, 2015, the Company believes it is well positioned with approximately $115 million in cash on hand and almost $500 million in liquidity and has ample liquidity and cash flow to optimize its opportunity set for the rest of 2015 and through 2016, which, of course, will be closely tied to the prices of oil and natural gas.

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 October 27, 2015, Matador had the following hedges in place, in the form of costless collars and swaps, for November and December of 2015.

• Approximately 0.5 million barrels of oil at a weighted average floor price of $67 per barrel and a weighted average ceiling price of $85 per barrel.

• Approximately 2.6 billion cubic feet of natural gas at a weighted average floor price of $3.32 per MMBtu and a weighted average ceiling price of $4.02 per MMBtu.

• Approximately 0.6 million gallons of natural gas liquids at a weighted average price of $1.02 per gallon.

Matador estimates that it now has approximately 80% of its anticipated oil production and approximately 65% of its anticipated natural gas production hedged for the months of November and December 2015 based on the midpoint of its revised production guidance (see below).

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At October 27, 2015, Matador had the following hedges in place, in the form of costless collars and swaps, for 2016. The Company has no hedges in place beyond 2016.

• Approximately 1.6 million barrels of oil at a weighted average floor price of $47 per barrel and a weighted average ceiling price of $75 per barrel.

• Approximately 8.4 billion cubic feet of natural gas at a weighted average floor price of $2.75 per MMBtu and a weighted average ceiling price of $3.80 per MMBtu.

2015 Guidance Update

At November 4, 2015, Matador increased its full-year 2015 natural gas production guidance from 26.0 to 27.0 billion cubic feet to 27.0 to 28.0 billion cubic feet. Matador reaffirmed all other full-year 2015 guidance estimates as revised upwards on August 4, 2015 including (1) capital expenditures of $425 million (excluding capital expenditures associated with the HEYCO merger), (2) oil production of 4.4 to 4.5 million barrels, (3) oil and natural gas revenues of $290 to $300 million and (4) Adjusted EBITDA of $220 to $230 million. Oil and natural gas revenues and Adjusted EBITDA guidance are based on estimated average realized oil and natural gas prices, excluding hedging gains and losses, of $50.00 per barrel and $3.00 per thousand cubic feet for the final three months of 2015.

Conference Call Information

The Company will host a live conference call on Thursday, November 5, 2015, at 9:00 a.m. Central Time to review third quarter 2015 financial results and operational highlights. To access the conference call, domestic participants should dial (855) 875-8781 and international participants should dial (720) 634-2925. The participant passcode is 69383877. The conference call will also be available through the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab. The replay for the event will be available on the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab through Monday, November 30, 2015.

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 Permian (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” 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,

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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 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

Investor Relations

(972) 371-5225

mschmitz@matadorresources.com

20

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED

(In thousands, except par value and share data)		September 30, 2015			December 31, 2014
	ASSETS
	Current assets
	Cash	$	13,887		$	8,407
	Restricted cash	450			609
	Accounts receivable
	Oil and natural gas revenues	23,743			28,976
	Joint interest billings	13,361			6,925
	Other	9,426			9,091
	Derivative instruments	28,165			55,549
	Assets held for sale	32,413			—
	Lease and well equipment inventory	2,106			1,212
	Prepaid expenses	2,989			1,649
	Total current assets	126,540			112,418
	Property and equipment, at cost
	Oil and natural gas properties, full-cost method
	Evaluated	2,018,241			1,617,913
	Unproved and unevaluated	392,299			264,419
	Other property and equipment	60,589			43,472
	Less accumulated depletion, depreciation and amortization	(1,329,082		)	(603,732		)
	Net property and equipment	1,142,047			1,322,072
	Other assets
	Derivative instruments	2,028			—
	Deferred income taxes	9,676			—
	Other assets	231			—
	Total other assets	11,935			—
	Total assets	$	1,280,522		$	1,434,490
	LIABILITIES AND SHAREHOLDERS’ EQUITY
	Current liabilities
	Accounts payable	$	16,012		$	17,526
	Accrued liabilities	102,327			109,502
	Royalties payable	21,737			14,461
	Advances from joint interest owners	306			—
	Amounts due to Joint Ventures	2,250			—
	Deferred income taxes	10,426			19,751
	Income taxes payable	—			444
	Other current liabilities	223			103
	Total current liabilities	153,281			161,787
	Long-term liabilities
	Borrowings under Credit Agreement	—			338,199
	Senior unsecured notes payable	390,959			—
	Asset retirement obligations	13,413			11,640
	Amounts due to Joint Ventures	4,500			—
	Deferred income taxes	—			53,783
	Other long-term liabilities	1,765			2,540
	Total long-term liabilities	410,637			406,162
	Shareholders’ equity
	Common stock - $0.01 par value, 120,000,000 and 80,000,000 shares authorized; 85,687,475 and 73,373,744 shares issued; and 85,520,957 and 73,342,777 shares outstanding, respectively	857			734
	Additional paid-in capital	1,023,425			724,819
	Retained (deficit) earnings	(308,529		)	140,855
	Total Matador Resources Company shareholders’ equity	715,753			866,408
	Non-controlling interest in subsidiary	851			133
	Total shareholders’ equity	716,604			866,541
	Total liabilities and shareholders’ equity	$	1,280,522		$	1,434,490

21

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED

(In thousands, except per share data)		Three Months Ended   September 30,						Nine Months Ended   September 30,
		2015			2014			2015			2014
	Revenues
	Oil and natural gas revenues	$	71,815		$	96,617		$	222,128		$	274,605
	Realized gain (loss) on derivatives	19,862			(701		)	52,146			(5,458		)
	Unrealized gain (loss) on derivatives	6,733			16,293			(25,356		)	7,950
	Total revenues	98,410			112,209			248,918			277,097
	Expenses
	Production taxes and marketing	9,291			8,617			26,598			23,739
	Lease operating	14,917			13,691			42,912			34,747
	Depletion, depreciation and amortization	45,237			35,143			143,477			90,970
	Accretion of asset retirement obligations	182			130			427			371
	Full-cost ceiling impairment	285,721			—			581,874			—
	General and administrative	12,151			8,099			38,523			23,417
	Total expenses	367,499			65,680			833,811			173,244
	Operating (loss) income	(269,089		)	46,529			(584,893		)	103,853
	Other income (expense)
	Net loss on asset sales and inventory impairment	—			—			(97		)	—
	Interest expense	(7,229		)	(673		)	(15,168		)	(3,685		)
	Interest and other income	999			267			1,885			715
	Total other expense	(6,230		)	(406		)	(13,380		)	(2,970		)
	(Loss) income before income taxes	(275,319		)	46,123			(598,273		)	100,883
	Income tax (benefit) provision
	Current	(295		)	(156		)	(295		)	2,658
	Deferred	(33,010		)	16,660			(148,750		)	34,017
	Total income tax (benefit) provision	(33,305		)	16,504			(149,045		)	36,675
	Net (loss) income	(242,014		)	29,619			(449,228		)	64,208
	Net income attributable to non-controlling interest in subsidiary	(45		)	—			(156		)	—
	Net (loss) income attributable to Matador Resources Company shareholders	$	(242,059	)	$	29,619		$	(449,384	)	$	64,208
	Earnings (loss) per common share
	Basic	$	(2.86	)	$	0.40		$	(5.58	)	$	0.93
	Diluted	$	(2.86	)	$	0.40		$	(5.58	)	$	0.92
	Weighted average common shares outstanding
	Basic	84,685			73,341			80,481			69,185
	Diluted	84,685			74,028			80,481			69,879

22

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED

(In thousands)		Nine Months Ended   September 30,
		2015			2014
	Operating activities
	Net (loss) income	$	(449,228	)	$	64,208
	Adjustments to reconcile net (loss) income to net cash provided by operating activities
	Unrealized loss (gain) on derivatives	25,356			(7,950		)
	Depletion, depreciation and amortization	143,477			90,970
	Accretion of asset retirement obligations	427			371
	Full-cost ceiling impairment	581,874			—
	Stock-based compensation expense	6,886			4,665
	Deferred income tax (benefit) provision	(148,750		)	34,017
	Amortization of debt issuance cost (non-cash interest expense)	551			—
	Net loss on asset sales and inventory impairment	97			—
	Changes in operating assets and liabilities
	Accounts receivable	1,997			(12,605		)
	Lease and well equipment inventory	(225		)	(193		)
	Prepaid expenses	(329		)	(74		)
	Other assets	665			(810		)
	Accounts payable, accrued liabilities and other current liabilities	16,863			(820		)
	Royalties payable	6,898			6,175
	Advances from joint interest owners	306			—
	Income taxes payable	(444		)	2,565
	Other long-term liabilities	(497		)	(160		)
	Net cash provided by operating activities	185,924			180,359
	Investing activities
	Oil and natural gas properties capital expenditures	(334,951		)	(407,023		)
	Expenditures for other property and equipment	(46,738		)	(2,906		)
	Business combination, net of cash acquired	(24,028		)	—
	Restricted cash in less-than-wholly-owned subsidiaries	158			—
	Net cash used in investing activities	(405,559		)	(409,929		)
	Financing activities
	Repayments of borrowings	(476,982		)	(180,000		)
	Borrowings under Credit Agreement	125,000			230,000
	Proceeds from issuance of senior unsecured notes	400,000			—
	Cost to issue senior unsecured notes	(9,479		)	—
	Proceeds from issuance of common stock	188,720			181,875
	Cost to issue equity	(1,151		)	(590		)
	Proceeds from stock options exercised	10			6
	Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiary	600			—
	Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries	(38		)	—
	Taxes paid related to net share settlement of stock-based compensation	(1,565		)	(285		)
	Net cash provided by financing activities	225,115			231,006
	Increase in cash	5,480			1,436
	Cash at beginning of period	8,407			6,287
	Cash at end of period	$	13,887		$	7,723

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

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	Three Months Ended									Nine Months Ended
(In thousands)	September 30, 2015			June 30, 2015			September 30, 2014			September 30, 2015			September 30, 2014
Unaudited Adjusted EBITDA Reconciliation to Net (Loss) Income:
Net (loss) income attributable to Matador Resources Company shareholders	$	(242,059	)	$	(157,091	)	$	29,619		$	(449,384	)	$	64,208
Interest expense	7,229			5,869			673			15,168			3,685
Total income tax (benefit) provision	(33,305		)	(89,350		)	16,504			(149,045		)	36,675
Depletion, depreciation and amortization	45,237			51,768			35,143			143,477			90,970
Accretion of asset retirement obligations	182			132			130			427			371
Full-cost ceiling impairment	285,721			229,026			—			581,874			—
Unrealized (gain) loss on derivatives	(6,733		)	23,532			(16,293		)	25,356			(7,950		)
Stock-based compensation expense	1,755			2,794			1,038			6,886			4,665
Net loss on asset sales and inventory impairment	—			—			—			97			—
Adjusted EBITDA	$	58,027		$	66,680		$	66,814		$	174,856		$	192,624

	Three Months Ended									Nine Months Ended
(In thousands)	September 30, 2015			June 30, 2015			September 30, 2014			September 30, 2015			September 30, 2014
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	72,535		$	20,043		$	66,883		$	185,924		$	180,359
Net change in operating assets and liabilities	(20,846		)	40,843			(586		)	(25,234		)	5,922
Interest expense, net of non-cash portion	6,678			5,869			673			14,617			3,685
Current income tax (benefit) provision	(295		)	—			(156		)	(295		)	2,658
Net income attributable to non-controlling interest in subsidiary	(45		)	(75		)	—			(156		)	—
Adjusted EBITDA	$	58,027		$	66,680		$	66,814		$	174,856		$	192,624

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 transaction costs for certain acquisitions along with the related tax effect 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.

25

	Three Months Ended September 30, 2015			Nine Months Ended September 30, 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	$	(242,059	)	$	(449,384	)
Total income tax benefit	(33,305		)	(149,045		)
Loss attributable to Matador Resources Company shareholders before taxes	(275,364		)	(598,429		)
Less non-recurring and unrealized charges to net income before taxes:
Full-cost ceiling impairment	285,721			581,874
Unrealized (gain) loss on derivatives	(6,733		)	25,356
Non-recurring transaction costs associated with the HEYCO merger	—			2,510
Adjusted income attributable to Matador Resources Company shareholders before taxes	3,624			11,311
Income tax expense	1,067			3,332
Adjusted net income attributable to Matador Resources Company shareholders	$	2,557		$	7,979
Basic weighted average shares outstanding, without participating securities	84,685			80,481
Dilutive effect of participating securities	756			743
Weighted average shares outstanding, including participating securities - basic	85,441			81,224
Dilutive effect of options, restricted stock units and preferred shares	167			703
Weighted average common shares outstanding - diluted	85,608			81,927
Adjusted earnings per share attributable to Matador Resources Company shareholders (non-GAAP)
Basic	$	0.03		$	0.10
Diluted	$	0.03		$	0.10

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 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 September 30, 2015			At December 31, 2014			At September 30, 2014
PV-10	$	692.7		$	1,043.4		$	952.0
Discounted future income taxes	(18.9		)	(130.1		)	(116.9		)
Standardized Measure	$	673.8		$	913.3		$	835.1

26

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									Nine Months Ended
	September 30, 2015			June 30, 2015			September 30, 2014			September 30, 2015			September 30, 2014
Cash Operating Expenses per BOE Reconciliation to Operating Expenses per BOE:
Total operating expenses (per BOE)(1)	$	33.92		$	37.16		$	44.27		$	36.23		$	43.70
Depletion, depreciation and amortization expenses (per BOE)	(18.81		)	(21.39		)	(23.73		)	(20.67		)	(23.00		)
Non-cash stock-based compensation expense (per BOE)	(0.73		)	(1.16		)	(0.70		)	(0.99		)	(1.18		)
Non-recurring transaction costs (per BOE)	—			(0.11		)	—			(0.36		)	—
Cash operating expenses (per BOE)	$	14.38		$	14.50		$	19.84		$	14.21		$	19.52
(1) Total does not include the impact of full-cost ceiling impairment charges or immaterial accretion expenses.

27

EX-99.2

November 4, 2015 Third Quarter 2015 Earnings Release NYSE: MTDR Exhibit 99.2

Disclosure Statements 2 Safe Harbor Statement – This presentation and statements made by representatives of Matador Resources Company (“Matador” or the “Company”) during the course of this presentation include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. “Forward-looking statements” are statements related to future, not past, events. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as “could,” “believe,” “would,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,” “predict,” “potential,” “project” and similar expressions that are intended to identify forward-looking statements, although not all forward- looking statements contain such identifying words. Actual results and future events could differ materially from those anticipated in such statements, and such forward-looking statements may not prove to be accurate. These forward-looking statements involve certain risks and uncertainties, including, but not limited to, the following risks related to Matador’s financial and operational performance: general economic conditions; Matador’s ability to execute its business plan, including whether Matador’s 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; Matador’s ability to replace reserves and efficiently develop its current reserves; Matador’s costs of operations, delays and other difficulties related to producing oil, natural gas and natural gas liquids; Matador’s ability to integrate the assets, employees and operations of Harvey E. Yates Company following its merger with one of Matador’s wholly-owned subsidiaries on February 27, 2015; Matador’s ability to make other acquisitions on economically acceptable terms; availability of sufficient capital to execute Matador’s business plan, including from its future cash flows, increases in Matador’s borrowing base and otherwise; weather and environmental conditions; and other important factors which could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. For further discussions of risks and uncertainties, you should refer to Matador’s SEC filings, including the “Risk Factors” section of Matador’s most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. Matador undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after the date of this presentation, 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 presentation. All forward-looking statements are qualified in their entirety by this cautionary statement. Cautionary Note – The Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. Potential resources are not proved, probable or possible reserves. The SEC’s guidelines prohibit Matador from including such information in filings with the SEC. Definitions – Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Matador’s production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where Matador produces liquids-rich natural gas, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. Estimated ultimate recovery (EUR) is a measure that by its nature is more speculative than estimates of proved reserves prepared in accordance with SEC definitions and guidelines and is accordingly less certain.

Key Accomplishments in Third Quarter 2015 3  Strong, better-than-expected quarterly oil, natural gas and total production in Q3 2015  Total BOE production of 2.41 million BOE, down 1% from Q2 2015, but up 62% year-over-year (“YoY”)  Total oil production of 1.16 million barrels, down 8% from Q2 2015, but up 38% YoY  Record total natural gas production of 7.5 Bcf, up 7% sequentially and up 94% YoY  Record oil, natural gas and total production for nine months ended September 30, 2015  Total BOE production of 6.94 million BOE, up 75% YoY  Total oil production of 3.43 million barrels (up 49% YoY) and total natural gas production of 21.1 Bcf (up 112% YoY)  Have exceeded oil, natural gas and total production for ALL of 2014  Sold Loving County natural gas processing plant and associated gathering assets to EnLink(1) for $143 million(2)  Retained infield natural gas gathering assets, oil and water gathering systems, and salt water disposal facility  Negotiated 15-year fixed fee agreement for priority one service for natural gas processing and gathering in Wolf prospect area  Transaction further enhances strong balance sheet with Net Debt to Adjusted EBITDA(3) of ~1.0 at closing on October 1  Borrowing base reaffirmed by lenders at $375 million based on June 30, 2015 reserves  Maturity of credit facility extended from December 2016 to October 2020  Currently have ~$500 million of combined liquidity from undrawn credit facility and proceeds from midstream sale  Continued solid execution in all operating areas  Delaware (Permian) – Drilling times and drilling and completion costs continue to improve; currently operating three rigs  Completed and began production on 11 gross (4.7 net) Delaware Basin wells, including 4 gross (4.0 net) operated and 7 gross (0.7 net) non-operated wells – up to 7 gross additional operated wells coming on line in October and early November  Haynesville – Haynesville/Cotton Valley production still over 50 MMcf/d  Two new Chesapeake-operated Haynesville wells completed and placed on production at Elm Grove in Q3 2015 with IPs ranging from 12 to 14 MMcf/d at flowing tubing pressures of 6,200 to 7,100 psi; costs approximately $7 to $7.5 million each (1) A subsidiary of EnLink Midstream Partners, LP (NYSE: ENLK) (2) Excluding customary purchase price adjustments. (3) Pro forma at September 30, 2015 for midstream sale on October 1, 2015. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see November 4, 2015 Press Release.

September 30, June 30, September 30, September 30, September 30, 2015 2015 2014 2015 2014 Net Production Volumes:(1) Oil production (MBbl) 1,161 1,260 839 3,429 2,302 Natural gas production (Bcf) 7.5 7.0 3.8 21.1 9.9 Total oil equivalent production (MBOE) 2,405 2,421 1,481 6,941 3,956 Average daily oil equivalent production (BOE/d) 26,137 26,601 16,096 25,427 14,490 Revenues and Average Sales Prices: Oil and natural gas revenues (in millions) 71.8$ 87.8$ 96.6$ 222.1$ 274.6$ Average realized oil price, $/Bbl 43.21$ 54.37$ 92.39$ 47.36$ 95.45$ Average realized natural gas price, $/Mcf 2.90$ 2.78$ 4.95$ 2.83$ 5.53$ Total realized revenues, with realized derivatives (in millions) 91.7$ 101.6$ 95.9$ 274.3$ 269.1$ Average realized oil price, with realized derivatives, $/Bbl 57.90$ 62.72$ 91.42$ 59.61$ 93.48$ Average realized natural gas price, with realized derivatives, $/Mcf 3.28$ 3.24$ 4.99$ 3.31$ 5.44$ Operating Expenses (per BOE): Production taxes and marketing 3.86$ 4.24$ 5.82$ 3.83$ 6.00$ Lease operating 6.20$ 6.18$ 9.25$ 6.18$ 8.78$ Depletion, depreciation and amortization 18.81$ 21.39$ 23.73$ 20.67$ 23.00$ General and administrative(2) 5.05$ 5.35$ 5.47$ 5.55$ 5.92$ Total operating expenses(3) 33.92$ 37.16$ 44.27$ 36.23$ 43.70$ Cash operating expenses(4) 14.38$ 14.50$ 19.84$ 14.21$ 19.52$ Earnings (loss) per diluted common share:(5) Earnings (loss) per diluted common share (5) (2.86)$ (1.89)$ 0.40$ (5.58)$ 0.92$ Adjusted earnings per diluted share (non-GAAP) (5)(6) 0.03$ 0.05$ N/A(7) 0.10$ N/A(7) Adjusted EBITDA(8) (in millions) 58.0$ 66.7$ 66.8$ 174.9$ 192.6$ Net Debt / LTM Adjusted EBITDA(8) 1.0(9) 1.4 1.0 1.0(9) 1.0 Three Months Ended Nine Months Ended Selected Operating and Financial Results 4 (1) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. (2) Includes approximately $0.73, $1.16, $0.70, $0.99 and $1.18 per BOE of non-cash, stock based compensation expense in the third quarter of 2015, the second quarter of 2015, the third quarter of 2015, the nine months ended September 30, 2015 and the nine months ended September 30, 2014. (3) Total does not include the impact of full-cost ceiling impairments or immaterial accretion expenses. (4) 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 November 4, 2015 Press Release. (5) Attributable to Matador Resources Company shareholders. (6) Adjusted earnings (loss) per common share is a non-GAAP financial measure. For a reconciliation of adjusted net income (non-GAAP) and adjusted earnings (loss) per common share (non-GAAP) to net income (GAAP) and earnings (loss) per common share (GAAP), please see November 4, 2015 Press Release. (7) Not calculated for three months and nine months ended September 30, 2014. (8) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see November 4, 2015 Press Release. (9) Pro forma at September 30, 2015 for midstream sale on October 1, 2015.

Matador’s Continued Growth in Production and Permian Position Average Daily Oil Production (Bbl/d) Average Daily Natural Gas Production (MMcf/d) Average Daily Total Production (MBOE/d) Total Permian Acreage (Net Acres) Growth since IPO Growth since IPO Growth since IPO Growth since IPO 3.9 7.0 9.0 11.7 16.1 23.5 26.6 26.1 2010 2011 2012 2013 2014 Q1 2015 Q2 2015 Q3 2015 91 422 3,317 5,843 9,095 11,206 13,847 12,617 2010 2011 2012 2013 2014 Q1 2015 Q2 2015 Q3 2015 23.0 39.8 34.1 35.4 41.9 73.8 76.5 81.1 2010 1 2 2013 2014 Q1 2015 Q2 2015 Q3 2015 6,700 7,600 44,800 66,100 90,700 2011 2 2013 2014 Today (1) (1) (1) (1) (2) (1) At December 31 of each respective year. (2) At November 4, 2015. 5

Permian Basin Acreage Position and Recent Test Results Note: All acreage at November 4, 2015. Some tracts not shown on map. 6 L E A LOVING WARD Matador Resources Acreage TWIN LAKES ~42,900 gross / ~30,000 net acres WOLF / LOVING AREA ~11,500 gross / ~7,300 net acres Jackson Trust RANGER ~32,300 gross / ~19,700 net acres ARROWHEAD ~47,400 gross / ~17,100 net acres E D D Y RUSTLER BREAKS ~20,700 gross / ~13,500 net acres Tiger/Guitar Wells Jackson Trust 3-well batch – Brushy, Avalon, 2nd BS In completion phase Hibiscus 08-19S-35E #124H – 2nd BS Waiting on completion Conine 03-20S-35E RN #121H – 2nd BS Waiting on completion Johnson 44-02S-B53 WF #202H & #206H – Wolfcamp A/X & A/Y Recently drilled Currently being drilled Significant non-op wells CTA State Com #3H & #4H – 2nd BS Concho (MRC: 15% WI) Tested = 992 & 1,063 BOE/d (~80% oil) White City #5H & #6H – 2nd BS Chevron (MRC: 12.5% WI) Tested = 1,100 – 1,200 BOE/d (~77% oil) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 19 20 17 18 Iggles 21-16 State Com #1H – 2nd BS Concho (MRC: 33% WI) Tested = 1,200 – 1,300 BOE/d (90% oil) Gobbler 5 B2PM #1H – 2nd BS Mewbourne (MRC: 6% WI) Tested = 2,300 BOE/d (80% oil) Scott Walker State 36-22S-27E RB #204H – Wolfcamp A/X-Y – IP = 504 BOE/d (70% oil) @ 1,100 psi on 32/64” choke Janie Conner 13-24S-28E RB #124H & #224H – 2nd BS, Wolfcamp B In completion phase CTA State Com #5H & #6H – 2nd BS Concho (MRC: 15% WI) Tested = 640 & 1,130 BOE/d (~90% oil) Billy Burt 90-TTT-B33 WF #201H & #204H – Wolfcamp A/Y Testing – 1,100 BOE/d (68% oil) & 800 BOE/d (67% oil) @ 2,500 psi on 26/64” choke Barnett 90-TTT-B01 WF #202H & #206H – Wolfcamp A/X & A/Y #202H (A/X) IP – 1,047 BOE/d (54% oil) @ 3,200 psi on 26/64” choke #206H (A/Y) IP – 1,127 BOE/d (55% oil) @ 3,400 psi on 24/64” choke Twin Lakes vertical pilot hole Wolfcamp A/X-Y well Pickard State 20-18S-34E RN#121H

Actual Previous Updated % YoY 2014 2015 Guidance(2) 2015 Guidance(3) Change Capital Spending $610 million $425 million(4) $425 million(4) - 30% Total Oil Production 3.3 million Bbl 4.4 to 4.5 million Bbl 4.4 to 4.5 million Bbl + 34% Total Natural Gas Production 15.3 Bcf 26.0 to 27.0 Bcf 27.0 to 28.0 Bcf + 80% Oil and Natural Gas Revenues $367.7 million $290 to $300 million $290 to $300 million - 20% Adjusted EBITDA(5) $262.9 million $220 to $230 million $220 to $230 million - 14% 7 2015 Guidance (As Updated November 4, 2015) (1) Shares outstanding at September 30, 2015 and share price as of November 3, 2015. (2) The Company raised its full-year 2015 guidance estimates on August 4, 2015. (3) Estimated 2015 oil and natural gas revenues and Adjusted EBITDA based upon the midpoint of 2015 guidance range as revised on November 4, 2015. Prices for oil and natural gas used in these estimates were $50.00/Bbl (WTI oil price of $55.00/Bbl less $5.00/Bbl differentials and transportation costs) and $3.00/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period October through December 2015 and weighted average realized prices for the period January through September 2015 of $47.36/Bbl and $2.83/Mcf. (4) Does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. (5) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see November 4, 2015 Earnings Release. Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 85.7 million common shares Share Price(1) $26.92/share Market Capitalization(1) $2.3 billion

0.0x 0.0x 0.1x 1.5x 0.2x 0.7x 1.1x 1.3x 1.5x 1.6x 0.8x 1.0x 1.2x 0.6x 1.0x 1.3x 1.6x 1.4x 1.0x 2008 2009 2010 2011 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 Net Debt / LTM EBITDA $76 $240 $256 $416 $243 In itial P u b lic O ff e rin g  Preserved and enhanced liquidity through April 2015 equity and Senior Notes offerings and sale of Loving County midstream assets for ~$143 million(1) in October 2015 – substantial liquidity to execute planned drilling program through 2016  Strong financial position with Net Debt/LTM Adjusted EBITDA(2)(3) of 1.0x after close of midstream sale  Target leverage at less than 2.0x Adjusted EBITDA(2), though profile typically more conservative We Remain Committed to Keeping our Balance Sheet Strong 8 (1) Excluding customary purchase price adjustments. (2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see November 4, 2015 Press Release. (3) Pro forma at September 30, 2015 for midstream sale on October 1, 2015. E q u it y Rais e E q u it y Rais e No te s O ff e rin g + E q u it y Rais e (2) Net Debt ($ millions) (3) M ids tr e a m S a le