May 2016 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,” “hypothetical,” “forecasted,” 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 acquisitions, including the merger with Harvey E. Yates Company; 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. Type curves shown in this presentation are used to compare actual well performance to a range of potential production results calculated without regard to economic conditions; actual recoveries may vary from these type curves based on individual well performance and economic conditions.
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 Delaware 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 2015 February 2015 HEYCO Combination 2013 April 2015 Inaugural High-Yield Offering of $400 million; Follow-on Offering at ~$27.00; 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) 2016 March 2016 Follow-on Offering at ~$19.00; net cash proceeds of ~$142 million
5 Company Overview Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 93.3 million common shares Share Price(1) $20.08/share Market Capitalization(1) ~$1.9 billion Actual Actual % YoY 2014 Results 2015 Results 2016 Guidance Change Capital Spending $610 million $482 million(2) $325 million - 33% Total Oil Production 3.3 million Bbl 4.5 million Bbl 4.9 to 5.1 million Bbl + 11% Total Natural Gas Production 15.3 Bcf 27.7 Bcf 26.0 to 28.0 Bcf - 3% Total Oil Equivalent Production 5.9 million BOE 9.1 million BOE 9.2 to 9.8 million BOE + 4% Adjusted EBITDA(3) $263 million $223 million $120 to $130 million(4) - 44% (1) Market capitalization based on closing share price as of May 6, 2016 and shares outstanding as reported in the Form 10-Q at May 6, 2016. (2) For operations only. Does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. (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) Estimated 2016 Adjusted EBITDA is based upon the midpoint of 2016 production guidance range as provided on February 3, 2016 and affirmed on May 3, 2016. Estimated average realized prices for oil and natural gas used in these estimates were $39.75/Bbl (WTI oil price of $43.75/Bbl less $4.00/Bbl of estimated price differentials) and $2.37/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period April through December 2016.
Matador Resources Company – Operations Overview Market Capitalization(1) ~$1.9 billion Avg. Daily Production – Q1 2016(2) 23,846 BOE/d Oil (% total) 11,473 Bbl/d (48%) Natural Gas (% total) 74.2 MMcf/d (52%) Proved Reserves @ 3/31/2016 90.2 million BOE % Proved Developed 37% % Oil 56% 2016E CapEx(3) $325 million % Delaware Basin ~97% Gross Acreage(4) ~223,700 acres Net Acreage(4) ~142,100 acres Engineered Drilling Locations(5) 4,322 gross / 1,804 net Delaware Basin 3,543 gross / 1,417 net Eagle Ford 260 gross / 228 net Haynesville/Cotton Valley 519 gross / 159 net * Note: Represents year-over-year increase as compared to each respective figure. (1) Market capitalization based on closing share price as of May 6, 2016 and shares outstanding as reported in the Form 10-Q at May 6, 2016. (2) Average daily production for the three months ended March 31, 2016. (3) 2016 estimated capital expenditures, including all anticipated operations, midstream, land and non-operated well expenditures as of May 6, 2016, assuming a 3-rig program in the Delaware Basin in 2016. (4) As of May 3, 2016. Excludes ~75,700 gross (~35,700 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, 2015, but including no locations at Twin Lakes. Includes all identified locations where Matador has an operated or non-operated working interest. 6 33% of total production Almost no oil 63% of total natural gas 25% of total production 37% of total oil 15% of total natural gas 42% of total production 63% of total oil 22% of total natural gas 14%* 48%* 32%*
Matador Has Made Tremendous Progress Since its IPO At IPO(1): February 7, 2012 Today(2) Difference Oil Production 414 Bbl/d (6% oil) 11,473 Bbl/d (48% oil) Proved Reserves 27 MMBOE (4% oil) 90 MMBOE (56% oil) Proved Oil Reserves 1.1 MMBbl 50.7 MMBbl Delaware Acreage ~7,500 net acres ~90,200 net acres(3) Leverage(4) 1.5x(5) 1.5x Share Price $12.00(6) $20.08(7) (1) Unless otherwise noted, at or for the nine months ended September 30, 2011. (2) Unless otherwise noted, at or for the three months ended March 31, 2016. (3) As of May 3, 2016. (4) Calculated as net debt divided by LTM Adjusted EBITDA. Net debt is equal to debt outstanding less available cash (including $43 million of restricted cash held in escrow at December 31, 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. (5) At December 31, 2011. (6) As of February 7, 2012 at time of IPO. (7) Closing share price as of May 6, 2016. 7 +28-fold +3-fold +46-fold +12-fold +67% Flat
422 3,317 5,843 9,095 12,306 11,206 13,847 12,617 11,547 11,473 2011 2012 2013 2014 2015 1Q15 2Q15 3Q15 4Q15 1Q16 Q1 2016 Production Volumes Consistent with Projections Average Daily Oil Production (Bbl/d) Average Daily Natural Gas Production (MMcf/d) Average Daily Total Production (MBOE/d) Oil Production Mix (% of Average Daily Production) 8 Growth since IPO Growth since IPO Growth since IPO Growth since IPO Oil up 3% YOY; down 2% sequentially Gas up 2% YOY; up 2% sequentially BOE up 3% YOY; flat sequentially 39.8 34.1 35.4 41.9 75.9 73.8 76.5 81.1 72.1 74.2 2011 2012 2013 2014 2015 1Q15 2Q15 3Q15 4Q15 1Q16 7.0 9.0 11.7 16.1 25.0 23.5 26.6 26.1 23.6 23.8 2011 2012 2013 2014 2015 1Q15 2Q15 3Q15 4Q15 1Q16 6% 37% 50% 57% 49% 48% 52% 48% 49% 48% 2011 2012 2013 20 4 20 1 15 2 15 3 15 4Q15 1Q16
9 Matador’s Reserves Volumes at an All-Time High at March 31, 2016 6% 11% 8% 7% 68.7 million BOE 24.2 million Bbl oil (35% oil) PV-10(1): $1,043.4 million $91.48 oil / $4.35 gas YE 2014 Eagle Ford $603.8 million, 58% Haynesville/CV $193.4 million, 18% Delaware Basin $246.2 million, 24% 85.1 million BOE 45.6 million Bbl oil (54% oil) PV-10(1): $541.6 million $46.79 oil / $2.59 gas YE 2015 Eagle Ford $175.1 million, 32% Haynesville/CV $51.9 million, 10% Delaware Basin $314.5 million, 58% Note: Oil and natural gas prices noted are in $/Bbl and $/MMBtu, respectively. Prices reflect the arithmetic average of first-day-of-month oil and natural gas prices for the 12-month periods January 1 to December 31, 2014 and 2015 and April 1, 2015 to March 31, 2016, respectively, as per SEC guidelines for reserves estimation. (1) PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 (non-GAAP) to Standardized Measure (GAAP), see Appendix. 90.2 million BOE 50.7 million Bbl oil (56% oil) PV-10(1): $501.9 million $42.77 oil / $2.40 gas Q1 2016 Eagle Ford $154.3 million, 31% Haynesville/CV $42.3 million, 8% Delaware Basin $305.3 million, 61%
0.0x 0.0x 0.1x 2.0x 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 1.6x 1.5x 1.5x 2008 2009 2010 2011 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 Net Debt / LTM EBITDA $101 $240 $256 $416 $340 $282 In iti a l P u b lic O ff e ri n g Preserved and enhanced liquidity through April 2015 equity and Senior Notes offerings, sale of certain Loving County midstream assets for ~$143 million(1) in October 2015 and March 2016 equity offering Substantial liquidity to execute planned drilling program throughout 2016, including proceeds from March 2016 equity offering of ~$142 million and $300 million in undrawn borrowing capacity at May 3, 2016 Strong financial position with Net Debt/LTM Adjusted EBITDA(2)(3)(4) of ~1.5x, well below peer average 10 E q u ity R a is e E q u ity R a is e N o te s O ff e ri n g + E q u ity R a is e (2)(3) Net Debt ($ millions) M id s tr e a m S a le (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) Net Debt is equal to debt outstanding less available cash (including $43 million of restricted cash held in escrow at December 31, 2015). E q u ity R a is e Committed to Maintaining Strong Balance Sheet
Delaware Basin Southeast New Mexico and West Texas
Delaware Basin Acreage Position and Recent Operations and Results 12 L E A LOVING WARD Matador Resources Acreage TWIN LAKES ~42,700 gross / ~30,300 net acres WOLF / LOVING AREA ~12,400 gross / ~7,700 net acres Jackson Trust RANGER ~31,500 gross / ~19,100 net acres ARROWHEAD ~47,400 gross / ~16,900 net acres E D D Y RUSTLER BREAKS ~21,700 gross / ~14,600 net acres Jimmy Kone 2-well “batch” - 1 Wolfcamp A-XY & 1 Wolfcamp B Note: All acreage at May 3, 2016. Some tracts not shown on map. Dorothy White 3-well “batch” - 3 Wolfcamp A-XY wells Combined IP = 4,327 BOE/d (68% oil) Olivine State 5-16S-37E TL #1 – Strawn (Twin Lakes vertical pilot hole) IP = 691 BOE/d (84% oil) Being completed Recently completed Awaiting completion Currently being drilled Non-op completions Dorothy White 2-well “batch” - 1 Wolfcamp A-X and 1 2nd BS Barnett 2-well “batch” - 2 Wolfcamp A-XY wells Dick Jay 4-well “batch” - 2 Wolfcamp A-XY wells, Wolfcamp A-Lower & 2nd BS Combined IP = 4,705 BOE/d (61% oil) Paul well - Wolfcamp A-XY Fastest Wolfcamp well drilled to-date (13.8 days spud-to-TD) Janie Conner, Tiger – 3 wells - 2 Wolfcamp A-XY & 1 Wolfcamp B B Banker well - Wolfcamp B Guitar well - Wolfcamp B Baroque “BTQ” Federal Com #1H – 2nd BS Yates (MRC: 9.5% WI) Tested = 1,300 BOE/d (85% oil) Operated Activity YTD 2016 Wolf • 9 wells drilled • 7 wells completed and online • 2 wells being completed • 2 wells being drilled Rustler Breaks • 6 wells drilled • 2 wells being completed • 4 wells awaiting completion • 2 wells being drilled Billy Burt 90-TTT-B33 WF #201H – Wolfcamp A-Y Diverting agent used – outperforming 80-acre offset by 38%
Understanding the Opportunities 3rd Bone Spring L. Avalon 800’ Most current unconventional plays target one or two zones across a trend area. The Delaware Basin has over a dozen unique targets between the top of the Brushy Canyon and the Woodford. All logs plotted at same scale Delaware Basin Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D Strawn Atoka Barnett Miss Lime Woodford U. Avalon 1st Bone Spring 2nd Bone Spring 13 Brushy Cyn. Ov e rp ress u re Tested by MTDR Tested by others Objective: To drill and complete better wells for less money Challenge: To 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!
Delaware Basin Inventory Continues to Increase Matador has identified up to 3,543 gross (1,417 net) potential locations(1) for future drilling on its Delaware Basin acreage Only 118 gross (71.1 net) locations are PUD locations at December 31, 2015 Matador anticipates operating up to 2,263 gross (1,284 net) of these potential locations(2) Inventory does not yet include any locations for Twin Lakes prospect area Formation Gross Net Delaware Group 276 100 Avalon 322 144 1st Bone Spring 556 177 2nd Bone Spring 657 243 3rd Bone Spring 489 203 Wolfcamp A-XY 280 122 Lower Wolfcamp A 339 164 Wolfcamp B 275 123 Wolfcamp D 349 140 TOTAL 3,543 1,417 14 Gross Net 178 90 233 136 290 152 381 215 325 186 187 111 256 154 191 113 222 126 2,263 1,284 Potential Matador Operated Locations(1)(2) Total Locations Identified(1)(3) (1) At December 31, 2015. (2) Includes any identified locations in which Matador’s working interest is at least 25%. (3) 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, 2015, but including no locations at Twin Lakes. Includes all identified locations where Matador has an operated or non-operated working interest.
43 32 35 26 18 15 17.3 13.8 0 5 10 15 20 25 30 35 40 45 50 Loving County Wolfcamp Eddy County Wolfcamp Dri llin g D ays 2014 Average 2015 Planned 2015 Best Well 2016 Record Well Improving Wolfcamp Drilling Times Significantly in 2015 and 2016 15 Note: Best wells are Dorothy White 82-TTT-B33 WF #203H in Loving County (Wolfcamp) and Paul 25-24S-27E RB #221H in Eddy County (Wolfcamp).
$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 H2 2014 Rigs Labor/ Supply Rentals Directional Fluids Casing/ Cement YE 2015 20% 9% 8% 6% 3% 24% 10% 22% 19% 12% 12% 17% 16 2015 Wolf Area Drilling Cost Improvements $7.4 $3.6 Drilli n g C o s ts, m illi o n s Rigs Labor/ Supply Rentals Directional Fluids Casing/ Cement
$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 H2 2014 YE 2015 YE 2016 51% Savings 17% Savings 2016 Anticipated Wolf Area Drilling Cost Improvements 17 Service Costs Service Costs Efficiencies Efficiencies $7.4 $3.6 $3.0 41% 59% 50% 50% Dri llin g Cos ts, milli o n s
Stimulation Location Surface Rentals CTU Drillout Wireline $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 H2 2014 Stimulation Location Surface Rentals CTU/Drillout Wireline YE 2015 15% 12% 12% 9% 52% 18 2015 Wolf Area Completion Cost Improvements $4.6 $2.4 C o m p leti o n C o sts, milli o n s
$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 H2 2014 YE 2015 YE 2016E 2016 Anticipated Wolf Area Completion Cost Improvements 19 $4.6 Service Costs 83% Service Costs 83% 75% 25% Efficiencies Efficiencies $2.4 $1.8 C o m p leti o n C o sts, milli o n s More to come? 48% Savings 25% Savings 17% 75%
$0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 H2 2014 YE 2015 YE 2016E 25% 2016 Anticipated Wolf Area Total Drilling and Completion Cost Improvements 20 $12.0 $6.0 $4.8 Drilli n g a n d C o m p le ti o n C o s ts, m illi o n s $100,000 Cost Reduction ROR Increase ~2% More to come? Service Costs Service Costs Efficiencies Efficiencies 56% 44% 63% 37% 50% Savings 20% Savings Note: Does not include production and facilities costs.
21 7,500 bbl 8,400 bbl 500 Mlbs 210 ft. 35 ft. Gen 1 Gen 2 Testing 2,000 lbs/ft 2,000 lbs/ft 3,000 lbs/ft 40 Bbl/ft 30 Bbl/ft 40 Bbl/ft 35’ cluster spacing 50’ cluster spacing 35’ cluster Spacing 10 wells 13 wells 1 well Gen 1 Testing 2,000 lbs/ft 3,000 lbs/ft 40 Bbl/ft 40 Bbl/ft 35’ cluster spacing 35’ cluster Spacing 1 well 1 well Bone Spring Upper Wolfcamp Lower Wolfcamp C o u p le d M ic ro -C o u p le d S o u rc e R o c k 630 Mlbs 630 Mlbs 210 ft. 35 ft. 8,400 bbl Evolution of Delaware Basin Frac Design – Reservoir Specific 350 ft. 50 ft. Gen 1 Gen 2 Testing 2,000 lbs/ft 1,333 lbs/ft 2,100 lbs/ft 40 Bbl/ft 20 Bbl/ft 40 Bbl/ft 50’ cluster spacing 75’ cluster spacing 50’ cluster Spacing 4 wells 6 wells 2 wells
Oil Eq. Oil Natural Gas % Pf (3) Choke Well (BOE/d) (Bbl/d) (MMcf/d) Oil (psi) (inches) 1,093 733 2.2 67% 1,410 36/64th 1,050 677 2.2 64% 3,000 28/64th Dick Jay 92-TTT-B01 WF #204H (Wolfcamp A-X) 1,553 906 3.9 58% 2,950 30/64th 1,009 539 2.8 53% 2,475 30/64th Total 4,705 2,855 11.1 61% 1,416 924 3.0 65% 2,600 32/64th 1,671 1,165 3.0 70% 2,800 32/64th 1,240 851 2.3 69% 2,400 32/64th Total 4,327 2,940 8.3 68% Dick Jay 92-TTT-B01 WF #124H (Second Bone Spring) Dick Jay 92-TTT-B01 WF #203H (Wolfcamp A-Y) Dick Jay 92-TTT-B01 WF #212H (Wolfcamp A-Lower) Dorothy White 82-TTT-B33 WF #202H (Wolfcamp A-X) Dorothy White 82-TTT-B33 WF #204H (Wolfcamp A-X) Dorothy White 82-TTT-B33 WF #208H (Wolfcamp A-Y) 22 Wolf Prospect Area – Continued Focus on Wolfcamp Development in 2016 Matador Acreage Recently Added 2016 Focus Area Norton Schaub 84-TTT-B33 WF #201 Cumulative BOE: 425 MBOE EUR (BOE): ~1,000 MBOE Dorothy White #1H Cumulative BOE: 515 MBOE EUR (BOE): >1,000 MBOE 2015 and Early 2016 Accomplishments Reduced Wolfcamp drilling times by 60% Re ent well drilled in 17.3 days Reduced drilling and completion costs by 50% in 2015 Generating “repeatable” results First use of diverting technology encouraging Billy Burt #201H outperforming 80-acre offset by 38% 2016 Plans Focus on Wolfcamp development and Bone Spring delineation 19 gross (16.3 net) wells planned for 2016 17 gross (15.3 net) wells on production Recent 24-Hour Initial Potential Test Results Note: All acreage at May 3, 2016. Not all wells depicted on map. 2nd Bone Spring Wolfcamp X/Y A-XY Wolfcamp A Dorothy White 3-well “batch” - 3 Wolfcamp A-XY wells Combined IP = 4,327 BOE/d (68% oil) Dick Jay 4-well “batch” - 2 Wolfcamp A-XY wells, Wolfcamp A-Lower & Second Bone Spring Combined IP = 4,705 BOE/d (61% oil) Billy Burt 90-TTT-B33 WF #201H – Wolfcamp A-Y Diverting agent used – outperforming 80-acre offset by 38% 1 2 1 2
2nd Bone Spring Wolfcamp X/Y Wolf Inventory – Multi-Pay Development Potential ~660’ Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp A-XY Wolfcamp A Full Development Location 1 mile MRC Spacing Test Completed Full Development Spacing Pattern (Cross-Section View) 23 A-XY Wolfcamp A 4 72 Eval. Ongoing 70 72 70 51 339 Formation Development Well Costs(1)(2) (millions) EUR(3) (MBOE) % Oil 2nd Bone Spring $4.0 – $5.0 400 – 500 50 – 65% Wolfcamp A-XY $5.5 – $6.5 650 – 1,100 65 – 80% (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent. (4) 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, 2015. (5) Includes any identified locations in which Matador’s working interest is at least 25%. Matador Acreage Note: All acreage at May 3, 2016. Total Gross Locations(4) Est. Operated Locations(5) 4 68 Eval. Ongoing 66 68 66 47 319 Loving Reeves
Drilling Wells in Batch Mode / Central Production Facilities 24 Dick Jay / Barnett Development (Top-Down View) Dick Jay / Barnett Development (Cross-Section View) Dick Jay Pad Barnett Pad 2nd Bone Spring 3rd Bone Spring Wolfcamp A-Lower Wolfcamp A-XY Dick Jay 124H Dick Jay 204H Dick Jay 203H Dick Jay 212H Barnett Dick Jay Recent Wells 2016 Planned Wells Central Tank Battery ~660’ $400,000 in savings/well by batch drilling!
10 100 1,000 10,000 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 P roduction R a te, BO E /d Time, Days Dorothy White #1H Norton Schaub #1H Billy Burt #203H Johnson #204H Barnett #201H Dorothy White #1H has produced 515 MBOE (68% oil) in 28 months Norton Schaub 84-TTT-B33 WF #201H has produced 425 MBOE (67% oil) in 21 months Billy Burt 90-TTT-B33 WF #203H has produced 195 MBOE (73% oil) in 12 months Johnson 44-02S-B53 WF #204H has produced 300 MBOE (66% oil) in 19 months Barnett 90-TTT-B01 WF #201H has produced 230 MBOE (64% oil) in 14 months ESP installed Wolf Area Wolfcamp A-XY Wells Continue Strong Performance Across Acreage 25 600 MBOE Type Curve 1,200 MBOE Type Curve 900 MBOE Type Curve Note: Production from selected Wolfcamp A-XY wells in Wolf prospect area as of April 2016.
0 25 50 75 100 $30 $35 $40 $45 $50 $55 $60 R OR % WTI Oil Price, $/Bbl 2nd Bone Spring 500 MBOE $4.0 MM D&C ROR % 500 MBOE $5.0 MM D&C ROR % 400 MBOE $4.0 MM D&C ROR % 400 MBOE $5.0 MM D&C ROR % Wolf – Estimated Returns by Formation 26 Formation Development Well Cost(1)(2) (millions) EUR(3) (MBOE) % Oil 2nd Bone Spring $4.0 - $5.0 400 – 500 50 – 65% Wolfcamp A-XY $5.5 - $6.5 650 – 1,100 65 – 80% 0 50 100 150 200 $30 $35 $40 $45 $50 $55 $60 R OR % WTI Oil Price, $/Bbl Wolfcamp A-XY 1,000 MBOE $5.5MM D&C ROR % 1,000 MBOE $6.5 MM D&C ROR % 700 MBOE $5.5 MM D&C ROR % 700 MBOE $6.5 MM D&C ROR % Note: Assumes $2.50/Mcf flat natural gas price with -$0.73/Mcf natural gas differential and -$1.75/Bbl oil differential. (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent.
Rustler Breaks – Focus on Wolfcamp Development in 2016 27 Wolfcamp A-XY Wolfcamp B Matador Acreage Dr K #203H 24 hr IP: 1,241 BOE/d (69% oil) Scott Walker #204H 24 hr IP: 504 BOE/d (70% oil) Rustler Breaks #224H 24 hr IP: 987 BOE/d (44% oil) Guitar #202H 24 hr IP: 1,274 BOE/d (79% oil) Tiger #224H 24 hr IP: 1,533 BOE/d (42% oil) Tiger #204H 24 hr IP: 1,405 BOE/d (75% oil) 2015 Accomplishments Identified multiple new horizons, particularly in the Wolfcamp A-XY and Wolfcamp B Reduced drilling times and well costs significantly Tested next generation frac design up to 3,000 lbs/ft 2016 Plans Focus on Wolfcamp development 19 gross (15.8 net) wells planned for 2016 17 gross (14.5 net) wells on production 8 Wolfcamp A-XY 9 Wolfcamp B Complete 60 MMcf/d cryogenic processing plant and gathering system to support operations Complete 3D seismic shoot across prospect area Note: All acreage at May 3, 2016. Janie Conner #224H 24 hr IP: 1,703 BOE/d (59% oil) Paul #221H Matador’s fastest drilled Wolfcamp well (13.8 days spud to TD)
Rustler Breaks Inventory – Multi-Pay Development Potential Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp A-XY Wolfcamp B ~80 0 ’ 171 178 183 188 173 235 167 1,637 Full Development Location Total Gross Locations(4)(5) Formation Development Well Costs(1)(2) (millions) EUR(3) (MBOE) % Oil Bone Spring $3.0 – $4.0 300 – 600 80 – 85% Wolfcamp A-XY $5.0 – $6.0 600 – 800 80 – 85% Wolfcamp B $5.5 – $6.5 800 – 1,000 40 – 50% 1 mile MRC Horizontal Drilled Full Development Spacing Pattern (Cross-Section View) 28 Wolfcamp A-XY Wolfcamp B 2nd Bone Spring Matador Acreage Est. Operated Locations(5)(6) 1,135 115 123 125 127 120 177 114 Note: All acreage at May 3, 2016. (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent. (4) 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, 2015. (5) Includes additional Wolfcamp A lower and Wolfcamp D locations not depicted in chart. As a result, total gross locations and estimated operated locations do not sum. (6) Includes any identified locations in which Matador’s working interest is at least 25%.
Rustler Breaks – 5 Wells Producing From 3 Zones on Multi-Well Pad 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 “XY” Tiger 14-24S-28E RB #224H IP: 1,533 BOE/d (42% oil) Tiger 14-24S-28E RB #204H IP: 1,405 BOE/d (75% oil) Tiger 14-24S-28E RB #124H IP: 702 BOE/d (83% oil) Multi-Well Pad Resistivity 29 Janie Conner 13-24S-28E RB #224H IP: 1,703 BOE/d (59% oil) Janie Conner 13-24S-28E RB #124H IP: 640 BOE/d (83% oil) Janie Conner 13-24S-28E RB #204H Currently completing West (Section 14) 3 producing wells East (Section 13) 2 producing wells TVD: 8,200’ 9,600’ 10,500’ Additional Wolfcamp B Targets Wolfcamp B – Upper Wolfcamp B – Lower Drilled by Matador in Rustler Breaks Being tested by other operators
8.3 8.6 5.1 5.9 6.9 3.9 5.0 5.5 3.0 $0 $1 $2 $3 $4 $5 $6 $7 $8 $9 $10 Guitar #202H Tiger #224 Tiger #124H Tiger #204H Janie Conner #224 Janie Conner #124 Wolfcamp A 2016 Target Wolfcamp B 2016 Target 2nd Bone Springs 2016 Target C o m p le te d W el l C o st , $ m ill io n s 30 Rustler Breaks Well Cost Achievements Wolfcamp A Wolfcamp B 2nd Bone Spring 2016 could result in $13.5 million total costs $9.00/BOE net(1) Tiger 3 well stack costs: $19.5 million Combined Gross EUR: ~2 MMBOE $13.00/BOE net(1) 2015 wells (1) Assumes 75% NRI (net revenue interest) for each well; 2016 well costs are estimates for year-end 2016.
10 100 1,000 10,000 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 P roduction R a te, BO E /d Time, Days Rustler Breaks #224H Tiger #224H Janie Conner #224H Rustler Breaks 12-24S-27E RB #224H has produced 260 MBOE (41% oil) in 24 months Tiger 14-24S-28E RB #224 has produced 280 MBOE (42% oil) in 13 months Janie Conner 13-24S-28E RB #224H has produced 160 MBOE (56% oil) in 5 months Rustler Breaks Wolfcamp B Wells Performing Above Expectations 31 700 MBOE Type Curve 1,000 MBOE Type Curve Note: Production as of April 2016.
10 100 1,000 10,000 0 50 100 150 200 250 300 350 400 P roduction R a te, BO E /d Time, Days Guitar #202H Tiger #204H Scott Walker #204H Dr. K #203H Guitar 10-24S-28E RB #202H produced 200 MBOE (76% oil) in 13 months Tiger 14-24S-28E RB #204H produced 215 MBOE (78% oil) in 10 months Scott Walker 36-22S-27E RB #204H produced 55 MBOE (72% oil) in 7 months Dr. K 24-23S-27E RB #203H produced 85 MBOE (71% oil) in 4 months Well put on compression Rustler Breaks Wolfcamp A-XY Wells Performing Above Expectations 32 Note: Production as of April 2016. 800 MBOE Type Curve 500 MBOE Type Curve
0 40 80 120 160 30 35 40 45 50 R O R, % WTI Oil Price, $/Bbl Rustler Breaks - Wolfcamp A-XY (85% oil) 800 MBOE, $5.0 MM 800 MBOE, $6.0 MM 600 MBOE, $5.0 MM 600 MBOE, $6.0 MM 0 20 40 60 80 100 30 35 40 45 50 R O R, % WTI Oil Price, $/Bbl Rustler Breaks - Wolfcamp B (45% oil) 1,000 MBOE, $5.5 MM 1,000 MBOE, $6.5 MM 800 MBOE, $5.5 MM 800 MBOE, $6.5 MM Rustler Breaks – Estimated Returns by Formation 33 Formation Development Well Cost(1)(2) (millions) EUR(3) (MBOE) % Oil Wolfcamp A-XY $5.0 – $6.0 600 – 800 80 – 85% Wolfcamp B $5.5 – $6.5 800 – 1,000 40 – 50% Note: Assumes $2.50/Mcf flat natural gas price with -$0.70/Mcf natural gas differential and -$3.26/Bbl oil differential. (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent.
Single Wolfcamp B Well at Rustler Breaks Holds Up To 15 Potential Locations 34 Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp B Wolfcamp A-XY One producing Wolfcamp B well holds 320 surface acres and up to 15 additional potential locations for future development 1/2 mile 1 mile 320 - Acre Development Spacing Pattern (Cross-Section View) 1 m ile 320 gross acres 1/2 mile 320 - Acre Development Spacing Pattern (Aerial View) Additional Locations Held With Wolfcamp B well 2 2 2 2 3 15 2 2
35 2nd Bone Spring 3rd Bone Spring Wolfcamp D Wolfcamp A Cimarron State RN #134H - IP: 804 BOE/d (94% oil) Matador Acreage Ranger/Arrowhead – Bone Spring and Wolfcamp Development in 2016 2015 Accomplishments Merged with HEYCO adding ~60,000 gross and ~20,000 net acres(1) 12 gross (4.5 net) wells Drilled Twin Lakes vertical data well Applied for 10 new Federal drilling permits 2016 Plans Further delineate and develop Bone Spring 7 gross (4.9 net) wells with 5 gross (3.9 net) wells on production Drill and complete horizontal in Wolfcamp D at Twin Lakes Submit 50 to 75 Federal drilling permits for approval and future development (20 submitted to date) Gobbler 5 B2PM 1H - Tested 2,300 BOE/d (80% oil) CTA State Com 3H, 4H, 5H, 6H - Tested avg. 956 BOE/d (85% oil) Mallon 27 Fed Com #2H, #3H, #4H - To Spud Q3 2016 (3rd Bone Spring w/ 7,500 ft laterals) Pickard State RN #124H - IP 594 BOE/d (92% oil) Iggles 21 State Com #1H - Tested 1,300 BOE/d (90% oil) Conine 03-20S-35E RN #121H - IP: 578 BOE/d (91% oil) Note: All acreage at May 3, 2016. (1) Including additional acreage acquired through subsequent joint ventures with affiliates of HEYCO. Non-Op Matador Operated Baroque “BTQ” Federal Com #1H - Tested 1,300 BOE/d (90% oil) Competitor Emerald PWU 20 #10 - Tested 1,390 BOE/d (90% oil)
Formation Development Well Costs(1)(2) (millions) EUR(3) (MBOE) % Oil Bone Spring $4.5 – $6.0 400 – 700 90 – 95% Wolfcamp $6.5 – $8.0 200 – 800* 80 – 85% Ranger Inventory – Multi-Well Development Potential 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp A-D * Based on Volumetrics and 4-8% Recovery Factor 36 2nd Bone Spring 3rd Bone Spring Wolfcamp D Matador Acreage Wolfcamp A ~1,320’ Wolfcamp A- XY ~75 0 ’ 155 169 89 194 48 655 1 mile MRC Horizontal Drilled Full Development Location Full Development Spacing Pattern (Cross-Section View) MRC Horizontal Planned Note: All acreage at May 3, 2016. Total Gross Locations(4) Est. Operated Locations(5) 342 80 90 43 114 15 (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent. (4) 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, 2015. (5) Includes any identified locations in which Matador’s working interest is at least 25%. Mallon 27 Fed Com #2H, #3H, #4H - Expected Spud Q3 2016 (3rd Bone Spring w/ 7,500 ft laterals)
Arrowhead Inventory – Multi-Well Development Potential 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp A-D Formation Development Well Costs(1)(2) (millions) EUR(3) (MBOE) % Oil Bone Spring $4.5 – $6.0 400 – 700 80 – 90% Wolfcamp $6.5 – $8.0 200 – 800* 80 – 85% * Based on Volumetrics and 4-8% Recovery Factor 37 2nd Bone Spring ~1,320’ Wolfcamp A-XY 210 210 120 88 14 642 1 mile Full Development Location Full Development Spacing Pattern (Cross-Section View) MRC Horizontal Planned Stebbins Fed 20-20S-29E AH #123H Expected Spud Q1 2017 Matador Acreage Note: All acreage at May 3, 2016. Total Gross Locations(4) Est. Operated Locations(5) ~75 0 ’ 269 77 78 59 44 11 (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent. (4) Gross locations identified as of December, 31, 2015. (5) Includes any identified locations in which Matador’s working interest is at least 25%.
10 100 1,000 10,000 0 100 200 300 400 500 600 700 800 900 P roduction R a te, BO E /d Time, Days Ranger #121H Ranger #122H Pickard #121H Cimarron State #134H Ranger State 33-20S-35E RN #121H produced 250 MBOE (91% oil) in 29 months (2nd Bone Spring) Ranger State 33-20S-35E RN #122H produced 80 MBOE (91% oil) in 12 months (2nd Bone Spring) Pickard State 20-18S-34E RN #121H produced 220 MBOE (89% oil) in 21 months (2nd Bone Spring) Cimarron State 16-19S-34E RN #134H produced 145 MBOE (94% oil) in 12 months (3rd Bone Spring) Wells shut in for offset fracs ESP installed ESP replaced 38 Ranger Area Bone Spring Wells Continued Strong Performance Note: Production as of April 2016. 700 MBOE Type Curve 400 MBOE Type Curve
Testing New Oil Shale Play in Twin Lakes Prospect 39 Olivine State 5-16S-37E TL #1 (vertical Strawn completion) - IP = 691 BOE/d (84% oil) @ 350 psi on 32/64” choke Matador Resources Acreage M ic ro -C o u p le d C o u p le d One of the primary source rocks for Twin Lakes prospect area (~42,700 gross and ~30,300 net acres) Super-charged area having produced 1.3 billion Bbl oil and 2.2 trillion cubic feet natural gas Drilled initial data collection well (Olivine State #1) to obtain full set of whole cores and geophysical logs Horizontal well to test Wolfcamp D planned in Q4 2016 after analyzing data for optimal landing target M ic ro -C o u p le d Porous Intervals > 8% Multiple “Hybrid” Reservoir Targets Over 400 ft Interval P e n n s y lv a n ia n S h a le Cored Interval Top Strawn Pennsylvanian-Lower Wolfcamp D Oil Shale Note: All acreage at May 3, 2016. Olivine State 5-16S-37E TL #1 Vertical Strawn Test 24 hr. IP: 691 BOE/d (84% Oil) 350 psi FTP on 32/64” choke Treatment: 250 bbls 15% HCl
Midstream
41 Longwood Gathering and Disposal Systems(1) in Delaware Basin Loving County, TX Gas gathering Water gathering Salt water disposal Oil gathering Cryogenic gas processing plant Sold to EnLink Eddy County, NM Gas gathering and compression Cryogenic gas processing plant Water gathering (under evaluation) Salt water disposal (under evaluation) (1) Longwood Gathering and Disposal Systems, LP is an indirect wholly owned subsidiary of Matador Resources Company.
42 Wolf - Loving County, TX – Significant Midstream Footprint Gas Gathering Water Gathering Salt Water Disposal Oil Gathering Matador Acreage Note: All acreage at May 3, 2016.
43 Matador Acreage Note: All acreage at May 3, 2016. Gas gathering and compression Cryogenic gas processing plant – expected to be operational in Q3 2016 Water gathering (under evaluation) Salt water disposal (under evaluation) Rustler Breaks - Eddy County, NM – Repeating the Proven Wolf Model
2016 Capital Investment Plan Update
N umb e r of O p e ra te d R ig s Ranger/Arrowhead Rustler Breaks Wolf Delaware Basin: 3-Rig Case We will keep the focus on our Delaware Basin assets and opportunities with the intent of creating and preserving long-term shareholder value Plan to run 3 rigs throughout 2016 Continue to improve drilling and completion efficiencies, lower costs, improve well recoveries and returns and upgrade our acreage position Continue to invest in Delaware midstream assets, particularly the cryogenic natural gas processing plant and gathering assets we are building in the Rustler Breaks prospect area in Eddy County, NM 45 2016 Capital Investment Plan – Summary
46 We estimate our capital budget in 2016 to be approximately $325 million (down 33% from 2015(1)) We expect to have sufficient liquidity to fund our 2016 capital investments – $118 million in cash and $300 million(2) in undrawn revolving credit facility at March 31, 2016 2016 Capital Investment Plan – Summary 21% 2014 CapEx $610 million 2015 CapEx 2016E CapEx 3 Delaware Basin rigs throughout 2016 $482 million(1) $325 million Land, Seismic, Etc. $91 million 15% Drilling, Completions, Facilities & Infrastructure $507 million 83% Midstream Activities $12 million 2% Land, Seismic, Etc. ~$54 million 11% Drilling, Completions, Facilities & Infrastructure ~$351 million 73% Midstream Activities ~$77 million 16% Land, Seismic, Etc. $25 million 8% Drilling, Completions, Facilities & Infrastructure $260 million 80% Midstream Activities $40 million 12% 33% (1) For operations only. Does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. (2) Borrowing base redetermined to $300 million on May 3, 2016.
47 We expect to grow oil production by about 11% and keep natural gas production close to flat; total BOE production growth of about 4% as compared to 2015 We expect to outspend cash flow by ~$230 million in 2016, including outspend associated with midstream and land, but anticipate funding most or all of this outspend without incurring significant additional debt by year-end We anticipate funding most or all of this outspend through a combination of: Additional operational efficiencies and cost savings Improved well performance Potential rise in oil and natural gas prices throughout the year Certain asset sales, including midstream assets and other non-strategic properties Joint ventures and creative land deals Additional equity Additional borrowings under our undrawn credit facility We raised ~$142 million in a March 2016 follow-on equity offering covering most of the 2016 projected outspend 2016 Capital Investment Plan – Summary
Matador’s 2016 Delaware Basin Operated Drilling Plan: 3-Rig Case(1) 48 Note: All acreage at May 3, 2016. Some tracts not shown on map. L E A LOVING WARD TWIN LAKES ~42,700 gross / ~30,300 net acres WOLF / LOVING AREA ~12,400 gross / ~7,700 net acres Jackson Trust RANGER ~31,500 gross / ~19,100 net acres ARROWHEAD ~47,400 gross / ~16,900 net acres E D D Y RUSTLER BREAKS ~21,700 gross / ~14,600 net acres Wolf/Loving Area − 20 gross (16.8 net) wells planned for 2016 − 18 gross (15.8 net) wells on production, including 10 Wolfcamp A-XY, 2 Wolfcamp A-Lower and 6 2nd Bone Spring wells Rustler Breaks − 19 gross (15.8 net) wells planned for 2016 − 17 gross (14.5 net) wells on production, including 8 Wolfcamp A-XY and 9 Wolfcamp B wells Ranger/Arrowhead − 7 gross (4.9 net) wells planned for 2016 − 5 gross (3.9 net) wells on production, including 2 2nd Bone Spring and 3 3rd Bone Spring wells Twin Lakes − 2 gross (2.0 net) well planned for 2016 − Strawn vertical well and initial Wolfcamp D horizontal well Total 3-Rig Program − 48 gross (39.5 net) wells planned for 2016 − 42 gross (36.7 net) wells on production, including 30 Wolfcamp wells and 11 Bone Spring wells 18 # Matador Resources Acreage Gross wells on production in 2016 17 5 2 (1) Updated May 3, 2016.
0 40 80 120 160 200 240 30 35 40 45 50 55 60 R O R, % WTI Oil Price, $/Bbl Rustler Breaks - Wolfcamp A-XY (85% oil) 800 MBOE, $5.0 MM 800 MBOE, $6.0 MM 600 MBOE, $5.0 MM 600 MBOE, $6.0 MM 49 0 50 100 150 200 250 300 30 35 40 45 50 55 60 R O R, % WTI Oil Price, $/Bbl Wolf - Wolfcamp A-XY (70% oil) 1,000 MBOE, $5.5 MM 1,000 MBOE, $6.5 MM 700 MBOE, $5.5 MM 700 MBOE, $6.5 MM 0 50 100 150 200 250 300 30 35 40 45 50 55 60 R O R, % WTI Oil Price, $/Bbl Ranger/Arrowhead - 2nd Bone Spring (90% oil) 700 MBOE, $4.5 MM 700 MBOE, $6.0 MM 400 MBOE, $4.5 MM 400 MBOE, $6.0 MM 0 20 40 60 80 100 120 140 30 35 40 45 50 55 60 R O R, % WTI Oil Price, $/Bbl Rustler Breaks - Wolfcamp B (45% oil) 1,000 MBOE, $5.5 MM 1,000 MBOE, $6.5 MM 800 MBOE, $5.5 MM 800 MBOE, $6.5 MM Note: $2.50/Mcf natural gas price used in all graphs, less differentials. Costs include total estimated drilling, completion, production and facilities costs for a typical development well in each area. Note: High end of cost range reflects Q1 2016 estimated costs; low end of cost range reflects 2016 target. (1) Oil price shown is West Texas Intermediate oil price (WTI). Differentials to WTI oil price are included in all graphs for each area. Delaware Basin – Sensitivities to Oil Price(1) and Cost Savings
2016E CapEx by Quarter – Revised Expectations $52.5 $83.4 $60.0 $64.0 $21.1 $18.0 $1.0 $13.5 $3.5 $4.0 $4.0 $87.1 $104.9 $65.0 $68.0 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 1Q16 2Q16 3Q16 4Q16 D&C + Facilities Midstream Land, Seismic, Etc. (Discretionary) 2016E CapEx of ~$325 million − Decrease of ~33% from 2015 capital expenditures of $482 million(1) − Includes estimated efficiency and cost savings of 15 to 20% throughout 2016, but additional savings may be realized CapEx for Q1 was 15% less than expected – Q1 and Q2 essentially “flip-flopped” − Lower than expected well costs in Q1 − Also reflects fewer wells being completed in Q1 in Wolf and Rustler Breaks than originally planned – completion costs incurred early in Q2 instead $75.0 $62.0 $62.0 $61.0 $22.0 $16.0 $2.0 $6.0 $6.0 $6.0 $7.0 $103.0 $84.0 $70.0 $68.0 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 1Q16 2Q16 3Q16 4Q16 D&C + Facilities Midstream Land, Seismic, Etc. (Discr tionary) 2016 Capital Investment Plan Summary 50 Land, Seismic, Etc. (Discretionary) $25 million 8% Drilling, Completions, Facilities, Infrastructure $260 million 80% Permian Midstream Activities (Longwood) $40 million 12% 2016E CapEx (3 rigs in the Delaware Basin throughout 2016) $325 million 2016E CapEx by Quarter – Original Guidance (As presented at Analyst Day on February 3, 2016) $ in m ill io n s (1) For operations only. Does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. $ in m ill io n s
$223 $108 $192 $263 $331 $125 $0 $100 $200 $300 $400 2013 2014 2015 2016E 37% (15%) (44%) Shows impact of EnLink transaction in 2015 2,133 3,320 4,492 4,800 4,285 5,870 9,108 9,133 2013 2014 2015 2016E 7% 0% 56% 37% 35% 55% 2,133 3,320 4,492 5,000 4,285 5,870 9,108 9,500 201 2014 2015 2016E 11% 4% 56% 37% 35% 55% Oil and Natural Gas Production Oil 51 2016 Oil and Natural Gas Production and Adjusted EBITDA Estimates 2016E CapEx: D&C / Facilities: $260 MM Midstream / Land: $65 MM Total: $325 MM Outspend: $230 MM Oil, MBbl Natural Gas, MBOE Total Adjusted EBITDA(1)(2) 2016E Oil Production Estimated oil production of 4.9 to 5.1 million barrels − 11% increase from 2015 to midpoint of 2016 range Average daily oil production of 13,700 Bbl/d, up from 12,300 Bbl/d in 2015 − 73% Delaware Basin; 27% Eagle Ford Q2 2016 up ~10 to 12% sequentially; Q4 2016 up 34% over Q4 2015 2016E Natural Gas Production Estimated natural gas production of 26.0 to 28.0 Bcf − 3% decrease from 2015 to midpoint of 2016 range Average daily natural gas production of 74.0 MMcf/d, compared to 75.9 MMcf/d in 2015 − 48% Haynesville/Cotton Valley; 40% Delaware Basin; 12% Eagle Ford Q2 2016 up ~5 to 7% sequentially; may decline in 2H 2016 2016E Adjusted EBITDA(1)(2) Estimated Adjusted EBITDA(1)(2) of $120 to $130 million − Decrease of ~44% from $223 million in 2015 Realized $37.50/Bbl $2.30/Mcf Realized $45.27/Bbl $2.71/Mcf Realized $99.79 Bbl $4.35/Mcf Realized $87.37/Bbl $5.08/Mcf $ in m ill io n s (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 2016 Adjusted EBITDA is based upon the midpoint of 2016 production guidance range as provided on February 3, 2016 and affirmed on May 3, 2016. Estimated average realized prices for oil and natural gas used in these estimates were $39.75/Bbl (WTI oil price of $43.75/Bbl less $4.00/Bbl of estimated price differentials) and $2.37/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period April through December 2016.
2.70 3.00 3.00 3.00 3.30 3.30 3.30 3.30 $3.60 $3.53 $3.53 $3.53 $3.42 $3.42 $3.42 $3.42 $2.64 $2.60 $2.60 $2.60 $2.34 $2.34 $2.34 $2.34 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Na tu ra l G as Vol umes He dg ed (B cf) 490,000 690,000 690,000 690,000 390,000 390,000 390,000 390,000$68.32 $61.16 $61.16 $61.16 $47.62 $47.62 $47.62 $47.62 $45.12 $42.48 $42.48 $42.48 $38.62 $38.62 $38.62 $38.62 $0 $20 $40 $60 $80 $100 $120 $140 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Oil Vol ume He dg ed (B bl) Hedging Profile Remainder of 2016 Hedges(1) Oil: ~1.8 million barrels of oil hedged for remainder of 2016 at weighted average floor and ceiling prices of $42/Bbl and $61/Bbl, respectively – Over 50% of oil hedged for remainder of 2016 Natural Gas: 8.0 Bcf of natural gas hedged for remainder of 2016 at weighted average floor and ceiling of $2.60/MMBtu and $3.53/MMBtu, respectively – Approximately 44% of natural gas hedged for remainder of 2016 2017 Hedges(1) Oil: ~1.6 million barrels of oil hedged for 2017 ($39/Bbl floor and $48/Bbl ceiling) Natural Gas: 13.2 Bcf of natural gas hedged for 2017 ($2.34/MMBtu floor and $3.42/MMBtu ceiling) 52 Oil Hedges (Costless Collars) Natural Gas Hedges (Costless Collars) (1) At May 3, 2016.
Strong, supportive bank group led by Royal Bank of Canada Borrowing base reduced on May 3, 2016 from $375 million to $300 million based on December 31, 2015 reserves using commodity price estimates prescribed by bank group First and only reduction in conforming borrowing base during two years of declining commodity prices All other provisions remain unchanged, including costs to borrow funds No further restrictions on Matador’s ability to access borrowings available under revolving credit facility No borrowings outstanding at May 3, 2016 Net Debt/Adjusted EBITDA(1)(2) of 1.5x at March 31, 2016 Financial covenant Maximum Total Debt to Adjusted EBITDA(2) Ratio of not more than 4.25:1.00 53 Credit Agreement Status (1) Net debt is equal to debt outstanding less available cash. (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
54 Summary and 2016 Guidance (as Affirmed May 3, 2016) (1) For operations only. Does not include capital expenditures associated with the HEYCO merger or two associated joint ventures. (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) Estimated 2016 Adjusted EBITDA is based upon the midpoint of 2016 production guidance range as provided on February 3, 2016 and affirmed on May 3, 2016. Estimated average realized prices for oil and natural gas used in these estimates were $39.75/Bbl (WTI oil price of $43.75/Bbl less $4.00/Bbl of estimated price differentials) and $2.37/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period April through December 2016. Plan to run 3 rigs in the Delaware Basin throughout 2016 Delaware Basin drilling expected to focus on Wolf and Rustler Breaks Wolfcamp development and further delineation of Ranger, Arrowhead and Twin Lakes prospect areas No Eagle Ford and minimal Haynesville non-operated drilling activity expected in 2016 Q1 2016 production results were consistent with forecasts; steadier growth profile for Q2 through Q4 expected rather than uneven or “lumpy” production projected at Analyst Day Estimate oil production to be up ~10 to 12% sequentially in Q2; estimate Q4 2016 will be 34% higher than Q4 2015 Estimate natural gas production to be up ~5 to 7% sequentially in Q2; may decline in 2H 2016 Actual 2015 Results 2016 Guidance % Change Capital Spending $482 million(1) $325 million - 33% Total Oil Production 4.5 million Bbl 4.9 to 5.1 million Bbl + 11% Total Natural Gas Production 27.7 Bcf 26.0 to 28.0 Bcf - 3% Total Oil Equivalent Production 9.1 million BOE 9.2 to 9.8 million BOE + 4% Adjusted EBITDA(2) $223 million $120 to $130 million(3) - 44%
Appendix
56 Eagle Ford – “Oil Bank” Note: All acreage at May 3, 2016. 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 Harris Newman Pena ZLS Carroll Lloyd Hurt Sojourner Sickenius Lyssy Falls City Pawelek Danysh Bishop-Brogan Campbellton-Haverlah Matador Resources Acreage Thiel Martin EAGLE FORD ACREAGE TOTALS ~39,000 gross / ~28,100 net acres EAGLE FORD “EAST” Measured Depth: 17,000’ – 18,000’ 80-acre spacing EAGLE FORD “CENTRAL” Measured Depth: 15,500’ – 16,500’ 40-50 acre spacing EAGLE FORD “WEST” Measured Depth: 12,500’ – 14,500’ 40-50 acre spacing
Note: All acreage at May 3, 2016. Haynesville Operations 57 5 gross (0.6 net) wells expected to be drilled and completed in the Haynesville in 2016 Estimated capital expenditures of ~$4 million 9 gross (1.9 net) Elm Grove wells operated by Chesapeake turned to sales in early 2016 ˗ Initial rates of ~13.5 MMcf/d of natural gas with drilling and completion costs under $7 million per well Haynesville and Cotton Valley average daily natural gas production of 46.7 MMcf/d in Q1 2016, a 14% sequential increase as compared to 41.0 MMcf/d in Q4 2015 2016 Haynesville Non-Op Program 2015 Haynesville Non-Op Program 22 gross (1.9 net) wells turned to sales throughout Tier 1 Haynesville in 2015 Includes 9 gross (1.6 net) wells turned to sales on Elm Grove properties operated by Chesapeake in 2015 (shown on map at left) ˗ Chesapeake deferred first production on 9 gross (1.9 net) Elm Grove wells drilled and completed in 2015 until early Q1 2016 Currently Producing Currently Drilling Anticipated Future Wells Producing Wells Currently Drilling or Completing Anticipated Future Wells 14N 12W 15N 11W Elm Grove Development – Chesapeake Operated Matador Acreage
58 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). 59
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 60 New Rig Technology for Horizontal Drilling – Saving Time and Money!
Future Bit Technology – The Evolution of the PDC bit 61 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
Optimizing Artificial Lift Operations Across the Delaware Basin Using ESP’s to Optimize Production 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 Quiet operation in environmentally sensitive areas Able to unload offset frac water even more effectively than gas lift in wells with lower GOR and high reservoir deliverability 62 Optimizing Gas Lift Operations Numerous 2nd Bone Spring wells on gas lift Accelerates production while reducing LOE Lower maintenance costs than beam pump Helps wells recover faster from offset fracs Very efficient with high GOR wells 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. 0 250 500 750 1,000 1,250 1,500 4/24/2015 6/13/2015 8/2/2015 9/21/2015 11/10/2015 12/30/2015 2/18/2016 8/ 8t hs Oil B bl/D ay ESP Install Replacement ESP Cimarron #134 produced 126,000 BO in 10 months (3rd BSPG)
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 63
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 James A. Rolfe - Of Counsel, Kendall Law Group - Retired United States Attorney, Northern District of Texas Law Michael C. Ryan - Partner, Berens Capital Management - Former Director, Matador Resources Company International Business and Finance Special Board Advisors – Expertise and Stewardship 64
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 37 years Since 2003 Craig N. Adams EVP – Land, Legal & Administration - Baker Botts L.L.P., Thompson & Knight LLP 23 years Since 2012 Van H. Singleton, II EVP – Land - Southern Escrow & Title, VanBrannon & Associates 19 years Since 2007 Bradley M. Robinson SVP of Reservoir Engineering and CTO - Schlumberger, S.A. Holditch & Associates, Inc., Marathon 39 years Since Inception Billy E. Goodwin SVP of Operations - Samson, Conoco 31 years Since 2010 G. Gregg Krug SVP 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 27 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 65
66 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 the Company’s 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, preliminary 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.
(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 (gain) 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 4Q 2015 1Q 2016 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) $ (230,401) $ (107,654) Interest expense 1,396 1,616 673 1,649 2,070 5,869 7,229 6,586 7,197 Total income tax provision (benefit) 9,536 10,634 16,504 27,701 (26,390) (89,350) (33,305) 1,677 - Depletion, depreciation and amortization 24,030 31,797 35,143 43,767 46,470 51,768 45,237 35,370 28,923 Accretion of asset retirement obligations 117 123 130 134 112 132 182 307 264 Full-cost ceiling impairment - - - - 67,127 229,026 285,721 219,292 80,462 Unrealized (gain) loss on derivatives 3,108 5,234 (16,293) (50,351) 8,557 23,532 (6,733) 13,909 6,839 Stock-based compensation expense 1,795 1,834 1,038 857 2,337 2,794 1,755 2,564 2,243 Net loss (gain) on asset sales and inventory impairment - - - - 97 - - (1,005) (1,065) Adjusted EBITDA $ 56,345 $ 69,464 $ 66,814 $ 70,320 $ 50,146 $ 66,680 $ 58,027 $ 48,299 $ 17,209 (In thousands) 1Q 2014 2Q 2014 3Q 2014 4Q 2014 1Q 2015 2Q 2015 3Q 2015 4Q 2015 1Q 2016 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 $ 22,611 $ 18,358 Net change in operating assets and liabilities 21,729 (15,221) (586) 56 (45,234) 40,843 (20,846) 16,254 (8,059) Interest expense, net of non-cash portion 1,396 1,616 673 1,649 2,070 5,869 6,678 6,285 6,897 Current income tax (benefit) provision 1,275 1,539 (156) (2,525) - - (295) 3,254 - Net (income) loss attributable to non-controlling interest in subsidiary - - - 17 (36) (75) (45) (105) 13 Adjusted EBITDA $ 56,345 $ 69,464 $ 66,814 $ 70,320 $ 50,146 $ 66,680 $ 58,027 $ 48,299 $ 17,209 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. 67
(In thousands) 2008 2009 2010 2011 2012 2013 2014 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 ($679,785) Interest expense - - 3 683 1,002 5,687 5,334 21,754 Total income tax (benefit) provision 20,023 (9,925) 3,521 (5,521) (1,430) 9,697 64,375 (147,368) Depletion, depreciation and amortization 12,127 10,743 15,596 31,754 80,454 98,395 134,737 178,847 Accretion of asset retirement obligations 92 137 155 209 256 348 504 734 Full-cost ceiling impairment 22,195 25,244 - 35,673 63,475 21,229 - 801,166 Unrealized loss (gain) on derivatives (3,592) 2,375 (3,139) (5,138) 4,802 7,232 (58,302) 39,265 Stock-based compensation expense 665 656 898 2,406 140 3,897 5,524 9,450 Net (gain) loss on asset sales and inventory impairment (136,977) 379 224 154 485 192 - (908) Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $262,943 $223,155 (In thousands) 2008 2009 2010 2011 2012 2013 2014 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 $208,535 Net change in operating assets and liabilities (17,888) 15,717 (2,230) (12,594) (9,307) 6,210 5,978 (8,980) Interest expense, net of non-cash portion - - 3 683 1,002 5,687 5,334 20,902 Current income tax (benefit) provision 10,448 (2,324) (1,411) (46) - 404 133 2,959 Net (income) loss attributable to non-controlling interest in subsidiary - - - - - - 17 (261) Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $262,943 $223,155 Year Ended December 31, Year Ended December 31, 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. 68
69 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 March 31, 2016 At December 31, 2015 At December 31, 2014 PV-10 (in millions) $501.9 $541.6 $1,043.4 Discounted Future Income Taxes (in millions) (6.3) (12.4) (130.1) Standardized Measure (in millions) $495.6 $529.2 $913.3