Exhibit 99.1

Investor Presentation March 2013

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, joint venture partners 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. 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

Company Overview Completed IPO of 14,883,334 shares (12,209,167 primary) including overallotment at $12.00/share in March 2012 Completed IPO of 14,883,334 shares (12,209,167 primary) including overallotment at $12.00/share in March 2012 Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 55.89 million common shares Share Price(1) $8.80/share Market Capitalization(1) $491.8 million 2012 Actual 2013 Guidance 2012 Actual 2013 Guidance 2012 Actual 2013 Guidance Capital Spending $335 million $310 million Total Oil Production 1.214 million barrels 1.6 to 1.8 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 $200 to $220 million(2) Adjusted EBITDA(3) $115.9 million $140 to $160 million(2) As of March 14, 2013 Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range using late November 2012 strip prices for oil and natural gas, plus property-specific differentials. Estimated average realized prices for oil and natural gas used in these estimates were $94.00/Bbl and $4.43/Mcf, respectively Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income 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

Daily Production @ 12/31/12(1) 9,000 BOE/d Oil Production (% total) 3,317 Bbl/d (37%) Gas Production (% total) 34.1 MMcf/d (63%) Proved Reserves @ 12/31/12 23.8 million BOE % Proved Developed 58% % Oil 44% 2013E CapEx $310 million % South Texas ~82% % Oil and Liquids ~98% 2013E Anticipated Drilling 31.3 net wells South Texas 27.4 net wells West Texas / New Mexico 3.0 net wells Gross Acreage(2) 141,782 acres Net Acreage(2) 87,650 acres Identified Drilling Locations(3)(4) 873 gross / 413 net Average daily production for the year ended December 31, 2012 At December 31, 2012 As of December 31, 2012 Engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Average daily production for the year ended December 31, 2012 At December 31, 2012 As of December 31, 2012 Engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Matador Resources Snapshot ~80% 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 Delaware Basin in 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

Matador’s Continued Growth 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 (loss) income and net cash provided by operating activities, see Appendix Note: 2013E at the mid-point of 2013 guidance, respectively in millions in millions

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

Eagle Ford South Texas

11 Eagle Ford and Austin Chalk Overview Drilled and completed 38 gross / 36.5 net operated wells to date(1) Acreage positioned in some of the most active counties for Eagle Ford and Austin Chalk Two rigs running, primarily focused on oil and liquids 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 Proved Reserves @ 12/31/12 14.3 million BOE % Proved Developed 46% % Oil / Liquids 72% Daily Oil Production(2) 3,261 Bbl/d Gross Acres(3) 42,456 acres Net Acres(3) 27,911 acres Eagle Ford(3)(4) 27,911 acres Austin Chalk(3)(4) 17,465 acres 2013E Anticipated Drilling 27.4 net wells 2013E CapEx Budget $242.7 million Identified Drilling Locations(3)(5) 274 gross / 221 net Total drilled and completed wells operated by Matador as of March 14, 2013 Estimated average daily oil production for year ended December 31, 2012 At December 31, 2012 Some of the same leases cover the net acres shown for Eagle Ford and Austin Chalk. Therefore, the sum for both formations is not equal to the total net acreage Engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Total drilled and completed wells operated by Matador as of March 14, 2013 Estimated average daily oil production for year ended December 31, 2012 At December 31, 2012 Some of the same leases cover the net acres shown for Eagle Ford and Austin Chalk. Therefore, the sum for both formations is not equal to the total net acreage Engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation.

12 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 $5.9 million, 1% SE New Mexico $2.0 million, 0% December 31, 2012 PV-10(1): $423.2 million(2) (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 (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 $704.2 million using YE 2012 SEC pricing of $91.21/Bbl oil and $2.757/MMBtu gas

Highlights 13 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 December 31, 2012 and all other acreage based on public information

14 EAGLE FORD EAST 7,707 gross / 6,307 net acres EOG OPERATED, MTDR WI ~21% 12,765 gross / 2,454 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 42,456 gross / 27,911 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 December 31, 2012 Karnes

2012 Operated Eagle Ford Completion Results – 24 Hour IP Tests

Well Name County Completion Date Perforated Length(1) Top Perf(2) Frac Stages Oil IP(3)(4) Gas IP(3)(4) Oil Equiv IP(5) Choke Pressure

Total (ft.) (ft.) (Bbl/day) (Mcf/day) (BOE/day) (inch) (psi)

2012 Wells

Martin Ranch A 8H La Salle 1/28/2012 6,092 9,559 21 1,089 831 1,228 26/64 1,750 Martin Ranch A 6H La Salle 2/8/2012 6,509 9,550 22 689 1,714 975 26/64 1,650 Martin Ranch A 7H La Salle 2/12/2012 4,902 9,502 17 609 481 689 26/64 1,040 Martin Ranch B 4H La Salle 2/18/2012 3,801 9,701 13 595 968 756 26/64 1,320 Matador Sickenius Orca 1H Karnes 3/16/2012 5,712 10,897 19 785 540 875 26/64 820 Northcut A 1H La Salle 3/23/2012 4,446 9,209 15 583 592 682 26/64 1,000 Matador Danysh Orca 1H Karnes 4/1/2012 4,962 11,537 17 1,012 1,126 1,200 26/64 1,175 Northcut A 2H La Salle 5/1/2012 4,503 9,273 15 758 761 885 24/64 950 Matador Pawelek Orca 1H Karnes 6/5/2012 6,103 11,231 20 670 739 793 16/64 2,510 Matador Pawelek Orca 2H Karnes 6/7/2012 6,202 11,240 28 861 755 987 16/64 2,460 Matador Danysh Orca 2H Karnes 6/10/2012 5,115 11,331 17 750 746 874 16/64 2,675 Glasscock Ranch 1H Zavala 6/27/2012 5,352 7,166 18 307 0 307 pump 140 Matador K. Love Orca 1H DeWitt 8/10/2012 5,077 13,048 17 1,793 2,171 2,155 16/64 5,280 Matador K. Love Orca 2H DeWitt 8/11/2012 4,871 12,830 17 1,757 2,126 2,111 16/64 5,900 Northcut B 2H LaSalle 9/6/2012 4,777 9,131 16 410 315 463 16/64 1,175 Northcut B 1H LaSalle 9/12/2012 4,798 9,085 16 423 169 451 16/64 1,500 Matador Sickenius Orca 2H Karnes 9/16/2012 5,982 10,829 25 851 556 944 16/64 2,000 Martin Ranch A 12H LaSalle 10/4/2012 4,897 9,507 21 640 1,955 966 16/64 1,680 Matador K. Love Orca 4H DeWitt 11/4/2012 4,012 12,611 14 1,509 841 1,649 16/64 4,900 Matador K. Love Orca 3H DeWitt 11/6/2012 4,777 12,787 16 1,456 1,585 1,720 16/64 4,775 Martin Ranch B 13H LaSalle 11/22/2012 5,364 9,476 23 519 162 546 14/64 2,125 Martin Ranch B 9RH LaSalle 11/25/2012 5,364 9,428 23 482 240 522 14/64 2,000 Frances Lewton 2H DeWitt 12/5/2012 6,277 13,072 21 1,178 4,203 1,879 14/64 6,150 Matador Cowey Orca 1H DeWitt 12/9/2012 3,332 13,593 13 580 3,325 1,134 12/64 8,000 Northcut A 4H LaSalle 12/18/2012 4,592 9,069 16 395 139 418 14/64 1,580

Average 5,113 18.4 828 Bbl/day 1,082 Mcf/day 1,008 BOE/day

1) Total length of perforated lateral from the first perforation to the last perforation

2) Top perf is measured depth

3) Rates as reported to the Texas Railroad Commission via W-2 or G-1 form

4) Rates are based on actual, stabilized, 24 hour production on a constant choke size

5) Oil equivalent rates are based on a 6:1 ratio of six Mcf gas per one Bbl oil

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Eagle Ford Well Costs Declined During 2012 – Western Acreage 16 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.

Eagle Ford Well Costs Declined During 2012 – Eastern Acreage 17 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.

Average Frac Stage Cost per Well 18 Note: Wells are displayed in chronological order; includes all Matador operated wells drilled and completed through December 31, 2012

Eagle Ford Well Estimated ROR as a Function of EUR and Well Cost 19 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

20 Recent Technical Advancements in the Eagle Ford Rotary Steerable Tools Drilling time in curve and lateral reduced by two days Measurement While Drilling (MWD) telemetry closer to drill bit Improves ability to stay in “sweet-spot” Removes sumps and high-angle curves Improved frac design Increases Stimulated Rock Volume (SRV) Tighter fracture spacing (25% more fractures than previous design) 35 Bbl/ft Frac fluid (75% increase from previous design) Zipper Fracs (simultaneous frac operations) 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 low gas/oil ratio (GOR) wells Gas-lift valves on high gas/oil ratio (GOR) wells Electric Submersible Pumps (ESP) to accelerate unloading frac fluids

Drilling Times and Efficiencies 21 Note: As of January 25, 2013 * Bold wells utilized rotary steerable systems First 4 Wells Recent Wells

22 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 December 31, 2012 Medina Zavala Frio Dimmit La Salle Webb Bexar Atascosa McMullen Dewitt Gonzales Wilson Karnes Live Oak Bee Goliad Guadalupe Uvalde

Delaware Basin Southeast New Mexico and West Texas

24 Matador Today Matador Today Gross Acres(1) 15,860 acres Net Acres(1) 7,591 acres Southeast New Mexico / West Texas Foothold of existing production and reserves On August 10, 2012, acquired approx. 4,900 gross and 2,900 net acres prospective for the Wolfbone play in the Delaware Basin in Loving County, Texas. Acreage at December 31, 2012 RANGER- QUERECHO WOLF INDIAN DRAW

25 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

Ranger Prospect Area: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Concho Stratojet 31 State #1H 2nd Bone Spring 11 mo.cum: 243 MBO; 276 MMcf Cimarex Energy Lynch 23 Fed #1H 3rd Bone Spring 9 mo.cum: 130 MBO; 99 MMcf Legacy Operating Lee Unit 4H 3rd Bone Spring 13 mo.cum: 57 MBO; 55 MMcf Concho AirCobra 12 #2H 3rd Bone Spring 12 mo.cum: 196 MBO; 132 MMcf XOG Operating (Vertical well) Jordan B #1 Wolfcamp 20 years cum: 386 MBO; 5 Bcf Concho (Vertical well) Neuhaus 14 Fed #2 Wolfcamp 8 years cum: 156 MBO; 2 Bcf 26 Bone Spring Lime. 1st Bone Spring Sand 2nd Bone Spring Sand 3rd Bone Spring Sand Wolfcamp Bone Spring / Upper Wolfcamp Type Log Proposed location for Matador 2013 test well Note: All acreage at December 31, 2012. Well information from public sources. 3 Rivers Oper Eagle 2 State 6H 3rd Bone Spring 2 mo.cum: 32 MBO; 13 MMcf Cimarex Energy Mallon 35 Fed 4H 3rd Bone Spring 14 mo.cum: 29 MBO; 20 MMcf

Wolf Leasehold: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Wolf Energy Wolf #1 (Vertical well) 3rd BS / Upr Wolfcamp 33 years cum: 58 MBO; 620 MMcf Wolf Energy Dorothy White #1 (Vertical well) 3rd BS / Upr Wolfcamp 17 years cum: 25 MBO; 92 MMcf Chesapeake Johnson 1-88 Lov #1H Wolfcamp 10 mo.cum: 72 MBO; 295 MMcf Chesapeake Johnson 1-86 (1H) Wolfcamp 17 mo.cum: 122 MBO; 344 MMcf OXY Reagan-McElvain 1H Spud 6/27/2012 IP 570 BOPD 2.6 MMcf/d 1 mo.cum: 18 MBO; 44MMcf Chesapeake Johnson 1-76 (1H) Wolfcamp 22 mo.cum: 140 MBO; 475 MMcf Energen Resources Grayling 1-69 IP: 791 BOPD 7.3 MMCFD 3,500 psi FTP 3 mo.cum: 29 MBO; 281 MMcf on restricted choke Energen Black Mamba 1-57 Wolfcamp 3 mo.cum: 61 MBO; 180 MMcf Proposed location for Matador 2013 test well Anadarko Black Tip Johnson 1-39(1H) Wolfcamp 29 mo.cum: 234 MBO; 323 MMcf 27 Note: All acreage at December 31, 2012. Well information from public sources.

Haynesville & Cotton Valley Northwest Louisiana and East Texas

Tier 1 Haynesville and Elm Grove Cotton Valley Acreage Positions – Almost all prospective Haynesville acreage is HBP Note: All acreage at December 31, 2012 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 this potential resource in its proved natural gas reserves at December 31, 2012 29

30 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.

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

Gracie Wyoming, Utah and Idaho

Matador Gracie Project Total Prospect Acreage IDAHO UTAH WYOMING WYOMING WYOMING IDAHO UTAH WYOMING 55,273 gross acres 27,180 net acres Crawford Federal #1H 33 Note: All acreage at December 31, 2012 Crawford Federal #1H completion scheduled for summer 2013

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 34

2013 Capital Investment Plan

2013 Capital Investment Plan Highlights 36 2013 projected capital expenditures of approximately $310 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 $25 million for land/seismic acquisition Compares to 2012 Drilling Program of 28 gross / 24.5 net wells for $334.6 million in capital expenditures 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 1.6 to 1.8 million barrels – mid-point up 40% 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 Oil and natural gas revenues(1) of $200 to $220 million – mid-point up 35% from $156.0 million in 2012 Adjusted EBITDA(1)(2) of $140 to $160 million – mid-point up 29% from $115.9 million in 2012 Total borrowings outstanding estimated to be $310 to $320 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 just over one times estimated 2013 operational cash flows (1) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range using late November 2012 strip prices for oil and natural gas, plus property-specific differentials. Estimated average realized prices for oil and natural gas used in these estimates were $94.00/Bbl and $4.43/Mcf, respectively (2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see Appendix

37 2013 Oil Production Estimated total oil production of 1.6 to 1.8 million barrels Mid-point is an increase of 40% from 2012 Oil production expected to decline from year-end 2012 levels in early 2013 Production delays, shut-ins due to pad drilling, zipper fracs, etc. Oil production expected to return to over 5,000 Bbl/d during second half of 2013 2013 Natural Gas Production Estimated total natural gas production of 11.0 to 12.0 Bcf Mid-point is a decrease of 8% from 2012 Gas production expected to remain relatively flat during 2013, but should include higher percentage of liquids-rich gas 2013 Production Expectations (1) Estimated (as of December 6, 2012) quarterly average oil and natural gas production at midpoint of guidance range Oil Production(1) (Bbl/d) Natural Gas Production(1) (MMcf/d) First sixty days of 2013 First sixty days of 2013

Funding for 2013 Capital Investment Plan 38 Maintain financial discipline by anticipated funding of 2013 capital expenditures through operating cash flows and borrowings under revolving credit facility Most of 2013 Eagle Ford program is development drilling and largely de-risked by 2012 results As of March 14, 2013, 1.34 million barrels of 2013 oil production hedged protecting cash flows below approximately $88/Bbl oil price Credit facility status at March 14, 2013 Borrowing base of $255 million; total facility size of $500 million; facility matures in December 2016 Borrowings outstanding of $180 million Ability to request quarterly borrowing base increases with growth in oil and natural gas reserves throughout 2013 Estimated borrowings outstanding of $310 to $320 million at YE 2013 Additional flexibility to manage liquidity No long-term drilling rig or service contract commitments $25 million estimated for discretionary land/seismic acquisitions No significant non-operated well obligations Simple capital structure; no high-yield debt or convertibles on balance sheet

39 Continued Oil/Liquids Focus to Fuel 2013 Growth

Continued Oil/Liquids Focus to Fuel 2013 Growth

2013 Anticipated Drilling 2013E CapEx Gross Wells Net Wells (in millions) Total Total % Total % South Texas

Eagle Ford Shale 31.0 25.8 82.4% $217.0 70.1% Austin Chalk, Buda, Edwards 3.0 1.6 5.1% $5.9 1.9% Facilities/Pipelines/Etc. — — —$19.8 6.4% Area Total 34.0 27.4 87.5% $242.7 78.4%

West Texas/Southeast New Mexico

Bone Spring/Wolfcamp 3.0 3.0 9.6% $30.2 9.8% Facilities/Pipelines/Etc. — — —$5.4 1.7% Area Total 3.0 3.0 9.6% $35.6 11.5%

Northwest Louisiana

Haynesville Shale 10.0 0.5 1.6% $5.1 1.7%

Southwest Wyoming

Meade Peak Shale 1.0 0.4 1.3% $1.0 0.3%

Other

Land/Seismic/Etc. — — —$25.0 8.1%

Total 48.0 31.3 100.0% $309.4 100.0%

40 EAGLE FORD EAST 7,707 gross / 6,307 net acres EOG OPERATED, MTDR WI ~21% 12,765 gross / 2,454 net acres GLASSCOCK (WINN) RANCH 8,891 gross / 8,891 net acres EAGLE FORD WEST 13,093 gross / 10,259 net acres San Antonio Uvald e Medina Zavala Frio Dimmit La Salle Webb Bexar Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson EAGLE FORD ACREAGE TOTALS 42,456 gross / 27,911 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 (1) We define Tier 1 Eagle Ford locations as those locations that we anticipate to have estimated ultimate recoveries of 225,000 Bbl of oil or greater. (2) We define Tier 2 Eagle Ford locations as those locations that we anticipate to have estimated ultimate recoveries of between 150,000 Bbl and 225,000 Bbl of oil or locations that are primarily prospective for natural gas. Note: All acreage values at December 31, 2012. Net wells reflect Matador’s working interest ownership Karnes 13 2 2 1 3 4 (Non-Op) 4 1 (Buda – Non-Op) 1 (Edwards – Non-Op) 1 1 1 (Austin Chalk) #—Gross wells planned in 2013; All Matador operated Eagle Ford wells unless noted otherwise 34 gross/27.4 net wells planned in 2013 Potential Remaining Eagle Ford Drilling Locations* 274 gross/221 net locations Tier 1 – 155 gross/125 net locations (40 to 80-acre spacing) Tier 2 – 119 gross/96 net locations (primarily Glasscock Ranch and Sutton, both HBP, 80 to 120-acre spacing) No Eagle Ford locations estimated for Atascosa acreage Numbers do not include any potential locations for other horizons – e.g., Austin Chalk, “Chalkleford”, Buda, Pearsall *At December 31, 2012 2013 South Texas Drilling Plan

Delaware Basin Acreage and 2013 Drilling Plan Matador’s acreage position at December 31, 2012 shown in red. Note: Certain additional Matador acreage in West Texas/Southeast New Mexico not considered prospective as of December 31, 2012 41 RANGER EDDY LEA LOVING WOLF DELAWARE BASIN PROSPECTIVE ACREAGE 15,860 gross / 7,591 net acres RANGER 1,955 gross / 1,562 net acres 1 1 Ranger A1 Primary Target: 2nd Bone Spring Sand Ranger A2 Primary Target: Wolfcamp Shale WOLF 5,203 gross / 2,977 net acres #—Matador operated wells planned in 2013 3 gross/3 net horizontal wells planned in 2013 1 Wolf 1 Primary Target: Wolfcamp Shale

Recent Production and Financial Highlights 42 December 2012 and early 2013 For the first sixty days of 2013, production averaging approximately 5,000 Bbl of oil per day and 34 MMcf of natural gas per day Compared to 2013 production guidance of approximately 4,000 Bbl of oil per day and 31 MMcf of natural gas per day as announced at Analyst Day on December 6, 2012 As previously reported in the January 7, 2013 operations update, production averaged approximately 5,800 Bbl of oil per day during the month of December 2012 About 10% above the mid-point of 2012 projected exit rate of 5,000 to 5,500 Bbl of oil per day December 2012 and early 2013 production performance attributable to better-than-expected results from several recent wells drilled and placed on production during the past three months in eastern and western Eagle Ford acreage

43 2013 Revenue and Adjusted EBITDA(1)(2) Estimated oil and natural gas revenues of $200 to $220 million Mid-point is an increase of 35% from $156.0 million in 2012 Estimated Adjusted EBITDA(1)(2) of $140 to $160 million Mid-point is an increase of 29% 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 Estimated average unit costs per BOE Production taxes/marketing = $4.10 Lease operating = $8.20 G&A = $4.70 Operating cash costs, excluding interest = $17.00 DD&A = $29.50 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 (loss) income 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 using late November 2012 strip prices for oil and natural gas, plus property-specific differentials. Estimated average realized prices for oil and natural gas used in these estimates were $94.00/Bbl and $4.43/Mcf, respectively Oil and Natural Gas Revenues(2) (millions) Adjusted EBITDA(1)(2) (millions)

Appendix

Board of Directors and Special Board Advisors – Expertise and Stewardship 45 Board Members and Advisors Professional Experience Business Expertise Dr. Stephen A. Holditch Director Professor and Former Head of Dept. of Petroleum Engineering, Texas A&M University— Founder / President S.A. Holditch & Associates—Past President of Society of Petroleum Engineers Oil & Gas Operations David M. Laney Lead Director Past Chairman, Amtrak Board of Directors Former Partner, Jackson Walker LLP Law & Investments Gregory E. Mitchell Director President / CEO, Toot’n Totum Food Stores Petroleum Retailing Dr. Steven W. Ohnimus Director Retired VP and General Manager, Unocal Indonesia Oil & Gas Operations Michael C. Ryan Director— Partner, Berens Capital Management International Business and Finance Margaret B. Shannon Director Retired VP and General Counsel, BJ Services Co. Former Partner, Andrews Kurth LLP Law and Corporate Governance Marlan W. Downey Special Board Advisor Retired President, ARCO International Former President, Shell Pecten International Past President of American Association of Petroleum Geologists Oil & Gas Exploration Wade I. Massad Special Board Advisor Managing Member, Cleveland Capital Management, LLC Former EVP Capital Markets, Matador Resources Company Formerly with KeyBanc Capital Markets and RBC Capital Markets Capital Markets Edward R. Scott, Jr. Special Board Advisor Former Chairman, Amarillo Economic Development Corporation Law Firm of Gibson, Ochsner & Adkins Law, Accounting and Real Estate Development W.J. “Jack” Sleeper, Jr. Special Board Advisor—Retired President, DeGolyer and MacNaughton (Worldwide Petroleum Consultants) Oil & Gas Executive Management

Proven Management Team – Experienced Leadership 46 Management Team Background and Prior Affiliations Industry Experience Matador Experience Joseph Wm. Foran Founder, Chairman and CEO Matador Petroleum Corporation, Foran Oil Company, J Cleo Thompson Jr. and Thompson Petroleum Corp. 32 years Since Inception David E. Lancaster EVP and COO Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 33 years Since 2003 Matthew V. Hairford EVP and Head of Operations— Samson, Sonat, Conoco 28 years Since 2004 David F. Nicklin Executive Director of Exploration— ARCO, Senior Geological Assignments in UK, Angola, Norway and the Middle East 41 years Since 2007 Bradley M. Robinson VP, Reservoir Engineering— Schlumberger, S.A. Holditch & Associates, Inc., Marathon 35 years Since Inception Craig N. Adams VP and General Counsel— Baker Botts L.L.P., Thompson & Knight LLP 20 years Since 2012 Ryan C. London VP and General Manager— Matador Resources Company 9 years Since 2003 Kathryn L. Wayne Controller and Treasurer— Matador Petroleum Corporation, Mobil 28 years Since Inception

47 2013 and 2014 Hedging Profile At March 14, 2013, Matador has: 1.34 million barrels of oil hedged for remainder of 2013 at weighted average floor and ceiling of $88/Bbl and $107/Bbl, respectively 6.9 Bcf of natural gas hedged for remainder of 2013 at weighted average floor and ceiling of $3.26/MMBtu and $4.57/MMBtu, respectively 7.4 million gallons of natural gas liquids hedged for remainder of 2013 at weighted average price of $1.25/gal 1.44 million barrels of oil, 7.2 Bcf of natural gas and 2.3 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.

Reserves Summary at December 31, 2012 48 Total proved reserves: 23.8 million BOE at December 31, 2012, including 10.5 million Bbl of oil and 80.0 Bcf of natural gas Oil reserves grew 176% to 10.5 million Bbl from 3.8 million Bbl at December 31, 2011 PV-10(1) increased 70% to $423.2 million from $248.7 million at December 31, 2011, despite removal of close to 100 Bcf of proved undeveloped Haynesville shale gas reserves at June 30, 2012 Oil reserves comprised 44% (1 Bbl = 6 Mcf basis) of total proved reserves at December 31, 2012, up from 12% at December 31, 2011 Eagle Ford reserves comprised 93% of total PV-10(1) at December 31, 2012 as compared to 52% at December 31, 2011 Sequential growth from September 30, 2012 to December 31, 2012 Oil reserves grew 25% to 10.5 million Bbl from 8.4 million Bbl at September 30, 2012 PV-10(1) increased 16% to $423.2 million from $363.6 million at September 30, 2012 (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix

49 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 (loss) income 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)

South Texas: Pearsall Play Anadarko Newfield Chesapeake Shell Gas Activity Top Pearsall Depth Map CI = 500’ Cheyenne Indio Tanks Horiz. program 4 horizs w/ 700 to 450 Bbl/d Plus 4 to 6 MMcf/d Yields 83 to 63 Bbls/MMcf 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 300 Bbl/mo. – Abnd. Cabot/Osaka JV Osaka 35% ($14,285/ac. – 17,500ac.) 6 Horiz. Drilled 3 Permits Schorp-White Ranch #101H 1st full mo. – 4,535 Bbl, 43MMcf RH Pickens #101H 1st full mo. – 5,339 Bbl, 16MMcf CHK – Wilson C #1H 3.2 MMcf/d, 334 Bbl/d 97 Bbls/MMcf Abnd. For EGFD Cheyenne Drilling Cheyenne Chilipitin LTD #101H Permit Valence Oper. 4 drilling wells and 2 Permits Rosetta Tom Henks #1 Testing 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 50 Note: All acreage at December 31, 2012. Well data from public information.

Pearsall Field Area Buda / Eagle Ford / Chalkleford Activity 51 CRIMSON Exp. Best 3 mo. ~ 12 MBbl Dan Hughes Activity US ENERCORP Best 3 mo. ~ 2 MBbl BBO&G Best 3 mo. ~ 15—6 MBbl US ENERCORP, ORXY CHKFD Activity Best 3 mo. ~ 52 to 37 MBbl Avg 21 MBbl BBO&G,Best 3 mo. ~ 14 MBbl BBO&G, Best 3 mo. ~ 10, 2 MBbl Sage ~ 869 Bbl/d BBO&G, Best 3 mo. ~ 13 MBbl GDP, BBO&G, TAR, Burnett Best 3 mo. ~ 46, 37,9, 8, 5 MBbl CABOT, CHEYENNE Best 3 mo. ~ 98 , 83 MBbl Avg 25 MBbl GOODRICH Best 3 mo. ~ 4 MBbl BBO&G—Morales Pedro Best 3 mo. ~ 19, 8, 5 MBbl GOODRICH, CHK, CARRIZO Best 3 mo. ~ 54, 45 MBbl Avg 28 MBbl GOODRICH—Burns Ranch Best 3 mo. ~ 19 MBbl CML CHKFD Activity Dual Laterals Play CHK, EP ENERGY Best 3 mo. ~ Avg 35 MBbl CHK Best 3 mo. ~ 44 to 35 MBbl Avg 24 MBbl Note: All acreage at December 31, 2012. Well data from public information.

52 Adjusted EBITDA Reconciliation This presentation includes, and certain statements made during this presentation may include, the non-GAAP financial measure of Adjusted EBITDA. We believe Adjusted EBITDA helps us evaluate our operating performance and compare our results of operations from period to period without regard to our financing methods or capital structure. We define 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, including stock option and grant expense and restricted stock and restricted stock units expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net (loss) income or cash flows as determined by GAAP. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. The following tables present our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net (loss) income and net cash provided by operating activities, respectively, that are of a historical nature. Where references to Adjusted EBITDA are forward-looking, prospective or estimates in nature, and not based on historical fact, the table does not provide a reconciliation. We could not provide such reconciliations without undue hardship because the Adjusted EBITDA numbers included in this presentation, and that may be included in certain statements made during the presentation, are estimations, approximations and/or ranges. In addition, it would be difficult for us to present a detailed reconciliation on account of many unknown variables for the reconciling items.

Adjusted EBITDA Reconciliation

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

Year Ended December 31,

(In thousands) 2007 2008 2009 2010 2011 2012 Unaudited Adjusted EBITDA reconciliation to Net Income (Loss):

Net (loss) income ($300) $103,878 ($14,425) $6,377 ($10,309) ($33,261) Interest expense ——3 683 1,002 Total income tax provision (benefit)—20,023 (9,925) 3,521 (5,521) (1,430) Depletion, depreciation and amortization 7,889 12,127 10,743 15,596 31,754 80,454 Accretion of asset retirement obligations 70 92 137 155 209 256 Full-cost ceiling impairment—22,195 25,244—35,673 63,475 Unrealized loss (gain) on derivatives 211 (3,592) 2,375 (3,139) (5,138) 4,802 Stock option and grant expense 205 605 622 824 2,362 (589) Restricted stock grants 15 60 34 74 44 729 Net loss (gain) on asset sales and inventory impairment—(136,977) 379 224 154 485

Adjusted EBITDA $8,090 $18,411 $15,184 $23,635 $49,911 $115,923

Year Ended December 31,

(In thousands) 2007 2008 2009 2010 2011 2012 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities:

Net cash provided by operating activities $7,881 $25,851 $1,791 $27,273 $61,868 $124,228 Net change in operating assets and liabilities 209 (17,888) 15,717 (2,230) (12,594) (9,307) Interest expense ——3 683 1,002 Current income tax provision (benefit)—10,448 (2,324) (1,411) (46)—

Adjusted EBITDA $8,090 $18,411 $15,184 $23,635 $49,911 $115,923

54 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 our 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 December 31, 2008, December 31, 2009, December 31, 2010, December 31, 2011 and December 31, 2012 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 PV-10 at December 31, 2008, December 31, 2009, December 31, 2010, December 31, 2011 and December 31, 2012 were, in millions, $44.1, $70.4, $119.9, $248.7 and $423.2, respectively. The discounted future income taxes at December 31, 2008, December 31, 2009, December 31, 2010, December 31, 2011 and December 31, 2012 were, in millions, $0.8, $5.3, $8.8, $33.2 and $28.6, respectively.