Matador Resources Company · NYSE:MTDR

Matador Resources — Investor Presentation (June 2014)

62 slides from Matador Resources's investor presentation, Jun 2, 2014

  1. Slide 1: June 2014 Investor Presentation

    June 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 Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 73.3 million common shares Share Price(2) $24.65/share Market Capitalization(1)(2) $1.8 billion (1) Shares outstanding as reported in the Form 10-Q for the quarter ended March 31, 2014 filed on May 7, 2014, plus an additional 7.5 m

  6. Slide 6: Matador's Execution History – Doing What We Say

    Matador’s Execution History – “Doing What We Say” Oil Production  414 Bbl/d of oil  6% oil  4,916 Bbl/d of oil  46% oil  7,344 Bbl/d of oil  62% oil Proved Reserves  27 MMBOE  1.1 MMBbl of oil  4% oil  39 MMBOE  12.1 MMBbl of oil  31% oil  55 MMBOE  16.9 MMBbl of oil  31% oil PV-10(2)

  7. Slide 7: Delivering Strong Results

    Delivering Strong Results 7 Q1 2014 Achievements Oil Production(2) 2014 Updated Capital Budget and Guidance  Oil Production – Company Record!  7,344 Bbl/d; 44% growth versus Q1 2013  Oil & Natural Gas Revenues  $78.9 million; 33% growth versus Q1 2013  Adjusted EBITDA(1)  $56.3 million; 39% gr

  8. Slide 8: Matador Resources Company Overview

    8 Matador Resources Company Overview Market Capitalization(1) $1.8 billion Average Daily Production(2) 11,904 BOE/d Oil (% total) 7,344 Bbl/d (62%) Natural Gas (% total) 27.4 MMcf/d (38%) Proved Reserves @ 3/31/14 54.6 million BOE % Proved Developed 34% % Oil 31% 2014E CapEx $570 million % South Tex

  9. Slide 9: Asset Highlights

    Asset Highlights 9  Completion of equity offering will provide capital to continue two-rig drilling program (177.7 net drilling locations(1))  ~56,200 net acres(2) in Lea and Eddy Counties, NM and Loving County, TX in the Permian Basin with multi-zone drilling potential  Successful performance of

  10. Slide 10: Keys to Matador's Success

    Keys to Matador’s Success 10  People  We have a strong, committed technical and financial team in place, and we continue to make additions and improvements to our staff, our capabilities and our process  Board and Special Advisor additions have strengthened Board skills and stewardship  Properti

  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 ~56% 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 31, 2013. Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. (2) For the twelve months ended December 31, 2011. (3) For

  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 May 6, 2014. 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 McMullen L

  15. Slide 15: Operational Improvements

    Overview 15 Operational Improvements (Normalized) Eagle Ford Drilling Costs / Drilled Foot(1) Eagle Ford Completion Costs / Completed Foot(2) West Central East West Central East  Over the past two years, made significant progress and increased knowledge of how to drill, complete and produce Eagle F

  16. Slide 16: Evolution of Matador Eagle Ford 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 0 ft. 300 ft. 11,750 Bbl 650 Mlbs Gen 6 Evolution of Matador Eagle Ford Frac Design 16 Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal wellbore. (1) Mlbs = thousands o

  17. Slide 17: Eagle Ford Cumulative Production by Generation

    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 ro du cti on (B bl) Time (Days) GEN 2 (80 Acre) GEN 4 (80 Acre) GEN 5 (80 Acre) 0 10,000 20,000 30,000 40,000 50,000 60,000 7

  18. Slide 18: Downspacing Comparison

    0 10000 20000 30000 40000 50000 60000 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 C u m u la ti v e Oil P ro d u c tio n ( b b l) Days Online Average 40 Acre (Gen 5-6) Average 80 Acre (Gen 2-4) 0 10000 20000 30000 40000 50000 60000 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 C u m

  19. Slide 19: 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 19 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 to 70% increase in Rig Efficiency from 2012 to 2014E! Improvement in Dril

  20. Slide 20: Compressing Drill Times

    Compressing Drill Times  Improving rig fleet  High tech, fast moving, faster drilling, walking style rigs  Improving Rate of Penetration (ROP)  Bit selection and development  Bottom Hole Assembly (BHA) selection  Rotary steerable systems  Vertical seeking  Directional drilling  Minimize dir

  21. Slide 21: Progression of Drilling Rig Technology 2010 to 2014

    Progression of Drilling Rig Technology from 2010 to 2014 21 RIG # ELECTRIC 1600 HP PUMPS INTEGRATED TOP DRIVE APEX RIG (FAST MOVE) HYDRAULIC CATWALK AC DRIVE SYSTEM TECHNOLOGY ROUND BOTTOM MUD PITS WALKING PACKAGE BOP HANDLER THREE SHAKERS 521 135   534   203      250        239  

  22. Slide 22: Artificial Lift: Accelerated Production Benefits of Gas Lift

    22 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 Note: Graph and data is for illustrative purposes only and not meant to re

  23. Slide 23: Buda Wells Activity – Potential Test

    Blackbrush O&G 10 Buda Completions May 2011 – Feb. 2014 Cum: 240 MBbl 1.13 Bcf TX American Resources Buchanan-1H 5/3/2013 11 mo avg: 331 Bbl/d 526 Mcf/d Cum: 109 MBbl 1.7 Bcf Dan A. Hughes Heitz Lease 4 Buda Completions Dec. 2011 – Feb. 2014 Cum: 900 MBbl 1.58 Bcf Crimson Exploration Beeler-6H Spud

  24. Slide 24: Buda Productive Area Seismic Mapping of Natural Fracture Trends

    Buda Productive Area Glasscock Ranch Seismic Mapping of Natural Fracture Trends Note: Well information from public sources as of March 2014. 24 TX American Resources Buchanan-1H 5/3/2013 IP: 756 Bbl/d 556 Mcf/d 11 mo.cum: 109 MBbl 1.7 Bcf Glasscock Ranch – Frio South Survey: Amplitude at Time Slice

  25. Slide 25: Permian Basin Southeast New Mexico and West Texas

    Permian Basin Southeast New Mexico and West Texas

  26. Slide 26: 2014 Permian Plan

    26  2014 projected capital expenditures of ~$190 million or ~33% of total  Continue 2-rig program working in Lea and Eddy Counties, NM and Loving County, TX  Drill and/or complete or participate in 14 gross (12.3 net) wells; several Wolf area wells drilled with second Permian rig not on productio

  27. Slide 27: Permian Basin

    Permian Basin Total Gross Acres 86,953 acres Net Acres 56,199 acres Permian Basin (1) Presented as of December 31, 2013. (2) As of May 6, 2014. 27  Estimated 241 gross (177.7 net) engineered drilling locations(1); anticipated to grow over time Progress-to-date(2)  Successful performance of first 3

  28. Slide 28: 2014 Wells Drilled Targeting Multiple Benches

    2014 Wells Drilled Targeting Multiple Benches in Permian Appraisal Program 28 Sand Carbonates (Limestones and Dolomites) Shale/ Mudstone 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 Wolf

  29. Slide 29: 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 areal extent Wolfc

  30. Slide 30: 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

  31. Slide 31: Wolf / Loving Prospect Area

    Wolf / Loving Prospect Area 31  10,943 gross (7,000 net) acres  50 gross (35.4 net) locations(1)  Primary Targets  Wolfcamp “A”  3rd Bone Spring  Avalon  Other Potential Targets  1st Bone Spring  2nd Bone Spring  Wolfcamp “B”  6 wells planned for 2014 Wolf Energy Wolf #1 (Vertical well) 3

  32. Slide 32: Ranger / Querecho Plains Prospect Area

    Ranger / Querecho Plains Prospect Area 32  14,035 gross (9,847 net) acres  83 gross (59.6 net) locations(1)  Primary Targets  2nd Bone Spring  3rd Bone Spring  Wolfcamp “A”, “B” and “D”  Other Potential Targets  Delaware  Avalon  1st Bone Spring  Bone Spring Carbonates  3 wells planned f

  33. Slide 33: Indian Draw / Rustler Breaks Prospect Area

    33  17,128 gross (12,341 net) acres  108 gross (82.8 net) locations(1)  Primary Targets  Wolfcamp “B”  2nd Bone Spring  Delaware  Other Potential Targets  Avalon  1st Bone Spring  3rd Bone Spring  Wolfcamp “A”  4 wells planned for 2014 Indian Draw / Rustler Breaks Prospect Area Concho R.

  34. Slide 34: Twin Lakes Prospect Area

    Twin Lakes Prospect Area 34  32,417 gross (22,151 net) acres  Primary Targets  Wolfcamp “D”  Strawn  Abo  Other Potential Targets  Cisco/Canyon  Devonian  Glorieta/San Andres  1 vertical well planned for 2014 − Vertical pilot hole to collect whole core and log data Vacuum Field Grayburg/ S

  35. Slide 35: Twin Lakes Area Cross Section

    Twin Lakes Area Cross Section 35 A TEST VOLUMES: 268 Bbl/d oil 350 Mcf/d gas No water TEST VOLUMES: 118 Bbl/d oil 625 Mcf/d gas 1,155 Bbl/d water Wolfcamp “D” A’ ~400ft

  36. Slide 36: Matador Permian Basin – First Generation Frac Designs

    Bone Spring 0 ft. 300 ft. Wolfcamp Matador Permian Basin – First Generation Frac Designs 36 Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal wellbore. (1) Mlbs = thousands of pounds of proppant pumped. 550 Mlbs 600 Mlbs 11,750 Bbl 11,750 Bbl Fluid Volume Pumped Proppan

  37. Slide 37: Haynesville Shale

    Haynesville Shale

  38. Slide 38: 2014 Haynesville Shale Plan

    2014 Tier 1 Haynesville Shale Plan 38  2014 projected capital expenditures of ~$62 million or about 11% of total  Estimated participation in 56 gross (7.8 net) non-operated wells(1)  Chesapeake may drill up to 30 gross (6.3 net to Matador) wells at Elm Grove in 2014; estimated CapEx of $50 millio

  39. Slide 39: 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  Highly competitive well economics on Ti

  40. Slide 40: Elm Grove Tier 1 Haynesville – Chesapeake Operated

    0 25 50 75 100 125 150 175 200 225 250 275 300 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 E sti m a te d Ra te o f Re tu rn, % Natural Gas Price, $/Mcf 8 Bcf - $8.0mm D&C Cost 9 Bcf - $8.0mm D&C Cost 10 Bcf - $8.0mm D&C Cost 8 Bcf - $9.0mm D&C Cost 9 Bcf - $9.0mm D&C Cost 10 Bcf - $9.0mm D&C Cost 40

  41. Slide 41: 2014 Capital Investment Plan

    2014 Capital Investment Plan

  42. Slide 42: Summary and Updated 2014 Guidance

    42 Summary and Updated 2014 Guidance(1) (1) As of May 6, 2014, except for capital spending which was updated to $570 million as of May 22, 2014. (2) As of May 6, 2014, the Company guided investors to the high end of its oil production guidance range. (3) Estimated 2014 oil and natural gas revenues a

  43. Slide 43: 2014 Updated Capital Investment Plan Summary

    43 2014 Updated Capital Investment Plan Summary  Continue 4-rig program full time in H2 2014: 2 rigs in the Eagle Ford and 2 rigs in the Permian  2014E capital expenditures of $570 million(1)  Eagle Ford development expected to be the major driver of our growth in 2014  Permian drilling program

  44. Slide 44: Funding for 2014 Capital Investment Plan

    Funding for 2014 Capital Investment Plan 44  Anticipate funding 2014 capital expenditures through proceeds from recent equity offering, operating cash flows and borrowings under revolving credit facility  1.8 million barrels of oil (between 70 and 75% of estimated oil production(1)) hedged for rem

  45. Slide 45: Investment Highlights

    45 Investment Highlights Strong Growth Profile with Increasing Focus on Oil / Liquids  YE2011 to 2014E oil production CAGR of ~172%(1) with expected year-over-year growth of ~45%(1) in 2014  ~89% of 2014E CapEx program focused on oil / liquids exploration and development High Quality Asset Base in

  46. Slide 46: Appendix

    = AN, jMatadar RESOURCES COMPANY Appendix

  47. Slide 47: Matador's Continued Growth

    $18.4 $15.2 $23.6 $49.9 $115.9 $191.8 2008 2009 2010 2011 2012 2013 $30.6 $19.0 $34.0 $67.0 $156.0 $269.0 2008 2009 2010 2011 2012 2013 7% 4% 2% 6% 37% 50% 2008 2009 2010 2011 2012 2013 1.5 2.3 3.9 7.0 9.0 11.7 2008 2009 2010 2011 2012 2013 Matador’s Continued Growth Average Daily Production (MBOE/d

  48. Slide 48: Recent Semi-Annual Performance Metrics

    Recent Semi-Annual Performance Metrics Through Year-End 2013 Oil Equivalent Production (BOE in thousands) Adjusted EBITDA(1) ($ in millions) Oil and Natural Gas Revenues ($ in millions) Oil Production (Bbl in thousands) 84 485 729 908 1,225 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1,277 1,525 1,768 1

  49. Slide 49: Matador Provides Growth on a Per Share Basis

    $0.47 $0.83 $1.57 $2.89 $4.58 $5.55 2009 2010 2011 2012 2013 2014E $1.75 $2.92 $5.82 $7.84 $11.15 2009 2010 2011 2012 2013 $0.38 $0.58 $1.17 $2.15 $3.26 $3.99 2009 2010 2011 2012 2013 2014E Matador Provides Growth on a Per Share(1) Basis 49 Oil and Natural Gas Revenues(4) per Share ($ per share) PV-

  50. Slide 50: Historical Financials and Margins

    Year Ended December 31, 2011 2012 2013 Production Oil Production (MBbl) 154 1,214 2,133 Natural Gas Production (Bcf) 14.5 12.5 12.9 % Oil 6% 37% 50% Total Production (MBOE) 2,573 3,294 4,285 Average Daily Production (BOE/d) 7,049 9,000 11,740 Realized Oil Price ($/Bbl)(1) $93.80 $103.55 $98.67 Reali

  51. Slide 51: Increasing Cash Operating Margin

    Increasing Cash Operating Margin 51 $31.97 $27.45 $28.80 $51.60 $62.57 $17.27 $16.24 $19.27 $35.13 $44.70 54.0% 59.2% 66.9% 68.1% 71.4% 2009 2010 2011 2012 2013 Revenue/BOE with Derivatives Cash Margin per BOE % Margin

  52. Slide 52: Oil Production and Revenues Through Q1 2014

    1.7 5.1 3.7 4.0 21.5 29.4 30.1 42.6 48.7 44.6 64.2 55.3 63.7 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 209 563 465 448 2,200 3,130 3,291 4,630 5,100 4,916 6,703 6,612 7,344 0 1,000 2,000 3,000 4,000 5,0 0 6,000 7,000 8,000 1Q11 2Q11 3Q11

  53. Slide 53: Quarterly Performance Metrics Through Q1 2014

    6,300 8,004 6,931 6,953 8,023 8,738 8,838 10,385 10,89710,582 13,482 11,968 11,904 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 53 Quarterly Performance Metrics Through Q1 2014 Oil and Natural Gas Revenues ($ in mm) Total Real

  54. Slide 54: Quarterly Expense Metrics

    $4 .6 2 $4 .2 5 $6 .6 0 $5 .4 3 $5 .1 9 $5 .1 5 $4 .2 3 $3 .3 7 $4 .6 9 $4 .3 1 $4 .3 5 $6 .0 2 $ 6. 74 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 $2 .8 3 $2 .7 0 $3 .2 4 $2 .5 1 $6 .3 6 $8 .0 2 $7 .9 8 $1 1. 17 $1 1. 11 $1

  55. Slide 55: 2014 Hedging Profile

    55 2014 Hedging Profile – Hedges in Place for Remainder of 2014 At May 6, 2014, Matador had:  1.8 million barrels of oil hedged for remainder of 2014 at weighted average floor and ceiling of $88/Bbl and $99/Bbl, respectively  7.7 Bcf of natural gas hedged for remainder of 2014 at weighted average

  56. Slide 56: Board of Directors and Special Advisors

    Board of Directors and Special Advisors – Expertise and Stewardship 56 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

  57. Slide 57: Proven Management Team – Experienced Leadership

    Proven Management Team – Experienced Leadership 57 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

  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

  59. Slide 59: Adjusted EBITDA Reconciliation

    59 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

  60. Slide 60: Adjusted EBITDA Reconciliation

    60 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 LTM at LTM at (In thous

  61. Slide 61: Adjusted EBITDA Reconciliation

    61 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. (In thousands) 1Q 2011 2Q 2011 3Q 2011 4Q 2011 1Q 2

  62. Slide 62: Adjusted EBITDA Reconciliation

    62 Adjusted EBITDA Reconciliation (In thousands) 12/31/2011 6/30/2012 12/31/2012 6/30/2013 12/31/2013 Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): Net (loss) income 10,135$ (2,875)$ (30,385)$ 9,615$ 35,479$ Interest expense 393 309 693 2,881 2,806 Total income tax (benefit) provisi

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