Matador Resources Company · NYSE:MTDR

Matador Resources — Investor Presentation (January 2014)

58 slides from Matador Resources's investor presentation, Jan 10, 2014

  1. Slide 1: January 2014 Investor Presentation

    January 2014 Investor Presentation NYSE: MTDR

  2. Slide 2: Disclosure Statements

    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 19

  3. Slide 3: Company Summary

    Company Summary

  4. Slide 4: Matador History

     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

  5. Slide 5: Company Overview

    5 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

  6. Slide 6: Matador Execution History – IPO vs. Today

    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

  7. Slide 7: Matador's Continued Growth

    T h o u s a n d B b l Matador’s Continued Growth 7 (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

  8. Slide 8: 2013 was an Excellent Year for Matador

    2013 was an Excellent Year for Matador! 8  Technical improvements in all aspects of our Eagle Ford operations resulting in better wells for less money!  Drilling times and costs per well decreased significantly  Improved hydraulic fracture treatment designs yielding better EURs per well  Flowbac

  9. Slide 9: Keys to Matador's Success

    Keys to Matador’s Success 9  People  We have a strong, committed technical and financial team in place, and we continue to make additions and improvements to our staff and our capabilities  Board and Special Advisor additions have strengthened Board skills and stewardship  Properties  Matador’s

  10. Slide 10: Matador Resources Company Overview

    10 Matador Resources Company Overview Market Capitalization(1) ~$1.3 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% 2013E CapEx $370 million % South

  11. Slide 11: Eagle Ford South Texas

    a‘, {Mata ador ee ee Eagle Ford South Texas

  12. Slide 12: 2014 South Texas Plan Details

    2014 South Texas Plan Details 12  2014 projected capital expenditures of ~$318 million or ~72% of total  2-rig program with almost all of the 2014 South Texas capital budget directed to the Eagle Ford shale  Drill and/or complete or participate in 50 gross (47.0 net) wells; 43 gross (40.0 net) we

  13. Slide 13: Eagle Ford Overview

    13 Eagle Ford Overview (1) At December 11, 2013. (2) For the year ended December 31, 2011. (3) For the nine months ended September 30, 2013. (4) Presented as of November 30, 2013. (5) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified

  14. Slide 14: Eagle Ford Well Costs and Estimated Ultimate Recovery

    14 Eagle Ford Well Costs and Estimated Ultimate Recovery (“EUR”) Note: All acreage at December 31, 2013. EURs represent typical range of results over last 12 months by area. Well costs reflect actual costs of all 2013 wells by area. Karnes Uvalde Medina Zavala Frio Dimmit La Salle Webb Atascosa McMu

  15. Slide 15: Operational Improvements

    $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 15 Operational Improvements Note: “2013 YTD” and “Last Well” – As of November 6, 2013. Year classification is based on spud date. (1) Excludes any/all well

  16. Slide 16: Improvement in Drilling Efficiency – Moving Towards Batch Drilling

    0 50,000 100,000 150,000 200,000 250,000 300,000 2014 2013 2012 2011 2010 Lateral Feet Drilled 16 La eral Fee Single Well Drilling PAD Drilling BATCH Drilling EXPLORATION DEVELOPMENT 1/3 RIG 2/3 RIG 2 RIGS 1 1/2 RIGS 2 RIGS 60-70% increase in Rig Efficiency from 2012 - 2014! Improvement in Drilling

  17. Slide 17: Accelerated Production Benefits of Gas Lift

    17 Flowing Rod Pumping Gas Lifting 300 Bbl/d 100 Bbl/d Accelerated Production Benefits of Gas Lift • Accelerates production • Reduces LOE • Lower maintenance • Helps wells recover faster from offset fracs Artificial Lift Time

  18. Slide 18: Evolution of Matador Frac Design

    Gen 2 Gen 3 Gen 4 Gen 5 5,770 Bbl 7,825 Bbl 9,550 Bbl 11,750 Bbl 375 Mlbs 500 Mlbs 405 Mlbs 515 Mlbs Fluid Volume Pumped Proppant Pumped(1) 0 ft. 300 ft. 11,750 Bbl 650 Mlbs Gen 6 Evolution of Matador Frac Design 18 Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal well

  19. Slide 19: Frac Generation Comparison

    19 Frac Generation Comparison (all wells normalized to 5,000’ horizontal) 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 110,000 120,000 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360 Cum ula tiv e P rod uctio n (B bl) Time (Days) GEN 2 (80 Acre) GEN

  20. Slide 20: Pearsall Field and Pearsall Arch Buda Wells Activity

    Blackbrush O&G Oppenheimer-101H Comp May 2013 6 mo avg: 251 Bbl/d 562 Mcf/d Cum: 45,759 Bbl 102,582 Mcf Blackbrush O&G 8 Buda Completions May 2011 – May 2013 Cum: 220 MBbl 672 MMcf Texas American Res Buchanan-1H Comp Apr 2013 5 mo avg: 507 Bbl/d 514 Mcf/d Cum: 76,989 Bbl 78,077 Mcf Dan A. Hughes Hei

  21. Slide 21: Glasscock Ranch Seismic Mapping of Natural Fracture Trends

    Buda Productive Area Glasscock Ranch – Frio South Survey Amplitude at Time Slice Near Top Buda Fracture trends from MTDR Glasscock #2H consistent with seismic trend Dan A. Hughes Heitz Lease 4 Buda Completions Dec 2011 – Aug 2012 Cum: 827 MBbl, 1.14 Bcf Glasscock Ranch Seismic Mapping of Natural Fra

  22. Slide 22: Permian Basin Southeast New Mexico and West Texas

    Permian Basin Southeast New Mexico and West Texas

  23. Slide 23: 2014 Permian Basin Plan Details

    2014 Permian Basin Plan Details 23  2014 projected capital expenditures of ~$109 million or ~25% of total  1-rig program working in Lea and Eddy Counties, NM and Loving County, TX  Drill and/or complete or participate in 12 gross (9.8 net) wells; 10 gross (8.3 net) wells turned to sales  Include

  24. Slide 24: Permian Basin Acreage Position

    Permian Basin Total Gross Acres(1) 70,819 acres Net Acres(1) 44,835 acres Permian Basin Acreage Position (1) Total acreage in Southeast New Mexico and West Texas at December 31, 2013, including some tracts not shown on map. (2) Presented as of November 30, 2013. 24  Acreage position in good neighbo

  25. Slide 25: Wolf-Bone Geological Setting

    265 mya End of Bone Springs – Warmer! Delaware Basin San Andres Yeso Abo Delaware Mountain Group 1st, 2nd, 3rd Bone Spring Sands Sands confined to channels and distributary systems 1st, 2nd, 3rd Bone Spring Carbonates Wolfcamp “A” Carbonates Wolfcamp “D” Carbonates More limited in aerial extent Wolf

  26. Slide 26: Permian Basin Petroleum Systems and the Wolfcamp Kitchens

    DELAWARE BASIN CENTRAL BASIN PLATFORM MIDLAND BASIN Wolfcamp Simpson ~23,000’ Sediment Fill East West Source “Kitchens” Now Unconventional Resource Plays  70,000 square mile area  Up to 25,000 feet of multiple, stacked, petroleum systems  Extensive drilling, coring and geological studies since 19

  27. Slide 27: Ranger-Querecho Plains Prospect Area

    Ranger-Querecho Plains Prospect Area Concho Stratojet 31 State #3H 2nd Bone Spring 24 mo.cum: 360 MBbl; 426 MMcf Concho AirCobra 12 #2H 3rd Bone Spring 25 mo.cum: 296 MBbl; 201 MMcf Note: All acreage at December 31, 2013. Well information from public sources as of November 2013. (1) Presented as of

  28. Slide 28: Ranger State Com #1H Frac Overview

    28 Ranger 33 State Com #1H Frac Overview 525 Mlbs Fluid Volume Pumped Proppant Pumped(1) 300 ft. 11,250 Bbl  18 total stages  450,000 lbs per stage  400,000 lbs 30/50 white sand per stage  50,000 lbs resin-coated sand tail-in per stage  50-ft spacing between clusters  5 clusters per stage 0 ft

  29. Slide 29: Ranger 33 State Com #1H Production History

    0 100 200 300 400 500 600 700 800 900 1000 0 200 400 600 800 1000 1200 1400 1600 1800 2000 0 5 10 15 20 25 30 35 40 45 50 55 60 Oil (B bl/ d) , Ga s ( M cf /d ) Fl ow in g Pr es su re (p si) Days 0 10 20 30 40 50 60 -20 -15 -10 -5 0 5 10 15 20 25 30 0 10 20 30 40 50 60 Cho k e S i z e (x/64" ) Axis

  30. Slide 30: Wolf Prospect Area

    Wolf Prospect Area Wolf Energy Wolf #1 (Vertical well) 3rd BS / Wolfcamp “A” 33.5 years cum: 61 MBbl; 642 MMcf OXY Reagan-McElvain #1H Wolfcamp “A” IP: 570 Bbl/d 2.6 MMcf/d 9 mo.cum: 102 MBbl; 261 MMcf Energen Grayling 1-69 Wolfcamp “A” IP: 791 Bbl/d 7.3 MMcf/d 3,500 psi FTP 13 mo.cum: 86 MBbl; 727

  31. Slide 31: Dorothy White #1H Horizontal Well Profile

    Wolfcamp VS MD Y Sand T V D Gas Units Large increase in gas units when we entered the “X” sand Dorothy White #1H Horizontal Well Profile 31  100% in target zone  Managed pressure drilling techniques – flaring while drilling  Good indications of porosity from cuttings while drilling

  32. Slide 32: Indian Draw-Rustler Breaks Prospect Area

    Note: All acreage at December 31, 2013. Well information from public sources as of November 2013. (1) Presented as of November 30, 2013. 32 Location of Matador 2013 test wells  12,276 gross (8,852 net) acres  103 gross (79.6 net) locations(1)  Primary Targets  Wolfcamp “B”  2nd Bone Spring  De

  33. Slide 33: Twin Lakes Prospect Area

    Twin Lakes Prospect Area Note: All acreage at December 31, 2013. Well information from public sources as of November 2013. 33  31,057 gross (20,791 net) acres  Primary Targets  Wolfcamp “D” (Cline)  Strawn  Abo  Other Potential Targets  Cisco/Canyon  Devonian  Glorieta/San Andres  1 well p

  34. Slide 34: Twin Lakes Area Cross Section

    Twin Lakes Area Cross Section 34 A TEST VOLUMES: 268 Bbl/d 350 Mcf/d 0 WATER TEST VOLUMES: 118 Bbl/d 625 Mcf/d 1155 WATER Wolfcamp “D”/Cline A’ ~400ft

  35. Slide 35: Permian Basin Stratigraphy and Lower Permian Petroleum Systems

    Bone Spring Lime Upper Avalon Shale Lower Avalon Shale First Bone Spring Sand Second Bone Spring Carbonate Second Bone Spring Sand Third Bone Spring Carbonate Wolfcamp “D”/ Cline Strawn Wolfcamp “A” Wolfcamp “B” Wolfcamp “C” Third Bone Spring Sand GR RE S Permian Basin Stratigraphy and Lower Permian

  36. Slide 36: Haynesville and Other Natural Gas Operations

    Haynesville and Other Natural Gas Operations

  37. Slide 37: 2014 Haynesville Shale Plan

    2014 Tier 1 Haynesville Shale Plan 37  2014 projected capital expenditures of ~$12 million or about 3% of total  Estimated participation in 26 gross (1.5 net) non-operated wells, some already drilling in late 2013  2014 capital plan includes no Matador operated Haynesville wells  Includes $2.5 m

  38. Slide 38: Significant Option Value on Natural Gas

    Significant Option Value on Natural Gas  Significant acreage position in the Haynesville  Recently added 3 sections to provide more operated drilling opportunities  Also prospective for the Cotton Valley, Travis Peak/Hosston and other shallow formations  Competitive well economics on Tier 1 Hayn

  39. Slide 39: Haynesville Well Economics – Tier 1 Area

    0 25 50 75 100 125 150 175 200 225 250 275 300 3 3.5 4 4.5 5 5.5 6 8 Bcf - $8.0 MM D&C Cost 9 Bcf - $8.0 MM D&C Cost 10 Bcf - $8.0 MM D&C Cost 8 Bcf - $9.0 MM D&C Cost 9 Bcf - $9.0 MM D&C Cost 10 Bcf - $9.0 MM D&C Cost 39 Haynesville Well Economics – Tier 1 Area Es ti m a te d Ra te o f Re tu rn, %

  40. Slide 40: Matador Gracie Prospect – Meade Peak Gas Shale

    Matador Gracie Prospect – Meade Peak Gas Shale IDAHO UTAH W Y O M IN G W Y OM IN G ID A H O U T A H WYOMING Crawford Federal #1H 40 Note: All acreage at December 31, 2013. Summary  76,496 gross (36,003 net) acres  Drilled Crawford Fed #1H in late 2012  Recently completed 5-stage fracture treatmen

  41. Slide 41: 2014 Capital Investment Plan

    2014 Capital Investment Plan

  42. Slide 42: Summary and 2014 Guidance

    42 Summary and 2014 Guidance (1) As updated on November 6, 2013. (2) 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 result

  43. Slide 43: 2014 Capital Investment Plan Summary

    43 2014 Capital Investment Plan Summary  Continue 3-rig program in 2014 – 2 rigs in Eagle Ford and 1 rig in Permian  2014 estimated capital expenditures of ~$440 million  Increase of ~19% from 2013 estimated capital expenditures of ~$370 million  Eagle Ford development will continue to be the ma

  44. Slide 44: 2014E Oil and Natural Gas Production

    44 2014E Oil Production  Estimated oil production of 2.8 to 3.1 million barrels  Increase of 40 to 50% from 2013, despite an average of 5 to 10% of oil production shut-in throughout 2014  Oil production growth to over 9,000 Bbl/d by YE 2014  Estimated 87% of oil production from Eagle Ford and 13

  45. Slide 45: 2014E Revenues and Adjusted EBITDA

    45 2014E Revenues and Adjusted EBITDA(1)(2)  Revenues and Adjusted EBITDA(1)(2) growth impacted by lower 2014 realized oil price estimate − 2014 realized oil price of $95/Bbl vs ~$100/Bbl realized in 2013 − 2014 realized natural gas price of $4.25/Mcf similar to 2013  Estimated oil and natural gas

  46. Slide 46: 2014 Anticipated Drilling and First Sales

    2014 Anticipated Drilling 2014 Anticipated First Sales(1) 2014E CapEx Gross Wells(2) Net Wells(2) Gross Wells(2) Net Wells(2) (in millions) Total Total % Total Total % Total % South Texas Eagle Ford 49 46.0 78.4% 42 39.0 78.3% $300.1 68.2% Buda 1 1.0 1.7% 1 1.0 2.0% $4.8 1.1% Facilities/Pipelines/Et

  47. Slide 47: Funding for 2014 Capital Investment Plan

    Funding for 2014 Capital Investment Plan 47  Anticipate funding 2014 capital expenditures through operating cash flows and borrowings under revolving credit facility  2.4 million barrels of oil (80 to 85% of estimated oil production) hedged for 2014, protecting cash flows below ~$88/Bbl oil price

  48. Slide 48: Credit Facility Terms

    TIER Borrowing Base Utilization LIBOR Margin BASE Margin Commitment Fee Tier One x < 25% 175 bps 75 bps 37.5 bps Tier Two 25% < or = x < 50% 200 bps 100 bps 37.5 bps Tier Three 50% < or = x < 75% 225 bps 125 bps 50 bps Tier Four 75% < or = x < 90% 250 bps 150 bps 50 bps Tier Five 90% < or = x < 100%

  49. Slide 49: 2014 Hedging Profile

    49 2014 Hedging Profile  2.4 million barrels of oil hedged for 2014 at weighted average floor and ceiling of $88/Bbl(1) and $99/Bbl(1), respectively  11.7 Bcf of natural gas hedged at weighted average floor and ceiling of $3.44/MMBtu(2) and $4.96/MMBtu(2), respectively  7.6 million gallons of nat

  50. Slide 50: Appendix

    = AN, jMatadar RESOURCES COMPANY Appendix

  51. Slide 51: Matador's Continued Growth

    $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 Continu

  52. Slide 52: 2014 South Texas Drilling Plan – 2-Rig Program

    52 2014 South Texas Drilling Plan – 2-Rig Program Note: All acreage at December 31, 2013. Uvalde Medina Zavala Frio Dimmit La Salle Webb Bexar Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson EAGLE FORD CENTRAL/EAST 7,570 gross / 6,360 net acres EOG OPERATED, MTDR WI ~21% 9,508 gross / 1

  53. Slide 53: 2014 Permian Basin Drilling Plan

    E D D Y L E A LOVING 53 Indian Draw/Rustler Breaks 12,276 gross / 8,852 net acres  Estimated capital expenditures of ~$109 million, including ~$30 million for land/seismic and facilities  12 gross (9.8 net) wells planned for 2014, with 10 gross (8.3 net) wells turned to sales  Ranger/Querecho Pla

  54. Slide 54: Board of Directors and Special Board Advisors

    Board of Directors and Special Board Advisors – Expertise and Stewardship 54 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 Presid

  55. Slide 55: Proven Management Team – Experienced Leadership

    Proven Management Team – Experienced Leadership 55 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 Matthew V. Ha

  56. Slide 56: Adjusted EBITDA Reconciliation

    56 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, investo

  57. Slide 57: Adjusted EBITDA Reconciliation to Net Income (Loss)

    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 t

  58. Slide 58: PV-10 Reconciliation

    58 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

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