November 2015 Investor Presentation NYSE: MTDR Exhibit 99.1
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 integrate the assets, employees and operations of Harvey E. Yates Company following its merger with one of Matador’s wholly-owned subsidiaries on February 27, 2015; Matador’s ability to make other 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
2012, 2013 and 2014 capital spending focused primarily on developing Eagle Ford and transitioning to oil February 2012 IPO at $12.00; net cash proceeds of ~$136 million May 2014 Follow-on Offering at $25.00; net cash proceeds of ~$181 million September 2013 Follow-on Offering at $15.25; net cash proceeds of ~$142 million 2012 2014 Matador has grown almost entirely through the drill bit, with a focus on unconventional reservoir plays Assembling Permian acreage position; begin delineation drilling program 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; evolved into Matador Petroleum Corporation Sold Matador Petroleum Corporation 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. (2) Excluding customary purchase price adjustments. Matador Today 2003 2008 2003 Founded by Joe Foran with $6 million, a proven management and technical team and board of directors 2008 Sold Haynesville rights in ~9,000 net acres to CHK for ~$180 million; retained 25% participation interest, carried working interest and overriding royalty interest 2010-2011 Redeployed capital into the Eagle Ford early in the play, acquiring over 30,000 net acres for ~$100 million 2012, 2013 and 2014 capital spending focused primarily on developing Eagle Ford and transitioning to oil February 2012 IPO at $12.00; net cash proceeds of ~$136 million May 2014 Follow-on Offering at $25.00; net cash proceeds of ~$181 million September 2013 Follow-on Offering at $15.25; net cash proceeds of ~$142 million 2010 2012 2014 Matador has grown almost entirely through the drill bit, with focus on unconventional reservoir plays, initially in Cotton Valley and Haynesville Assembling Permian acreage position; begin delineation drilling program 2015 February 2015 HEYCO Combination 2015 February 2015 HEYCO Combination 2013 April 2015 Inaugural High-Yield Offering of $400 million; Follow-on Offering at $26.96; net cash proceeds of ~$187 million 2003 2008 2009 2010 2011 2012 2003 Founded by Joe Foran with $6 million, a proven management and technical team and board of directors 2008 Sold Haynesville rights in ~9,000 net acres to CHK for ~$180 million; retained 25% participation interest, carried working interest and overriding royalty interest 2010-2011 Redeployed capital into the Eagle Ford early in the play, acquiring over 30,000 net acres for ~$100 million Pre – IPO Post – IPO October 2015 Sale of certain Loving County midstream assets for ~$143 million(2)
5 Company Overview Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 85.6 million common shares Share Price(1) $26.70/share Market Capitalization(1) $2.3 billion Actual Previous Updated % YoY 2014 2015 Guidance(2) 2015 Guidance(3) Change Capital Spending $610 million $425 million $425 million - 30% Total Oil Production 3.3 million Bbl 4.4 to 4.5 million Bbl 4.4 to 4.5 million Bbl + 34% Total Natural Gas Production 15.3 Bcf 26.0 to 27.0 Bcf 27.0 to 28.0 Bcf + 80% Oil and Natural Gas Revenues $367.7 million $290 to $300 million $290 to $300 million(4) - 20% Adjusted EBITDA(5) $262.9 million $220 to $230 million $220 to $230 million(4) - 14% (1) Market capitalization based on closing share price as of November 9, 2015 and shares outstanding as reported in the Form 10-Q for the quarter ended September 30, 2015. (2) The Company raised its full-year 2015 guidance estimates on August 4, 2015. (3) The Company raised its 2015 natural gas production guidance from 26.0 to 27.0 Bcf to 27.0 to 28.0 Bcf on November 4, 2015. (4) Estimated 2015 oil and natural gas revenues and Adjusted EBITDA based upon the midpoint of 2015 guidance range as revised on August 4, 2015. Prices for oil and natural gas used in these estimates were $50.00/Bbl (WTI oil price of $55.00/Bbl less $5.00/Bbl differentials and transportation costs) and $3.00/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period October through December 2015 and weighted average realized prices for the period January through September 2015 of $47.36/Bbl and $2.83/Mcf. (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.
Matador Resources Company – Operations Overview Market Capitalization(1) $2.3 billion Avg. Daily Production – Q3 2015(2) 26,137 BOE/d Oil (% total) 12,617 Bbl/d (48%) Natural Gas (% total) 81.1 MMcf/d (52%) Proved Reserves @ 9/30/2015 87.1 million BOE % Proved Developed 39% % Oil 49% 2015E CapEx(3) $425 million Gross Acreage(4) 225,997 acres Net Acreage(4) 144,945 acres Engineered Drilling Locations(5) 2,265 gross / 1,362 net Eagle Ford 278 gross / 240 net Permian 1,445 gross / 960 net Haynesville/Cotton Valley 542 gross / 162 net *Note: Represents increase as compared to each respective figure at or for the three months ended September 30, 2014. **Note: Represents increase as compared to each respective figure at December 31, 2013. (1) Market capitalization based on closing share price as of November 9, 2015 and shares outstanding as reported in the Form 10-Q for the quarter ended September 30, 2015. (2) Average daily production for the three months ended September 30, 2015. (3) 2015 estimated capital expenditures for operations only. Revised upwards from $350 million on August 4, 2015; does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. (4) Presented as of November 4, 2015. Excludes 75,674 gross (35,732 net) acres still under lease in Wyoming, Utah and Idaho. (5) Identified and engineered locations for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Locations identified as of December 31, 2014, but including no locations at Twin Lakes and no locations associated with the HEYCO transaction or two associated joint ventures. 6 +440%** +139%** +43%* +62%* 33% of total production Almost no oil 63% of total natural gas 38% of total production 56% of total oil 22% of total natural gas 29% of total production 44% of total oil 15% of total natural gas
Matador’s Execution History – “Doing What We Say” Oil Production 414 Bbl/d of oil 6% oil 4,916 Bbl/d of oil 46% oil 12,617 Bbl/d of oil 48% oil Proved Reserves 27 MMBOE 1.1 MMBbl of oil 4% oil 39 MMBOE 12.1 MMBbl of oil 31% oil 87 MMBOE 42.5 MMBbl of oil 49% oil PV-10(2) and Asset Coverage $155.2 million 24% of PV-10 in Eagle Ford PV-10 / debt of 2.0x $522.3 million 90% of PV-10 in Eagle Ford PV-10 / debt of 2.1x $692.7 million 88% of PV-10 in Eagle Ford / Permian PV-10 / debt of 1.7x LTM Adjusted EBITDA(3) $50 million(4) $148 million $245 million Leverage(5) 1.5x(4) 1.6x 1.0x(11) after midstream sale Acreage ~7,500 net Permian acres ~32,900 net Permian acres ~90,700 net Permian acres(12) Enterprise Value (“EV”)(6) $0.65 billion(7) $1.2 billion(9) $2.7 billion(13) 12x growth in oil production 11x growth in oil reserves ~200% growth Doubled EV Over 4x growth in Permian acres At IPO(1) September 2013 Follow-On(8) 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) At or for the twelve months ended December 31, 2011. (5) Calculated as debt divided by LTM Adjusted EBITDA. (6) Enterprise value equals market capitalization plus long-term debt. (7) As of February 7, 2012 at time of IPO. (8) Unless otherwise noted, at or for the three months ended June 30, 2013. (9) As of September 1, 2013. (10) Unless otherwise noted, at or for the three months ended September 30, 2015. (11) Net debt at October 1, 2015 and LTM Adjusted EBITDA at September 30, 2015. (12) As of November 4, 2015. (13) Market capitalization based on closing share price as of November 9, 2015 and shares outstanding as reported in the Form 10-Q for the quarter ended September 30, 2015. 157% growth in oil production 3.5x growth in oil reserves 66% growth 125% growth 2.8x growth in Permian acres 33% growth despite lower prices September 30, 2015(10) Matador continues to execute on its core strategy of acquiring great assets, developing a highly professional, committed workforce, maintaining a strong balance sheet and generating significant shareholder returns 7 Remained conservative Improved
September 30, June 30, September 30, September 30, September 30, 2015 2015 2014 2015 2014 Net Production Volumes:(1) Oil production (MBbl) 1,161 1,260 839 3,429 2,302 Natural gas production (Bcf) 7.5 7.0 3.8 21.1 9.9 Total oil equivalent production (MBOE) 2,405 2,421 1,481 6,941 3,956 Average daily oil equivalent production (BOE/d) 26,137 26,601 16,096 25,427 14,490 Revenues and Average Sales Prices: Oil and natural gas revenues (in millions) 71.8$ 87.8$ 96.6$ 222.1$ 274.6$ Average realized oil price, $/Bbl 43.21$ 54.37$ 92.39$ 47.36$ 95.45$ Average realized natural gas price, $/Mcf 2.90$ 2.78$ 4.95$ 2.83$ 5.53$ Total realized revenues, with realized derivatives (in millions) 91.7$ 101.6$ 95.9$ 274.3$ 269.1$ Average realized oil price, with realized derivatives, $/Bbl 57.90$ 62.72$ 91.42$ 59.61$ 93.48$ Average realized natural gas price, with realized derivatives, $/Mcf 3.28$ 3.24$ 4.99$ 3.31$ 5.44$ Operating Expenses (per BOE): Production taxes and marketing 3.86$ 4.24$ 5.82$ 3.83$ 6.00$ Lease operating 6.20$ 6.18$ 9.25$ 6.18$ 8.78$ Depletion, depreciation and amortization 18.81$ 21.39$ 23.73$ 20.67$ 23.00$ General and administrative(2) 5.05$ 5.35$ 5.47$ 5.55$ 5.92$ Total operating expenses(3) 33.92$ 37.16$ 44.27$ 36.23$ 43.70$ Cash operating expenses(4) 14.38$ 14.50$ 19.84$ 14.21$ 19.52$ Earnings (loss) per diluted common share:(5) Earnings (loss) per diluted common share (5) (2.86)$ (1.89)$ 0.40$ (5.58)$ 0.92$ Adjusted earnings per diluted share (non-GAAP) (5)(6) 0.03$ 0.05$ N/A(7) 0.10$ N/A(7) Adjusted EBITDA(8) (in millions) 58.0$ 66.7$ 66.8$ 174.9$ 192.6$ Net Debt / LTM Adjusted EBITDA(8) 1.0(9) 1.4 1.0 1.0(9) 1.0 Three Months Ended Nine Months Ended Selected Operating and Financial Results 8 (1) Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. (2) Includes approximately $0.73, $1.16, $0.70, $0.99 and $1.18 per BOE of non-cash, stock based compensation expense in the third quarter of 2015, the second quarter of 2015, the third quarter of 2015, the nine months ended September 30, 2015 and the nine months ended September 30, 2014. (3) Total does not include the impact of full-cost ceiling impairments or immaterial accretion expenses. (4) Cash operating expenses per BOE is a non-GAAP financial measure. For a definition of cash operating expenses per BOE and a reconciliation of cash operating expenses per BOE (non-GAAP) to operating expenses per BOE (GAAP), please Appendix. (5) Attributable to Matador Resources Company shareholders. (6) Adjusted earnings (loss) per common share is a non-GAAP financial measure. For a reconciliation of adjusted net income (non-GAAP) and adjusted earnings (loss) per common share (non-GAAP) to net income (GAAP) and earnings (loss) per common share (GAAP), see Appendix. (7) Not calculated for three months and nine months ended September 30, 2014. (8) 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. (9) Pro forma at September 30, 2015 for midstream sale on October 1, 2015.
9 December 31, 2013 Total proved reserves = 51.7 million BOE PV-10(1): $655.2 million $93.42 oil / $3.67 natural gas Total proved reserves = 68.7 million BOE PV-10(1): $1,043.4 million $91.48 oil / $4.35 natural gas December 31, 2014 Total proved reserves = 87.1 million BOE PV-10(1): $692.7 million $55.73 oil / $3.06 natural gas September 30, 2015 Oil and Natural Gas Proved Reserves and PV-10(1) by Area (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. Eagle Ford $540.4 million, 82% Haynesville/CV $82.9 million, 13% Permian $31.9 million, 5% Eagle Ford $282.8 million, 41% Haynesville/CV $82.1 million, 12% Permian $327.8 million, 47% Eagle Ford $603.8 million, 58% Haynesville/CV $193.4 million, 18% Permian $246.2 million, 24%
Matador’s Continued Growth in Production and Permian Position Average Daily Oil Production (Bbl/d) Average Daily Natural Gas Production (MMcf/d) Average Daily Total Production (MBOE/d) Total Permian Acreage (Net Acres) Growth since IPO Growth since IPO Growth since IPO Growth since IPO 3.9 7.0 9.0 11.7 16.1 23.5 26.6 26.1 2010 2011 2012 2013 2014 Q1 2015 Q2 2015 Q3 2015 91 422 3,317 5,843 9,095 11,206 13,847 12,617 2010 2011 2012 2013 2014 Q1 2015 Q2 2015 Q3 2015 23.0 39.8 34.1 35.4 41.9 73.8 76.5 81.1 2010 1 2 2013 2014 Q1 2015 Q2 2015 Q3 2015 6,700 7,600 44,800 66,100 90,700 2011 2 2013 2014 Today (1) (1) (1) (1) (2) (1) At December 31 of each respective year. (2) At November 4, 2015. 10
0.0x 0.0x 0.1x 1.5x 0.2x 0.7x 1.1x 1.3x 1.5x 1.6x 0.8x 1.0x 1.2x 0.6x 1.0x 1.3x 1.6x 1.4x 1.0x 2008 2009 2010 2011 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 Net Debt / LTM EBITDA $76 $240 $256 $416 $243 In itial P u b lic O ff e rin g Preserved and enhanced liquidity through April 2015 equity and Senior Notes offerings and sale of Loving County midstream assets for ~$143 million(1) in October 2015 – substantial liquidity to execute planned drilling program through 2016 Strong financial position with Net Debt/LTM Adjusted EBITDA(2)(3) of 1.0x after close of midstream sale Target leverage at less than 2.0x Adjusted EBITDA(2), though profile typically more conservative We Remain Committed to Keeping our Balance Sheet Strong 11 (1) Excluding customary purchase price adjustments. (2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. (3) Pro forma at September 30, 2015 for midstream sale on October 1, 2015. E q u it y Rais e E q u it y Rais e No te s O ff e rin g + E q u it y Rais e (2) Net Debt ($ millions) (3) M ids tr e a m S a le
12 Previous Oil Price Declines Have Created Opportunities for Matador(1) Comparison of Major Oil Corrections and Major Matador Turning Points Since 1980 Date Event % Change in Oil Price Length of Oil Price Decline (in trading days) % Increase in Oil Price – 1-Year Post-Low 1986 Saudi Market Share War -67.2% 82 79.0% A number of Mesa’s top technical staff join Matador I 1988 Oil Glut -43.7% 295 58.4% Matador I buys key waterflood properties and New Mexico natural gas acreage 1991 Global Recession / End of Gulf War -57.2% 90 5.4% First interests in Amaker-Tippett acquired; becomes Matador I’s largest field 1998 Asian Crisis -59.6% 484 134.5% Unocal exchanges NM properties for Matador I’s stock 2001 Global Recession -53.1% 290 46.2% Matador I shifts to unconventionals (Marlan Downey joins Board) 2008 Great Recession -78.4% 119 134.8% Matador II builds Eagle Ford position and drills first Haynesville wells Average -59.9% 227 76.4% 2014- 2015 Current Dip(2) -59.8% ~300 ? -MTDR and HEYCO join forces -MTDR sells midstream assets to EnLink (1) Includes Matador Resources Company, Foran Oil and Matador Petroleum Corporation and other predecessor entities. (2) Length of oil price decline in trading days using high of $107.26 on June 20, 2014 and low of $38.24 on August 24, 2015.
Keys to Matador’s Success Over Last 35 Years(1) 13 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 processes 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 – Permian, Eagle Ford 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 more efficient operations, improved financial results and increased shareholder value Gaining momentum as a successful publicly-held company Execution Increase total BOE production by ~54%, with oil production expected to increase to ~4.45 million barrels and natural gas production expected to increase to ~27.5 Bcf in 2015 Maintain quality acreage positions in the Permian, Eagle Ford and Haynesville – successfully integrate HEYCO acreage in Permian Reduce drilling and completion times and costs – improve operational efficiencies Maintain strong financial position and technical and administrative teams (1) Includes Matador Resources Company and its predecessor entities.
Permian (Delaware) Basin Southeast New Mexico and West Texas
15 Delaware Basin – A “World Class” Hydrocarbon System 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 cumulative production >1.0 million Bbl each 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.
Spectrum of Unconventional Play Types In general there is no consensus on the what an “unconventional” reservoir is… At Matador, we think of an unconventional reservoir as a spectrum of play types. The distribution and quality of these play types are both spatially and temporally variable. Play types from Bishop 2014. Block diagram modified from Hanford (1981). 16
Determining “Good, Better, Best” important as potential exceeds inter-formational stacked pay 2015 program will expand on intra-formational stacked pay tests performed in each asset area Wolf Area Type Log – Wolfcamp X/Y X Test Y Test 80 acre 100’ Rustler Breaks Type Log Wolfcamp B 350’ X Test Y Test 160 acre Ranger Type Log 2nd Bone Spring DPHI > 8% LLD > 10 ohm INTRA-Formational Stacked Pays Decoupled – Coupled – Micro-coupled Bone Spring Lime Upper Avalon Shale Lower Avalon Shale First Bone Spring Sand Second Bone Spring Carbonate Third Bone Spring Carbonate Wolfcamp “D” / Penn Strawn Wolfcamp “C” Third Bone Spring Sand INTER-Formational Stacked Pay Second Bone Spring Sand Wolfcamp “A” Wolfcamp “B” 100’ Wolfcamp “X-Y” 17 Gamma Ray Resistivity 4,000 feet of Hydrocarbon Column Creates Opportunity Horizon tested by MTDR
Permian Basin Acreage Position and Selective Well Results Note: All acreage at November 4, 2015. Some tracts not shown on map. (1) As of early November 2015 unless otherwise noted. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. 18 Selected well performance(1) 1 2 3 4 5 6 7 8 9 10 11 L E A LOVING WARD 2 4 1 3 6 5 7 8 # Matador Resources Acreage Location of Matador Well 9 TWIN LAKES ~42,900 gross / ~30,000 net acres Jackson Trust RANGER ~32,300 gross / ~19,700 net acres ARROWHEAD ~47,400 gross / ~17,100 net acres E D D Y RUSTLER BREAKS ~20,700 gross / ~13,500 net acres WOLF / LOVING AREA ~11,500 gross / ~7,300 net acres Permian Basin Total Gross Acres ~158,700 acres Net Acres ~90,700 acres 10 11 Cumulative Production Recent Production Oil Eq. % Oil Natural Gas EUR(2) Well Months (BOE) Oil (Bbl/d) (Mcf/d) (MBOE) Ranger State 33-20S-35E RN #121H (2nd Bone Spring) 23.5 228,000 91 170 130 650 Dorothy White #1H (Wolfcamp "A"/"X") 22.0 453,000 68 310 690 1,050 Rustler Breaks 12-24S-27E RB #224H (Wolfcamp "B") 18.0 221,000 41 90 920 700 Norton Schaub 84-TTT-B33 WF #201H (Wolfcamp "A"/"X") 16.0 315,000 68 480 1400 800 Pickard State 20-18S-34E RN #121H (2nd Bone Spring) 15.5 179,000 90 400 620 600 Johnson 44-02S-B53 #204H (Wolfcamp "A"/"X") 13.5 247,000 65 330 740 900 Norton Schaub 84-TTT-B33 WF #2010H (Wolfcamp "A") 11.0 119,000 72 150 390 450 Guitar 10-24S-28E RB #202H (Wolfcamp "A"/"X") 8.0 137,000 79 340 680 700 Tiger 14-24S-28E RB #224H (Wolfcamp "B") 7.5 191,000 44 270 2100 1,000 Tiger 14-24S-28E RB #204H (Wolfcamp "A/X-Y") 4.5 105,000 80 600 560 700 Cimarron 16-19S-34E RN #134H (3rd Bone Spring) 6.5 103,000 94 330 100 450
Permian Basin Acreage Position and Recent Test Results Note: All acreage at November 4, 2015. Some tracts not shown on map. 19 L E A LOVING WARD Matador Resources Acreage TWIN LAKES ~42,900 gross / ~30,000 net acres WOLF / LOVING AREA ~11,500 gross / ~7,300 net acres Jackson Trust RANGER ~32,300 gross / ~19,700 net acres ARROWHEAD ~47,400 gross / ~17,100 net acres E D D Y RUSTLER BREAKS ~20,700 gross / ~13,500 net acres Tiger/Guitar Wells Jackson Trust 3-well batch – Brushy, Avalon, 2nd BS In completion phase Hibiscus 08-19S-35E #124H – 2nd BS Waiting on completion Conine 03-20S-35E RN #121H – 2nd BS Waiting on completion Johnson 44-02S-B53 WF #202H & #206H – Wolfcamp A/X & A/Y Recently drilled Currently being drilled Significant non-op wells CTA State Com #3H & #4H – 2nd BS Concho (MRC: 15% WI) Tested = 992 & 1,063 BOE/d (~80% oil) White City #5H & #6H – 2nd BS Chevron (MRC: 12.5% WI) Tested = 1,100 – 1,200 BOE/d (~77% oil) Iggles 21-16 State Com #1H – 2nd BS Concho (MRC: 33% WI) Tested = 1,200 – 1,300 BOE/d (90% oil) Gobbler 5 B2PM #1H – 2nd BS Mewbourne (MRC: 6% WI) Tested = 2,300 BOE/d (80% oil) Scott Walker State 36-22S-27E RB #204H – Wolfcamp A/X-Y – IP = 504 BOE/d (70% oil) @ 1,100 psi on 32/64” choke Janie Conner 13-24S-28E RB #124H & #224H – 2nd BS, Wolfcamp B In completion phase CTA State Com #5H & #6H – 2nd BS Concho (MRC: 15% WI) Tested = 640 & 1,130 BOE/d (~90% oil) Billy Burt 90-TTT-B33 WF #201H & #204H – Wolfcamp A/Y Testing – 1,100 BOE/d (68% oil) & 800 BOE/d (67% oil) @ 2,500 psi on 26/64” choke Barnett 90-TTT-B01 WF #202H & #206H – Wolfcamp A/X & A/Y #202H (A/X) IP – 1,047 BOE/d (54% oil) @ 3,200 psi on 26/64” choke #206H (A/Y) IP – 1,127 BOE/d (55% oil) @ 3,400 psi on 24/64” choke Twin Lakes vertical pilot hole Wolfcamp A/X-Y well Pickard State 20-18S-34E RN#121H
Matador is a Significant Delaware Basin Player MTDR MTDR MTDR Matador’s 90,700 net acres place it among the largest operators in the Delaware Basin − Matador holds largest Delaware Basin acreage position among small and mid-cap publicly traded energy companies(1) − Matador is the second largest operator in terms of the ratio of Delaware Basin acreage to enterprise value or market capitalization among all public traded energy companies(1) Key Operators in the Delaware Basin(2): − Oxy 1,500,000 net acres − Chevron 1,000,000 net acres − Shell 618,000 net acres − Concho 425,000 net acres − Cimarex 400,000 net acres − EOG 307,000 net acres − Anadarko 255,000 net acres − Apache 230,000 net acres − Conoco 150,000 net acres − Energen 113,000 net acres − Matador 158,700 gross / 90,700 net acres (1) Based on an independent market analysis prepared by BMO Capital Markets in January 2015. Small and mid-cap publicly traded energy companies defined as those companies with an enterprise value between $500 million and $3.5 billion. Companies below $100 million in market capitalization were excluded in determining the ratio of Delaware Basin acreage to market capitalization. Matador acreage at November 4, 2015. (2) Goldman Sachs Equity Research report dated April 1, 2015 (Singer). 20 MTDR MTDR
Task at Hand – Understanding the Opportunities 3rd Bone Spring Lower Avalon 800’ Objective: We want to drill and complete the best wells at the lowest cost. Challenge: How do we identify the best targets within multiple prospective intervals across a geologically complex basin? Matador’s geoscience staff is committed to bringing the best targets forward! Most current unconventional plays target one or two zones across a trend area. The Permian Basin has roughly two dozen unique targets within the Midland and Delaware sub-basins. All logs plotted at same scale Delaware Basin Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D Strawn Atoka Barnett Miss. Lime Woodford Upper Avalon 1st Bone Spring 2nd Bone Spring 21 Brushy Cyn. O verp ressur e Tested by MTDR Tested by others Images source: Pioneer Natural Resources Co. (NYSE: PXD)
Wolf Inventory – Multi-Pay Development Potential ~660’ Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp X/Y Wolfcamp A 4 66 Eval. Ongoing 34 66 66 66 302 Full Development Location Gross Wells Development Well D&C(1) CapEx EUR(2) (MBOE) Bone Spring $5.5 – $6.5 million 450 – 600 Wolfcamp $6.5 – $8.0 million 650 – 1,100 1 mile MRC Spacing Test Completed Full Development Spacing Pattern (Cross-Section View) 22 (1) Drilling and completion. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. Matador Well Location Wolfcamp X/Y Wolfcamp A 2nd Bone Spring Matador Acreage
23 Wolf Area Wolfcamp “A”/“X” Wells Performing Above Expectations 500 MBOE Type Curve 1,000 MBOE Type Curve Note: Production as of early November 2015. 700 MBOE Type Curve 10 100 1,000 10,000 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 Production R ate, BO E/ d Time, Days Dorothy White #1H Norton Schaub #201H Norton Schaub #2010H Billy Burt #202H Billy Burt #203H 500 MBOE Type Curve 700 MBOE Type Curve 1,000 MBOE Type Curve Wolfcamp "A"/"X" horizontals in Loving County, Texas Dorothy White #1H has produced 453,000 BOE (68% oil) in 22 months - "X" Norton Schaub 84-TTT-B33 WF #201H has produced 315,000 BOE (68% oil) in 16 months - "X" Norton Schaub 84-TTT-B33 WF #2010H has produced 118,000 BOE (73% oil) in 11 months - "A" Billy Burt 90-TTT-B33 WF #202H has produced 95,000 BOE (74% oil) in 6.5 months - "X" Billy Burt 90-TTT-B33 WF #203H has produced 99,000 BOE (74% oil) in 6.5 months - "X" Well put on compressor Well put on ESP Shut in for Offset Frac
Rustler Breaks Inventory – Multi-Pay Development Potential Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring X/Y Wolfcamp B ~8 0 0 ’ 65 73 73 77 69 77 65 499 Full Development Location Gross Wells Development Well D&C(1) CapEx EUR(2) (MBOE) Bone Spring $4.0 – $5.0 million 300 – 600 Wolfcamp $5.5 – $7.5 million 500 – 1,000 For clarity only 160 gross ac. well slots shown 1 mile MRC Horizontal Drilled Full Development Spacing Pattern (Cross-Section View) 24 (1) Drilling and completion. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. Matador Well Location Wolfcamp X/Y Wolfcamp B 2nd Bone Spring Matador Acreage
Historically oil productive interval. Matador’s First Three-Zone Stacked Lateral Test at Rustler Breaks Bone Spring Lime Upper Avalon Shale Lower Avalon Shale First Bone Spring Sand Second Bone Spring Carbonate Third Bone Spring Carbonate Wolfcamp / Pennsylvanian Strawn Wolfcamp “C” Third Bone Spring Sand Gamma Ray INTER-Formational Stacked Pay Second Bone Spring Sand Wolfcamp “A” Wolfcamp “B” Wolfcamp “X-Y” Tiger 14-24S-28E RB #224H IP: 1,525 BOE/d (43% oil) TVD: 10,500 feet Lateral Length: 4,376 feet Tiger 14-24S-28E RB #204H IP: 1,405 BOE/d (75% oil) TVD: 9,600 feet Lateral Length: 4,656 feet Tiger 14-24S-28E RB #124H IP: 800 BOE/d (81% oil) TVD: 8,200 feet Lateral Length: 4,364 feet Multi-Well Pad Resistivity 25 4th zone tested in Upper Wolfcamp B in Rustler Breaks 12- 24S-27E RB #224H
26 Rustler Breaks Wolfcamp “B” Wells Performing Above Expectations 500 MBOE Type Curve 600 MBOE Type Curve 700 MBOE Type Curve 1,000 MBOE Type Curve Note: Production as of early November 2015. 10 100 1,000 10,000 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560 Production R ate, BO E/ d Time, Days Rustler Breaks #224H Tiger #224H 500 MBOE Type Curve 600 MBOE Type Curve 700 MBOE Type Curve 1000 MBOE Type Curve Wolfcamp "B" horizontals in Eddy County, New Mexico Rustler Breaks 12-24S-27E #224H has produced 221,000 BOE (41% oil) in 18 months Tiger 14-24S-28E RB #224 has produced 191,000 BOE (44% oil) in 7.5 months Well shut in for offset frac
27 Rustler Breaks Wolfcamp “A”/“X-Y” Wells, Off to Strong Start 700 MBOE Type Curve 500 MBOE Type Curve Note: Production as of early November 2015. 10 100 1,000 10,000 0 20 40 60 80 100 120 140 160 180 200 220 240 Production R ate, BO E/ d Time, Days Guitar #202H Tiger #204H 500 MBOE Type Curve 700 MBOE Type Curve Wolfcamp "A"/"X-Y" horizontals in Eddy County, New Mexico Guitar 10-24S-28E RB #202H has produced 137,000 BOE (79% oil) in 8 months - "X-Y" Tiger 14-24S-28E RB #204H has produced 105,000 BOE (80%) in 4.5 months - "X-Y" Well shut in for offset frac
Ranger Inventory – Multi-Well Development Potential ~1,320’ 1st Bone Spring 2nd Bone Spring 3rd Bone Spring X/Y Wolfcamp A-D ~7 5 0 ’ 43 55 30 70 6 204 1 mile MRC Horizontal Drilled Full Development Location Full Development Spacing Pattern (Cross-Section View) Gross Wells Development Well D&C(1) CapEx EUR(2) (MBOE) Bone Spring $5.5 – $6.5 million 400 – 600 Wolfcamp $7 – $9 million 200 – 800* * Based on Volumetrics and 4-8% Recovery Factor 28 (1) Drilling and completion. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. For clarity only 160 gross ac. well slots shown Matador Well Location 2nd Bone Spring 3rd Bone Spring Wolfcamp D Matador Acreage Location estimates do not include HEYCO acreage.
29 Ranger Area Second Bone Spring Wells Performing Above Expectations 400 MBOE Type Curve 600 MBOE Type Curve Note: Production as of early November 2015. 10 100 1,000 10,000 0 100 200 300 400 500 600 700 Production R ate, BO E/ d Time, Days Ranger 33 #121H Pickard #121H 400 MBOE Type Curve 600 MBOE Type Curve 2nd Bone Spring horizontals in Ranger Area - Lea County, New Mexico Ranger State 33-20S-35E RN #121H has produced 228,000 BOE (91% oil) in 23.5 months Pickard State 20-18S-34E RN #121H has produced 179,000 BOE (90% oil) in 15.5 months Well shut in for offset fracs
30 Matador Acreage Most HEYCO acreage is Federal acreage Most held by production by older, vertical wells Typically 87.5% NRI on most Federal acreage Contiguous acreage aids in full development and minimizes costs for pads, facilities and LOE Matador Operated Horizontal Plans (Q1 2016) SST State 06-19S-29E AH #123H & #124H • Second Bone Spring laterals • Offset to Mewbourne Gobbler wells (non-op) Non-Operated Well Activity CTA State Com #3H: Tested 992 BOE/d (84% Oil); 143,000 BOE in first 7 months(1) CTA State Com #4H: Tested 1,063 (78% Oil); 126,000 BOE in first 6 months(1) CTA State Com #5H: Tested 640 BOE/d (92% Oil) CTA State Com #6H: Tested 1,130 BOE/d (88% Oil) Gobbler 5 B2PM #1H: Tested 2,300 BOE/d (80% Oil); 140,000 BOE in first 4 months(1) Mewbourne, Concho, Cimarex wells provide operational data and reference points across Matador acreage Arrowhead – HEYCO Acreage Provides Unique Opportunities (1) As of early November 2015. 2nd Bone Spring Non-Op Activity Matador Well Plans 2nd Bone Spring CTA State Com 3H - Tested 992 BOE/d (84% Oil) CTA State Com 4H - Tested 1,063 BOE/d (78% Oil) SST State Gobbler 5 B2PM 1H - Tested 2,300 BOE/d (80% Oil) CTA State Com 5H - Tested 640 BOE/d (92% Oil) CTA State Com 6H - Tested 1,130 BOE/d (88% Oil)
Future Bit Technology – The Evolution of the PDC bit 31 Matador continues to be at the forefront of new bit technology Smith Bits latest technology StingBlade design StingBlade design features Alternating Stinger/PDC cutters Stinger cutters cut troughs in the formation with the PDC cutters coming behind and removing the ridges Stinger cutters do the hard work, PDC cutters keep the speed Ultimate combination of speed, durability and steerability
7,500 psi Pressure Rating Estimated reduction in drilling time of 20 to 25% in the lateral on Wolfcamp wells Telescoping Flex-joint Estimated reduction in drilling time of 12 to 18 hours per well Integrated Mud-Gas Separator Estimated savings of 50% compared to rental separator BOP Wrangler Estimated reduction in drilling time of 12 hours per well Walking System & V-door turned 90° Allows for batch-drilling and simultaneous operations Reduced Downtime 32 New Rig Technology for Horizontal Drilling – Saving Time and Money!
Latest Technology: Simultaneous Operations (Sim-Ops) Capable Rigs 33 Conventional Drilling Configuration Sim-Ops Capable with V-door turned 90° Space available for frac operations while simultaneously drilling on the same pad Drilling rig must leave location prior to frac operations
43 32 35 26 22 15 0 5 10 15 20 25 30 35 40 45 50 Loving County Wolfcamp Eddy County Wolfcamp Dr illin g Da y s Historical Well 2015 Planned Well Recent Well Improving Wolfcamp Drilling Times Significantly in 2015 34 *Historical days averaged from 2014 wells. *Recent days from Billy Burt 90-TTT-B33 WF #204H & Tiger 14-24S-28E RB #204H.
Completion Overall cost reduced by 50% since first well Cost of pumping and drill out has driven down costs Drill out days down from using micro trips Lowers the overall time per plug Cost Reduction Metrics (Drilling and Completion) 35 Drilling Overall cost reduced by 43% since first well Days down from 43 to 22 in the Wolfcamp Cost improvements that can stay with us moving forward Matador Wells Matador Wells Drilling Costs per Foot – Loving County Completion Cost per Foot – Loving County
36 7,500 Bbl 9,000 Bbl 8,400 Bbl 600 Mlbs 420 Mlbs 500 Mlbs 375 ft. 300 ft. 50 ft. 75 ft. 210 ft. 35 ft. Gen 1 Gen 2 2,000 lbs/ft 1,333 lbs/ft 40 Bbl/ft 20 Bbl/ft 50’ cluster spacing 75’ cluster spacing Gen 1 Gen 2 2,000 lbs/ft 2,000 lbs/ft 40 Bbl/ft 30 Bbl/ft 35’ cluster spacing 50’ cluster spacing Bone Spring Upper Wolfcamp Lower Wolfcamp C o u p le d M ic ro -C o u p le d S o u rce R o c k Gen 1 Gen 2 2,000 lbs/ft 40 Bbl/ft 35’ cluster spacing TESTING SOON Evolution of Permian Basin Frac Design – Reservoir Specific
Optimizing Artificial Lift Operations Across the Basin Starting to Use ESP’s Accelerated production while maintaining a controlled drawdown of bottomhole pressure BHP gauges aid in analyzing 3rd Bone Spring reservoir properties Quick startup after shut in for maintenance = minimal downtime Once on grid power, will be very quiet operation in Chicken/Lizard environment Able to unload offset frac water even more effectively than gas lift 37 Optimizing Gas Lift Operations All 2nd Bone Spring wells on gas lift Accelerates production while reducing LOE Lower maintenance costs than rod pump Helps wells recover faster from offset fracs Note: Graph and data in gas lift figure above is for illustrative purposes only and not meant to reflect historical or forecasted data from actual well.
0 20 40 60 80 100 120 140 160 180 200 40 45 50 55 60 65 70 75 80 ROR , % Realized Oil Price, $ Rustler Breaks (Wolfcamp A-X/Y) 500 - 700 MBOE 700 MBOE, $6.5 MM D&C 700 MBOE, $5.5 MM D&C 500 MBOE, $6.5 MM D&C 500 MBOE, $5.5 MM D&C uses $3 flat Gas price 0 20 40 60 80 100 120 140 40 45 50 55 60 65 7 75 80 ROR , % Realized Oil Price, $ Rustler Breaks (Wolfcamp B) 700 - 1,000 MBOE 1000 MBOE, $7.5 MM D&C 1000 MBOE, $6.5 MM D&C 700 MBOE, $7.5 MM D&C 700 MBOE, $6.5 MM D&C uses $3 flat Gas pric 20 40 60 80 100 120 140 160 40 45 50 55 60 65 70 75 80 ROR , % Realized Oil Price, $ Dorothy White (Wolfcamp X/Y) 700 - 1,000 MBOE 1,000 MBOE, $8.5 MM D&C 1,000 MBOE, $7 MM D&C 700 MBOE, $8.5 MM D&C 700 MBOE, $7 MM D&C uses $3 flat Gas price 0 50 100 5 200 250 300 350 400 40 45 50 55 60 65 70 75 80 ROR , % Realized Oil Price, $ Ranger 33 (2nd Bone Spring) 400 - 700 MBOE 700 MBOE, $7 MM D&C 700 MBOE, $5.5 MM D&C 400 MBOE, $7 MM D&C 400 MBOE, $5.5 MM D&C uses $3 flat Gas price 38 Permian Basin Economics – Oil Price Sensitivities /Bbl /Bbl /Bbl /Bbl
Significant Delaware Basin Inventory Matador has identified 1,445 gross (960 net) locations(1) This inventory does not yet include the HEYCO properties (mostly Arrowhead prospect area) or Twin Lakes locations Formation Gross Locations Net Locations Delaware Group 109 67 Avalon 160 112 1st Bone Spring 146 96 2nd Bone Spring 210 141 3rd Bone Spring 224 148 Wolfcamp X/Y 152 104 Wolfcamp A 207 134 Wolfcamp B 92 62 Wolfcamp D 145 96 TOTAL 1,445 960 39 (1) Identified and engineered locations for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Locations identified as of December 31, 2014, but including no locations at Twin Lakes and no locations associated with the HEYCO transaction or two associated joint ventures. Note: Inventory only includes wells with >30% working interest. Note: All acreage at November 4, 2015. Some tracts not shown on map. Delaware Basin E d d y L e a Lo v in g W in k le r Ward Texas New Mexico Chaves WOLF / LOVING AREA RANGER TWIN LAKES Potash Mine Matador Resources Acreage RUSTLER BREAKS ARROWHEAD Jackson Trust
Midstream
41 Loving County, Texas Natural gas gathering Water gathering Oil gathering Salt water disposal Commercial facility disposing of 20,000 Bbl/d Saved Matador $4 million to date Cryogenic natural gas processing plant Sold to EnLink for ~$143 million(2) Eddy County, New Mexico Natural gas gathering Water gathering (Planned) Oil gathering (Planned) Salt water disposal (Planned) Cryogenic natural gas processing plant Plans to construct underway Projected inlet capacity of 60MMcf/d Projected on line in Q3 2016 (1) Longwood Gathering and Disposal Systems, LP is an indirect wholly owned subsidiary of Matador Resources Company. (2) Excluding customary purchase price adjustments. Longwood Gathering and Disposal Systems Activities Longwood Gathering and Disposal Systems(1) in Delaware Basin
Summary: Sale of Loving County Gas Gathering & Processing Assets (1) A subsidiary of EnLink Midstream Partners, LP (NYSE: ENLK) (2) Excluding customary purchase price adjustments. (3) Net Debt at October 1, 2015. LTM Adjusted EBITDA at September 30, 2015. 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 sold certain Delaware Basin natural gas gathering and processing assets in Loving County, Texas to EnLink(1) for ~$143 million(2) in cash in October 2015. Assets include a cryogenic natural gas processing plant with ~35 MMcf per day of inlet capacity and six miles of high-pressure gathering pipeline which connects a Matador-owned gathering system to the plant Consideration for Sale $143 million(2) in cash Matador has ability to defer taxes through potential like- kind exchanges Matador enters into 15-year, fixed fee gathering and processing agreement with EnLink(1) Matador retains “priority one” service in exchange for a volume commitment Matador dedicates current Loving County leasehold interests to EnLink – future leasehold acquisitions can be dedicated to EnLink at Matador’s option Matador retains its natural gas gathering system up to a central delivery point and other Loving County midstream assets, including oil and water gathering systems and salt water disposal wells Solidifies Matador’s already strong balance sheet and enhances its ample liquidity to execute its capital plans in 2015 and 2016 and further capitalize on its current opportunities in the Delaware Basin Net Debt/LTM EBITDA(3) of ~1.0x following closing Liquidity of over $500 million including nothing drawn against credit facility as of closing 42 Retained Sold to EnLink - Commercial facility disposing 20,000 Bbl/d - Saved Matador $4 million to date
Eagle Ford “Oil Bank”
44 Eagle Ford Is Still a Valuable Asset Note: All acreage at November 4, 2015. Some tracts not shown on map. Karnes Uvalde Medina Zavala Frio Dimmit La Salle Webb Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson 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 ACREAGE TOTALS ~40,100 gross / ~29,900 net acres Harris Newman Pena ZLS Carroll Lloyd Hurt Sojourner Sickenius Lyssy Repka Falls City Pawelek Danysh Bishop-Brogan Campbellton-Haverlah 8 5 2 2 Matador Resources Acreage Gross wells turned to sales in 2015 Planned operated D&C operations completed for 2015 17 gross (17.0 net) operated wells turned to sales “Oil Bank” for future development Pursuing acreage additions # EAGLE FORD “EAST” ~3,600 gross / ~2,700 net acres Measured Depth: 17,000’ – 18,000’ Well Costs: $7.5-9.5 million 80-acre spacing EAGLE FORD “CENTRAL” ~4,300 gross / ~4,300 net acres Measured Depth: 15,500’ – 16,500’ Well Costs: $5.5-7.0 million 40-50 acre spacing EAGLE FORD “WEST” ~14,800 gross / ~12,100 net acres Measured Depth: 12,500’ – 14,500’ Well Costs: $4.5-5.0 million 40-50 acre spacing
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 11,750 Bbl 650 Mlbs Gen 6 45 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) Gen 7 650 Mlbs 11,750 Bbl 3 0 0 f t. Evolution of Matador Eagle Ford Frac Design
Haynesville Shale “Gas Bank”
47 2015 Haynesville Non-Op Program Estimated capital expenditures of ~$25 million for non-operated well participation interests ˗ Only ~6% of 2015 estimated capital expenditures ˗ Originally budgeted ~$15 million for 2015 Haynesville & Cotton Valley average daily natural gas production up 137% to 51.3 MMcf/d in Q3 2015 from 21.6 MMcf/d in Q3 2014 31 gross (3.8 net) wells turned to sales throughout Tier 1 Haynesville in 2015 Includes 18 gross (3.5 net) wells turned to sales on Elm Grove properties operated by Chesapeake in 2015 (shown on map at left) Chesapeake placed two additional wells on production in mid-July 2015 ˗ Initial rates of ~12-14 MMcf/d of natural gas with drilling and completion costs of $7 to $7.5 million Currently 12 gross (2.5 net) Chesapeake wells are in progress on our Elm Grove area Haynesville – Chesapeake Elm Grove Operations Note: All acreage at November 4, 2015. Some tracts not shown on map. Currently producing Anticipated future wells Producing Wells Currently drilling or completing Anticipated future wells Currently D&C’ing Date IP (Mcf/d) Choke Size (in) Flowing Pressure (psi) 1/19/2015 15,262 22/64 7,115 1/19/2015 14,173 22/64 6,590 1/19/2015 14,910 22/64 6,875 2/21/2015 14,630 20/64 7,950 3/19/2015 15,506 22/64 6,720 3/19/2015 15,793 22/64 6,495 3/19/2015 14,661 20/64 6,255 7/11/2015 14,003 20/64 7,110 7/11/2015 12,613 20/64 6,260 Reported IP’s for Recent Elm Grove Wells
48 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. D&C cost = drilling and completion cost. 0 50 100 150 200 250 300 350 400 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 R a te o f R e turn (% ) Natural Gas Price ($/Mcf) $6MM D&C Cost $7MM D&C Cost $8MM D&C Cost Matador’s Advantaged Economics NRI’s of 85 to 90% on many properties due to ORRI’s Improved pricing: increase of ~$0.70/MMBtu due to taking natural gas in kind Longer laterals and better completion techniques Economics of Tier 1 Wells (10 Bcf) Haynesville at Elm Grove
2015 Updated Capital Investment Plan
50 2015 Capital Investment Plan At the beginning of 2015, reduced drilling program from 5 rigs to 2 rigs due to lower commodity prices, with primary focus on Permian (Delaware) Basin In late July 2015, took delivery of a third rig in the Delaware Basin Currently operating 3 rigs – all in the Delaware Basin New-build rigs, latest technology and designed for simultaneous operations (Sim-Ops) # o f RIg s 5 4 3 2 2 2 2 3 Nu m be r o f Ope rated R ig s Eagle Ford Rig Permian Rig 3 3 3 3 3 3
0 10 20 30 40 50 60 70 80 2011 2012 2013 2014 2015E Haynesville/CV Eagle Ford Permian 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2011 2012 2013 2014 2015E Eagle Ford Permian 422 3,318 5,843 9,095 12,192 (1) 39.8 34.1 35.4 41.9 75.3 (2) 2015E Oil Production Estimated oil production of 4.4 to 4.5 million barrels − 34% increase from 2014 despite decreased drilling Average daily oil production of 12,200 Bbl/d, up from 9,100 Bbl/d in 2014 − Eagle Ford ~7,650 Bbl/d (63%) − Permian ~4,550 Bbl/d (37%) Quarterly production peaked in Q2; Q4 2015 oil production up slightly as compared to Q4 2014 and Q1 2015 − Permian production increases 3.5-fold in 2015; Eagle Ford production relatively flat 2015E Natural Gas Production Estimated natural gas production of 27 to 28 Bcf − 80% increase from 2014 despite decreased drilling; significant Haynesville impact Average daily natural gas production of 75.3 MMcf/d, up from 41.9 MMcf/d in 2014 − Haynesville ~48.6 MMcf/d (65%) − Eagle Ford ~15.3 MMcf/d (20%) − Permian ~11.4 MMcf/d (15%) 2015 Updated Production Estimates – Oil Equivalent Growth of ~54%(1)(2) 51 Oil Production Growth (Bbl/d) Natural Gas Production Growth (MMcf/d) (1) At midpoint of 2015 total oil production guidance range as revised on August 4, 2015 to 4.4 to 4.5 million Bbl. (2) At midpoint of 2015 total natural gas production guidance range as revised on November 4, 2015 to 27.0 to 28.0 Bcf.
$23.6 $49.9 $115.9 $191.8 $262.9 $225.0 $0.0 $100.0 $200.0 $300.0 2010 2011 2012 2013 2014 2015E $34.0 $67.0 $156.0 $269.0 $367.7 $295.0 $0.0 $100.0 2 . $300.0 $400.0 2010 2011 2012 2013 2014 2015E 2015E Revenues and Adjusted EBITDA(1)(2) Revenues and Adjusted EBITDA(1)(2) growth significantly impacted by lower estimated 2015 realized oil and natural gas prices − 2015E realized oil price of ~$48/Bbl vs ~$87/Bbl realized in 2014 − 2015E realized natural gas price of ~$3.00/Mcf vs ~$5.00/Mcf in 2014 Estimated oil and natural gas revenues of $290 to $300 million − Increased guidance on August 4, 2015 from $270 to $290 million − Decrease of ~20% from $367.7 million in 2014 − Oil and natural gas hedges estimated to contribute $66 million in additional revenues in 2015, as compared to $5 million in 2014 Estimated Adjusted EBITDA(1)(2) of $220 to $230 million − Increased guidance on August 4, 2015 from $200 to $220 million − Decrease of ~14% from $262.9 million in 2014 ~49% oil by volume, ~73% oil by revenue in 2015(2); compared to ~57% oil by volume, ~79% oil by revenue in 2014 2015 Updated Capital Investment Plan (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 2015 oil and natural gas revenues, Adjusted EBITDA and production based upon the midpoint of 2015 guidance range as revised on August 4, 2015 and November 4, 2015. Prices for oil and natural gas used in these estimates were $50.00/Bbl (WTI oil price of $55.00/Bbl less $5.00/Bbl differentials and transportation costs) and $3.00/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period October through December 2015 and weighted average realized prices for the period January through September 2015 of $47.36/Bbl and $2.83/Mcf. 52 Oil and Natural Gas Revenues(2) (millions) Adjusted EBITDA(1)(2) (millions) $76.39 $93.80 $1 1.86 $99.79 $87.37 $47.96 $3.75 $3.62 $ .59 $4.35 $5.08 $2.87 Realized Oil and Natural Gas Prices, $/Bbl and $/Mcf
Appendix
Strong, supportive bank group led by Royal Bank of Canada Borrowing base reaffirmed on October 16, 2015 at $375 million based on June 30, 2015 reserves Maturity of credit facility extended from December 2016 to October 2020 Bank group unanimous in supporting borrowing base affirmation and maturity extension No borrowings outstanding at November 4, 2015 Net Debt/Adjusted EBITDA(1)(2) of 1.0x at October 1, 2015 following close of midstream sale Financial covenants Maximum Total Debt to Adjusted EBITDA(2) Ratio of not more than 4.25:1.00 Under this covenant, Total Debt could be ~$1.1 billion based on LTM Adjusted EBITDA(1) 54 Credit Agreement Status (1) Net Debt at October 1, 2015 and LTM Adjusted EBITDA at Septermber 30, 2015. (2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA an a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. 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
420,000 680,000 810,000 810,000 390,000 390,000 390,000 390,000 $99.75 $87.72 $84.60 $84.60 $74.64 $74.64 $74.64 $74.64 $83.00 $70.38 $67.11 $67.11 $47.46 $47.46 $47.46 $47.46 $0 $50 $100 $150 $200 $250 $300 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Oil Vol ume He dg ed (B bl) 4.65 4.35 4.35 4.05 2.10 2.10 2.10 2.10 $4.65 $3.94 $3.94 $3.99 $3.80 $3.80 $3.80 $3.80 $3.73 $3.26 $3.26 $3.30 $2.75 $2.75 $2.75 $2.75 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.00 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Na tu ra l G as Vol umes He dg ed (B cf) Hedging Profile 2015 Hedges(1) Oil: 0.5 million barrels of oil hedged for remainder of 2015 at weighted average floor and ceiling prices of $67/Bbl and $85/Bbl, respectively – Approximately 80% of oil hedged for remainder of 2015(2) Natural Gas: 2.6 Bcf of natural gas hedged for remainder of 2015 at weighted average floor and ceiling of $3.32/MMBtu and $4.02/MMBtu, respectively – Approximately 65% of natural gas hedged for remainder of 2015(2) Natural Gas Liquids: 0.6 million gallons of natural gas liquids hedged for remainder of 2015 at weighted average price of $1.02/gal Oil and natural gas hedges estimated to add $66 million to projected oil and natural gas revenues in 2015 2016 Hedges Oil: 1.6 million Bbl of oil ($47/Bbl floor and $75/Bbl ceiling) Natural Gas: 8.4 Bcf of natural gas ($2.75/MMBtu floor and $3.80/MMBtu ceiling) 55 2015 Oil Hedges (Costless Collars) 2015 Natural Gas Hedges (Costless Collars) (1) At October 27, 2015. (2) Based upon the midpoint of 2015 guidance range of 4.4 to 4.5 million Bbl of oil as revised upward on August 4, 2015 and 27.0 to 28.0 Bcf of natural gas as revised upward on November 4, 2015. Ceiling Floor Ceiling Floor
North Ranger-Twin Lakes Area Pennsylvanian/Wolfcamp Production Distribution 56 A A’ MATADOR RESOURCES COMPANY PICKARD STATE 20-18-34 #2H Northern Delaware Horizontal Pennsylvanian/Wolfcamp Shale Test Vacuum Field Townsend Field 166 wells 25 million Bbl, 49 Bcf Sanmal & Leamex Fields Corbin Field Kemnitz Field 94 wells 19 million Bbl, 78 Bcf Sanmal and Leamex Fields 40 wells 3.4 million Bbl, 5.4 Bcf Vacuum Field 135 wells 19 million Bbl, 48 Bcf Airstrip Field Corbin Field 77 wells 7.6 million Bbl, 18 Bcf Airstrip Field 14 wells 0.26 million Bbl, 0.17 Bcf Wolfcamp/ Upper Pennsylvanian Production ~74 million Bbl, 190 Bcf ~526 vertical wells ~141,000 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 Bcf = billions of cubic feet of natural gas.
0 1 5 0 G R (C TR ) 2 2 0 0 0 0 L L D 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 GR (C TR ) 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 G R (C TR ) 2 2 0 0 0 0 ILM 2 2 0 0 0 0 L L D 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 GR (C TR ) 2 2 0 0 0 0 ILM 2 2 0 0 0 0 L L D 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 G R (C T R ) 2 2 0 0 0 0 ILM 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 G R (C TR ) 2 2 0 0 0 0 ILM 2 2 0 0 0 0 L L D 0 .3 0 D P H I 0 .3 0 N P H I 95 00 10 00 0 10 50 0 11 00 0 11 50 0 10 00 0 10 50 0 11 00 0 11 50 0 12 00 0 10 00 0 10 50 0 11 00 0 11 50 0 12 00 0 10 50 0 11 00 0 11 50 0 10 50 0 11 00 0 11 50 0 12 00 0 12 50 0 10 50 0 11 00 0 11 50 0 12 00 0 12 50 0 Pennsylvanian/Wolfcamp “Hybrid” Production Target Interval 30025300490000 AVRA OIL COMPANY 30025257790000 ELK OIL COMPANY 30025346940000 Legacy Reserves Oper. Co. 30025397370000 CML EXPLORATION 30025414070000 CML EXPLORATION 30025416140000 MATADOR PRODUCTION A B E N A KI 1 0 S T A T E # 1 S T A T E ` 7 ` # 1 NOR T H E A S T K E M NI T Z # 3 O S C A S T A T E CO M # 1 B E A M S 1 5 S T A T E # 3 P ICK A R D S T A T E # 2 H P IL 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 91,200 BOE – 14.5 mo. IP (24 hr.) from source rock: • 232 Bbl/d, 225 Mcf/d (86% oil) • 1,150 psi surface pressure • 18/64th inch choke A North A’ South Pickard #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 ’ Th ic k Cumulative volumes produced from older vertical wells Flowed oil on test Re g io n a ll y pro d u c ti v e “ Hy brid ” Ta rge t In te rv a l 57 MMBbl = millions of barrels of oil. Bcf = billions of cubic feet of natural gas. MMcf = millions of cubic feet of natural gas.
Board of Directors – Expertise and Stewardship 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 & Development 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 Carlos M. Sepulveda, Jr. Director - Executive 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 Don C. Stephenson Director - Retired Partner, Baker Botts L.L.P. Law and Tax Strategy George M. Yates Director - Chairman & CEO of HEYCO Energy Group, Inc. Oil and Gas Exploration & Development 58
Special Board Advisors Professional Experience Business Expertise Ronney F. Coleman - Retired President – North America, Archer - Former Vice President North America Pumping, BJ Services Co. Oilfield Services Marlan W. Downey - Retired President, ARCO International - Former President, Shell Pecten International - Past President of American Association of Petroleum Geologists Oil and Gas Exploration John R. Gass - VP, Eastern Hemisphere Operations, Nabors Drilling International Limited based in Dubai, UAE - Previously spent 28 years with Parker Drilling Company in various management roles Oil and Gas Drilling David F. Nicklin - Retired Executive Director of Exploration, Matador Resources Company Oil and Gas Exploration Wade I. Massad - Managing Member, Cleveland Capital Management, LLC - Formerly with KeyBanc Capital Markets and RBC Capital Markets Capital Markets Greg L. McMichael - Retired Vice President and Group Leader – Energy Research of A.G. Edwards Capital Markets Dr. James D. Robertson - Retired VP Exploration, Chief Geophysicist, ARCO International Oil and Gas Exploration Michael C. Ryan - Partner, Berens Capital Management - Former Director, Matador Resources Company International Business and Finance W.J. “Jack” Sleeper, Jr. - Retired President, DeGolyer and MacNaughton (Worldwide Petroleum Consultants) Oil and Gas Executive Management Special Board Advisors – Expertise and Stewardship 59
Proven Management Team – Experienced Leadership Management Team Background and Prior Affiliations Industry Experience Matador Experience Joseph Wm. Foran Founder, Chairman and CEO - Matador Petroleum Corporation, Foran Oil Company, James Cleo Thompson Jr. 35 years Since Inception Matthew V. Hairford President, Chair of Operating Committee - Samson, Sonat, Conoco 31 years Since 2004 David E. Lancaster EVP and CFO - Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 36 years Since 2003 Craig N. Adams EVP – Land, Legal & Administration - Baker Botts L.L.P., Thompson & Knight LLP 22 years Since 2012 Van H. Singleton, II EVP – Land - Southern Escrow & Title, VanBrannon & Associates 19 years Since 2007 Bradley M. Robinson VP – Reservoir Engineering and CTO - Schlumberger, S.A. Holditch & Associates, Inc., Marathon 38 years Since Inception Billy E. Goodwin VP – Drilling - Samson, Conoco 31 years Since 2010 G. Gregg Krug VP and Head of Marketing and Midstream - Williams Companies, Samson, Unit Corporation 32 years Since 2005 Matthew D. Spicer VP and General Manager of Midstream - Matador Resources Company 2 years Since 2014 Trent W. Green VP – Production - HEYCO, Bass Enterprises, Schlumberger, S.A. Holditch & Associates, Inc., Amerada Hess 26 years Since 2015 Robert T. Macalik VP and CAO - Pioneer Natural Resources, PricewaterhouseCoopers (PwC) 13 years Since 2015 Kathryn L. Wayne Controller and Treasurer - Matador Petroleum Corporation, Mobil 31 years Since Inception 60
61 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 pro forma, 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 reconciliations without undue hardship because such Adjusted EBITDA numbers 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.
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. 62 (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 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 Interest expense 106 184 171 222 308 1 144 549 1,271 1,609 2,038 768 Total income tax provision (benefit) (6,906) (46) - 1,430 3,064 (3,713) (593) (188) 46 32 2,563 7,056 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 Accretion of asset retirement obligations 39 57 62 51 53 58 59 86 81 80 86 100 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 Stock-based compensation expense 53 128 1,234 991 (363) 191 (51) 363 492 1,032 1,239 1,134 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 (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 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 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) Interest expense, net of non-cash portion 106 184 171 222 308 1 144 549 1,271 1,609 2,038 768 Current income tax (benefit) provision - (45) (1) - - - 188 (188) 46 32 902 (576) Net (income) loss attributable to non-controlling interest in subsidiary - - - - - - - - - - - - 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 (In thousands) 1Q 2014 2Q 2014 3Q 2014 4Q 2014 1Q 2015 2Q 2015 3Q 2015 Unaudited Adjusted EBITDA reconciliation to Net (loss) Income: Net (loss) income $ 16,363 $ 18,226 $ 29,619 $ 46,563 $ (50,234) $ (157,091) $ (242,059) Interest expense 1,396 1,616 673 1,649 2,070 5,869 7,229 Total income tax provision (benefit) 9,536 10,634 16,504 27,701 (26,390) (89,350) (33,305) Depletion, depreciation and amortization 24,030 31,797 35,143 43,767 46,470 51,768 45,237 Accretion of asset retirement obligations 117 123 130 134 112 132 182 Full-cost ceiling impairment - - - - 67,127 229,026 285,721 Unrealized (gain) loss on derivatives 3,108 5,234 (16,293) (50,351) 8,557 23,532 (6,733) Stock-based compensation expense 1,795 1,834 1,038 857 2,337 2,794 1,755 Net loss on asset sales and inventory impairment - - - - 97 - - Adjusted EBITDA $ 56,345 $ 69,464 $ 66,814 $ 70,320 $ 50,146 $ 66,680 $ 58,027 (In thousands) 1Q 2014 2Q 2014 3Q 2014 4Q 2014 1Q 2015 2Q 2015 3Q 2015 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $ 31,945 $ 81,530 $ 66,883 $ 71,123 $ 93,346 $ 20,043 $ 72,535 Net change in operating assets and liabilities 21,729 (15,221) (586) 56 (45,234) 40,843 (20,846) Interest expense, net of non-cash portion 1,396 1,616 673 1,649 2,070 5,869 6,678 Current income tax (benefit) provision 1,275 1,539 (156) (2,525) - - (295) Net (income) loss attributable to non-controlling interest in subsidiary - - - 17 (36) (75) (45) Adjusted EBITDA $ 56,345 $ 69,464 $ 66,814 $ 70,320 $ 50,146 $ 66,680 $ 58,027
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. 63 Note: LTM is last 12 months. (In thousands) 2008 2009 2010 2011 2012 2013 2014 6/30/2013 9/30/2015 9/30/2014 9/30/2015 Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): Net income (loss) $103,878 ($14,425) $6,377 ($10,309) ($33,261) $45,094 $110,771 ($20,771) ($402,821) $64,208 ($449,384) Interest expense - - 3 683 1,002 5,687 5,334 3,574 16,817 3,685 15,168 Total income tax (benefit) provision 20,023 (9,925) 3,521 (5,521) (1,430) 9,697 64,375 (703) (121,344) 36,675 (149,045) Depletion, depreciation and amortization 12,127 10,743 15,596 31,754 80,454 98,395 134,737 97,801 187,242 90,970 143,477 Accretion of asset retirement obligations 92 137 155 209 256 348 504 307 560 371 427 Full-cost ceiling impairment 22,195 25,244 - 35,673 63,475 21,229 - 51,499 581,874 - 581,874 Unrealized loss (gain) on derivatives (3,592) 2,375 (3,139) (5,138) 4,802 7,232 (58,302) 13,945 (24,995) (7,950) 25,356 Stock-based compensation expense 665 656 898 2,406 140 3,897 5,524 1,836 7,743 4,665 6,886 Net (gain) loss on asset sales and inventory impairment (136,977) 379 224 154 485 192 - 617 97 - 97 Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $262,943 $148,105 $245,173 $192,624 $174,856 (In housands) 2008 2009 2010 2011 2012 2013 2014 6/30/2013 9/30/2015 9/30/2014 9/30/2015 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 $251,481 $156,614 $257,047 $180,359 $185,924 Net change in operating assets and liabilities (17,888) 15,717 (2,230) (12,594) (9,307) 6,210 5,978 (12,161) (25,181) 5,922 (25,234) Interest expense, net of non-cash portion - - 3 683 1,002 5,687 5,334 3,574 16,266 3,685 14,617 Current income tax (benefit) provision $10,448 ($2,324) (1,411) (46) - 404 133 78 (2,820) 2,658 (295) Net (income) loss attributable to non-controlling interest in subsidiary - - - - - - 17 - (139) - ($156) Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $262,943 $148,105 $245,173 $192,624 $174,856 Year Ended December 31, Year Ended December 31, LTM at LTM at Nine Months Ended Nine Months Ended
(In thousands, except per share data) 6/30/2015 9/30/2015 9/30/2015 Unaudited Adjusted Net Income and Adjusted Earnings Per Share Reconcilliation to Net Loss: Net loss attributable to Matador Resources Company shareholders ($157,091) ($242,059) ($449,384) Total income tax benefit (89,350) (33,305) (149,045) Loss attributable to Matador Resources Company shareholders before taxes (246,441) (275,364) (598,429) Less non-recurring and unrealized charges to net income before taxes: Full-cost ceiling impairment 229,026 285,721 581,874 Unrealized (gain) loss on derivatives 23,532 (6,733) 25,356 Non-recurring transaction costs associated with the HEYCO merger 275 - 2,510 Adjusted income attributable to Matador Resources Company shareholders before taxes 6,392 3,624 11,311 Income tax expense 1,915 1,067 3,332 Adjusted net income attributable to Matador Resources Company shareholders $4,477 $2,557 $7,979 Basic weighted average shares outstanding, without participating securities 82,938 84,685 80,481 Dilutive effect of participating securities 706 756 743 Weighted average shares outstanding, including participating securities - basic 83,644 85,441 81,224 Dilutive effect of options, restricted stock units and preferred shares 627 167 703 Weighted average common shares outstanding - diluted 84,271 85,608 81,927 Adjusted earnings per share attributable to Matador Resources Company shareholders (non-GAAP) Basic $0.05 $0.03 $0.10 Diluted $0.05 $0.03 $0.10 Three Months Ended Nine Months Ended Adjusted Net Income and Adjusted Earnings Per Share Reconciliation 64 Adjusted net income and adjusted earnings per common share are non-GAAP financial measures and are measured as net income (loss) attributable to Matador Resources Company shareholders, adjusted for dollar and per share impact of certain items, including unrealized gains or losses on derivatives, the impact of full cost-ceiling impairment charges, if any, and nonrecurring transaction costs for certain acquisitions along with the related tax effect for all periods. This non-GAAP financial information is provided as additional information for investors and is not in accordance with, or an alternative to, GAAP financial measures. Additionally, these non-GAAP financial measures may be different than similar measures used by other companies. The Company believes the presentation of adjusted net income and adjusted earnings per diluted common share provides useful information to investors, as it provides them an additional relevant comparison of the Company’s performance across periods and to the performance of the Company’s peers. In addition, these non-GAAP financial measures reflect adjustments for items of income and expense that are often excluded by securities analysts and other users of the Company’s financial statements in evaluating the Company’s performance. The table below reconciles adjusted net income and adjusted earnings per diluted common share to their most directly comparable GAAP measure of net income (loss) attributable to Matador Resources Company shareholders.
Cash Operating Expenses per BOE Reconciliation 65 Cash operating expenses per BOE is a non-GAAP financial measure and is measured as operating expenses per BOE excluding non-cash DD&A expense, non-cash stock- based compensation expense and non-recurring transaction costs associated with the HEYCO merger, each as adjusted on a per BOE basis. This non-GAAP financial information is provided as additional information for investors and is not in accordance with, or an alternative to, GAAP financial measures. Additionally, this non-GAAP financial measure may be different than similar measures used by other companies. The Company believes the presentation of cash operating expenses per BOE provides useful information to investors and other users of the Company’s financial information in evaluating the Company’s operating performance. The following table reconciles cash operating expenses per BOE (non-GAAP) to operating expenses per BOE (GAAP). 9/30/2014 6/30/2015 9/30/2015 9/30/2014 9/30/2015 Cash Operating Expenses per BOE Reconciliation to Operating Expenses per BOE: Total operating expenses (per BOE) (1) $44.27 $37.16 $33.92 $43.70 $36.23 Depletion, depreciation and amortization expenses (per BOE) (23.73) (21.39) (18.81) (23.00) (20.67) Non-cash stock-based compensation expense (per BOE) (0.70) (1.16) (0.73) (1.18) (0.99) Non-recurring transaction costs (per BOE) - (0.11) - - (0.36) Cash operating expenses (per BOE) $19.84 $14.50 $14.38 $19.52 $14.21 Three Months Ended Nine Months Ended (1) Total does not include the impact of full-cost ceiling impairments or immaterial accretion expenses.
66 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 September 30, 2011 At June 30, 2013 At December 31, 2013 At December 31, 2014 At September 30, 2015 PV-10 (in millions) $155.2 $522.3 $655.2 $1,043.4 $692.7 Discounted Future Income Taxes (in millions) $(11.8) $(44.7) $(76.5) $(130.1) $(18.9) Standardized Measure (in millions) $143.4 $477.6 $578.7 $913.3 $673.8