Matador Resources Company · NYSE:MTDR
Matador Resources — Investor Day (December 2013)
71 slides from Matador Resources's investor day presentation, Dec 12, 2013
Slide 1: 2013 Analyst Day Presentation
December 12, 2013 2013 Analyst Day Presentation NYSE: MTDR
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
Slide 3: Welcome and Opening Remarks
mes = Ly (Matador iyaer Welcome and Opening Remarks
Slide 4: Company Overview
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
Slide 5: MTDR up 154% Year to Date
5 MTDR up 154% Year to Date $8.05 $7.72 $8.52 $9.98 $12.08 $11.52 $17.80 $15.35 $16.03 $21.08 $18.08 $23.72 $20.82 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 $20.00 $22.00 $24.00 0 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000 6,000,000 7,000,000 8,000,000 1 / 2 / 2 0 1 3 1 / 9 / 2 0 1 3 1 /
Slide 6: Keys to Matador's Success
Keys to Matador’s Success 6 square4 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 square4 Properties
Slide 7: 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 square4 7.1 MBOE/d square4 414 Bbl/d of oil square4 6% oil square4 13.5 MBOE/d square4 6,700 Bbl/d of oil square4 50% oil Proved Reserves square4 27 MMBOE s
Slide 8: Matador's Continued Growth
T h o u s a n d B b l Matador’s Continued Growth 8 (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
Slide 9: 2013 Has Been an Excellent Year for Matador
2013 Has Been an Excellent Year for Matador! 9 square4 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 wel
Slide 10: 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
Slide 11: Today's Agenda
Today’s Agenda 11 square4 Welcome and Opening Remarks − Joseph Wm. Foran, Chairman and CEO − Matthew V. Hairford, President square4 2014 Capital Investment Plan − David E. Lancaster, Executive Vice President, COO and CFO square4 Eagle Ford Operations and Development − Ryan C. London, Vice President
Slide 12: 2014 Capital Investment Plan
2014 Capital Investment Plan
Slide 13: Matador Resources Company Overview
13 Matador Resources Company Overview Market Capitalization(1) ~$1.4 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
Slide 14: 2014 Capital Investment Plan Summary
14 2014 Capital Investment Plan Summary square4 Continue 3-rig program in 2014 – 2 rigs in Eagle Ford and 1 rig in Permian square4 2014 estimated capital expenditures of ~$440 million − Increase of ~19% from 2013 estimated capital expenditures of ~$370 million square4 Eagle Ford development will con
Slide 15: 2014 Anticipated Drilling
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
Slide 16: 2014E Oil Production
16 2014E Oil Production square4 Estimated oil production of 2.8 to 3.1 million barrels square4 Increase of 40 to 50% from 2013, despite an average of 5 to 10% of oil production shut-in throughout 2014 square4 Oil production growth to over 9,000 Bbl/d by YE 2014 square4 Estimated 87% of oil productio
Slide 17: 2014E Revenues and Adjusted EBITDA
17 2014E Revenues and Adjusted EBITDA(1)(2) square4 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 square4 Estimated oil and
Slide 18: Funding for 2014 Capital Investment Plan
Funding for 2014 Capital Investment Plan 18 square4 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
Slide 19: 2014 Hedging Profile
19 2014 Hedging Profile square4 2.4 million barrels of oil hedged for 2014 at weighted average floor and ceiling of $88/Bbl(1) and $99/Bbl(1), respectively square4 10.8 Bcf of natural gas hedged at weighted average floor and ceiling of $3.42/MMBtu(2) and $4.98/MMBtu(2), respectively square4 7.6 mill
Slide 20: 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%
Slide 21: 2014 South Texas Plan Details
2014 South Texas Plan Details 21 square4 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 n
Slide 22: 2014 South Texas Drilling Plan – 2-Rig Program
22 2014 South Texas Drilling Plan – 2-Rig Program Note: All acreage at November 30, 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
Slide 23: 2014 Permian Basin Plan Details
2014 Permian Basin Plan Details 23 square4 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 − I
Slide 24: Permian Basin Acreage Position
Permian Basin Total Gross Acres(1) 65,185 acres Net Acres(1) 40,824 acres Permian Basin Acreage Position (1) Total acreage in Southeast New Mexico and West Texas as of November 30, 2013, including some tracts not shown on map. (2) At November 30, 2013. (3) From January 1, 2013 through November 30, 2
Slide 25: 2014 Permian Basin Drilling Plan
E D D Y L E A LOVING 25 Indian Draw/Rustler Breaks 10,028 gross / 7,177 net acres square4 Estimated capital expenditures of ~$109 million, including ~$30 million for land/seismic and facilities square4 12 gross (9.8 net) wells planned for 2014, with 10 gross (8.3 net) wells turned to sales square4 R
Slide 26: 2014 Haynesville Shale Plan
2014 Tier 1 Haynesville Shale Plan 26 square4 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
Slide 27: Haynesville and Elm Grove Cotton Valley Acreage Positions
Tier 1 Haynesville and Elm Grove Cotton Valley Acreage Positions Note: All acreage at November 30, 2013. Matador acreage shown in red. (1) At November 30, 2013. (2) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units an
Slide 28: Summary and 2014 Guidance
28 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
Slide 29: Eagle Ford Development and Operations
Eagle Ford Development and Operations
Slide 30: Eagle Ford Overview
30 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) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral
Slide 31: Eagle Ford Well Costs and EUR
31 Eagle Ford Well Costs and Estimated Ultimate Recovery (“EUR”) Note: All acreage at November 30, 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
Slide 32: 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 32 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
Slide 33: Pad Drilling
Pad Drilling
Slide 34: Batch Drilling
Batch Drilling Approx. $300,000 cost reduction per well when going from single well pad to a four-well batch drilled pad!
Slide 35: Advancing Rig Technology
Progression of Drilling Rig Technology from 2010 to 2014 35 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 checkbld checkbld 534 checkbld checkbld 203 checkbld
Slide 36: Improvement in Drilling Efficiency
0 50,000 100,000 150,000 200,000 250,000 300,000 2014 2013 2012 2011 2010 Lateral Feet Drilled 36 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 Efficiency –
Slide 37: 2014 Planned Operated Drilling Schedule – Batch Drilling
37 Drilling Stimulation Shut-in Producing BATCH DRILLING “LUMPY” Production 2014 Planned Operated Drilling Schedule
Slide 38: 2014 Planned Operated Drilling Schedule – Pad Drilling
38 Drilling Stimulation Shut-in Producing BATCH DRILLING PAD DRILLING 2014 Planned Operated Drilling Schedule
Slide 39: Accelerated Production Benefits of Gas Lift
39 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
Slide 40: 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 40 Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal well
Slide 41: Frac Generation Comparison
41 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 Cu m u l a t i v e P r od u c t i o n ( Bb l ) Time (Days) GEN 2 (8
Slide 42: Downspacing Program
42 330’ 40 acre Test Wells 1st Well on Lease 80 Acre Spacing Development 4 Downspacing Program
Slide 43: Downspacing Program – Cumulative Production vs. Time
43 Downspacing Program – Cumulative Production vs. Time 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 0 20 40 60 80 100 120 140 160 C u m u l a t i v e P r o d u c t i o n ( B b l ) Time (Days) GEN 5 (80 Acre) GEN 5 (40 Acre) 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 0 20
Slide 44: Buda Wells Activity Since January 1, 2010
Comp May 2013 : Blackbrush O&G Oppenheimer-101H 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 H
Slide 45: Glasscock Ranch Seismic Mapping of Natural Fracture Trends
Buda Productive Area Glasscock Ranch - Frio South Survey Amplitude at Time Slice Near Top Buda Texas American Res Buchanan-1H Comp Apr 2013 5 mo avg: 507 Bbl/d, 514 Mcf/d Cum: 77 MBbl, 78 MMcf Fracture trends from MTDR Glasscock #2H consistent with seismic trend Dan A. Hughes Heitz Lease 4 Buda Comp
Slide 46: Permian Exploration and Operations
Permian Exploration and Operations
Slide 47: Permian Basin – Matador's Next Major Growth Area
Permian Basin – Matador’s Next Major Growth Area 47 Why the Permian? square4 The Permian Basin is a world class, stacked petroleum system that has been explored and developed for over 100 years with a solid base of infrastructure square4 Over 30 billion barrels of oil have been recovered from conven
Slide 48: Matador's Criteria for Screening and High-Grading Opportunities
Basin Scale: square4 Large basins, “supercharged”, stacked, petroleum systems square4 Stratigraphically and structurally predictable square4 Significant drilling and conventional production history Target (Pay-Zone) Scale: square4 Density porosity (permeability) : > 7% square4 Organic richness, matu
Slide 49: 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
Slide 50: 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
Slide 51: Permian Basin Petroleum Systems and the Wolfcamp Kitchens
DELAWARE BASIN CENTRAL BASIN PLATFORM MIDLAND BASIN Wolfcamp Simpson ~23,000’ Sediment Fill EastWest Source “Kitchens” Now Unconventional Resource Plays square4 70,000 square mile area square4 Up to 25,000 feet of multiple, stacked, petroleum systems square4 Extensive drilling, coring and geological
Slide 52: Permian Basin Acreage Position
Matador Resources Acreage LOVING Permian Basin Acreage Position square4 Offsetting multi-billion barrels in basin flanking conventional fields square4 Hydrocarbon migration route-ways square4 Stacked conventional and unconventional reservoir potential square4 Primary Targets • Bone Spring (Avalon, 1
Slide 53: Twin Lakes Prospect Area
Twin Lakes Prospect Area Note: All acreage at November 30, 2013. Well information from public sources as of November 2013. Matador acreage shown in red. 53 square4 27,485 gross (17,813 net) acres square4 Primary Targets square4 Wolfcamp “D” (Cline) square4 Strawn square4 Abo square4 Other Potential
Slide 54: Twin Lakes Area Cross Section
Twin Lakes Area Cross Section 54 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
Slide 55: 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 November 30, 2013. Well information from public sources as of November 2013. Matador acreage show
Slide 56: Ranger State Com #1H Frac Overview
56 Ranger 33 State Com #1H Frac Overview 525 Mlbs Fluid Volume Pumped Proppant Pumped(1) 300 ft. 11,250 Bbl square4 18 total stages square4 450,000 lbs per stage square4 400,000 lbs 30/50 white sand per stage square4 50,000 lbs resin-coated sand tail-in per stage square4 50-ft spacing between cluste
Slide 57: 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 F l o w i n g P r e s s u r e ( p s i ) Days 10 20 30 40 50 15 20 25 30 C h o k e S i z e ( x / 6 4 " ) O i l ( B b l / d ) , G a s ( M c f / d ) Flowing Pressure Oil Gas C
Slide 58: 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
Slide 59: 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 59 square4 100% in target zone square4 Managed pressure drilling techniques – flaring while drilling square4 Good indications of porosity from cuttings while drill
Slide 60: Indian Draw-Rustler Breaks Prospect Area
Note: All acreage at November 30, 2013. Well information from public sources as of November 2013. Matador acreage shown in red. 60 Location of Matador 2013 test wells square4 10,028 gross (7,177 net) acres square4 103 gross (79.6 net) locations square4 Primary Targets square4 Wolfcamp “B” square4 2n
Slide 61: Haynesville and Other Natural Gas Operations
Haynesville and Other Natural Gas Operations
Slide 62: Significant Option Value on Natural Gas
Significant Option Value on Natural Gas square4 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 square4 Competitive well economics on
Slide 63: 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 63 Haynesville Well Economics – Tier 1 Area E s t i m a t e d R a t e o f R e t u
Slide 64: Matador Gracie Prospect – Meade Peak Gas Shale
Matador Gracie Prospect – Meade Peak Gas Shale IDAHO UTAH W YO M ING W YO M ING I D A H O U T A H WYOMING Crawford Federal #1H 64 Note: All acreage at November 30, 2013. Matador acreage shown in red. Summary square4 76,500 gross (36,000 net) acres square4 Drilled Crawford Fed #1H in late 2012 square
Slide 65: Summary and Closing Remarks/Q&A
Summary and Closing Remarks/Q&A
Slide 66: Summary and 2014 Guidance
66 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
Slide 67: 2013 Analyst Day Presentation
December 12, 2013 2013 Analyst Day Presentation NYSE: MTDR
Slide 68: Appendix
mes = by (Matador iyaer Appendix
Slide 69: Adjusted EBITDA Reconciliation
69 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
Slide 70: 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
Slide 71: PV-10 Reconciliation
71 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