Investor Presentation November 2013
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.
Company Summary
4 Company Overview Completed IPO of 14,883,334 shares (12,209,167 primary) including overallotment at $12.00/share in March 2012 and Follow-on Offering of 9,775,000 shares including overallotment at $15.25/share in September 2013 Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 65.6 million common shares Share Price(2) $20.98/share Market Capitalization(2) $1.4 billion 2012 Actual 2013 Guidance Capital Spending $335 million $370 million Total Oil Production 1.214 million barrels 2.0 to 2.1 million barrels Total Natural Gas Production 12.5 billion cubic feet 12.0 to 13.0 billion cubic feet Oil and Natural Gas Revenues $156.0 million $250 to $270 million(3) Adjusted EBITDA(4) $115.9 million $180 to $190 million(3) (1) As reported in the Form 10-Q for the quarter ended September 30, 2013 filed on November 8, 2013. (2) As of November 11, 2013. (3) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA based upon production guidance range as updated on November 6, 2013. Guidance includes actual results for the nine months ended September 30, 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $96.00/Bbl and $4.30/Mcf, respectively, for the period October through December 2013. (4) 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.
Founded by Joe Foran in 1983 – most participants are still shareholders today. 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 $6 million, a proven management and technical team and board of directors Grown entirely 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 Redeployed capital into the Eagle Ford, relatively early in the play, acquiring over 30,000 net acres for approximately $100 million, mainly in 2010 and 2011 2012 and 2013 capital spending focused primarily on developing Eagle Ford and transitioning to oil IPO in February 2012 (NYSE: MTDR) had net cash proceeds of approximately $136 million Follow-on Offering in September 2013 had net cash proceeds of approximately $142 million CAGR since 2008 – Average Daily Production (54%)(2), Revenues (62%)(2) and Adjusted EBITDA(3) (56%)(4) Predecessor Entities (1) Tom Brown purchased by Encana in 2004. (2) Through first nine months of 2013. See Financial Overview. (3) 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. (4) For the last twelve months ended September 30, 2013. See page 34. Matador Today
T h o u s a n d Bb l Matador’s Continued Growth 6 (1) 2013 estimates at midpoint of guidance range as updated on November 6, 2013. Guidance includes actual results for the nine months ended September 30, 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $96.00/Bbl and $4.30/Mcf, respectively, for the period October 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 m il li o n s in m il li o n s Growth Since the IPO TOTAL OIL AND TOTAL OIL PRODUCTION (1) NATURAL GAS REVENUES (1) ADJUSTED EBITDA (1)(2) $8.1 $18.4 $15.2 $23.6 $49.9 $115.9 $185.0 2007 2008 2009 2010 2011 2012 2013E $14.0 $30.6 $19.0 $34.0 $67.0 $156.0 $260.0 2007 2008 2009 2010 2011 2012 2013E 22 37 30 33 154 1,214 2,050 2007 2008 2009 2010 2011 2012 2013E
Matador Execution History – IPO (February 7, 2012) vs. Today Grow with a focus on the Eagle Ford to create a more balanced portfolio Production 7.1 MBOE/d 414 Bbl/d of oil 6% oil 13.5 MBOE/d 6,700 Bbl/d of oil 50% oil Proved Reserves 27 MMBOE 1.1 MMBbl of oil 4% oil 44 MMBOE 13.9 MMBbl of oil 31% oil PV-10(2) $155.2 million 24% of PV-10 value in the Eagle Ford $538.6 million 89% of PV-10 value in the Eagle Ford LTM Adjusted EBITDA(3) $50 million(4) $181 million Identify and develop additional oil opportunities Acreage ~7,500 net acres in the Permian ~40,400 net acres in the Permian(8) Create value for stakeholders Enterprise Value(5) $0.65 billion(6) Over $1.5 billion(9) 16x growth in oil production Over 12x growth in oil reserves ~260% growth More than doubled Enterprise Value Increased Permian leasehold position by over 5x What we said at IPO 7 At IPO(1) What we’ve done Today(7) 3.5x growth in PV-10 (1) Unless otherwise noted, at or for the nine months ended September 30, 2011. (2) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. (3) 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. (4) For the twelve months ended December 31, 2011. (5) Enterprise value equals market capitalization plus borrowings under our revolving credit agreement. (6) As of February 7, 2012 at time of IPO. (7) Unless otherwise noted, at or for the three months ended September 30, 2013. (8) As of November 6, 2013. (9) As of November 11, 2013. Metric
8 Total Enterprise Value(1) Over $1.5 billion Average Daily Production(2) 11,663 BOE/d Oil (% total) 5,584 Bbl/d (48%) Natural Gas (% total) 36.5 MMcf/d (52%) Proved Reserves @ 9/30/2013 44.2 million BOE % Proved Developed 37% % Oil 31% PV-10(3) $538.6 million 2013E CapEx $370 million % South Texas ~72% % Oil and Liquids ~97% Gross Acreage(4) 209,529 acres Net Acreage(4) 129,563 acres Engineered Drilling Locations(4)(5) 949 gross / 456.5 net (1) Enterprise value equals market capitalization plus borrowings under credit agreement as of November 11, 2013. (2) Average daily production for the nine months ended September 30, 2013. (3) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non- GAAP), see Appendix. (4) Presented as of November 6, 2013. (5) Identified and 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 Company Overview ~72% 2013E CapEx
9 Investment Highlights Strong Growth Profile with Increasing Focus on Oil / Liquids Average daily production CAGR of 54% since 2008 with 16x growth in oil production since IPO ~97% of 2013E capital expenditure program focused on oil / liquids exploration and development High Quality Asset Base in Attractive Areas ~27,000 net acres in the Eagle Ford in some of the most active counties in the play including Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala counties ~40,400 net acres in the Permian Basin prospective for the liquids-rich Wolfcamp, Bone Spring and other targets Long-term option on natural gas, with Haynesville, Cotton Valley and Bossier assets almost all HBP Multi-year Drilling Inventory 211.0 net identified drilling locations in the Eagle Ford 74.5 net identified drilling locations in the Permian Basin with escalating activity to de-risk the play 151.4 net drilling locations in the Haynesville and Cotton Valley Low Cost Operations Substantially reduced Eagle Ford drilling days and well costs since IPO Batch drilling program has potential to further reduce well costs by $300,000 per well Strong Financial Position Liquidity available to execute planned drilling program Proven Management and Technical Team and Active Board of Directors Management and senior technical team average over 25 years of industry experience Board with extensive industry knowledge, business experience and company ownership Strong record of stewardship
$0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 $550 $600 2008 2009 2010 2011 2012 Q3 2013 Growth in PV-10(1) from SEC Proved Reserves $57.65 oil $3.87 gas $75.96 oil $4.38 gas $92.71 oil $4.12 gas $91.21 oil $2.76 gas $91.69 oil $3.61 gas P V -1 0 (1 ) , m il li o n s 10 SEC Pricing Oil, $/Bbl Gas, $/MMBtu $41.00 oil $5.71 gas (2) (2) (2) (2) (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. (3) At September 30, 2013. (3)
11 SEC Proved Reserves Value Growth By Area Eagle Ford $130 million, 52% Haynesville $96.6 million, 39% Cotton Valley $19.5 million, 8% SE New Mexico $2.4 million, 1% Sept. 30, 2013 PV-10(1): $538.6 million $91.69 oil $3.61 gas (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. Eagle Ford $393.7 million, 93% Haynesville $21.8 million, 5% Cotton Valley $5.9 million, 1% SE New Mexico $2 million, 1% Dec. 31, 2012 PV-10(1): $423.2 million $91.21 oil $2.76 gas Dec. 31, 2011 PV-10(1): $248.7 million $92.71 oil $4.12 gas Eagle Ford $479.3 million, 89% Haynesville $45.2 million, 8% Cotton Valley $10.0 million, 2% SE New Mexico $4.1 million, 1%
Eagle Ford South Texas
13 Significant Eagle Ford Exposure (1) For the year ended December 31, 2011. (2) For the nine months ended September 30, 2013. (3) At November 6, 2013. (4) Identified and 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. Proved Reserves @ 9/30/2013 17.9 million BOE % Proved Developed 55% % Oil 75% Daily Oil Equivalent Production(2) 7,865 BOE/d (70% Oil) Gross Acres(3) 38,756 acres Net Acres(3) 26,981 acres 2013E CapEx Budget $288 million Engineered Drilling Locations(3)(4) 260 gross (211.0 net) Overview Operations Summary Continuing a two-rig program in the Eagle Ford Significantly reduced number of days to drill wells (days on wells) ~72% of 2013E total capital expenditure program focused on oil and liquids development in the Eagle Ford Realized three-fold growth in proved oil reserves since December 31, 2011 Established acreage position in the Eagle Ford shale in some of the most active counties including: Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala – ~16,000 net acres are also prospective for Austin Chalk in addition to potential prospects in the Buda, Edwards and Pearsall formations – ~9,000 net acres in Zavala County prospective for emerging Buda play 53 gross (46 net) wells(2) producing from the Eagle Ford, increasing oil production from ~330 Bbl/d(1) to ~6,700 Bbl/d(2) with an additional 260 gross (211.0 net) locations identified for potential future drilling
14 Eagle Ford Properties Note: All acreage at November 6, 2013. Uvalde Medina Zavala Frio Dimmit La Salle Webb Bexar Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson EAGLE FORD EAST 7,570 gross / 6,360 net acres EOG OPERATED, MTDR WI ~21% 9,508 gross / 1,777 net acres GLASSCOCK (WINN) RANCH 8,891 gross / 8,891 net acres EAGLE FORD WEST 12,787 gross / 9,953 net acres EAGLE FORD ACREAGE TOTALS 38,756 gross / 26,981 net acres Matador Resources Acreage San Antonio Glasscock Ranch Shelton Newman Martin Ranch Northcut Affleck Troutt Sutton MRC/EOG Pawelek Danysh Sickenius Lyssy Repka RCT Wilson Love Cowey Keseling Lewton Hennig Nickel Ranch Pena COMBO LIQUIDS / GAS FAIRWAY DRY GAS FAIRWAY OIL FAIRWAY ZLS Karnes
15 Eagle Ford Well Costs and Estimated Ultimate Recovery (“EUR”) Note: All acreage at November 6, 2013. EUR’s represent typical range of results over last 12 months by area. Well costs reflect actual costs of all 2013 wells by area. See pages 17-19 for additional information. Karnes Uvalde Medina Zavala Frio Dimmit La Salle Webb Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson Matador Resources Acreage San Antonio Glasscock Ranch Shelton Newman Martin Ranch Northcut Affleck Troutt Sutton MRC/EOG Pawelek Danysh Sickenius Lyssy Repka RCT Wilson Love Cowey Keseling Lewton Hennig Nickel Ranch Pena COMBO LIQUIDS / GAS FAIRWAY DRY GAS FAIRWAY OIL FAIRWAY EAGLE FORD “WEST” (p. 17) Well Costs: $6-7 million EUR: 300-500 MBOE EAGLE FORD “EAST” (p. 19) Well Costs: $8-10 million EUR: 600-1,000 MBOE EAGLE FORD “CENTRAL” (p. 18) Well Costs: $7-8 million EUR: 400-500 MBOE
$9.9 $7.8 $6.5 $5.6 2011 2012 2013YTD Last Well $11.0 $9.4 $7.3 $7.0 2011 2012 2013YTD Last Well $10.4 $8.3 $8.2 2012 2013YTD Last Well Overview 16 Operational Improvements Note: “2013 YTD” and “Last Well” – As of November 6, 2013. Year classification is based on spud date. (1) Excludes any/all wells drilled with a pilot hole. Drilling days are from spud to total depth. (2) Reflects the most recent drilled and completed development well – excludes a well that is burdened with extra costs associated with drilling the first well on any given lease, for example: constructing a frac pit, building the lease road, etc. Eagle Ford Drilling Days(1) Eagle Ford Total Well Cost(1) West Central East West Central East Experience in the Eagle Ford has led to significant reductions in drilling days and well costs Drilling from four-well batch drilled pads has the potential to yield additional savings (2) (2) (2) Cost Savings Rig Moves ~$115,000 Location ~$60,000 Drilling Efficiencies ~$125,000 Total Per Well Cost Savings ~$300,000 Four-Well Batch Drilled Pad vs. Single Well Pad 18.8 20.1 15.0 13.0 2011 2012 2013YTD Last Well 19.2 12.6 11.3 8.0 2011 2012 2013YTD Last Well 24.7 18.9 18.0 2012 2013YTD Last Well
17 Eagle Ford “West” 8,000’ – 9,000’ True Vertical Depth ~240°F (3) 2-String Casing Design White Sand Note: “2013 YTD” and “Last Well” – As of November 6, 2013. Year classification is based on spud date. (1) Excludes any/all wells drilled with a pilot hole. Drilling days are from spud to total depth. (2) Reflects the most recent drilled and completed development well – excludes a well that is burdened with extra costs associated with drilling the first well on any given lease, for example: constructing a frac pit, building the lease road, etc. DRILLING DAYS (1) FRAC STAGE COST TOTAL WELL COST (2) ($ in thousands) ($ in millions) $9.9 $7.8 $6.5 $5.6 2011 2012 2013 YTD Last Well $247.9 $126.2 $118.8 $106.8 2011 2012 2013 YTD Last Well 19.2 12.6 11.3 8.0 2011 2012 2013 YTD Last Well
18 Eagle Ford “Central” (3) 10,500’ – 11,500’ True Vertical Depth ~300°F 2-String Casing Design White Sand DRILLING DAYS (1) FRAC STAGE COST TOTAL WELL COST (2) ($ in thousands) ($ in millions) $11.0 $9.4 $7.3 $7.0 2011 2012 2013 YTD Last Well $159.5 $130.1 $121.2 $120.9 2011 2012 2013 YTD Last Well 18.8 20.1 15.0 13.0 2011 2012 2013 YTD Last Well Note: “2013 YTD” and “Last Well” – As of November 6, 2013. Year classification is based on spud date. (1) Excludes any/all wells drilled with a pilot hole. Drilling days are from spud to total depth. (2) Reflects the most recent drilled and completed development well – excludes a well that is burdened with extra costs associated with drilling the first well on any given lease, for example: constructing a frac pit, building the lease road, etc.
19 Eagle Ford “East” (3) 12,500’ – 13,500’ True Vertical Depth ~330°F 2-String or 3-String Casing Design Premium Proppant(3) Note: “2013 YTD” and “Last Well” – As of November 6, 2013. Year classification is based on spud date. (1) Excludes any/all wells drilled with a pilot hole. Drilling days are from spud to total depth. (2) Reflects the most recent drilled and completed development well – excludes a well that is burdened with extra costs associated with drilling the first well on any given lease, for example: constructing a frac pit, building the lease road, etc. (3) Premium proppant typically used is resin-coated sand which is more expensive than white sand. DRILLING DAYS (1) FRAC STAGE COST TOTAL WELL COST (2) ($ in thousands) ($ in millions) $10.4 $8.3 $8.2 2012 2013 YTD Last Well $219.7 $183.5 $120.0 2012 2013 YTD Last Well 24.7 18.9 18.0 2012 2013 YTD Last Well
Batch Drilling – Reducing Well Costs and Well Times Further 20 Time Savings •Rig Moves ~2 Days •Drilling Efficiencies ~1 Day Total Per Well Time Savings ~3 Days Cost Savings •Rig Moves ~$115,000 •Location ~$60,000 •Drilling Efficiencies ~$125,000 Total Per Well Cost Savings ~$300,000 Approx. $300,000 cost reduction per well when going from single well pad to a four-well batch drilled pad! Four-Well Batch Drilled Pad vs. Single Well Pad
21 Evolution of Matador Frac Design Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal wellbore. (1) Mlbs = thousands of pounds of proppant pumped.
22 Well Improvement with Evolution of Frac Design Example 1: Rate(1) vs. Cum. Oil Production Example 2: Rate(1) vs. Cum. Oil Production Example 1: Cum. Oil Production vs. Time Example 2: Cum. Oil Production vs. Time Note: DOFP = Date of first production. (1) Oil rate shown is a five day trailing average. 0 100 200 300 400 500 600 700 800 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 Ra te, Bbl/ d Cumulative Production, Bbl Second Generation Frac Design (DOFP: 3/25/12) Third Generation Frac Design (DOFP: 9/14/12) Fourth Generation Frac Design (DOFP: 12/18/12) 0 100 200 300 400 500 600 700 800 900 1,000 0 10, 00 20,000 30,000 40, 0 50,000 60,000 7 ,000 80,000 90,000 1 0,000 110,0 120,000 130,000 Ra te, Bbl/ d Cumulative Production, Bbl Second Generation Frac Design (DOFP: 3/17/12) Third Generation Frac Design (DOFP: 9/29/12) Fifth Generation Frac Design (DOFP: 7/16/13) 0 10,000 20,000 30,000 40,0 50,000 60,000 70,000 80,000 90,000 100,000 0 50 100 150 200 250 300 350 400 450 Cu mul ati ve Oil P rodu ction, Bb l Time, Days Second Generation Frac Design (DOFP: 3/25/12) Third Generation Frac Design (DOFP: 9/14/12) Fourth Generation Frac Design (DOFP: 12/18/12) 0 20,000 40,000 60,0 80,000 100,000 120,000 140,000 0 50 100 150 200 250 300 350 400 450 500 Cu mul ati ve Oil P rodu ction, Bb l Time, Days Second Generation Frac Design (DOFP: 3/17/12) Third Generation Frac Design (DOFP: 9/29/12) Fifth Generation Frac Design (DOFP: 7/16/13)
Permian Basin Southeast New Mexico and West Texas
24 Gross Acres(1) 64,893 acres Net Acres(1) 40,425 acres Increasing Exposure to the Permian Foothold of existing production and reserves Acreage position in good neighborhoods, surrounded by other operators’ ongoing drilling Targeting 107 gross (74.5 net) engineered drilling locations(2) Currently running one rig in Southeast New Mexico and West Texas to conduct a three-well exploration program Plan to run one rig throughout remainder of 2013 and 2014 Year to date(3) acquired approximately 49,000 gross (32,800 net) acres primarily in Lea and Eddy Counties, New Mexico (1) Total acreage in Southeast New Mexico and West Texas as of November 6, 2013, including some tracts not shown on map. Matador acreage shown in red. (2) At November 6, 2013. (3) From January 1, 2013 through November 6, 2013. RANGER- QUERECHO WOLF INDIAN DRAW E D D Y L E A LOVING
Ranger Prospect Area: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results 7 7 5 0 8 0 0 0 8 2 5 0 8 5 0 0 8 7 5 0 9 0 0 0 9 2 5 0 9 5 0 0 9 7 5 0 1 0 0 0 0 1 0 2 5 0 1 0 5 0 0 1 0 7 5 0 1 1 0 0 0 1 1 2 5 0 1 1 5 0 0 0 150 GR (CTR) 0.2 2000 LLD 0.2 2000 LLS Log Depth(ft) Log Depth(ft) 7500 7500 7750 7750 8000 8000 8250 8250 8500 8500 8750 8750 9000 9000 9250 9250 9500 9500 9750 9750 10000 10000 10250 10250 10500 10500 10750 10750 11000 11000 11250 11250 11500 11500 Wells 9,000' > HS=0 PETRA 11/28/2012 5:33:57 PM Bone Spring Lime 1st Bone Spring Sand 2nd Bone Spring Sand Wolfcamp Bone Spring / Upper Wolfcamp Type Log 3rd Bone Spring Sand 25 Concho Stratojet 31 State #3H 2nd Bone Spring 24 mo.cum: 360 MBbl; 426 MMcf Cimarex Energy Lynch 23 Fed #1H 3rd Bone Spring 22 mo.cum: 197 MBbl; 183 MMcf Legacy Operating Lea Unit 4H 3rd Bone Spring 24 mo.cum: 81 MBbl; 83 MMcf Concho AirCobra 12 #2H 3rd Bone Spring 25 mo.cum: 296 MBbl; 201 MMcf XOG Operating (Vertical well) Jordan B #1 Wolfcamp 20 years cum: 387 MBbl; 5 Bcf Concho (Vertical well) Neuhaus 14 Fed #2 Wolfcamp 8 years cum: 156 MBbl; 2 Bcf 3 Rivers Oper Eagle 2 State 6H 3rd Bone Spring 8 mo.cum: 87 MBbl; 51 MMcf Cimarex Energy Mallon 35 Fed 4H 3rd Bone Spring 30 mo.cum: 42 MBbl; 34 MMcf Amtex Energy Teapot 2H 2nd Bone Spring 25 mo.cum: 64 MBbl; 58 MMcf Concho Condor State #1H 2nd Bone Spring 6 mo.cum: 66 MBbl; 43 MMcf Devon Ironhouse 19 State #1H 2nd Bone Spring IP: 603 Bbl/d; 298 Mcf/d 3 mo. Cum: 20 MBbl; 12 MMcf Note: All acreage at November 6, 2013. Well information from public sources as of November 2013. Matador acreage shown in red. Location of Matador 2013 test wells
Wolf Leasehold: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Wolf Energy Wolf #1 (Vertical well) 3rd BS / Upr Wolfcamp 33.5 years cum: 61 MBbl; 642 MMcf Wolf Energy Dorothy White #1 (Vertical well) 3rd BS / Upr Wolfcamp 17 years cum: 25 MBbl; 92 MMcf Shell Johnson 1-88 Lov #1H Wolfcamp 18 mo.cum: 63 MBbl; 265 MMcf Shell Johnson 1-86 (1H) Wolfcamp 30 mo.cum: 186 MBbl; 537 MMcf OXY Reagan-McElvain #1H Wolfcamp IP: 570 Bbl/d 2.6 MMcf/d 9 mo.cum: 102 MBbl; 261 MMcf Shell Johnson 1-76 (1H) Wolfcamp 35 mo.cum: 178 MBbl; 572 MMcf Energen Grayling 1-69 Wolfcamp IP: 791 Bbl/d 7.3 MMcf/d 3,500 psi FTP 13 mo.cum: 86 MBbl; 727 MMcf Energen Black Mamba 1-57 Wolfcamp 12 mo.cum: 213 MBbl; 541 MMcf Shell Owens 1-75 Lov #1H Wolfcamp 19 mo.cum: 98 MBbl; 211 MMcf Energen Bushmaster 1-58 1H Wolfcamp 15 mo.cum: 131 MBbl; 355 MMcf Energen Katie 1-72 Wolfcamp 13 mo.cum: 40 MBbl; 121 MMcf Note: All acreage at November 6, 2013. Well information from public sources as of November 2013. Matador acreage shown in red. 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 26 Location of Matador 2013 test wells
Haynesville & Cotton Valley Northwest Louisiana and East Texas
Significant Option Value on Natural Gas Balanced portfolio of assets provides optionality should natural gas prices continue to recover Significant acreage position in the Haynesville play Also prospective for the Cotton Valley, Travis Peak and other shallow formations 97% of Haynesville acreage is HBP(4)(6) Potential drilling locations remain available to be drilled at any future time Competitive well economics on Tier 1 Haynesville wells at $4.50 / Mcf natural gas price As a result of the improvement in natural gas prices over the past year, Matador added approximately 100 Bcf (16.7 million BOE) of proved undeveloped natural gas reserves NW Louisiana / East Texas(1) Proved Reserves(2) 154.1 Bcfe Daily Production(3) 3,772 BOE/d (99% natural gas) Net Acres(4) 26,153 acres Net Producing Wells(4) 82.6 Drilling Locations(4)(5) 151.4 net wells % HBP(4)(6) 97% (1) Includes both Haynesville and Cotton Valley acreage. (2) At September 30, 2013. (3) For the nine months ended September 30, 2013. (4) At November 6, 2013. (5) Identified and 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. (6) Acreage held by production or fee mineral interests owned by Matador. 28 CADDO BOSSIER BIENVILLE RED RIVER DESOTO Elm Grove Cotton Valley: 49 Net Locations Matador Operated Acreage(4): 9,992 gross, 9,802 net Locations(4)(5): 71 gross, 49 net Tier 1 Haynesville: 50 Net Locations Acreage(4): 13,758 gross, 6,925 net Locations(4)(5): 440 gross, 51 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 MATADOR CALLON CHESAPEAKE ENCANA EXCO GOODRICH J-W PETROHAWK / BHP QUESTAR SAMSON SHELL Note: All acreage at November 6, 2013. Matador acreage shown in red.
29 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 September 30, 2013. (2) NYMEX gas price, less property-specific differentials. $22 $30 $38 $46 $54 $62 $70 $102$26 $79 $141 $207 $275 $342 $619 $6 $21 $101 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 $8.00 PV -1 0( 1) , $ m ill ion s Gas Price(2) , $/Mcf Haynesville - Tier 2 (Undrilled), $millions Haynesville - Tier 1 (Undrilled), $millions Haynesville Proved Producing, $millions
Gracie Wyoming, Utah and Idaho
Matador Gracie Project Total Prospect Acreage IDAHO UTAH W YO M IN G W Y O M IN G ID A H O U T A H WYOMING 76,497 gross acres 36,004 net acres Crawford Federal #1H 31 Note: All acreage at November 6, 2013. Matador acreage shown in red.
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 32
Financial Overview
$18.4 $15.2 $23.6 $49.9 $115.9 $181.0 2008 2009 2010 2011 2012 9/30/2013 LTM 1.5 2.3 3.9 7.0 9.0 11.7 2008 2009 2010 2011 2012 First 9 mo. 2013 7% 4% 2% 6% 37% 48% 2008 2009 2010 2011 2012 First 9 mo. 2013 $30.6 $19.0 $34.0 $67.0 $156.0 $252.1 2008 2009 2010 2011 2012 9/30/2013 LTM Matador’s Continued Growth 34 Average Daily Production(1) (MBOE/d) Oil Production Mix(1) (% of Average Daily Production) Oil & Natural Gas Revenues ($ in millions) Adjusted EBITDA(2) ($ in millions) (1) Nine months ended September 30, 2013 reflects average daily production for the first nine months of 2013. 2008 – 2012 average daily production reflects average for each respective year. (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. (3) LTM is last twelve months through September 30, 2013. (unaudited) (3) (3)
$19.0 $34.0 $67.0 $156.0 $260.0 $0.0 $50.0 $100.0 $150.0 $200.0 $250.0 $300.0 2009 2010 2011 2012 2013E $15.2 $23.6 $49.9 $115.9 $185.0 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 $140.0 60 $180.0 $200.0 2009 2010 2011 2012 2013E 35 2013 Oil and Natural Gas Revenues(1) Estimated oil and natural gas revenues of $250 to $270 million − Mid-point is an increase of 67% from $156.0 million in 2012 2013 Adjusted EBITDA(1)(2) Estimated Adjusted EBITDA(1)(2) of $180 to $190 million − Mid-point is an increase of 60% from $115.9 million in 2012 2013 Financial Guidance (1) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA based upon production guidance range as updated on November 6, 2013. Guidance includes actual results for the nine months ended September 30, 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $96.00/Bbl and $4.30/Mcf, respectively, for the period October 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. (3) Midpoint of 2013 annual guidance. Oil and Natural Gas Revenues(1) (millions) Adjusted EBITDA(1)(2) (millions) (3) (3)
36 2013 and 2014 Hedging Profile At November 6, 2013, Matador had: 0.3 million barrels of oil hedged for remainder of 2013 at weighted average floor and ceiling of $88/Bbl and $106/Bbl, respectively 0.8 Bcf of natural gas hedged for remainder of 2013 at weighted average floor and ceiling of $3.19/MMBtu and $4.45/MMBtu, respectively 2.0 million gallons of natural gas liquids hedged for remainder of 2013 at weighted average price of $1.20/gal 2.3 million barrels of oil, 8.4 Bcf of natural gas and 5.8 million gallons of natural gas liquids hedged for 2014 Note: Hedged volumes shown in table for 2013 are for remainder of 2013; volumes shown in table for 2014 are for full calendar year. Oil Hedges (Costless Collars) 2013 2014 Total Volume Hedged by Ceiling (Bbl) 264,400 2,294,000 Weighted Average Price ($ / Bbl) $108.23 $98.92 Total Volume Hedged by Floor (Bbl) 264,400 2,294,000 Weighted Average Price ($ / Bbl) $87.27 $87.75 Oil Hedges (Swaps) 2013 2014 Total Volume Hedged (Bbl) 40,000 - Weighted Average Price ($ / Bbl) $90.43 - Natural Gas Hedges (Costless Collars) 2013 2014 Total Volume Hedged by Ceiling (Bcf) 0.83 8.40 Weighted Average Price ($ / MMBtu) $4.45 $5.15 Total Volume Hedged by Floor (Bcf) 0.83 8.40 Weighted Average Price ($ / MMBtu) $3.19 $3.32 Natural Gas Liquids (NGLs) Hedges (Swaps) 2013 2014 Total Volume Hedged (gal) 1,984,800 5,820,000 Weighted Average Price ($ / gal) $1.20 $1.28
Appendix
Proven Management Team – Experienced Leadership 38 Management Team Background and Prior Affiliations Industry Experience Matador Experience Joseph Wm. Foran Founder, Chairman and CEO - Matador Petroleum Corporation, Foran Oil Company and James Cleo Thompson Jr. 33 years Since Inception David E. Lancaster EVP, COO and CFO - Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 34 years Since 2003 Matthew V. Hairford EVP and Head of Operations - Samson, Sonat, Conoco 29 years Since 2004 David F. Nicklin Executive Director of Exploration - ARCO, Senior Geological Assignments in UK, Norway, Indonesia, China and the Middle East 42 years Since 2007 Craig N. Adams EVP – Land & Legal - Baker Botts L.L.P., Thompson & Knight LLP 20 years Since 2012 Bradley M. Robinson VP and CTO - Schlumberger, S.A. Holditch & Associates, Inc., Marathon 36 years Since Inception Ryan C. London VP and General Manager - Matador Resources Company (Began as intern) 9 years Since 2004 Billy E. Goodwin VP of Drilling - Samson, Conoco 29 years Since 2010 Van H. Singleton, II VP of Land - Southern Escrow & Title, VanBrannon & Associates 17 years Since 2007 G. Gregg Krug VP of Marketing - Williams Companies, Samson, Unit Corporation 30 years Since 2005 Kathryn L. Wayne Controller and Treasurer - Matador Petroleum Corporation, Mobil 28 years Since Inception
Board of Directors and Special Board Advisors – Expertise and Stewardship 39 Board Members and Advisors Professional Experience Business Expertise Dr. Stephen A. Holditch Director - Professor Emeritus and Former Head of Dept. of Petroleum Engineering, Texas A&M University - Founder and Former President, S.A. Holditch & Associates - Past President of Society of Petroleum Engineers Oil and Gas Operations David M. Laney Lead Director - Past Chairman, Amtrak Board of Directors - Former Partner, Jackson Walker LLP Law and Investments Gregory E. Mitchell Director - President and CEO, Toot’n Totum Food Stores Petroleum Retailing Dr. Steven W. Ohnimus Director - Retired VP and General Manager, Unocal Indonesia Oil and Gas Operations Michael C. Ryan Director - Partner, Berens Capital Management International Business and Finance Carlos M. Sepulveda, Jr. Director - Chairman of the Board, Triumph Bancorp, Inc. - Retired President and CEO, Interstate Battery System International, Inc. - Director and Audit Chair, Cinemark Holdings, Inc. 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 and 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 and Gas Executive Management
Southwest Glasscock Ranch Buda Production History Global Geophysical 3D Seismic Survey Area Outline Dan Hughes Heitz 302 3H 8/18/2012 IP: 350 Bbl/d 500 Mcf/d 14 mo.cum: 250,333 Bbl 262,009 Mcf TX American Resources Buchanan 1H 5/3/2013 IP: 756 Bbl/d 556 Mcf/d 5 mo.cum: 76,989 Bbl 78,077 Mcf Dan Hughes Heitz 302 5H 13 mo.cum: 151,715 Bbl 293,114 Mcf Crimson Beeler 2H 5/13/2013 IP: 761 Bbl/d 253 Mcf/d 4 mo.cum: 58,060 Bbl 68,146 Mcf Sage Energy Mills-Wood Unit 1H 5/19/2013 IP: 585 Bbl/d 0 Mcf/d 5 mo.cum: 42,933 Bbl 88,769 Mcf Sage Energy Mills 2H 11/28/2012 IP: 889 Bbl/d 650 Mcf/d 10 mo.cum: 77,402 Bbl 122,978 Mcf Sage Energy Mills 1H 3/5/2013 IP: 959 Bbl/d 541 Mcf/d 7 mo.cum: 59,186 Bbl 92,375 Mcf Dan Hughes Heitz 303 2H 5/1/2012 IP: 351 Bbl/d 665 Mcf/d 18 mo.cum: 199,090 Bbl 203,911 Mcf Dan Hughes Heitz 1H 12/15/2011 IP: 200 Bbl/d 150 Mcf/d 21 mo.cum: 225,897 Bbl 379,157 Mcf Dan Hughes Heitz-Fehrenbach 1H 1/25/2013 IP: 85 Bbl/d 200 Mcf/d 8 mo.cum: 10,284 Bbl 39,002 Mcf US Enercorp Lang 1H 7/4/2012 IP: 165 Bbl/d 200 Mcf/d 13 mo.cum: 4,270 Bbl 33,729 Mcf TX American Resources Flores 1H 10/24/2012 IP: 205 Bbl/d 0 Mcf/d 7 mo.cum: 26,114 Bbl 0 Mcf Dan Hughes Irish-Seeligson Unit 1H 7 mo.cum: 28,865 Bbl 7,059 Mcf Dan Hughes Baty-Heitz Unit 1H 3 mo.cum: 8,748 Bbl 420 Mcf TX American Resources Haley-Tarh 1H 1/6/2013 IP: 222 Bbl/d 1,828 Mcf/d 4 mo.cum: 7,152 Bbl 14,538 Mcf Dan Hughes Haley 1H 6 mo.cum: 4,310 Bbl 12,409 Mcf Note: All acreage at November 6, 2013. Well information from public sources as of November 2013. Matador acreage shown in red. Dan Hughes Proprietary Data is Excluded 40
41 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.
Nine Months Ended LTM at (In thousands) 2007 2008 2009 2010 2011 2012 9/30/2013 9/30/2013 Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): Net (loss) income ($300) $103,878 ($14,425) $6,377 ($10,309) ($33,261) $29,720 $8,532 Interest expense - - - 3 683 1,002 4,919 5,468 Total income tax provision (benefit) - 20,023 (9,925) 3,521 (5,521) (1,430) 2,641 2,453 Depletion, depreciation and amortization 7,889 12,127 10,743 15,596 31,754 80,454 74,593 102,248 Accretion of asset retirement obligations 70 92 137 155 209 256 248 334 Full-cost ceiling impairment - 22,195 25,244 - 35,673 63,475 21,229 47,903 Unrealized loss (gain) on derivatives 211 (3,592) 2,375 (3,139) (5,138) 4,802 6,626 10,279 Stock-based compensation expense 220 665 656 898 2,406 140 2,763 3,126 Net (gain) loss on asset sales and inventory impairment - (136,977) 379 224 154 485 192 617 Adjusted EBITDA $8,090 $18,411 $15,184 $23,635 $49,911 $115,923 $142,931 $180,960 Nine Months Ended LTM at (In thousands) 2007 2008 2009 2010 2011 2012 9/30/2013 9/30/2013 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 $127,192 $171,095 Net change in operating assets and liabilities 209 (17,888) 15,717 (2,230) (12,594) (9,307) 9,840 3,605 Interest expense - - - 3 683 1,002 4,919 5,468 Current income tax provision (benefit) - 10,448 (2,324) (1,411) (46) - 980 792 Adjusted EBITDA $8,090 $18,411 $15,184 $23,635 $49,911 $115,923 $142,931 $180,960 Year Ended December 31, Year Ended December 31, 42 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. Note: LTM is last 12 months through September 30, 2013.
43 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 September 30, 2013, December 31, 2012, December 31, 2011, September 30, 2011, December 31, 2010, December 31, 2009 and December 31, 2008 were, in millions, $538.6, $423.2, $248.7, $155.2, $119.9, $70.4 and $44.1 respectively, and 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 September 30, 2013, December 31, 2012, December 31, 2011, September 30, 2011, December 31, 2010, December 31, 2009 and December 31, 2008 were, in millions, $52.5, $28.6, $33.2, $11.8, $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.