Exhibit 99.2

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Investor Presentation June 2013

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2 Disclosure Statements 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 our financial and operational performance: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop our current reserves; our costs of operations, delays and other difficulties related to producing oil, natural gas and natural gas liquids; our ability to make acquisitions on economically acceptable terms; availability of sufficient capital to execute our business plan, including from our future cash flows, increases in our 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.

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Company Summary

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4 Company Overview Company Overview 2012 Actual 2013 Guidance 2012 Actual 2013 Guidance 2012 Actual 2013 Guidance Capital Spending $335 million $325 million Total Oil Production 1.214 million barrels 1.8 to 2.0 million barrels Total Natural Gas Production 12.5 billion cubic feet 11.0 to 12.0 billion cubic feet Oil and Natural Gas Revenues $156.0 million $220 to $240 million(3) Adjusted EBITDA(4) $115.9 million $155 to $175 million(3) As reported in the Form 10-Q for the quarter ended March 31, 2013 filed on May 10, 2013 As of June 4, 2013 Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December 2013 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 Appendix

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Founded by Joe Foran in 1983 Foran Oil funded with $270,000 in contributed capital from 17 friends and family members Sold to Tom Brown, Inc.(1) in June 2003 for an enterprise value of $388 million in an all-cash transaction Foran Oil & Matador Petroleum 5 Matador History Matador Resources Company Founded by Joe Foran in 2003 with a proven management and technical team and board of directors Grown through the drill bit, with focus on unconventional reservoir plays, initially in Haynesville In 2008, sold Haynesville rights in approximately 9,000 net acres to Chesapeake for approximately $180 million; retained 25% participation interest, carried working interest and overriding royalty interest Relatively early in the play, redeployed capital into the Eagle Ford, acquiring over 30,000 net acres for approximately $100 million, most in 2010 and 2011 Capital spending focused on developing Eagle Ford and transition to oil IPO in February 2012 (NYSE: MTDR) had net cash proceeds of approximately $136.6 million Predecessor Entities Tom Brown purchased by Encana in 2004 Matador Today

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6 6 Matador Resources Snapshot ~78% 2013E CapEx

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7 Investment Highlights Strong Financial Position and Prudent Risk Management High Quality Asset Base in Attractive Areas Eagle Ford provides immediate oil-weighted value and upside Expanding acreage position in Southeast New Mexico and West Texas Other key assets provide long-term option value on natural gas, with Haynesville, Bossier and Cotton Valley assets all essentially held by production (HBP) Proven Management and Technical Team and Active Board of Directors Management averaging over 25 years of industry experience Board with extensive industry experience and expertise as well as significant company ownership Strong record of stewardship for nearly 30 years Strong Growth Profile with Increasing Focus on Oil / Liquids Oil production up almost five-fold in 2011 and up almost eight-fold in 2012 2013E capital expenditure program focused on oil and liquids exploration and development

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Matador’s Continued Growth 8 (1) 2013 estimates at midpoint of guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in revenue and Adjusted EBITDA estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December 2013 (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 Appendix in millions in millions Thousand Bbl Growth Since the IPO

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(CHART) Growth in PV-10(1) from Proved Reserves 2008 (2) 2009 (2) 2010 (2) 2011 (2) 2012 (2) (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix (2) At December 31 of each respective year PV-10, millions 9

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10 Haynesville Total Resource Potential – Price Sensitivity (1) PV-10 is a non-GAAP measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. All PV-10 values estimated as of March 31, 2013 (2) NYMEX gas price, less property-specific differentials

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Eagle Ford South Texas

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12 Eagle Ford and Austin Chalk Overview Drilled and completed 45 gross / 42.5 net operated wells to date(1) Acreage positioned in some of the most active counties for Eagle Ford and Austin Chalk One rig running currently, primarily focused on oil and liquids; expect to return to two-rig program in September 2013 2013E capital expenditure program focused on oil and liquids development Proved reserves growth from 4.7 million BOE at December 31, 2011 and less than 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010

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13 Value of Proved Reserves Up 70% and Shifting to Oil Over Past Year Eagle Ford $393.6 million, 93% Haynesville $21.8 million, 5% Cotton Valley $5.8 million, 1% SE New Mexico $2.0 million, 0% December 31, 2012 PV-10(1): $423.2 million(3) (Standardized Measure = $394.6 million) Proved Producing Reserves PV-10(1): $297.5 million Haynesville $96.6 million, 39% Cotton Valley $19.5 million, 8% Eagle Ford $130.2 million, 52% SE New Mexico $2.4 million, 1% December 31, 2011 PV-10(1): $248.7 million(2) (Standardized Measure = $215.5 million) Proved Producing Reserves PV-10(1): $154.1 million PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix Future undiscounted net revenue of $494.8 million using YE 2011 SEC pricing of $94.65/Bbl oil and $3.731/MMBtu gas Future undiscounted net revenue of $704.2 million using YE 2012 SEC pricing of $91.21/Bbl oil and $2.757/MMBtu gas

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Highlights 14 Eagle Ford Properties are in Good Neighborhoods Matador’s acreage in counties with robust transaction activity – “good neighborhoods” Transaction values ranging from $10,000 to $30,000 per acre Matador’s Eagle Ford position approximately 28,000 net acres Acreage in both the eastern and western areas of the play Approximately 90% of acreage in prospective oil and liquids windows Acreage offers potential for Austin Chalk, Buda, Pearsall and other formations Good reputation with land and mineral owners Note: All Matador acreage at June 1, 2013 and all other acreage based on public information as of April 2013

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15 EAGLE FORD EAST 7,730 gross / 6,330 net acres EOG OPERATED, MTDR WI ~21% 11,588 gross / 2,240 net acres GLASSCOCK (WINN) RANCH 8,891 gross / 8,891 net acres EAGLE FORD WEST 13,093 gross / 10,259 net acres San Antonio Uvalde Medina Zavala Frio Dimmit La Salle Webb Bexar Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson EAGLE FORD ACREAGE TOTALS 41,302 gross / 27,720 net acres COMBO LIQUIDS / GAS FAIRWAY DRY GAS FAIRWAY OIL FAIRWAY Glasscock Ranch Shelton Newman ZLS Martin Ranch Northcut Affleck Troutt Sutton MRC/EOG Pawelek Danysh Sickenius Lyssy Repka RCT Wilson Love Cowey Keseling Finney Lewton Hennig Nickel Ranch Pena Matador Resources Acreage Eagle Ford Properties Note: All acreage at June 1, 2013 Karnes

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2012 Operated Eagle Ford Completion Results – 24 Hour IP Tests 16

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17 Well Improvement with Evolution of Frac Design Eagle Ford East Offsetting Wells: Example 1 Eagle Ford Middle Offsetting Wells: Example 2 Eagle Ford Middle Offsetting Wells: Example 3 Recent Eagle Ford West Well Performance with Fourth Generation Frac Note: First well on this lease Vertical Depth: 7,424 ft. Lateral Length: 4,762 ft.

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Eagle Ford Well Costs Declined During 2012 – Western Acreage 18 (CHART) Note: Wells are displayed in chronological order. Wells drilled and completed using two casing strings. Well drilling and completions costs only; costs do not include pipelines and lease facilities.

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Eagle Ford Well Costs Declined During 2012 – Eastern Acreage 19 (CHART) Note: Wells are displayed in chronological order. Wells drilled and completed using two casing strings. Well drilling and completions costs only; costs do not include pipelines and lease facilities.

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Average Frac Stage Cost per Well 20 Note: Wells are displayed in chronological order; includes all Matador operated wells drilled and completed through December 31, 2012

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Eagle Ford Well Estimated ROR as a Function of EUR and Well Cost 21 Note: Individual well economics only. NGL price differential +$1.85/Mcf. Oil price differential +$7.00/Bbl. $90.00/Bbl NYMEX oil; $3.00/Mcf NYMEX natural gas Western Acreage Eastern Acreage

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(CHART) Drilling Times and Efficiencies 22 Note: As of June 5, 2013 First 4 Wells Spudded after 01/01/13 Spudded prior to 01/01/13

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23 Recent Technical Advancements in the Eagle Ford Pad drilling 5-10% reduction in cost to drill and complete Drilling cycle time reduction of nearly 4 days/well Safer operations with less moving of heavy equipment Provides for consolidated production operations on multi-well pads Improved frac design Generation 5 frac design 25 to 40 foot fracture spacing (20% to 100% more fractures than generation 2 design) 40 Bbl/ft frac fluid (100% increase from generation 2 design) 1,700 lbs/ft (50% increase from generation 2 design) Cut frac stage cost by 20% (compared to generation 2 design) Zipper fracs Daily fixed cost reduced by 20% Increases drainage efficiency Choke size reduction Delays effects of pressure-dependent formation permeability Increases Estimated Ultimate Recovery (EUR) Delays installation of artificial lift Lowers bottom-hole pressure differential Mitigates damage to proppant pack Artificial lift Pumping units with pump-off controllers on selected lower fluid volume wells Gas-lift installations on wells with higher fluid volume in fields with existing gas compression Greatly aids in returning producing wells affected by offset fracs to normal production levels as a result of accelerated frac water removal

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24 San Antonio Multi-Pay Fairway with Pearsall, Austin Chalk and Buda potential OIL FAIRWAY DRY GAS FAIRWAY Matador Resources Acreage Emerging Multi-Pay Area in Eagle Ford Oil Fairway and MTDR Acreage Note: All acreage at June 1, 2013 Medina Zavala Frio Dimmit La Salle Webb Bexar Atascosa McMullen Dewitt Gonzales Wilson Karnes Live Oak Bee Goliad Guadalupe Uvalde

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Delaware Basin Southeast New Mexico and West Texas

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26 Gross Acres(1) 34,094 acres Net Acres(1) 22,498 acres Southeast New Mexico / West Texas Foothold of existing production and reserves Acreage position in good neighborhoods, surrounded by other operators’ ongoing drilling Year to date(2) acquired 18,234 gross and 14,827 net acres in Lea and Eddy Counties, New Mexico Company considers approximately 26,412 gross and 20,429 net acres to be prospective for multiple oil and liquids-rich targets, including the Wolfcamp and Bone Spring plays Total acreage in Southeast New Mexico and West Texas at June 1, 2013 At June 1, 2013 RANGER- QUERECHO WOLF INDIAN DRAW EDDY LEA LOVING

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27 Wolfbone Play in the Delaware Basin (West Texas) Stratigraphic Column Avalon Shale Depth: 7,900’ – 8,300’ (Oil Window) Density Porosity: 12-14% Thickness: 300-500 ft. Normal Pressure (0.45 psi/ft.) Total Organic Carbon (TOC) 5-8% XRD: 15-20% clay and 40-60% silica IP: 100-270 Bbl/d 200-1,200 Mcf/d Middle Wolfcamp Depth: 11,500’ – 12,000’ Density Porosity: 12-15% Thickness: 200-300 ft. Geopressure (0.7psi/ft.) Total Organic Carbon (TOC) 2-4% Upper Wolfcamp Depth: 10,500’ – 10,600’ (Oil Window) Density Porosity: >10% Thickness: 280-350 ft. Geopressure (0.7psi/ft.) IP: 121-900 Bbl/d 250-3,300 Mcf/d Horizontal Targets 1st 2nd 3rd Bone Spring Depth: 8,500’ – 10,600’ (Oil Window) Density Porosity: >10% Thickness: 10-100 ft. Normal Pressure (0.45 psi/ft.) IP: 10-600 Bbl/d 500-2,500 Mcf/d Note: Information from public sources

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Ranger Prospect Area: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Concho Stratojet 31 State #3H 2nd Bone Spring 20 mo.cum: 329 MBO; 395 MMcf Cimarex Energy Lynch 23 Fed #1H 3rd Bone Spring 17 mo.cum: 157 MBO; 136 MMcf Legacy Operating Lea Unit 4H 3rd Bone Spring 16 mo.cum: 62 MBO; 64 MMcf Concho AirCobra 12 #2H 3rd Bone Spring 21 mo.cum: 271 MBO; 181 MMcf XOG Operating (Vertical well) Jordan B #1 Wolfcamp 20 years cum: 387 MBO; 5 Bcf Concho (Vertical well) Neuhaus 14 Fed #2 Wolfcamp 8 years cum: 156 MBO; 2 Bcf Bone Spring Lime 1st Bone Spring Sand 2nd Bone Spring Sand Wolfcamp Bone Spring / Upper Wolfcamp Type Log 3rd Bone Spring Sand Location of Matador 2013 test well Note: All acreage at June 1, 2013. Well information from public sources as of June 2013. 3 Rivers Oper Eagle 2 State 6H 3rd Bone Spring 4 mo.cum: 46 MBO; 21 MMcf Cimarex Energy Mallon 35 Fed 4H 3rd Bone Spring 23 mo.cum: 37 MBO; 27 MMcf Amtex Energy Teapot 2H 2nd Bone Spring 21 mo.cum: 58 MBO; 48 MMcf Concho Condor State #1H 2nd Bone Spring 2 mo.cum: 23 MBO; 9 MMcf Concho Haumea St. #2H 2nd Bone Spring Completed March 2013 Now Flowing Back 28

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Wolf Leasehold: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Wolf Energy Wolf #1 (Vertical well) 3rd BS / Upr Wolfcamp 33 years cum: 60 MBO; 637 MMcf Wolf Energy Dorothy White #1 (Vertical well) 3rd BS / Upr Wolfcamp 17 years cum: 25 MBO; 92 MMcf Shell Johnson 1-88 Lov #1H Wolfcamp 13 mo.cum: 53 MBO; 218 MMcf Shell Johnson 1-86 (1H) Wolfcamp 25 mo.cum: 139 MBO; 398 MMcf OXY Reagan-McElvain #1H Spud 6/27/2012 IP: 570 BOPD 2.6 MMcf/d 4 mo.cum: 66 MBO; 169 MMcf Shell Johnson 1-76 (1H) Wolfcamp 30 mo.cum: 160 MBO; 528 MMcf Energen Grayling 1-69 IP: 791 BOPD 7.3 MMcf/d 3,500 psi FTP 8 mo.cum: 54 MBO; 525 MMcf on restricted choke Energen Black Mamba 1-57 Wolfcamp 11 mo.cum: 159 MBO; 400 MMcf Proposed location for Matador 2013 test well Shell Owens 1-75 Lov #1H Wolfcamp 14 mo.cum: 83 MBO; 191 MMcf Energen Bushmaster 1-58 Wolfcamp 12 mo.cum: 53 MBO; 125 MMcf Energen Katie 1-72 Wolfcamp 13 mo.cum: 69 MBO; 200 MMcf Note: All acreage at June 1, 2013. Well information from public sources as of June 2013. Bone Spring / Upper Wolfcamp Type Log Bone Spring Lime 1st Bone Spring Sand 2nd Bone Spring Sand Wolfcamp 3rd Bone Spring Sand Avalon Shale Base Avalon Shale 29

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Haynesville & Cotton Valley Northwest Louisiana and East Texas

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Tier 1 Haynesville and Elm Grove Cotton Valley Acreage Positions – Almost all prospective Haynesville acreage is HBP Note: All acreage at June 1, 2013 CADDO BOSSIER BIENVILLE RED RIVER DESOTO Elm Grove Cotton Valley: 49 Net Locations Matador Operated Acreage: 9,980 gross, 9,800 net Locations: 71 gross, 49 net (@ 3-4 locations/section) Potential Resource(1): 135 – 170 Bcf net Tier 1 Haynesville: 50 Net Locations Acreage: 12,568 gross, 5,737 net Locations: 397 gross, 50 net (@ 7 locations/section) Potential Resource(1): 250 – 310 Bcf net MTDR CV Horizontal T. Walker #1H MTDR Haynesville L.A. Wildlife #1H MTDR Haynesville Williams (BLM) #1H TIER 1: 6 – 10+ Bcf TIER 2: 4 – 6 Bcf TIER 3: 2 – 4 Bcf (1) Potential resource should not be considered proved natural gas reserves. Potential resource may be converted to proved natural gas reserves as a result of successful drilling operations and higher natural gas prices Note: Matador does not include any of these potential resources in its proved natural gas reserves at March 31, 2013 31

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(CHART) 32 Haynesville Well Economics – Tier 1 Area Rate of Return, % Natural Gas Price, $/Mcf Note: Individual well economics only. D&C cost = drilling and completion cost. Natural gas price differential = ($0.85)/Mcf.

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33 Cotton Valley Horizontal Well Economics Note: Individual well economics only. D&C cost = drilling and completion cost. Natural gas price differential = (10%) (CHART)

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Gracie Wyoming, Utah and Idaho

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Matador Gracie Project Total Prospect Acreage IDAHO UTAH WYOMING WYOMING IDAHO UTAH WYOMING 61,897 gross acres 30,492 net acres Crawford Federal #1H 35 Note: All acreage at June 1, 2013 Crawford Federal #1H completion scheduled for summer 2013

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Southwest Wyoming Stratigraphy and Target Zones Lamberson, Paul, 1982, The Fossil Basin and its Relationship to the Absaroka Thrust System, Wyoming and Utah, RMAG 13% TOC Meade Peak Shale Cretaceous Shales 2% TOC Crawford Federal #1: Drilled straight hole in late 2011 Encountered 161’ Meade Peak with 46’ of main pay Recovered 50’ conventional core across pay zone TOCave 4.52% (Maximum 14.2%) Thermally mature: Ro 1.69% Porosity Average: 3.0–5.0% Micro-Darcy Permeability Drilled 2,500-ft horizontal lateral in late 2012; plan to complete in summer 2013 36

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Financial Overview

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38 2013 Revenue and Adjusted EBITDA(1)(2) Estimated oil and natural gas revenues of $220 to $240 million Mid-point is an increase of 47% from $156.0 million in 2012 Estimated Adjusted EBITDA(1)(2) of $155 to $175 million Mid-point is an increase of 42% from $115.9 million in 2012 Adjusted EBITDA(1)(2) growth expected to be impacted by lower oil price realizations and an estimated decrease of approximately $13 million in realized hedging gains compared to 2012 2013 Operating Costs(3) Estimated average unit costs per BOE Production taxes/marketing = $4.30 Lease operating = $9.50 G&A = $5.20 Operating cash costs, excluding interest = $19.00 DD&A = $30.00 2013 Financial Expectations (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix (2) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December 2013. (3) Consistent with updated guidance provided on May 8, 2013. Oil and Natural Gas Revenues(2) (millions) Adjusted EBITDA(1)(2) (millions) (CHART) (CHART)

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2013 Capital Investment Plan Highlights 39 2013 projected capital expenditures of approximately $325 million Drill and complete or participate in 48 gross/31.3 net wells in 2013 Including 31.0 gross/25.8 net Eagle Ford Shale and 3.0 gross/3.0 net Bone Spring/Wolfcamp Also includes 3.0 gross/1.6 net exploratory Austin Chalk, Buda and Edwards tests Includes approximately $25 million for pipelines/facilities and $40 million for land/seismic acquisition Compares to 2012 drilling program of 58 gross / 27.6 net wells for $334.6 million in capital expenditures, including 28 gross / 24.5 net Eagle Ford Shale wells 2013 expenditures are estimated to be funded 50% through cash flows and 50% through borrowings under revolving credit facility 2013 Production Expectations Oil production of 1.8 to 2.0 million barrels – mid-point up 58% from 1.2 million barrels in 2012 Natural gas production of 11.0 to 12.0 Bcf – mid-point down 8% from 12.5 Bcf in 2012 2013 Financial Expectations(1) Oil and natural gas revenues of $220 to $240 million – mid-point up 47% from $156.0 million in 2012 Adjusted EBITDA(2) of $155 to $175 million – mid-point up 42% from $115.9 million in 2012 Total borrowings outstanding estimated to be $320 to $330 million at YE 2013 Maintain financial discipline by funding 2013 capital expenditures through operating cash flows and borrowings under revolving credit facility 2013 oil production volumes well hedged to protect cash flows below about $88/Bbl oil price Current borrowings are less than 2x estimated 2013 operational cash flows Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December 2013. (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 Appendix

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First Quarter 2013 Earnings Release Highlights 40 Production Growth Oil production of 460,000 Bbl for the quarter ended March 31, 2013, a year-over-year increase of 130% from 200,000 Bbl of oil produced in the quarter ended March 31, 2012 and a sequential increase of 8% from 426,000 Bbl of oil produced in the quarter ended December 31, 2012 Average daily oil equivalent production of approximately 10,900 BOE per day for the quarter ended March 31, 2013, consisting of about 5,100 Bbl of oil per day and 34.7 MMcf of natural gas per day, a year-over- year BOE increase of 36% from approximately 8,000 BOE per day, consisting of about 2,200 Bbl of oil per day and 34.9 MMcf of natural gas per day, for the quarter ended March 31, 2012 Financial Performance Total realized revenues of $59.7 million in the first quarter of 2013, including $0.4 million in realized gain on derivatives, a year-over-year increase of 85% from total realized revenues of $32.2 million, including $3.1 million in realized gain on derivatives, reported in the first quarter of 2012 Oil and natural gas revenues of $59.3 million for the quarter ended March 31, 2013, a year-over-year increase of 103% from $29.2 million reported for the quarter ended March 31, 2012 Adjusted EBITDA(1) of $40.7 million for the quarter ended March 31, 2013, a year-over-year increase of 91% from $21.3 million reported for the quarter ended March 31, 2012 Acreage Acquisitions During March and April 2013, acquired an additional 14,700 gross and 12,500 net acres in Lea and Eddy Counties, New Mexico Consider approximately 22,900 gross and 18,100 net acres to be prospective for multiple oil and liquids- rich targets, including the Wolfcamp and Bone Spring play (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix

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41 Financial Performance (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix (2) Includes realized gain on derivatives Oil and Natural Gas Revenues ($ in mm) Total Realized Revenues(2) ($ in mm) Adjusted EBITDA(1) ($ in mm) Average Daily Production (BOE/d)

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42 2013 and 2014 Hedging Profile At May 8, 2013, Matador had: 1.08 million barrels of oil hedged for remainder of 2013 at weighted average floor and ceiling of $88/Bbl and $107/Bbl, respectively 5.8 Bcf of natural gas hedged for remainder of 2013 at weighted average floor and ceiling of $3.25/MMBtu and $4.52/MMBtu, respectively 6.7 million gallons of natural gas liquids hedged for remainder of 2013 at weighted average price of $1.21/gal 1.68 million barrels of oil, 8.4 Bcf of natural gas and 3.7 million gallons of natural gas liquids hedged for 2014 Note: Hedged volumes shown in table for 2013 are for remainder of 2013; volumes shown in table for 2014 are for full calendar year.

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Reserves Summary at March 31, 2013 43 Total proved reserves: 23.6 million BOE at March 31, 2013, including 10.7 million Bbl of oil and 77.5 Bcf of natural gas Oil reserves grew 88% to 10.7 million Bbl from 5.7 million Bbl at March 31, 2012 PV-10(1) increased 33% to $438.1 million from $329.6 million at March 31, 2012, despite removal of close to 100 Bcf of proved undeveloped Haynesville shale gas reserves at June 30, 2012 Oil reserves comprised 45% (1 Bbl = 6 Mcf basis) of total proved reserves at March 31, 2013, up from 17% at March 31, 2012 Eagle Ford reserves comprised 93% of total PV-10(1) at March 31, 2013 as compared to 74% at March 31, 2012 and 93% at December 31, 2012 Sequential growth: Proved developed oil reserves grew 13% to 5.4 million Bbl at March 31, 2013 from 4.8 million Bbl at December 31, 2012 PV-10(1) increased 4% to $438.1 million at March 31, 2013 from $423.2 million at December 31, 2012 (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix

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Appendix

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Board of Directors and Special Board Advisors – Expertise and Stewardship 45 45

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Proven Management Team – Experienced Leadership 46 Management Team Background and Prior Affiliations Industry Experience Matador Experience Joseph Wm. ForanFounder, Chairman and CEO Matador Petroleum Corporation, Foran Oil Company, J Cleo Thompson Jr. and Thompson Petroleum Corp. 33 years Since Inception David E. LancasterEVP and COO Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 34 years Since 2003 Matthew V. HairfordEVP and Head of Operations— Samson, Sonat, Conoco 29 years Since 2004 David F. NicklinExecutive Director of Exploration— ARCO, Senior Geological Assignments in UK, Angola, Norway and the Middle East 42 years Since 2007 Bradley M. RobinsonVP and CTO— Schlumberger, S.A. Holditch & Associates, Inc., Marathon 36 years Since Inception Craig N. AdamsVP and General Counsel— Baker Botts L.L.P., Thompson & Knight LLP 20 years Since 2012 Ryan C. LondonVP and General Manager—Matador Resources Company 9 years Since 2003 Kathryn L. WayneController and Treasurer—Matador Petroleum Corporation, Mobil 28 years Since Inception

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South Texas: Pearsall Play Anadarko Newfield Chesapeake Shell Gas Activity Top Pearsall Depth Map CI = 500’ Cheyenne Indio Tanks Horiz. program 4 horizs w/ 450 to 700 Bbl/d (all wells) Plus 4 to 6 MMcf/d Cromwell #1H – 5 mo. 4 MBbl, 71 MMcf A Williams B #1H – 5 mo. 20 MBbl, 129 MMcf ZCW #1H – 5 mo. – 17 MBbl, 154 Mcf CHK – Brownlow #1H Could not test Liquid potential increases CHK—Avant D #1H Suspended, waiting on further completion work Cabot/Osaka JV Osaka 35% ($14,285/ac. – $17,500/ac.) 6 Horiz. Drilled 3 Permits Schorp-White Ranch #101H 1st full mo. – 4,535 Bbl, 43 MMcf RH Pickens #101H 1st full mo. – 5,339 Bbl, 16 MMcf Chiliptin #101H IP: 670 Bbl/d, 761 Mcf/d 18/64” CHK – Wilson C #1H IP: 920 Mcf/d, 93 Bbl/d Abandoned for EGFD Cheyenne Rockin S #1H Completed 12-21-2012 Valence Oper. 4 drilling wells and 2 Permits Murray #1H IP: 258 Bbl/d, 106 Mcf/d Completed—Jan ‘13 Rosetta Tom Hanks #1 Completed and waiting on hook-up. EOG Tests 500 – 2000 Bbl/mo. Temp. Abnd. or EGFD Horiz. EOG Robert Hindes #1H IP: 263 Bbl/d, 4.3 MMCF/d 26/64” w/ 1977 Ftp CHK Ralph Edwards E #1H IP: 135 Bbl/d, 1752 Mcf/d 17/64” w/ 2797 Ftp 5 mo.cum 6,917 Bbl, 153 MMcf 47 Note: All acreage at June 1, 2013. Well data from public information as of June 2013.

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48 Adjusted EBITDA Reconciliation This investor presentation 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 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 investor presentation 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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49 Adjusted EBITDA Reconciliation The following table presents our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.

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50 PV-10 Reconciliation 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. The PV-10 at March 31, 2013, December 31, 2012, March 31, 2012, December 31, 2011, December 31, 2010, December 31, 2009 and December 31, 2008 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. The discounted future income taxes at March 31, 2013, December 31, 2012, March 31, 2012, December 31, 2011, December 31, 2010, December 31, 2009 and December 31, 2008 were, in millions, $31.1, $28.6, $42.2, $33.2, $8.8, $5.3 and $0.8 respectively. We have not provided a reconciliation of PV-10 to Standardized Measure where references are forward- looking, estimates or prospective in nature. We could not provide such a reconciliation without undue hardship on account of many unknown variables for the reconciling items. We have not provided a reconciliation of PV-10 to Standardized Measure with respect to proved producing reserves because such PV- 10 values are subsets of the PV-10 of our total proved reserves.