November 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 Matador’s financial and operational performance: general economic conditions; Matador’s ability to execute its business plan, including whether Matador’s 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; Matador’s ability to replace reserves and efficiently develop its current reserves; Matador’s costs of operations, delays and other difficulties related to producing oil, natural gas and natural gas liquids; Matador’s ability to make acquisitions on economically acceptable terms; availability of sufficient capital to execute Matador’s business plan, including from its future cash flows, increases in Matador’s 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 that 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
square4 Founded by Joe Foran in 1983 – most participants are still shareholders today square4 Foran Oil funded with $270,000 in contributed capital from 17 friends and family members square4 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 Timeline Predecessor Entities (1) Tom Brown acquired by Encana in 2004. Matador Today
5 Company Overview Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 73.4 million common shares Share Price(2) $24.03/share Market Capitalization(1)(2) $1.8 billion (1) Shares outstanding as reported in the Form 10-Q for the quarter ended September 30, 2014 filed on November 7, 2014. (2) As of November 7, 2014. (3) As reaffirmed on November 5, 2014. (4) The Company raised its 2014 oil production guidance range from 2.8 to 3.1 million barrels to 3.2 to 3.3 million barrels on October 14, 2014. The Company guided investors to the top end of this range on November 5, 2014. (5) The Company guided investors to the middle or lower half of its natural gas guidance range on October 14, 2014. (6) Estimated 2014 oil and natural gas revenues and Adjusted EBITDA based on production guidance range. Estimated average realized prices for oil and natural gas used in these estimates were $80.00/Bbl and $5.00/Mcf, respectively, for the period October through December 2014. (7) 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. 2012 Actual 2013 Actual 2014 Guidance(3) Capital Spending $335 million $374 million $570 million Total Oil Production 1.214 million Bbl 2.133 million Bbl 3.2 to 3.3 million Bbl(4) Total Natural Gas Production 12.5 Bcf 12.9 Bcf 16.0 to 17.5 Bcf(5) Oil and Natural Gas Revenues $156.0 million $269.0 million $380 to $400 million(6) Adjusted EBITDA(7) $115.9 million $191.8 million $270 to $290 million(6)
Matador’s Execution History – “Doing What We Say” Oil Production square4 414 Bbl/d of oil square4 6% oil square4 4,916 Bbl/d of oil square4 46% oil square4 ~12,100 Bbl/d of oil(10) square4 56% oil(10) Proved Reserves square4 27 MMBOE square4 1.1 MMBbl of oil square4 4% oil square4 39 MMBOE square4 12.1 MMBbl of oil square4 31% oil square4 61 MMBOE square4 21.5 MMBbl of oil square4 35% oil PV-10(2) square4 $155.2 million square4 24% of PV-10 in Eagle Ford square4 $522.3 million square4 90% of PV-10 in Eagle Ford square4 $952.0 million square4 64% of PV-10 in Eagle Ford LTM Adjusted EBITDA(3) square4 $50 million (4) square4 $148 million square4 $241 million Acreage square4 ~7,500 net Permian acres square4 ~32,900 net Permian acres square4 ~65,000 net Permian acres(11) Enterprise Value (“EV”)(5) square4 $0.65 billion(6) square4 $1.2 billion(8) square4 $2.1 billion(12) 12x growth in oil production 11x growth in oil reserves ~200% growth Doubled EV Over 4x growth in Permian acres 6 At IPO(1) 2013 Follow-On(7) Over 3x 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 June 30, 2013. (8) As of September 1, 2013. (9) Unless otherwise noted, at or for the three months ended September 30, 2014. (10) For the month ended October 31, 2014. (11) As of October 1, 2014. (12) As of November 7, 2014. 146% growth in oil production 56% growth in oil reserves 63% growth 75% EV growth Doubled Permian acres 82% growth in PV-10 Today(9) Matador continues to execute on its core strategy of acquiring great assets, retaining a best-in-class workforce, maintaining a strong balance sheet and generating significant shareholder returns
Delivering Strong Results 7 Q3 2014 Achievements Oil Production(4) 2014 Capital Budget and Guidance square4 Oil Production – Company Record! − 9,123 Bbl/d; 36% growth versus Q3 2013 square4 Oil & Natural Gas Revenues − $96.6 million; 18% growth versus Q3 2013 square4 Adjusted EBITDA(1) − $66.8 million; 9% growth versus Q3 2013 square4 $570 million capital budget for 2014 square4 Adjusted EBITDA(1) of $270 to $290 million square4 Oil and natural gas revenues of $380 to $400 million square4 Estimated oil production of 3.2 to 3.3 million Bbl(2) square4 Estimated natural gas production of 16.0 to 17.5 Bcf(3) Oil & Natural Gas Revenues(5) Adjusted EBITDA(1)(5) (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. (2) The Company raised its 2014 oil production guidance range from 2.8 to 3.1 million barrels to 3.2 to 3.3 million barrels on October 14, 2014. The Company guided investors to the top end of this range on November 5, 2014. (3) The Company guided investors to the middle to lower half of its natural gas guidance range on October 14, 2014. (4) 2014 estimate at top end of guidance range as provided on November 5, 2014. (5) 2014 estimates at midpoint of guidance range as reaffirmed on November 5, 2014. Estimated average realized prices for oil and natural gas used in these estimates were $80.00/Bbl and $5.00/Mcf, respectively, for the period October through December 2014. (MBbl) ($ in millions) ($ in millions) $19 $34 $67 $156 $269 $390 2009 2010 2011 2012 2013 2014E $15 $24 $50 $116 $192 $280 2009 2010 2011 2012 2013 2014E 30 33 154 1,214 2,133 3,300 2009 2010 2011 2012 2013 2014E
8 Matador Resources Company Overview Market Capitalization(1) $1.8 billion Average Daily Production(2) 21,800 BOE/d Oil (% total) 12,100 Bbl/d (56%) Natural Gas (% total) 57.8 MMcf/d (44%) Proved Reserves @ 9/30/14 61.0 million BOE % Proved Developed 41% % Oil 35% 2014E CapEx $570 million % South Texas ~56% % Permian ~33% % Oil and Liquids ~89% Gross Acreage(3) 242,054 acres Net Acreage(3) 155,179 acres Engineered Drilling Locations(4)(5) 1,112 gross / 570.8 net Eagle Ford 273 gross / 229.3 net Permian 241 gross / 177.7 net Haynesville/Cotton Valley 598 gross / 163.8 net (1) Market capitalization based on shares outstanding as reported in the Form 10-Q for the three months ended September 30, 2014 filed on November 7, 2014 and closing share price as of November 7, 2014. (2) Average daily production for the month ended October 31, 2014. (3) At October 1, 2014. (4) Presented as of December 31, 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.
Asset Highlights 9 square4 Currently running a two-rig drilling program (177.7 net drilling locations(1)) square4 ~65,000 net acres(2) in Lea and Eddy Counties, NM and Loving County, TX in the Permian Basin with multi-zone drilling potential square4 Successful performance of three initial horizontal wells − Ranger 33: 158,000 BOE in twelve months (91% oil); producing 300 Bbl/d of oil(3); shallower than expected decline − Dorothy White: 246,000 BOE in ten months (67% oil); producing 500 Bbl/d of oil and 1.5 MMcf/d of natural gas(3); shallower than expected decline − Rustler Breaks: 111,000 BOE in seven months (45% oil); producing 175 Bbl/d of oil and 1.4 MMcf/d of natural gas(3); shallower than expected decline square4 Successfully drilled horizontal wells targeting five separate benches square4 Currently running a two “walking” rig drilling program in South Texas (229.3 net drilling locations(1)) square4 Net oil production of ~7,600 Bbl/d in Q3 2014 (up 14% as compared to Q3 2013)(4) square4 ~29,200 net acres(5) primarily located in the oil window square4 Expect batch drilling operations to continue to improve drilling times and costs square4 Fracture stimulation techniques continue to improve square4 Gas lift operations adding value and reducing costs square4 Continuing to acquire new leasehold interests at attractive prices to replace developed acreage and replenish inventory square4 Encouraging 40 to 50-acre downspacing results square4 ~25,000 net acres in NW Louisiana and East Texas(5)(6) − ~6,900 net Tier 1 acres in the core of the play with 6 to 12 Bcf EURs square4 Drilled and tested one of the first Haynesville wells square4 Increased industry activity as a result of higher natural gas prices leading to additional non-operated participation opportunities square4 Expect up to 56 gross (7.8 net) non- operated wells to be drilled on Matador’s acreage in 2014 square4 Anticipate Chesapeake drilled up to 45 gross (8.7 net) Haynesville wells in Elm Grove area through 2016; nine gross (2.0 net) wells on production in early October square4 Estimated ROR ranges from 60 to 100% or higher at $4.00 to $4.50/Mcf and above in Elm Grove area Permian Basin Exploratory and Delineation Program Eagle Ford Shale Development Program Haynesville Shale Natural Gas Bank Applying our Expertise (1) As of December 31, 2013. (2) At October 1, 2014. Includes small amounts of acreage in Reeves, Ward, Howard and Dawson Counties, TX. (3) As of November 5, 2014. (4) Includes two wells producing small quantities 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. (5) At October 1, 2014. (6) Includes acreage prospective for Cotton Valley.
Keys to Matador’s Success 10 square4 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 square4 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 square4 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 square4 Execute − Increase oil production from 2.1 million barrels of oil to 3.3 million barrels of oil − Maintain quality acreage position in the Eagle Ford, Permian and Haynesville − Maintain strong financial position, technical team and approach − Reduce drilling and completion times
Eagle Ford South Texas
2014 South Texas Plan Details 12 square4 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) wells turned to sales − 2014 Eagle Ford program is development drilling, with most locations planned at 40 to 50-acre spacing − No Upper Eagle Ford tests currently planned for 2014 square4 Key objectives of 2014 South Texas plan − Further improvement in operational efficiencies and well performance in the Eagle Ford − Batch drilling with two “walking” rigs to continue reducing drilling times and costs − Recent well in La Salle County drilled spud to total depth of 12,300 feet in 7.4 days – new Company record! − Continue to improve and optimize stimulation operations – increased fluid and proppant volumes, reduced cluster spacing and increased number of stages, as needed − Continue to optimize artificial lift program – gas lift to rod pump and plunger lift implementations − Reduce LOE throughout all properties − LOE declined 6% year-over-year in the first nine months of 2014 compared to the comparable period in 2013 − Successful implementation of 40 to 50-acre downspacing across acreage position − Testing 40 to 50-acre spacing at Sickenius, Danysh and Pawelek in Eagle Ford Central and Martin Ranch and Northcut in Eagle Ford West, with encouraging results − Continue to add to acreage position as opportunities arise, particularly in and near existing properties − Added 3,100 gross (2,900 net) acres(1) prospective for the Eagle Ford (up to 75 potential well locations) since January 1, 2014, more than replacing current year drilling inventory (1) At October 1, 2014.
13 Eagle Ford Overview (1) At September 30, 2014. 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 the three months ended September 30, 2014. (4) Presented as of December 31, 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 October 1, 2014. Proved Reserves @ 9/30/14 22.5 million BOE % Proved Developed 62% % Oil 73% Daily Oil Equivalent Production(3) 10,400 BOE/d(73% Oil) Gross Acres(6) 39,243 acres Net Acres(6) 29,165 acres % HBP(4) 82% 2014E CapEx Budget $318 million Engineered Drilling Locations(4)(5) 273 gross (229.3 net) Operations Summary square4 107 gross (89.1 net) wells(1) producing from the Eagle Ford square4 An increase in oil production from ~330 Bbl/d(2) in 2011 to ~7,600 Bbl/d(3) net to Matador square4 273 gross (229.3 net) engineered drilling locations identified for potential future drilling(4)(5) square4 2014 South Texas Drilling Plan square4 Continuing a 2-rig program in the Eagle Ford square4 All H2 2014 drilling in Eagle Ford Central and West square4 $318 million CapEx (including facilities, land and seismic) square4 Drill 50 gross wells (45 operated); complete 45 gross wells (43 operated) square4 Turn 43 gross wells to sales (38 operated) square4 Approximately 5 to 10% of yearly production capacity shut-in during 2014; up to 20% at various times
14 Eagle Ford Measured Depths and Well Costs Note: All acreage at October 1, 2014. Some tracts not shown on map. 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 Martin Ranch Northcut Affleck Troutt Sutton Love Cowey Lewton Hennig Nickel Ranch COMBO LIQUIDS / GAS FAIRWAY DRY GAS FAIRWAY OIL FAIRWAY EAGLE FORD “WEST” Measured Depth: 13,500’ – 14,500’ Well Costs: $6-7 million Testing 40-50 acre spacing EAGLE FORD “EAST” Measured Depth: 17,000’ – 18,000’ Well Costs: $8-10 million 80-acre spacing EAGLE FORD “CENTRAL” Measured Depth: 15,500’ – 16,500’ Well Costs: $7-8 million Testing 40-50 acre spacing EAGLE FORD ACREAGE TOTALS 39,243 gross / 29,165 net acres Harris Newman Pena ZLS Carroll Lloyd Hurt Sojourner Sickenius Lyssy Repka Falls City Pawelek Danysh Bishop-BroganCampbellton-Haverlah
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 square4 Over the past two years, made significant progress and increased knowledge of how to drill, complete and produce Eagle Ford wells square4 Experience and operational improvements have led to significant reductions in drilling and completion costs square4 Recent well in La Salle County drilled spud to total depth of 12,300 feet in 7.4 days – new Company record! square4 In 2013, began drilling from batch drilled pads using a drilling rig equipped with a “walking” package − Realized cost savings of approx. $325,000 per well on initial wells drilled using this rig − Expect the use of batch drilling and the “walking” rig will lead to total cost savings of approx. $400,000 per well or more going forward Note: “Q1 2014” – As of March 1, 2014. Year classification is based on spud date. (1) Drilled foot is the measured depth from surface to total depth. Excludes any/all wells drilled with a pilot hole, any/all wells drilled outside the West, Central and East and any/all wells drilled with three strings of casing. (2) Completed foot is the completed length of the lateral. Excludes any/all wells drilled with a pilot hole. Excludes any/all wells in the West and Central where premium proppant was used. $1,280 $1,322 2012 2013 $1,132 $908 $845 2011 2012 2013 $1,129 $874 $854 2011 2012 2013 $260 $203 2012 2013 $271 $258 $186 2011 2012 2013 $242 $209 $193 $153 2011 2012 2013 Q1 2014
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 of pounds of proppant pumped. Fluid Volume Pumped Proppant Pumped(1) Geometry of the Frac
0 20,000 40,000 60,000 80,000 100,000 120,000 0 50 100 150 200 250 300 350 400 C u m u l a tiv e P r o d u c t i o n ( Bbl ) Time (Days) GEN 2 (80 Acre) GEN 5 (40 Acre) GEN 4 (80 Acre) GEN 3 (80 Acre) GEN 6 (40 Acre) 0 20,000 40,000 60,000 80,000 100,000 120,000 0 50 100 150 200 250 300 350 400 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 2 (80 Acre) GEN 5 (40 Acre) GEN 3 (80 Acre) GEN 6 (40 Acre) 17 Frac Generation and Downspacing Comparison Eagle Ford “WEST” Eagle Ford “CENTRAL” Note: All wells normalized to 5,000’ horizontal 5 (4 cr ) 3 8 6 4 (40 r ) (80 r ) (80 r ) 3 (80 ) 6 (40 ) 5 40
0 50,000 100,000 150,000 200,000 250,000 300,000 2014 2013 2012 2011 2010 Lateral Feet Drilled 18 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 Drilling Efficiency – Moving Towards Batch Drilling E
Compressing Drill Times square4 Improving rig fleet − High tech, fast moving, faster drilling, walking style rigs square4 Improving Rate of Penetration (ROP) − Bit selection and development − Bottom Hole Assembly (BHA) selection − Rotary steerable systems − Vertical seeking − Directional drilling square4 Minimize directional work related to surface locations square4 Utilization of Managed Pressure Drilling square4 Development Phase − Pre-setting surface casing − Simultaneous operations 19
Progression of Drilling Rig Technology from 2010 to 2014 20 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 checkbld checkbld checkbld checkbld 250 checkbld checkbld checkbld checkbld checkbld checkbld checkbld 239 checkbld checkbld checkbld checkbld checkbld checkbld checkbld checkbld 279 checkbld checkbld checkbld checkbld checkbld checkbld checkbld checkbld Advancing Rig Technology
21 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 Reducing Natural Production Declines Time Note: Graph and data is for illustrative purposes only and not meant to reflect historical or forecasted data from actual well.
22 Buda Wells Activity Since January 1, 2010 – Potential Test Note: All acreage at October 1, 2014. Well information from public sources available as of August 2014. 5/3/2013 mo avg: TX American Resources Buchanan-1H 14 285 Bbl/d 466 Mcf/d Cum: 119 MBbl 1.9 Bcf Dan A. Hughes Heitz Lease 7 Buda Completions Dec. 2011 – May 2014 Cum: 960 MBbl 1.8 Bcf 14 back rate of Crimson Exploration Beeler-6H Spud on 2-13- Peak early 24-hr flow 1,185 BOE/d (91% oil yield) 2 mo avg: 586 Bbl/d 1,091 Mcf/d Cum: 35,180 Bbl 65,473 Mcf Pearsall Field and Pearsall Arch Comp May 2013 Blackbrush O&G Oppenheimer-101H 14 mo avg: 137 Bbl/d 376 Mcf/d Cum: 57 MBbl 158,013 Mcf Matador Resources Acreage Trend of Austin Chalk and Buda Production Blackbrush O&G 10 Buda Completions May 2011 – May 2014 Cum: 250 MBbl 1.4 Bcf CML Jessica-1 2 mo avg: 485 Bbl/d 244 Mcf/d Cum: 29,071 Bbl 14,627 Mcf
Permian Basin Southeast New Mexico and West Texas
24 square4 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 anticipated to come on production in Q4 2014 or early 2015 − Completion targets include various Bone Spring and Wolfcamp intervals across acreage position − Initial and recently completed wells exceeding expectations − $80 million allocated to land, seismic and facilities square4 Key objectives of Permian Basin plan − Further evaluate our acreage position and completion targets to define an expanded development program for 2015 and beyond − Planning to add at least one additional rig in Q4 2014 or beginning of 2015 − Permian Basin proved reserves increased from 1.4 million BOE at December 31, 2013, or only 3% of Matador’s total proved reserves, to 7.8 million BOE at September 30, 2014, or 13% of Matador’s total proved reserves − Validate and convert acreage position to held by production (“HBP”) − 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 − Added 27,700 gross (20,200 net) acres (1) in Permian Basin since January 1, 2014 − Doubled Loving County acreage position to 11,200 gross (7,200 net) acres (1) 2014 Permian Basin Plan Details (1) At October 1, 2014.
E D D Y L E A LOVING Matador Resources Acreage Location of Matador Well WARD TWIN LAKES 38,982 gross / 27,456 net acres INDIAN DRAW / RUSTLER BREAKS 21,023 gross / 14,785 net acres RANGER / QUERECHO PLAINS 14,875 gross / 10,776 net acres WOLF / LOVING AREA 11,183 gross / 7,155 net acres # 24 1 3 7 8 5 10 9 Permian Basin Total Gross Acres 98,440 acres Net Acres 64,982 acres Permian Basin Note: All acreage at October 1, 2014. Some tracts not shown on map. (1) As of November 5, 2014. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. (3) Flowing surface pressure. (4) At October 1, 2014. 25 6 Successful performance of initial horizontal wells(1) Recent activity and 24-hour initial potential tests Current activity square4 Continue current 2-rig drilling program in Lea and Eddy Counties, NM and Loving County, TX square4 Added ~20,200 net acres YTD 2014(4) Cumulative Production Current Production Oil Eq. % Oil Natural Gas EUR(2) Well Months (BOE) Oil (Bbl/d) (Mcf/d) (MBOE) Ranger 33 State Com #1H (2nd Bone Spring) 12 158,000 91% 300 170 500 Dorothy White #1H (Wolfcamp "A") 10 246,000 67% 500 1,500 1,000 Rustler Breaks 12-24-27 #1H (Wolfcamp "B") 7 111,000 45% 175 1,350 600 Norton Schaub #1H (Wolfcamp "A") 4 85,000 69% 420 1,200 700 Oil Eq. Oil Natural Gas % Pf (3) Choke Well Date (BOE/d) (Bbl/d) (Mcf/d) Oil (psi) (inches) Pickard State 20-18-34 #1H (2nd Bone Spring) Mid-July 2014 592 535 340 90% 750 22/64 th Pickard State 20-18-34 #2H (Wolfcamp "D") Mid-July 2014 270 232 225 86% 1,150 18/64 th Arno #1H (Wolfcamp "A") Mid-Sept 2014 1,110 300 4,900 27% 4,100 26/64 th Johnson 44-02S-B53 #204H (Wolfcamp "A") Late Sept 2014 1,286 793 3,000 62% 4,000 24/64 th Jim Rolfe 22-18-34 RN State #131Y (3rd Bone Spring) Flowing back after completion. Barnett 90-TTT-B01-WF #2001H (Wolfcamp "A") Waiting on completion operations. 1 2 3 4 5 6 7 8 9 10
26 square4 New rigs arriving in 2015 have even more advanced technology than current Eagle Ford rigs − Walking packages, hydraulic catwalks, reconfiguration of rig layouts, high pressure circulating systems, etc. − New rig features designed to match drilling plans – i.e. reconfiguration of rig layout allows for simultaneous operations (hydraulic fracturing and drilling operations simultaneously, on same location) square4 Geosteering capabilities and techniques allowing us to stay within defined target zones − Staying in target window maximizes well productivity and optimizes stimulation consistency − Target windows can be relatively thin within formations – i.e. the “X-Sand” target within the Wolfcamp “A” formation in Loving County, TX square4 Continuous improvement in frac design − Bigger fracs making better, more economic wells, as compared to earlier offset completions − In particular, Wolfcamp has similar characteristics to Eagle Ford barb2right using larger stimulation designs from the beginning − Frac designs will continue to evolve and improve square4 Production methods enhancing EURs, flattening declines and accelerating production − Flowing wells on restricted chokes has led to better bottomhole pressure management, keeping wells flowing longer and likely increasing EURs − Applying gas lift assist at optimal time is flattening decline rates and accelerating early production of hydrocarbons − Dorothy White #1H, Ranger 33 State Com #1H and Rustler Breaks 12-24-27 #1H are some of the best wells in their respective areas Technology Transfer and Application from Eagle Ford to Permian
27 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 studies since 1920s square4 >1,500 conventional reservoirs with cumulative production >1.0 million Bbl each square4 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
28 “Wolf-Bone” Geological Setting, Predicting Where the Better Rocks Are 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 Wolfcamp “A”, “B”, “D” = Oil & Gas Source Rocks and Resource Reservoir Rocks Extensively distributed basin-wide
2014 Wells Drilled Targeting Multiple Benches in Permian Appraisal Program 29 Sand Carbonates (Limestone's 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 Wolfcamp “D” Strawn Wolfcamp “A” Wolfcamp “B” Wolfcamp “C” Third Bone Spring Sand GR RES Brushy Canyon Sand Pickard 20-18-34 #2H (IP: 270 BOE/d, 86% oil) Rustler Breaks 12-24-27 #1H (111,000 BOE in 7 mo.(1)) Dorothy White #1H (246,000 BOE in 10 mo.(1)) Ranger 33 State Com #1H (158,000 BOE in 12 mo.(1)) Matador has successfully drilled horizontal wells targeting five separate Bone Spring and Wolfcamp benches Potential Future Targets (1) As of November 5, 2014. Jim Rolfe 22-18-34 RN #131Y (Completed – flowing back(1))
Wolf / Loving Prospect Area 30 square4 11,183 gross (7,155 net) acres square4 50 gross (35.4 net) locations(1) square4 Primary Targets − Wolfcamp “A” − 3rd Bone Spring − Avalon square4 Other Potential Targets − 1st Bone Spring − 2nd Bone Spring − Wolfcamp “B” square4 Approaching development status Location of Matador wells Note: All Matador acreage information as of October 1, 2014. Not all tracts shown on map. All Matador well information as of November 5, 2014. Other well information from public sources available as of August 2014. (1) Presented as of December 31, 2013. OXY Regan-McElvain #1H Wolfcamp “A” IP: 570 Bbl/d 2.6 MMcf/d 17 mo.cum: 140 MBbl; 357 MMcf Energen Grayling 1-69 #1H and #2H Wolfcamp “A” and “B”, resp. 19 mo.cum: 146 MBbl; 1 Bcf (commingled) Dorothy White #1H Wolfcamp “A” 10 mo.cum: 246,000 BOE (67% oil) Loving Matador Resources Acreage Norton Schaub #1H Wolfcamp “A” 4 mo.cum: 85,000 BOE (69% oil) Arno #1H Wolfcamp “A” IP: 1,110 BOE/d 300 Bbl/d; 4.9 MMcf/d Johnson 44-02S-B53 #204H Wolfcamp “A” IP: 1,286 BOE/d 793 Bbl/d; 3.0 MMcf/d Barnett 90-TTT-B01-WF #2001H Wolfcamp “A” Waiting on completion operations Norton Schaub 84-TTT-B33 WF #2010H Wolfcamp “A” Currently drilling Barnett 90-TTT-B01-WF #205H Wolfcamp “A” Currently drilling
Ranger / Querecho Plains Prospect Area 31 square4 14,875 gross (10,776 net) acres square4 83 gross (59.6 net) locations(1) square4 Primary Targets − 2nd Bone Spring − 3rd Bone Spring − Wolfcamp “A”, “B” and “D” square4 Other Potential Targets − Delaware − Avalon − 1st Bone Spring − Bone Spring Carbonates Location of Matador wells Note: All Matador acreage information as of October 1, 2014. All Matador well information as of November 5, 2014. Other well information from public sources available as of August 2014. (1) Presented as of December 31, 2013. Concho Stratojet 31 State #3H 2nd Bone Spring Sand 33 mo.cum: 402 MBbl; 488 MMcf Concho AirCobra 12 #2H 3rd Bone Spring 34 mo.cum: 353 MBbl; 242 MMcf Ranger 12 State #1 Data Well Ranger 33 State Com #1H 2nd Bone Spring Sand 12 mo.cum: 158,000 BOE (91% oil) Matador Resources Acreage Three Rivers 3rd Bone Spring Eagle 2 State #6H 17 mo.cum: 133 MBbl; 80 MMcf Pickard State 20-18-34 #1H 2nd Bone Spring Sand 3 mo.cum: 43,000 BOE (92% oil) Pickard State 20-18-34 #2H Wolfcamp “D” 3 mo.cum: 21,000 BOE (88% oil) Jim Rolfe 22-18-34 RN State #131Y 3rd Bone Spring Sand Flowing back after completion
32 square4 21,023 gross (14,785 net) acres square4 108 gross (82.8 net) locations(1) square4 Primary Targets − Wolfcamp “B” − 2nd Bone Spring − Delaware square4 Other Potential Targets − Avalon − 1st Bone Spring − 3rd Bone Spring − Wolfcamp “A” Rustler Breaks / Indian Draw Prospect Area Location of Matador wells Note: All Matador acreage information as of October 1, 2014. All Matador well information as of November 5, 2014. Other well information from public sources available as of August 2014. (1) Presented as of December 31, 2013. Concho R. Scary Fed #5H 2nd Bone Spring Sand 22 mo.cum: 121 MBbl; 361 MMcf Mewbourne Oil Co. San Lorenzo 15 DM #1H Wolfcamp 19 mo.cum: 68 MBbl; 421 MMcf Mewbourne Oil Co. Layla 35 MD Fee #1H Delaware 18 mo.cum: 156 MBbl; 757 MMcf Devon Energy 8 Drilling Permits Approved 2nd Bone Spring Sand Matador Resources Acreage Rustler Breaks 12-24-27 #1H Wolfcamp “B” 7 mo.cum: 111,000 BOE (45% oil) Mewbourne Oil Co. Malaga 30 MP Fed Com #1H 2nd Bone Spring Sand 8 mo.cum: 59 MBbl; 115 MMcf
Twin Lakes Prospect Area 33 square4 38,982 gross (27,456 net) acres square4 Primary Targets − Wolfcamp “D” − Strawn − Abo square4 Other Potential Targets − Cisco/Canyon − Devonian − Glorieta/San Andres Location of Matador well Note: All acreage at October 1, 2014. Well information from public sources available as of August 2014. Vacuum 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 Historical Twin Lakes Area Production 1.3 Billion Barrels Cumulative Oil 2.2 Trillion Cubic Feet Cumulative Natural Gas
North Ranger-Twin Lakes Area Pennsylvanian/Wolfcamp “D” Production Distribution 34 A A’ MATADOR RESOURCES COMPANY PICKARD STATE 20-18-34 #2H Vacuum Field Townsend Field 166 wells 25 MMBbl, 49 Bcf Sanmal & Leamex Fields Corbin Field Kemnitz Field 94 wells 19 MMBbl, 78 Bcf Sanmal and Leamex Fields 39 wells 3.3 MMBbl, 5.5 Bcf Vacuum Field 137 wells 17 MMBbl, 39 Bcf Airstrip Field Corbin Field 77 wells 7.6 MMBbl, 18 Bcf Airstrip Field 14 wells 0.26 MMBbl, 0.17 Bcf Wolfcamp/ Upper Pennsylvanian Production ~72 MMBbl, 190 Bcf ~527 vertical wells ~137,000 Bbl per vertical well Matador Resources Acreage Note: Information from public sources available as of November 2014. Vacuum N and NW Fields Kemnitz & Lea Fields MMBbl = millions of barrels of oil. Bcf = billions of cubic feet of natural gas.
Pennsylvanian/Wolfcamp “D” “Hybrid” Production Target Interval 30025300490000 AVRA OIL COMPANY 30025257790000 ELK OIL COMPANY 30025019240000 UNION OIL 30025397370000 CML EXPLORATION 30025414070000 CML EXPLORATION 30025416140000 MATADOR PRODUCTION A B E N A K I 1 0 S T A T E # 1 S T A T E ` 7 ` # 1 N O R T H E A S T K E M N I T Z # 3 S T A T E - L E A E # 1 B E A M S 1 5 S T A T E # 3 P I C K A R D S T A T E # 2 H P I L O T TOP OF WOLFCAMP LWTS GR Res. Dens. Neut. 10 MBbl 48 MMcf 197 MBbl 356 MMcf 140 MBbl 296 MMcf 90 MBbl 410 MMcf 11 MBbl 60 MMcf First Horizontal Landing Zone in source rock play: overpressured 0.7 psi/ft Produced 21,000 BOE – 3 mo. IP (24 hr.) from source rock: • 232 Bbl/d, 225 Mcf/d (86% oil) • 1,150 psi surface pressure • 18/64th inch choke As of November 5, 2014: • 150 Bbl/d, 175 Mcf/d • Gas-lift assist A North A’ SouthPickard #2H Future horizontal landing zones (oil on pits while drilling) in “hybrid” reservoirs: porous, sandstone/limestone and source rock. ~ 6 0 0 - 8 0 0 ’ T h i c k Cumulative volumes produced from older vertical wells 172 MBbl 536 MMcf Flowed oil on test R e g i o n a l l y p r o d u c t i v e “ H y b r i d ” T a r g e t I n t e r v a l 35MMBbl = millions of barrels of oil. Bcf = billions of cubic feet of natural gas.
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 BblFluid Volume Pumped Proppant Pumped(1) Geometry of the Frac
Haynesville Shale
2014 Tier 1 Haynesville Shale Plan 38 square4 2014 projected capital expenditures of ~$62 million or about 11% of total − Estimated participation in up to 56 gross (7.8 net) non-operated wells − Chesapeake in the process of drilling up to 45 gross (8.7 net to Matador) wells on Elm Grove through early 2016; ran three rigs on Elm Grove properties in Q3 2014 − Chesapeake recently placed nine wells (2.0 net to Matador) online(1) − Each well producing 8 to 12 MMcf (gross) natural gas per day – total of about 17 MMcf natural gas per day net to Matador’s interest; 8 gross (1.9 net) additional wells expected to be placed on production in late Q4 2014 − Drilling and completion costs between $7.0 to $8.0 million − 2014 capital plan includes no Matador operated Haynesville wells square4 Haynesville/Cotton Valley acreage in Northwest Louisiana and East Texas is essentially all held by existing production square4 Operational flexibility to drill operated Haynesville shale well(s) should natural gas prices improve sufficiently, but no plans to do so at present time square4 Completion of natural gas gathering agreement in December 2013 for a portion of our Haynesville natural gas reducing transportation costs by an average of approximately $0.70 or more per MMBtu in 2014 and increasing net gas realizations by the same amount square4 Haynesville/Cotton Valley continue to represent large “gas bank” providing significant and increasing value as natural gas prices improve above $4.00/Mcf − Highly competitive well economics for Tier 1 Haynesville at $4.00 to $4.50/Mcf and above, with estimated RORs of 60 to 100% or higher in Elm Grove area (1) At November 5, 2014.
Significant Option Value on Natural Gas square4 Significant acreage position in the Haynesville − Added 3 sections in 2014 to provide more operated drilling opportunities − Also prospective for the Cotton Valley, Travis Peak / Hosston and other shallow formations square4 Highly competitive well economics on Tier 1 Haynesville wells at $4.00 to $4.50/Mcf and above − Estimated ROR ranges from 60 to 100% or higher in Elm Grove area − Elm Grove natural gas gathering contract reducing costs an average of approximately $0.70 or more per MMBtu – improved economics square4 Non-operated drilling activity increasing − CHK anticipated to drill up to 45 gross (8.7 net) wells through early 2016 − 9 wells (2.0 net) producing; 8 to 12 MMcf/d (gross) each(9): 17 MMcf/d net to Matador − Expect 8 gross (1.9 net) wells in late Q4 2014 − Other operators continuing activity square4 Cotton Valley horizontal EURs ~6 Bcf NW Louisiana / East Texas(1) Proved Reserves(2) 183.6 Bcfe Daily Production(3) 3,600 BOE/d(>99% natural gas) Net Acres(4) 25,028 acres Net Producing Wells(5) 78.0 Drilling Locations(6)(7) 163.8 net wells % HBP(6)(8) 97% (1) Includes both Haynesville and Cotton Valley acreage. Includes one well producing from the Frio formation in Orange County, Texas. (2) At September 30, 2014. (3) For the three months ended September 30, 2014. (4) At October 1, 2014. (5) Presented as of September 30, 2014. (6) Presented as of December 31, 2013. (7) 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. (8) Acreage held by production or fee mineral interests owned by Matador. (9) As of November 5, 2014. 39 Note: All acreage at October 1, 2014. Matador acreage shown in red. HAYNESVILLE OPERATORS MATADOR CHESAPEAKE ENCANA EXCO GOODRICH -J W PETROHAWK / BHP QUESTAR SAMSON SHELL CADDO BOSSIER BIENVILLE RED RIVER DESOTO Elm Grove Cotton Valley: 49 Net Locations Matador Operated Acreage: 9,992 gross, 9,802 net Locations(6)(7): 71 gross, 49.3 net Tier 1 Haynesville: 63.6 Net Locations Acreage: 13,721 gross, 6,888 net Locations(6)(7): 452 gross, 63.6 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 BcfElm Grove Area
Anticipated Chesapeake Elm Grove Haynesville Operations – 2014 Through Early 2016 40 Currently producing • MTDR anticipates 45-well program through early 2016 • Three walking rigs actively drilling in third quarter 2014 • MTDR in discussions with CHK regarding rig moves and pace of development Solid – Drilling/Proposed/Producing Dashed – Anticipated through early 2016 Currently producing Currently producing
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 s t i m a t e d R a t e o f R e t u r n , % Natural Gas Price, $/Mcf 10 Bcf - $7.0mm D&C Cost 10 Bcf - $8.0mm D&C Cost 10 Bcf - $9.0mm D&C Cost Elm Grove Tier 1 Haynesville – Chesapeake Operated 41 Note: Individual well economics only. Excludes costs prior to drilling (i.e. acquisition or acreage costs). Economics use a NRI / WI of 85% but actual interests vary. Natural gas price differential = ($0.55)/Mcf. D&C cost = drilling and completion cost. Matador’s Advantaged Economics - NRI’s of 85% to 90% on many properties due to ORRI’s - Improved pricing/differentials due to taking gas in kind - Longer laterals and better completion techniques
2014 Capital Investment Plan
43 Summary and 2014 Guidance square4 Continue 4-rig program full-time in Q4 2014 – 2 rigs in the Eagle Ford and 2 rigs in the Permian square4 Eagle Ford development continues to be the major driver of our growth in 2014 square4 Permian drilling program designed to further evaluate our acreage position and define an expanded development plan for 2015 and beyond 2012 Actual 2013 Actual 2014 Guidance(1) Capital Spending $335 million $374 million $570 million Total Oil Production 1.214 million Bbl 2.133 million Bbl 3.2 to 3.3 million Bbl(2) Total Natural Gas Production 12.5 Bcf 12.9 Bcf 16.0 to 17.5 Bcf(3) Oil and Natural Gas Revenues $156.0 million $269.0 million $380 to $400 million(4) Adjusted EBITDA(5) $115.9 million $191.8 million $270 to $290 million(4) (1) As reaffirmed on November 5, 2014. (2) The Company raised its 2014 oil production guidance range from 2.8 to 3.1 million barrels to 3.2 to 3.3 million barrels on October 14, 2014. The Company guided investors to the top end of this range on November 5, 2014. (3) The Company guided investors to the middle or lower half of its natural gas guidance range on October 14, 2014. (4) Estimated 2014 oil and natural gas revenues and Adjusted EBITDA based on production guidance range. Estimated average realized prices for oil and natural gas used in these estimates were $80.00/Bbl and $5.00/Mcf, respectively, for the period October through December 2014. (5) 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.
44 2014 Capital Investment Plan Summary square4 Continue 4-rig program full time in Q4 2014: 2 rigs in the Eagle Ford and 2 rigs in the Permian square4 2014E capital expenditures of $570 million square4 Eagle Ford development continues to be the major driver of our growth in 2014 with growing Permian contribution square4 Permian drilling program designed to further evaluate our acreage position and define an expanded development plan for 2015 and beyond square4 Haynesville development assumes increased participation in non-operated wells 2014E CapEx by Region 2014E CapEx by Expense Type Haynesville Non-Op / Other $62 million 10.9% Permian $190 million 33.3% Eagle Ford $318 million 55.8% Land, Seismic, Etc. (Discretionary) $80 million 14.0% Facilities, Infrastructure, Etc. $20 million 3.5% Drilling and Completions $470 million 82.5% 2014E CapEx: $570 million
Funding for 2014 Capital Investment Plan 45 square4 Anticipate funding remaining 2014 capital expenditures through operating cash flows and borrowings under revolving credit facility − 0.4 million barrels of oil hedged for remainder of 2014, protecting cash flows below ~$88/Bbl oil price − 1.1 Bcf of natural gas hedged for remainder of 2014, protecting cash flows below ~$3.50/MMBtu gas price square4 Simple capital structure square4 Strong liquidity position with Debt/LTM Adjusted EBITDA(1) ~1.2x square4 Increased borrowing capacity to $450 million with September 2014 borrowing base determination square4 Flexibility to manage liquidity − Most drilling is operated; low non-operated drilling obligations − $80 million estimated for discretionary land/seismic acquisitions − Limited long-term drilling rig or service contract commitments (1) Assumes borrowings outstanding of approximately $290 million on November 5, 2014 and LTM Adjusted EBITDA of $241 million at September 30, 2014. 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.
46 Investment Highlights Strong Growth Profile with Increasing Focus on Oil / Liquids − YE2011 to 2014E oil production CAGR of ~178%(1) with expected year-over-year growth of ~55%(1) in 2014 − ~89% of 2014E CapEx program focused on oil / liquids exploration and development High Quality Asset Base in Attractive Areas(2) − ~65,000 net acres in the Permian Basin prospective for the liquids-rich Wolfcamp, Bone Spring and other targets − ~29,200 net acres in the Eagle Ford in some of the most active counties in South Texas, including Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties − Long-term option on natural gas with Haynesville, Cotton Valley and Bossier assets almost all HBP Multi-year Drilling Inventory(3)(4) − 177.7 net drilling locations in the Permian Basin with escalating activity to de-risk the play; anticipate significant increase in locations with further delineation drilling − 229.3 net drilling locations in the Eagle Ford − 163.8 net drilling locations in the Haynesville and Cotton Valley Low Cost Operations − Substantially reduced Eagle Ford drilling days and well costs since IPO − Batch drilling program and other improvements have potential to further reduce well costs and improve spud to sales times Strong Financial Position − Low leverage(5) of ~1.2x allows for operational flexibility − Liquidity available to execute planned drilling program Proven Management and Technical Team and Active Board of Directors − Management and senior technical team average over 25 years of industry experience − Board with extensive industry knowledge, business experience and company ownership − Strong record of stewardship (1) Represents growth to the top end of 2014 oil production guidance of 3.2 to 3.3 million barrels. (2) At October 1, 2014. (3) Presented as of December 31, 2013. (4) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. (5) Assumes borrowings outstanding of approximately $290 million on November 5, 2014 and LTM Adjusted EBITDA of $241 million at September 30, 2014. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix.
Appendix
48 Oil Production and Revenues Through Q3 2014 Average Daily Natural Gas Production (MMcf/d) Natural Gas Revenues ($ in mm) Oil Revenues ($ in mm) Average Daily Oil Production (Bbl/d) 209 563 465 448 2,200 3,130 3,291 4,630 5,115 4,916 6,703 6,612 7,344 8,809 9,123 0 2,000 4,000 6,000 8,000 10,000 12,000 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 36.5 44.6 38.8 39.0 34.8 33.7 33.7 34.5 33.7 33.7 40.2 32.1 27.4 39.7 41.8 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 2Q14 3Q14 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 78.5 77.5 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 12.0 15.8 13.8 10.9 7.6 6.7 7.9 10.1 10.6 13.5 17.6 14.4 15.3 20.6 19.1 0.0 5.0 10.0 15.0 20.0 25.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 All-time high oil production in Q3 2014 CHK Haynesville wells starting to impact Oil revenues down slightly in Q3 2014 due to lower oil prices Gas revenues down slightly in Q3 2014 due to lower natural gas prices
$10.1 $15.3 $12.1 $12.4 $21.3 $27.9 $28.6 $38.0 $40.7 $40.8 $61.5 $48.8 $56.3 $69.5 $66.8 $0.0 $10.0 $20.0 $30.0 $40.0 $50.0 $60.0 $70.0 $80.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 $15.5 $21.8 $18.9 $17.9 $32.2 $40.8 $41.4 $55.6 $59.7 $58.4 $80.7 $69.3 $77.1 $96.1 $95.9 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 $13.7 $20.9 $17.4 $15.0 $29.2 $36.1 $38.0 $52.7 $59.3 $57.7 $81.9 $69.7 $78.9 $99.1 $96.6 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 6,300 8,004 6,931 6,953 8,023 8,738 8,838 10,385 10,89710,582 13,482 11,968 11,904 15,424 16,096 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 49 Quarterly Performance Metrics Through Q3 2014 Oil and Natural Gas Revenues ($ in mm) Total Realized Revenues ($ in mm) Adjusted EBITDA(1) ($ in mm) Average Daily Equivalent Production (BOE/d) $49.9 $74.1 $67.0 (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. 15-20% shut-in at times during Q3 2014 Q3 2014 slightly lower due to lower commodity prices Q3 2014 slightly lower due to lower commodity prices
50 Quarterly Expense Metrics Through Q3 2014 Lease Operating (per BOE) General and Administrative (per BOE) Depletion, Depreciation and Amortization (per BOE) Production Taxes and Marketing (per BOE) $ 2 . 2 9 $ 2 . 2 7 $ 2 . 9 0 $ 2 . 3 1 $ 2 . 9 5 $ 3 . 2 9 $ 3 . 4 7 $ 4 . 2 6 $ 4 . 1 8 $ 4 . 6 2 $ 5 . 2 9 $ 5 . 3 3 $ 5 . 6 1 $ 6 . 5 0 $ 5 . 8 2 $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 2Q14 3Q14 $ 2 . 8 3 $ 2 . 7 0 $ 3 . 2 4 $ 2 . 5 1 $ 6 . 3 6 $ 8 . 0 2 $ 7 . 9 8 $ 1 1 . 1 7 $ 1 1 . 1 1 $ 1 0 . 5 3 $ 6 . 9 1 $ 8 . 2 8 $ 8 . 7 3 $ 8 . 3 4 $ 9 . 2 5 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 $ 1 2 . 5 4 $ 1 1 . 2 3 $ 1 1 . 4 3 $ 1 4 . 3 4 $ 1 5 . 3 5 $ 2 5 . 0 4 $ 2 6 . 6 6 $ 2 8 . 9 5 $ 2 8 . 7 9 $ 2 1 . 0 1 $ 2 1 . 0 6 $ 2 1 . 6 2 $ 2 2 . 4 3 $ 2 2 . 6 6 $ 2 3 . 7 3 $0.00 $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 $35.00 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 $ 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 . 7 4 $ 5 . 7 7 $ 5 . 4 7 $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 2Q14 3Q14 Reflects growth in oil production / revenues Mostly flat Q/Q DD&A relatively steady G&A declining on per BOE 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 $3.99 2009 2010 2011 2012 2013 2014E Matador Provides Growth on a Per Share(1) Basis 51 Oil and Natural Gas Revenues(4) per Share ($ per share) PV-10(2) per Share ($ per share) Adjusted EBITDA(3)(4) per Share ($ per share) (1) Weighted Average Basic Shares Outstanding. Value for 2014E assumes no shares issued for remainder of 2014. (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) 2014 estimates at midpoint of guidance range reaffirmed on October 14, 2014. Estimated average realized prices for oil and natural gas used in these estimates were $80.00/Bbl and $5.00/Mcf, respectively, for the period October through December 2014. (in thousands) Shares (1) PV-10(2) Adj. EBITDA(3)(4) Oil & Natural Gas Revenues (4) 2009 40,123 $70,359 $15,184 $19,039 2010 41,037 $119,869 $23,635 $34,042 2011 42,718 $248,700 $49,911 $67,000 2012 53,957 $423,200 $115,923 $155,998 2013 58,777 $655,200 $191,771 $269,030 2014E 70,227 $280,000 $390,000
$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 $269.0 2008 2009 2010 2011 2012 2013 7% 4% 2% 6% 37% 50% 2008 2009 2010 2011 2012 2013 1.5 2.3 3.9 7.0 9.0 11.7 2008 2009 2010 2011 2012 2013 Matador’s Continued Growth Average Daily Production (MBOE/d) Oil Production Mix (% of Average Daily Production) Oil and Natural Gas Revenues ($ in millions) Adjusted EBITDA(1) ($ in millions) 52 Growth since IPO Growth since IPOGrowth since IPO Growth since IPO (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.
84 485 729 908 1,225 1,463 1,837 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E 1,277 1,525 1,768 1,944 2,341 2,475 3,525 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E Semi-Annual Performance Metrics Through 2014 Oil Production (Bbl in thousands) Oil Equivalent Production (BOE in thousands) Oil and Natural Gas Revenues ($ in millions) Adjusted EBITDA(1) ($ in millions) (2) $32.4 $65.2 $90.8 $117.5 $151.5 $178.0 $212.0 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E $24.4 $49.3 $66.7 $81.5 $110.3 $125.8 $154.2 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E (3) (4)(4) 53 (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) 2H 2014E value is estimated based on the top end of 2014 guidance range of 3.2 to 3.3 million barrels of oil as provided on November 5, 2014. (3) 2H 2014E value is estimated based on the top of 2014 projections of 5.9 to 6.0 million BOE, as disclosed on November 5, 2014. (4) 2H 2014E values are estimated based on the midpoint of 2014 guidance for each metric as reaffirmed on November 5, 2014.
1,277 1,525 1,768 1,944 2,341 2,475 3,525 4,430 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E 1H 2015E 84 485 729 908 1,225 1,463 1,837 2,085 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E 1H 2015E $24.4 $49.3 $66.7 $81.5 $110.3 $125.8 $154.2 $172.0 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E 1H 2015E $32.4 $65.2 $90.8 $117.5 $151.5 $178.0 $212.0 $230.0 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E 1H 2015E Semi-Annual Performance Metrics and Hypothetical 2015 Stress Case Scenario Oil Production (Bbl in thousands) Total Oil and Natural Gas Production (BOE in thousands) Oil and Natural Gas Revenues ($ in millions) Adjusted EBITDA(1) ($ in millions) (2) (4) (5)(5) For 2015, assumes: Oil at $80 per Bbl; $570mm CapEx; Rigs: 1½ Eagle Ford + 4 Permian + Non-Op Haynesvi lle (3) (3) (3)(3) 54 (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) 2H 2014E value is estimated based on the top end of 2014 guidance range of 3.2 to 3.3 million barrels of oil as provided on November 5, 2014. (3) 2015 information, including expected capital expenditures and rig count, is presented as a hypothetical stress case scenario and is not guidance or otherwise intended to reflect anticipated results in 2015. Hypothetical stress case scenario only represents estimates and does not take into consideration changes in differentials, operational costs, oil field services costs, changes in commodity prices or other circumstances. Matador intends to release 2015 guidance in connection with its Analyst Day to be held on January 15, 2015. (4) 2H 2014E value is estimated based on the top of 2014 projections of 5.9 to 6.0 million BOE, as disclosed on November 5, 2014.. (5) 2H 2014E values are estimated based on the midpoint of 2014 guidance for each metric as reaffirmed on November 5, 2014.
55 Hedging Profile – Hedges in Place for Remainder of 2014 and 2015 At November 5, 2014, Matador had: square4 0.4 million barrels of oil hedged for remainder of 2014 at weighted average floor and ceiling of $88/Bbl and $99/Bbl, respectively square4 1.1 Bcf of natural gas hedged for remainder of 2014 at weighted average floor and ceiling of $3.50/MMBtu and $4.93/MMBtu, respectively square4 1.3 million gallons of natural gas liquids hedged for remainder of 2014 at weighted average price of $1.25/gal square4 1.7 million barrels of oil, 9.0 Bcf of natural gas and 3.8 million gallons of natural gas liquids hedged for 2015 Note: Hedged volumes shown in table for 2014 are for remainder of 2014. Oil Hedges (Costless Collars) 2014 2015 Total Volume Hedged by Ceiling 442,400 Bbl 1,680,000 Bbl Weighted Average Price $98.95 /Bbl $99.75 /Bbl Total Volume Hedged by Floor 442,400 Bbl 1,680,000 Bbl Weighted Average Price $87.83 /Bbl $83.00 /Bbl Natural Gas Hedges (Costless Collars) 2014 2015 Total Volume Hedged by Ceiling 1.1 Bcf 9.0 Bcf Weighted Average Price $4.93 /MMBtu $4.79 /MMBtu Total Volume Hedged by Floor 1.1 Bcf 9.0 Bcf Weighted Average Price $3.50 /MMBtu $3.77 /MMBtu Natural Gas Liquids (NGLs) Hedges (Swaps) 2014 2015 Total Volume Hedged 1,274,000 gal 3,816,000 gal Weighted Average Price $1.25 /gal $1.02 /gal
square4 Strong, supportive bank group led by Royal Bank of Canada square4 Borrowing base at $450 million, based on July 31, 2014 reserves, increased from $385 million based on December 31, 2013 reserves, and increased from $125 million at time of IPO in February 2012 square4 Borrowings outstanding of $290 million at November 5, 2014 square4 Ability to request quarterly borrowing base increases with growth in oil and natural gas reserves throughout 2015, as needed square4 Financial covenants − Maximum Total Debt to Adjusted EBITDA(1) Ratio of not more than 4.25:1.00 − No Current Ratio test TIER Conforming Borrowing Base Utilization LIBOR Margin BASE Margin Commitment Fee Tier One x < 25% 150 bps 50 bps 37.5 bps Tier Two 25% < or = x < 50% 175 bps 75 bps 37.5 bps Tier Three 50% < or = x < 75% 200 bps 100 bps 50 bps Tier Four 75% < or = x < 90% 225 bps 125 bps 50 bps Tier Five 90% < or = x < 100% 250 bps 150 bps 50 bps Tier Six 100% < or = x < 110% 300 bps 200 bps 50 bps Tier Seven x = or > 110% 375 bps 275 bps 50 bps 56 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.
57 SEC Proved Reserves Value Growth By Area September 30, 2014 PV-10(1): $952.0 million $95.56 oil(2), $4.236 natural gas(2) (Standardized Measure = $835.1 million) (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. (2) Oil prices in $/Bbl; natural gas prices in $/MMBtu. December 31, 2013 PV-10(1): $655.2 million $93.42 oil(2), $3.67 natural gas(2) (Standardized Measure = $578.7 million) September 30, 2013 PV-10(1): $538.6 million $91.69 oil(2), $3.605 natural gas(2) (Standardized Measure = $486.1 million) Eagle Ford $479.3 million, 89% Permian $4.1 million, 1% Eagle Ford $540.4 million, 82% Haynesville/CV $82.9 million, 13% Permian $31.9 million, 5% Eagle Ford $614.7 million, 64% Haynesville/CV $168.7 million, 18% Permian $168.6 million, 18% Haynesville/CV $55.2 million, 10%
Board of Directors and Special Advisors – Expertise and Stewardship 58 Board Members Professional Experience Business Expertise David M. Laney Lead Director - Past Chairman, Amtrak Board of Directors - Former Partner, Jackson Walker LLP Law and Investments Reynald A. Baribault Director - Vice President / Engineering and Co-founder, North Plains Energy, LLC - President and CEO, IPR Energy Partners, LLC - Former Vice President, Netherland, Sewell & Associates, Inc. Oil and Gas Exploration Gregory E. Mitchell Director - President and CEO, Toot’n Totum Food Stores Petroleum Retailing Dr. Steven W. Ohnimus Director - Retired Vice President 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 Vice President and General Counsel, BJ Services Co. - Former Partner, Andrews Kurth LLP Law and Corporate Governance Special Board Advisors Professional Experience Business Expertise 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 Executive Vice President – 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 59 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. 34 years Since Inception Matthew V. Hairford President - Samson, Sonat, Conoco 30 years Since 2004 David E. Lancaster EVP, COO and CFO - Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 35 years Since 2003 David F. Nicklin Executive Director of Exploration - ARCO, Senior Geological Assignments in UK, Norway, Indonesia, China and the Middle East 43 years Since 2007 Craig N. Adams EVP – Land & Legal - Baker Botts L.L.P., Thompson & Knight LLP 21 years Since 2012 Ryan C. London VP and General Manager - Matador Resources Company (Began as intern) 10 years Since 2004 Bradley M. Robinson VP and CTO - Schlumberger, S.A. Holditch & Associates, Inc., Marathon 37 years Since Inception Billy E. Goodwin VP of Drilling - Samson, Conoco 30 years Since 2010 William F. McMann VP of Production & Facilities - Independent Consultant, Wagner Oil Company, Denbury Resources 29 years Since 2011 Van H. Singleton, II VP of Land - Southern Escrow & Title, VanBrannon & Associates 18 years Since 2007 Mark Golborne VP of Exploration - ARCO, BP, Global Conventional and Unconventional Exploration, Appraisal and Development 33 years Since 2014 G. Gregg Krug VP of Marketing - Williams Companies, Samson, Unit Corporation 31 years Since 2005 Sandra K. Fendley VP and CAO - J-W Midstream, Crosstex Energy 23 years Since 2013 Kathryn L. Wayne Controller and Treasurer - Matador Petroleum Corporation, Mobil 30 years Since Inception
60 MTDR Trading versus BOE/d Production since IPO 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 22,000 $0.00 $4.00 $8.00 $12.00 $16.00 $20.00 $24.00 $28.00 $32.00 I P O 3 / 31 / 201 2 6 / 30 / 201 2 9 / 30 / 201 2 1 2 / 31 / 201 2 3 / 31 / 201 3 6 / 30 / 201 3 9 / 30 / 201 3 1 2 / 31 / 201 3 3 / 31 / 201 4 6 / 30 / 201 4 9 / 30 / 201 4 T o d a y D a i l y O i l E q u i v a l e n t P r o d u c t i o n , B O E / d M T D R C l o s i n g P r i c e BOE/d MTDR Note: Matador closing share price through November 7, 2014. October 2014 averaged ~21,800 BOE/d
61 MTDR Trading versus Growing Permian Acreage since IPO 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 $0.00 $4.00 $8.00 $12.00 $16.00 $20.00 $24.00 $28.00 $32.00 P e r m i a n A c r e a g e P o s i t i o n , N e t A c r e s M T D R C l o s i n g P r i c e MTDR Permian Net Acreage Note: Matador closing share price through November 7, 2014.
62 MTDR Trading versus PV-10 Growth since IPO Note: Matador closing share price through November 7, 2014. $0.0 $100.0 $200.0 $300.0 $400.0 $500.0 $600.0 $700.0 $800.0 $900.0 $1,000.0 $0.00 $4.00 $8.00 $12.00 $16.00 $20.00 $24.00 $28.00 $32.00 I P O 3 / 3 1 / 20 1 2 6 / 3 0 / 20 1 2 9 / 3 0 / 20 1 2 12 / 3 1 / 20 1 2 3 / 3 1 / 20 1 3 6 / 3 0 / 20 1 3 9 / 3 0 / 20 1 3 12 / 3 1 / 20 1 3 3 / 3 1 / 20 1 4 6 / 3 0 / 20 1 4 9 / 3 0 / 20 1 4 T o d a y P V - 1 0 , $ i n m i l l i o n s M T D R C l o s i n g P r i c e PV-10 MTDR
63 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. PV-10 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. At December 31, 2009 At December 31, 2010 At September 30, 2011 At December 31, 2011 At March 31, 2012 At June 30, 2012 At September 30, 2012 At December 31, 2012 PV-10 (in millions) $70.4 $119.9 $155.2 $248.7 $329.6 $303.4 $363.6 $423.2 Discounted Future Income Taxes (in millions) $(5.3) $(8.8) $(11.8) $(33.2) $(42.2) $(21.9) $(29.7) $(28.6) Standardized Measure (in millions) $65.1 $111.1 $143.4 $215.5 $287.4 $281.5 $333.9 $394.6 At March 31, 2013 At June 30, 2013 At September 30, 2013 At December 31, 2013 At March 31, 2014 At June 30, 2014 At September 30, 2014 PV-10 (in millions) $438.1 $522.3 $538.6 $655.2 $739.8 $826.0 $952.0 Discounted Future Income Taxes (in millions) $(31.1) $(44.7) $(52.5) $(76.5) $(86.2) $(103.0) $(116.9) Standardized Measure (in millions) $407.0 $477.6 $486.1 $578.7 $653.6 $723.0 $835.1
64 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.
65 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 thousands) 2008 2009 2010 2011 2012 2013 6/30/2013 9/30/2014 Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): Net income (loss) $103,878 ($14,425) $6,377 ($10,309) ($33,261) $45,094 ($20,771) $79,582 Interest expense - - 3 683 1,002 5,687 3,574 4,453 Total income tax (benefit) provision 20,023 (9,925) 3,521 (5,521) (1,430) 9,697 (703) 43,730 Depletion, depreciation and amortization 12,127 10,743 15,596 31,754 80,454 98,395 97,801 114,772 Accretion of asset retirement obligations 92 137 155 209 256 348 307 470 Full-cost ceiling impairment 22,195 25,244 - 35,673 63,475 21,229 51,499 - Unrealized loss (gain) on derivatives (3,592) 2,375 (3,139) (5,138) 4,802 7,232 13,945 (7,345) Stock-based compensation expense 665 656 898 2,406 140 3,897 1,836 5,801 Net (gain) loss on asset sales and inventory impairment (136,977) 379 224 154 485 192 617 - Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $148,105 $241,463 LTM at LTM at (In thousands) 2008 2009 2010 2011 2012 2013 6/30/2013 9/30/2014 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $25,851 $1,791 $27,273 $61,868 $124,228 $179,470 $156,614 $232,636 Net change in operating assets and liabilities (17,888) 15,717 (2,230) (12,594) (9,307) 6,210 (12,161) 2,292 Interest expense - - 3 683 1,002 5,687 3,574 4,453 Current income tax (benefit) provision 10,448 (2,324) (1,411) (46) - 404 78 2,082 Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $148,105 $241,463 Year Ended December 31, Year Ended December 31,
66 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 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 Unaudited Adjusted EBITDA reconciliation to Net (loss) Income: Net (loss) income $ (27,596) $ 7,153 $ 6,194 $ 3,941 $ 3,801 $ (6,676) $ (9,197) $ (21,188) $ (15,505) $ 25,119 $ 20,105 $ 15,374 $ 16,363 $ 18,226 $ 29,619 Interest expense 106 184 171 222 308 1 144 549 1,271 1,609 2,038 768 1,396 1,616 673 Total income tax provision (benefit) (6,906) (46) - 1,430 3,064 (3,713) (593) (188) 46 32 2,563 7,056 9,536 10,634 16,504 Depletion, depreciation and amortization 7,111 8,180 7,287 9,176 11,205 19,914 21,680 27,655 28,232 20,234 26,127 23,802 24,030 31,797 35,143 Accretion of asset retirement obligations 39 57 62 51 53 58 59 86 81 80 86 100 117 123 130 Full-cost ceiling impairment 35,673 - - - - 33,205 3,596 26,674 21,230 - - - - - - Unrealized (gain) loss on derivatives 1,668 (332) (2,870) (3,604) 3,270 (15,114) 12,993 3,653 4,825 (7,526) 9,327 606 3,108 5,234 (16,293) Stock-based compensation expense 53 128 1,234 991 (363) 191 (51) 363 492 1,032 1,239 1,134 1,795 1,834 1,038 Net loss on asset sales and inventory impairment - - - 154 - 60 - 425 - 192 - - - - - Adjusted EBITDA $ 10,148 $ 15,324 $ 12,078 $ 12,361 $ 21,338 $ 27,926 $ 28,631 $ 38,029 $ 40,672 $ 40,772 $ 61,485 $ 48,840 $ 56,345 $ 69,464 $ 66,814 (In thousands) 1Q 2011 2Q 2011 3Q 2011 4Q 2011 1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $ 12,732 $ 6,799 $ 14,912 $ 27,425 $ 5,110 $ 46,416 $ 28,799 $ 43,903 $ 32,229 $ 51,684 $ 43,280 $ 52,278 $ 31,945 $ 81,530 $ 66,883 Net change in operating assets and liabilities (2,690) 8,386 (3,004) (15,286) 15,920 (18,491) (500) (6,235) 7,126 (12,553) 15,265 (3,630) 21,729 (15,221) (586) Interest expense 106 184 171 222 308 1 144 549 1,271 1,609 2,038 768 1,396 1,616 673 Current income tax (benefit) provision - (45) (1) - - - 188 (188) 46 32 902 (576) 1,275 1,539 (156) Adjusted EBITDA $ 10,148 $ 15,324 $ 12,078 $ 12,361 $ 21,338 $ 27,926 $ 28,631 $ 38,029 $ 40,672 $ 40,772 $ 61,485 $ 48,840 $ 56,345 $ 69,464 $ 66,814
67 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) 12/31/2011 6/30/2012 12/31/2012 6/30/2013 12/31/2013 6/30/2014 Unaudited Adjusted EBITDA reconciliation to Net (Loss) Income: Net (loss) income 10,135$ (2,875)$ (30,385)$ 9,615$ 35,479$ 34,589$ Interest expense 393 309 693 2,881 2,806 3,012 Total income tax (benefit) provision 1,430 (649) (781) 78 9,619 20,170 Depletion, depreciation and amortization 16,463 31,119 49,335 48,466 49,929 55,827 Accretion of asset retirement obligations 113 111 145 162 186 241 Full-cost ceiling impairment 0 33,205 30,270 21,229 - - Unrealized loss (gain) on derivatives (6,474) (11,844) 16,646 (2,701) 9,933 8,342 Stock-based compensation expense 2,225 (172) 312 1,524 2,373 3,629 Net loss on asset sales and inventory impairment 154 60 425 192 - - Adjusted EBITDA 24,439$ 49,264$ 66,660$ 81,446$ 110,325$ 125,810$ (In thousands) 12/31/2011 6/30/2012 12/31/2012 6/30/2013 12/31/2013 6/30/2014 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities 42,337$ 51,526$ 72,702$ 83,912$ 95,558$ 113,475$ Net change in operating assets and liabilities (18,290) (2,571) (6,735) (5,425) 11,635 6,509 Interest expense 393 309 693 2,881 2,806 3,012 Current income tax provision (benefit) (1) - - 78 326 2,814 Adjusted EBITDA 24,439$ 49,264$ 66,660$ 81,446$ 110,325$ 125,810$ Six Months Ended Six Months Ended