UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 8-K
_________________________________
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of Earliest Event Reported) January 10, 2014
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Matador Resources Company
(Exact name of registrant as specified in its charter)
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Texas | 001-35410 | 27-4662601 | ||
(State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) | ||
5400 LBJ Freeway, Suite 1500, Dallas, Texas | 75240 | |
(Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: (972) 371-5200
Not Applicable
(Former name or former address, if changed since last report)
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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 7.01 | Regulation FD Disclosure. |
Matador Resources Company expects to make presentations concerning its business to potential investors. The materials to be utilized during the presentations are furnished as Exhibit 99.1 hereto and incorporated herein by reference.
The information furnished pursuant to this Item 7.01, including Exhibit 99.1, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.
Item 9.01 | Financial Statements and Exhibits. |
(d) Exhibits
Exhibit No. | Description of Exhibit | ||
99.1 | Presentation Materials. | ||
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
MATADOR RESOURCES COMPANY | ||||||
Date: January 10, 2014 | By: | /s/ David E. Lancaster | ||||
Name: | David E. Lancaster | |||||
Title: | Executive Vice President | |||||
Exhibit Index
Exhibit No. | Description of Exhibit | ||
99.1 | Presentation Materials. | ||
January 2014 Investor Presentation NYSE: MTDR
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. Definitions – Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Matador’s production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where Matador produces liquids-rich natural gas, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. Estimated ultimate recovery (EUR) is a measure that by its nature is more speculative than estimates of proved reserves prepared in accordance with SEC definitions and guidelines and is accordingly less certain.
Company Summary
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 4 Matador History Matador Resources Company Founded by Joe Foran in 2003 with $6 million and 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 acquired 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 51. Matador Today
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 shares Share Price(2) $19.39/share Market Capitalization(2) ~$1.3 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 January 9, 2014. (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.
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 ~44,800 net acres in the Permian(8) Create value for stakeholders Enterprise Value(5) $0.65 billion(6) ~$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 6x What we said at IPO 6 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) At December 31, 2013. (9) As of January 9, 2014. Metric
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 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 ill io n s in m ill io 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
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 Flowback and production (gas-lift) operations resulting in better early well performance Began initial downspacing tests and early results are encouraging Built a significant acreage position in the emerging Permian Basin play and initiated exploration and operations Increased Permian acreage(1) position to ~70,800 gross (~44,800 net) acres during 2013 Initial drilling results encouraging; running one rig continuously and plan to do so throughout 2014 Oil production growth of ~75% Approximately 2.1 million barrels in 2013, as compared to 1.2 million barrels in 2012 Expected Adjusted EBITDA(2) growth of ~60% Estimated $180 to $190 million in 2013, as compared to $115.9 million in 2012 Completed a successful equity offering of 9.775 million shares in September 2013 Strong balance sheet and simple capital structure; no high-yield debt or convertibles Debt outstanding of $200 million at December 31, 2013; ~1.1x estimated 2013 Adjusted EBITDA(2) MTDR share price up 127% during 2013 One of the top performers in the Russell 2000 Energy Index in 2013 Recent equity offering has resulted in significant increase in trading liquidity (1) At December 31, 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.
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 acreage positions and multi-year drilling inventory are significant and located in three of the industry’s best plays – Eagle Ford, Permian and Haynesville Our property mix provides us with a balanced opportunity set for both oil and natural gas Process Continuous improvement in all aspects of our business leading to better production and financial results and increased shareholder value Gaining experience in being a publicly-held company Execute Increase oil production from 2 million barrels of oil to 3 million barrels of oil Maintain quality acreage position in the Eagle Ford, Permian and Haynesville Maintain strong financial position
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 Texas ~72% % Oil and Liquids ~97% Gross Acreage(3) 215,683 acres Net Acreage(3) 134,138 acres Engineered Drilling Locations(4)(5) 1,105 gross / 558.6 net Eagle Ford 270 gross / 222.7 net Permian 235 gross / 171.8 net Haynesville/Cotton Valley 600 gross / 164.1 net (1) Market capitalization based on shares outstanding and closing share price as of January 9, 2014. (2) Average daily production for the nine months ended September 30, 2013. (3) At December 31, 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 production units and estimated lateral lengths, costs and well spacing using objective criteria for designation.
Eagle Ford South Texas
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) wells turned to sales Includes $13.5 million for additional land/seismic and facilities 2014 Eagle Ford program is development drilling, with most locations planned at 40-acre spacing No Upper Eagle Ford tests currently planned for 2014 One exploratory Buda test planned at Glasscock Ranch Location to be selected from seismic data shot over Glasscock Ranch during 2013 Looking to extend trend of encouraging Buda drilling nearby, particularly southwest of Glasscock Ranch Key objectives of 2014 South Texas plan Further improvement in operational efficiencies and well performance in the Eagle Ford Batch drilling to continue reducing drilling times and costs; plan to pick up second “walking” rig Continue to improve and optimize stimulation operations – increased fluid and proppant volumes, reduced cluster spacing and additional stages, as needed Continue to optimize artificial lift program – gas lift to rod pump implementations Reduce LOE throughout all properties Successful implementation of 40-acre downspacing across acreage position Continue to add to acreage position as opportunities arise, particularly in and near existing properties
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 production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. (6) At December 31, 2013. Proved Reserves @ 9/30/2013 17.9 million BOE % Proved Developed 55% % Oil 75% Daily Oil Equivalent Production(3) 7,865 BOE/d (70% Oil) Gross Acres(6) 38,985 acres Net Acres(6) 27,147 acres 2014E CapEx Budget $318 million Engineered Drilling Locations(4)(5) 270 gross (222.7 net) Operations Summary 57 gross (50 net) wells(1) currently producing from the Eagle Ford An increase in oil production from ~330 Bbl/d(2) to ~6,700 Bbl/d(3) 270 gross (222.7 net) engineered drilling locations identified for potential future drilling(4)(5) 2014 South Texas Drilling Plan Continuing a two-rig program in the Eagle Ford $318 million CapEx (including facilities, land and seismic) Drill 50 gross wells (45 operated) Complete 45 gross wells (43 operated) Turn 43 gross wells to sales (38 operated) Approximately 5-10% of yearly production capacity shut-in during 2014
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 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” Well Costs: $6-7 million EUR: 300-500 MBOE EAGLE FORD “EAST” Well Costs: $8-10 million EUR: 600-1,000 MBOE EAGLE FORD “CENTRAL” Well Costs: $7-8 million EUR: 400-500 MBOE EAGLE FORD ACREAGE TOTALS 38,985 gross / 27,147 net acres
$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 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 yields 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
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 Efficiency – Moving Towards Batch Drilling
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
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 wellbore. (1) Mlbs = thousands of pounds of proppant pumped.
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 4 (80 Acre) GEN 5 (80 Acre) 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 3 (80 Acre) GEN 4 (80 Acre) 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 3 (80 Acre) GEN 5 (40 Acre) 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 4 (80 Acre) GEN 5 (80 Acre) EF “CENTRAL” EF “CENTRAL” EF “WEST” EF “WEST”
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 Heitz Lease 4 Buda Completions Dec 2011 – Aug 2012 Cum: 827 MBbl, 1.14 Bcf Contango O&G Beeler-3H Comp Sept 2013 1st Month IP: 310 Bbl/d 195 Mcf/d Cum: 9,312 Bbl 5,924 Mcf Buda Wells Activity Since January 1, 2010 20 Pearsall Field and Pearsall Arch Note: All acreage at December 31, 2013. Well information from public sources as of November 2013. Matador Resources Acreage
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 Fracture Trends Note: Well information from public sources as of November 2013. 21 Texas American Res Buchanan-1H Comp Apr 2013 5 mo avg: 507 Bbl/d 514 Mcf/d Cum: 76,989 Bbl 78,077 Mcf
Permian Basin Southeast New Mexico and West Texas
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 Includes $30 million for additional land/seismic and facilities Completion targets include various Bone Spring and Wolfcamp intervals across acreage position Key objectives of Permian Basin plan Further evaluate our acreage position and completion targets to define an expanded development program for 2015 and beyond With success, prepare for potential multi-rig development program beginning in late 2014 or early 2015 Leverage and transfer knowledge from Eagle Ford and Haynesville experience to improve operating efficiencies in the Permian Basin Continue to add to acreage position as opportunities arise, particularly in and near existing properties
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 neighborhoods, surrounded by other operators’ ongoing drilling Estimated 235 gross (171.8 net) engineered drilling locations(2); anticipated to grow over time with drilling success Plan to run one rig full-time in West Texas and Southeast New Mexico throughout 2014 During 2013, acquired ~55,400 gross (~38,900 net) acres primarily in Lea and Eddy Counties, New Mexico − Have also acquired 2,033 gross (1,449 net) acres in eastern Permian Basin in Howard and Dawson Counties, Texas E D D Y L E A Twin Lakes 31,057 gross / 20,791 net acres Indian Draw/Rustler Breaks 12,276 gross / 8,852 net acres Wolf 5,273 gross / 3,311 net acres Matador Resources Acreage LOVING Ranger/Querecho Plains 11,775 gross / 9,013 net acres
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 Wolfcamp “A”, “B”, “D” = Oil & Gas Source Rocks and Resource Reservoir Rocks Extensively distributed basin-wide “Wolf-Bone” Geological Setting, Predicting Where the Better Rocks Are 25
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 1920s >1,500 conventional reservoirs with cum production > 1.0 million Bbl Cumulative production from 1,500 conventional reservoirs, as of year 2000 (pre-horizontal drilling) > 30.0 billion Bbl(1) (1) Dutton et al, AAPG 2005 Permian Basin Petroleum Systems and the Wolfcamp “Kitchens” 26
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 November 30, 2013. 27 11,775 gross (9,013 net) acres 82 gross (58.6 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 6 wells planned for 2014 Location of Matador 2013 test wells Ranger 12 State #1 Data Well Ranger 33 State Com #1H 2nd Bone Spring Since late December 2013: 715 BOE/d with 90% oil Matador Resources Acreage
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. Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal wellbore. (1) Mlbs = thousands of pounds of proppant pumped.
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 Title -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 Title 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 c f / d ) Fl o w i n g P r es s u r e (p s i ) Days 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 2 25 30 35 40 45 50 55 60 Oil (Bbl/d), Ga s (Mcf/d) Flowing Pres sure (psi) Days Flowing Pressure Oil Gas Choke Ranger 33 State Com #1H Production History 29 24-hr IP: 575 Bbl/d oil, 263 Mcf/d gas, 543 Bbl/d water Flowing at 490 psi on 26/64” choke 12-9-13 23/64” Choke
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 MMcf Energen Black Mamba 1-57 Wolfcamp “A” 12 mo.cum: 213 MBbl; 541 MMcf Note: All acreage at December 31, 2013. Well information from public sources as of November 2013. (1) Presented as of November 30, 2013. 30 Location of Matador 2013 test wells 5,273 gross (3,311 net) acres 50 gross (33.6 net) locations(1) Primary Targets Wolfcamp “A” 3rd Bone Spring Avalon Other Potential Targets 1st Bone Spring 2nd Bone Spring Wolfcamp “B” 2 wells planned for 2014 Dorothy White #1H Wolfcamp “A” Well Drilled Now Completing Loving Matador Resources Acreage
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
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 Delaware Other Potential Targets Avalon 1st Bone Spring 3rd Bone Spring Wolfcamp “A” 3 wells planned for 2014 Concho R. Scary Fed 5H 2nd Bone Spring Sand 9 mo. cum: 84.5 MBbl; 270 MMcf Mewbourne Oil Co. San Lorenzo 15 DM 1H Wolfcamp 9 mo. cum: 50.6 MBbl; 333 MMcf Mewbourne Oil Co. Layla 35 MD Fee 1H Delaware 9 mo. cum: 116.5 MBbl; 470 MMcf Rustler Breaks Riddle 31 #1H Wolfcamp “B” Horizontal Test TVD 10,185’ (15,255’ MD) Indian Draw-Rustler Breaks Prospect Area Devon Energy 8 Drilling Permits Approved 2nd Bone Spring Sand Matador Resources Acreage
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 planned for 2014 Vaccum Field Grayburg/ San Andreas/ABO 690 MMBbl, 1.1 Tcf Maljamar Field Grayburg/San Andreas/Yeso 185 MMBbl, 186 BCF Denton Wolfcamp/Devonian 157 MMBbl, 78 Bcf Lovington West San Andres 27 MMBbl, 45 Bcf Lovington Paddock 74 MMBbl, 35 Bcf Townsend Field Penn/Perm 26 MMBbl, 105 Bcf Saunders Penn/Perm 43 MMBbl, 62 Bcf Dean Penn/Perm 9.5 MMBbl, 6.0 Bcf Caudill Penn/Perm 8.1 MMBbl, 6.0 Bcf Kemnitz Lower Wolfcamp 20 MMBbl, 153 Bcf A A’ Matador Resources Acreage
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
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 Petroleum Systems 35 Organic rich shales (source rocks) Low permeability sand and carbonates reservoirs requiring unconventional completion methods Sand Carbonates (Limestones and Dolomites) Shale/Mudstone
Haynesville and Other Natural Gas Operations
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 million for additional acreage acquisition as opportunities arise Haynesville/Cotton Valley acreage in Northwest Louisiana and East Texas is essentially all held by existing production Operational flexibility to drill operated Haynesville shale well(s) in 2014 should natural gas prices continue to improve, but no plans to do so at present time Completion of new gas gathering agreement in December 2013 for a portion of our Haynesville natural gas should reduce costs and improve pricing in 2014 Haynesville/Cotton Valley continue to represent large “gas bank” providing significant and increasing value as natural gas prices improve above $4.00/Mcf Competitive well economics for Tier 1 Haynesville at $4.50/Mcf and above, with estimated RORs of 40 to 100+%
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 Haynesville wells at $4.50 /Mcf Estimated ROR ranges from 40% - 100+% Pending Elm Grove gas gathering contract should reduce cost $0.65 - $0.92 /MMBtu – improved economics Anticipate increase in future drilling activity CHK evaluating drilling program at Elm Grove Other operators continuing activity Expect ~1.5 net wells in 2014 and 2015 Cotton Valley horizontal EURs ~6 Bcf 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(5) 83.3 Drilling Locations(5)(6) 164.1 net wells % HBP(5)(7) 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 December 31, 2013. (5) Presented as of November 30, 2013. (6) 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. (7) Acreage held by production or fee mineral interests owned by Matador. CADDO BOSSIER BIENVILLE RED RIVER DESOTO Elm Grove Cotton Valley: 49 Net Locations Matador Operated Acreage: 9,992 gross, 9,802 net Locations(5)(6): 71 gross, 49 net Tier 1 Haynesville: 63.8 Net Locations Acreage: 13,758 gross, 6,925 net Locations(5)(6): 454 gross, 63.8 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 30, 2013. Matador acreage shown in red. 38
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, % Natural Gas Price, $/Mcf Note: Individual well economics only. D&C cost = drilling and completion cost. Natural gas price differential = ($0.85)/Mcf .
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 treatment Initiated flow back to recover frac fluid and flow test Matador Resources Acreage
2014 Capital Investment Plan
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 results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these est imates were $96.00/Bbl and $4.30/Mcf, respectively, for the period October through December 2013. (3) Estimated 2014 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range. Estimated average realized prices for oil and natural gas used in these estimates were $95.00/Bbl and $4.25/Mcf, respectively, for the period January through December 2014. (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. Continue 3-rig program in 2014 – 2 rigs in Eagle Ford and 1 rig in Permian Eagle Ford development will continue to be the major driver of our growth in 2014 Permian drilling program designed to further evaluate our acreage position and define an expanded development plan for 2015 and beyond 2013 Guidance(1) 2014 Guidance % Increase Capital Spending $370 million $440 million ~19% Total Oil Production 2.0 to 2.1 million Bbl 2.8 to 3.1 million Bbl ~44% Total Natural Gas Production 12.0 to 13.0 Bcf 13.5 to 15.0 Bcf ~14% Oil and Natural Gas Revenues $250 to $270 million(2) $325 to $355 million(3) ~31% Adjusted EBITDA(4) $180 to $190 million(2) $235 to $265 million(3) ~35%
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 major driver of our growth in 2014 Permian drilling program designed to further evaluate our acreage position and define an expanded development plan for 2015 and beyond Haynesville development assumes only participation in non-operated wells Permian $109 million 24.7% Haynesville Non-Op/Other $13 million 3.0% Eagle Ford $318 million 72.4% 2014 Estimated CapEx = $440 million Land, Seismic, Etc. $30 million 6.8% Facilities, Infrastructure, Etc. $16 million 3.6% Drilling and Completions $394 million 89.5% 2014 Estimated CapEx = $440 million
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% from Permian in 2014 Quarterly production growth will continue to be somewhat variable, but expected to be less so than in 2013 − Timing effects due to batch drilling, shut-ins due to offset fracturing operations, etc. 2014E Natural Gas Production Estimated natural gas production of 13.5 to 15.0 Bcf Increase of ~14% from 2013, due primarily to participation in additional Haynesville non-op wells Estimated 50% of natural gas production from Haynesville and Cotton Valley, 43% from Eagle Ford and 7% from Permian in 2014 Uplift of $2.00 to $2.50/Mcf due to NGLs 2014 Oil and Natural Gas Production Estimates (1) Estimated quarterly average oil and natural gas production at midpoint of 2014 guidance range. Oil Production @ Midpoint(1) (Bbl/d) Natural Gas Production @ Midpoint(1) (MMcf/d) 0 2,000 4,000 6,000 8,000 10,000 1Q14E 2Q14E 3Q14E 4Q14E 0 5 10 15 20 25 30 35 40 45 1Q14 2Q14 3Q14 4Q14
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 revenues of $325 to $355 million − Increase of ~31% from estimated $250 to $270 million in 2013 Estimated Adjusted EBITDA(1)(2) of $235 to $265 million − Increase of ~35% from estimated $180 to $190 million in 2013 2014 production and revenue composition − Estimated 55% oil by volume, approaching 60% by YE 2014 − Estimated 82% oil by revenue, approaching 85% by YE 2014 2014E Operating Costs Estimated average unit costs per BOE ‒ Production taxes/marketing = $5.00 ‒ Lease operating = $8.00 ‒ G&A = $4.75 ‒ Operating cash costs, excluding interest = $17.75; compared to ~$19.00 in 2013 ‒ Costs vary +/- 5% over course of year ‒ DD&A = $25.00 2014 Financial Estimates Oil and Natural Gas Revenues(2) (millions) Adjusted EBITDA(1)(2) (millions) $19.0 $34.0 $67.0 $156.0 $260.0 $340.0 $0.0 $50.0 $100.0 $150.0 $200.0 $250.0 $300.0 $350.0 2009 2010 2011 2012 2013E 2014E $15.2 $23.6 $49.9 $115.9 $185.0 $250.0 $0.0 $40.0 $80.0 $120.0 $160.0 $200.0 $240.0 $280.0 2009 2010 2011 2012 2013E 2014E (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see Appendix. (2) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA 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 est imates were $96.00/Bbl and $4.30/Mcf, respectively, for the period October through December 2013. Estimated 2014 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range. Estimated average realized prices for oil and natural gas used in these estimates were $95.00/Bbl and $4.25/Mcf, respectively, for the period January through December 2014.
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/Etc. - - - - - - $6.0 1.4% Land/Seismic/Etc. - - - - - - $7.5 1.7% Area Total 50 47.0 80.1% 43 40.0 80.3% $318.4 72.4% West Texas/Southeast New Mexico Bone Spring/Wolfcamp 12 9.8 16.7% 10 8.3 16.7% $78.6 17.9% Facilities/Pipelines/Etc. - - - - - - $10.0 2.3% Land/Seismic/Etc. - - - - - - $20.0 4.5% Area Total 12 9.8 16.7% 10 8.3 16.7% $108.6 24.7% Northwest Louisiana Haynesville Shale 26 1.5 2.6% 26 1.5 3.0% $9.5 2.2% Land/Seismic/Etc. - - - - - - $2.5 0.5% Area Total 26 1.5 2.6% 26 1.5 3.0% $12.0 2.7% Southwest Wyoming Meade Peak Shale 1 0.4 0.7% - - - $1.0 0.2% Total 89 58.7 100.0% 79 49.8 100.0% $440.0 100.0% 46 Oil/Liquids Focus Continues to Drive 2014 Growth 97% of our 2014 capital investments directed toward oil and liquids-rich targets (3) (1) Some wells drilled in late 2014 will not be completed and turned to sales until early 2015. As a result, they do not contribute to our estimated oil and natural gas production volumes for 2014. (2) Includes Matador operated and non-operated wells. (3) A portion of the CapEx associated with these wells is expected to be incurred in 2013, as some wells were already being drilled at December 12, 2013.
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 Simple capital structure; no high-yield debt or convertibles on balance sheet Strong liquidity position with current Debt/Adjusted EBITDA(1) ~1.1x at December 31, 2013 Flexibility to manage liquidity Most drilling is operated and no significant non-operated drilling obligations $30 million estimated for discretionary land/seismic acquisitions No long-term drilling rig or service contract commitments (1) 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.
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% 275 bps 175 bps 50 bps Tier Six 100% < or = x < 110% 325 bps 225 bps 50 bps Tier Seven x = or > 110% 400 bps 300 bps 50 bps Strong, supportive bank group led by RBC Borrowing base at $350 million, based on June 30, 2013 reserves Borrowings outstanding of $200 million at December 31, 2013 Ability to request quarterly borrowing base increases with growth in oil and natural gas reserves throughout 2014, as needed Financial covenants Minimum current ratio of not less than 1.0:1.0, with current ratio first tested at June 30, 2014 Maximum Total Debt to Adjusted EBITDA(1) Ratio of not more than 4.0:1.0 48 Credit Agreement Status (1) 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.
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 natural gas liquids hedged at weighted average price of $1.25/gal(3) (1) NYMEX West Texas Intermediate oil futures. (2) NYMEX Henry Hub natural gas futures. (3) Mont Belvieu Spot Gas Liquids prices: NON-TET prop. Oil Hedges (Costless Collars) 2014 Total Volume Hedged by Ceiling 2,414,000 Bbl Weighted Average Price $99.00 /Bbl Total Volume Hedged by Floor 2,414,000 Bbl Weighted Average Price $87.61 /Bbl Natural Gas Hedges (Costless Collars) 2014 Total Volume Hedged by Ceiling 11.7 Bcf Weighted Average Price $4.96 /MMBtu Total Volume Hedged by Floor 11.7 Bcf Weighted Average Price $3.44 /MMBtu Natural Gas Liquids (NGLs) Hedges (Swaps) 2014 Total Volume Hedged 7,644,000 gal Weighted Average Price $1.25 /gal
Appendix
$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 $252.1 2008 2009 2010 2011 2012 9/30/2013 LTM Matador’s Continued Growth 51 Average Daily Production(1) (MBOE/d) Oil Production Mix(1) (% of Average Daily Production) Oil & Natural Gas Revenues ($ 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)
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 / 1,777 net acres GLASSCOCK (WINN) RANCH 8,891 gross / 8,891 net acres EAGLE FORD WEST 13,016 gross / 10,119 net acres EAGLE FORD ACREAGE TOTALS 38,985 gross / 27,147 net acres 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 Potential Remaining Eagle Ford Drilling Locations Estimated 270 gross (222.7 net) Tier 1/Tier 2 Eagle Ford engineered drilling locations at November 30, 2013. No additional Eagle Ford locations estimated for Atascosa acreage. Numbers do not include any potential locations for other horizons – e.g., Austin Chalk, Buda, etc. 13 5 (Non-Op) 1 (Buda) 6 4 2 9 5 5 50 gross (47.0 net) wells planned in 2014; all wells Matador-operated unless otherwise noted Matador Resources Acreage 4 Gross wells planned by lease in 2014
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 Plains − 6 gross (4.5 net) wells testing 1st, 2nd and 3rd Bone Spring and Wolfcamp D targets Indian Draw/Rustler Breaks − 3 gross (2.5 net) wells testing 2nd Bone Spring and Wolfcamp B targets Wolf − 2 gross (1.8 net) wells testing Wolfcamp A Twin Lakes − 1 gross (1.0 net) well targeting Wolfcamp D − Pilot hole budgeted to gather detailed logs, whole core, etc. 2014 Drilling Plan Highlights 1 6 3 2 2014 Permian Basin Drilling Plan Matador Resources acreage 2 Gross wells planned in 2014 12 gross (9.8 net) wells planned in 2014 All Matador-operated wells Twin Lakes 31,057 gross / 20,791 net acres Ranger/Querecho Plains 11,775 gross / 9,013 net acres Wolf 5,273 gross / 3,311 net acres Note: All acreage at December 31, 2013.
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 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
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. Hairford President - Samson, Sonat, Conoco 29 years Since 2004 David E. Lancaster EVP, COO and CFO - Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 34 years Since 2003 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 Sandra K. Fendley VP and CAO - J-W Midstream, Crosstex Energy 22 years Since 2013 Kathryn L. Wayne Controller and Treasurer - Matador Petroleum Corporation, Mobil 28 years Since Inception
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, 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, 57 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.
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 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 and September 30, 2011 were, in millions, $538.6 and $155.2 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 and September 30, 2011 were, in millions, $52.5 and $11.8 respectively.