UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________________
FORM 8-K
_________________________________
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of Earliest Event Reported) August 20, 2013
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Matador Resources Company
(Exact name of registrant as specified in its charter)
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Texas | 001-35410 | 27-4662601 | ||
(State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) | ||
5400 LBJ Freeway, Suite 1500, Dallas, Texas | 75240 | |
(Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: (972) 371-5200
Not Applicable
(Former name or former address, if changed since last report)
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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 7.01 | Regulation FD Disclosure. |
Matador Resources Company expects to make presentations concerning its business to potential investors. The materials to be utilized during the presentations are furnished as Exhibit 99.1 hereto and incorporated herein by reference.
The information furnished pursuant to this Item 7.01, including Exhibit 99.1, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.
Item 9.01 | Financial Statements and Exhibits. |
(d) Exhibits
Exhibit No. | Description of Exhibit | ||
99.1 | Presentation Materials. | ||
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
MATADOR RESOURCES COMPANY | ||||||
Date: August 20, 2013 | By: | /s/ David E. Lancaster | ||||
Name: | David E. Lancaster | |||||
Title: | Executive Vice President | |||||
Exhibit Index
Exhibit No. | Description of Exhibit | ||
99.1 | Presentation Materials. | ||
Investor Presentation August 2013 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 our financial and operational performance: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop our current reserves; our costs of operations, delays and other difficulties related to producing oil, natural gas and natural gas liquids; our ability to make acquisitions on economically acceptable terms; availability of sufficient capital to execute our business plan, including from our future cash flows, increases in our borrowing base and otherwise; weather and environmental conditions; and other important factors which could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. For further discussions of risks and uncertainties, you should refer to Matador’s SEC filings, including the “Risk Factors” section of Matador’s most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. Matador undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after the date of this presentation, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. All forward-looking statements are qualified in their entirety by this cautionary statement. Cautionary Note – The Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. Potential resources are not proved, probable or possible reserves. The SEC’s guidelines prohibit Matador from including such information in filings with the SEC.
Company Summary
4 Company Overview Completed IPO of 14,883,334 shares (12,209,167 primary) including overallotment at $12.00/share in March 2012 Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 55.8 million common shares Share Price(2) $17.03/share Market Capitalization(2) $951.0 million 2012 Actual 2013 Guidance Capital Spending $335 million $325 million Total Oil Production 1.214 million barrels 1.8 to 2.0 million barrels Total Natural Gas Production 12.5 billion cubic feet 11.0 to 12.0 billion cubic feet Oil and Natural Gas Revenues $156.0 million $220 to $240 million(3) Adjusted EBITDA(4) $115.9 million $155 to $175 million(3) (1) As reported in the Form 10-Q for the quarter ended June 30, 2013 filed on August 9, 2013 (2) As of August 16, 2013 (3) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December 2013 (4) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix
Founded by Joe Foran in 1983 Foran Oil funded with $270,000 in contributed capital from 17 friends and family members Sold to Tom Brown, Inc.(1) in June 2003 for an enterprise value of $388 million in an all-cash transaction Foran Oil & Matador Petroleum 5 Matador History Matador Resources Company Founded by Joe Foran in 2003 with $6 million, a proven management and technical team and board of directors Grown through the drill bit, with focus on unconventional reservoir plays, initially in Haynesville In 2008, sold Haynesville rights in approximately 9,000 net acres to Chesapeake for approximately $180 million; retained 25% participation interest, carried working interest and overriding royalty interest Redeployed capital into the Eagle Ford, relatively early in the play, acquiring over 30,000 net acres for approximately $100 million, most in 2010 and 2011 2012 and YTD 2013(2) capital spending focused primarily on developing Eagle Ford and transition to oil IPO in February 2012 (NYSE: MTDR) had net cash proceeds of approximately $136 million; 2013E Adjusted EBITDA(3) between $155 million and $175 million In 2013(2), acquired approx. 30,200 gross and 20,700 net Permian Basin acreage (Lea and Eddy Counties, NM) Predecessor Entities (1) Tom Brown purchased by Encana in 2004 (2) Through August 7, 2013 (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 Matador Today
6 Average Daily Production(1) 10,739 BOE/d Oil Production(1) (% total) 5,015 Bbl/d (47%) Gas Production(1) (% total) 34.3 MMcf/d (53%) Proved Reserves @ 6/30/13 38.9 million BOE % Proved Developed 42% % Oil 31% 2013E CapEx $325 million % South Texas ~78% % Oil and Liquids ~98% 2013E Anticipated Drilling 31.3 net wells South Texas 27.4 net wells West Texas / New Mexico 3.0 net wells Gross Acreage(2) 174,372 acres Net Acreage(2) 109,947 acres Engineered Drilling Locations(2)(3) 863 gross / 411 net (1) Average daily production for the six months ended June 30, 2013 (2) At August 7, 2013 (3) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Matador Resources Snapshot ~78% 2013E CapEx
T h o u s a n d Bb l TOTAL OIL AND TOTAL OIL PRODUCTION (1) NATURAL GAS REVENUES (1) ADJUSTED EBITDA (1)(2) $8.1 $18.4 $15.2 $23.6 $49.9 $115.9 $165.0 2007 2008 2009 2010 2011 2012 2013E $14.0 $30.6 $19.0 $34.0 $67.0 $156.0 $230.0 2007 2008 2009 2010 2011 2012 2013E 22 37 30 33 154 1,214 1,900 2007 2008 2009 2010 2011 2012 2013E Matador’s Continued Growth 7 (1) 2013 estimates at midpoint of guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in revenue and Adjusted EBITDA estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December 2013 (2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix in m il li o n s in m il li o n s Growth Since the IPO
$0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 $550 $600 2008 2009 2010 2011 2012 Q2 2013 Growth in PV-10(1) from SEC Proved Reserves $57.65 oil $3.87 gas $75.96 oil $4.38 gas $92.71 oil $4.12 gas $91.21 oil $2.76 gas $88.13 oil $3.44 gas P V -1 0 (1 ) , mil li o n s 8 SEC Pricing Oil, $/Bbl Gas, $/MMBtu $41.00 oil $5.71 gas (2) (2) (2) (2) (2) (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix (2) At December 31 of each respective year (3) At June 30, 2013 (3)
9 SEC Proved Reserves Value Growth Eagle Ford $130.2 million, 52% Haynesville $96.6 million, 39% Cotton Valley $19.5 million, 8% SE New Mexico $2.4 million, 1% June 30, 2013 PV-10(1): $522.3 million $88.13 oil(2), $3.44 gas(2) (Standardized Measure = $477.6 million) Eagle Ford $393.6 million, 93% Haynesville $21.8 million, 5% Cotton Valley $5.8 million, 1% SE New Mexico $2.0 million, 1% December 31, 2012 PV-10(1): $423.2 million $91.21 oil(2), $2.76 gas(2) (Standardized Measure = $394.6 million) December 31, 2011 PV-10(1): $248.7 million $92.71 oil(2), $4.12 gas(2) (Standardized Measure = $215.5 million) Eagle Ford $467.2 million, 89% Haynesville $41.9 million, 8% Cotton Valley $10.3 million, 2% SE New Mexico $2.9 million, 1% (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix (2) Oil prices in $/Bbl; gas prices in $/MMBtu
Eagle Ford South Texas
11 Eagle Ford Overview Proved reserves growth from 4.7 million BOE at December 31, 2011 and less than 0.1 million BOE at December 31, 2010 Drilled and completed 49 gross / 46.5 net operated wells to date(1) Acreage positioned in some of the most active counties for Eagle Ford and Austin Chalk Approximately 16,000 net acres are also prospective for Austin Chalk(3) One rig running currently, primarily focused on oil and liquids; expect to return to two-rig program in late August 2013 ~78% of 2013E total capital expenditure program focused on oil and liquids development in the Eagle Ford Proved Reserves @ 6/30/13 15.7 million BOE % Proved Developed 59% % Oil / Liquids 75% Daily Oil Production(2) 4,974 Bbl/d Gross Acres(3) 38,316 acres Net Acres(3) 26,148 acres 2013E Anticipated Drilling 27.4 net wells 2013E CapEx Budget $242.7 million Engineered Drilling Locations(3)(4) 269 gross / 219 net (1) Total drilled and completed wells operated by Matador as of August 7, 2013; includes 47 gross / 44.5 net Eagle Ford wells and 2 gross / 2.0 net Austin Chalk wells (2) Average daily oil production for the six months ended June 30, 2013 (3) At August 7, 2013 (4) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation
12 Eagle Ford Properties Note: All acreage at August 7, 2013 Uvalde Medina Zavala Frio Dimmit La Salle Webb Bexar Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson EAGLE FORD EAST 6,485 gross / 5,412 net acres EOG OPERATED, MTDR WI ~21% 10,152 gross / 1,891 net acres GLASSCOCK (WINN) RANCH 8,891 gross / 8,891 net acres EAGLE FORD WEST 12,788 gross / 9,954 net acres EAGLE FORD ACREAGE TOTALS 38,316 gross / 26,148 net acres Matador Resources Acreage San Antonio Glasscock Ranch Shelton Newman Martin Ranch Northcut Affleck Troutt Sutton MRC/EOG Pawelek Danysh Sickenius Lyssy Repka RCT Wilson Love Cowey Keseling Lewton Hennig Nickel Ranch Pena COMBO LIQUIDS / GAS FAIRWAY DRY GAS FAIRWAY OIL FAIRWAY
13 Eagle Ford Well Costs and Estimated Ultimate Recovery (“EUR”) Note: All acreage at August 7, 2013. EUR’s represent typical range of results over last 12 months by area. Well costs reflect actual costs of all 2013 wells by area. See pages 14, 15 and 16 for additional information. Uvalde Medina Zavala Frio Dimmit La Salle Webb Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson Matador Resources Acreage San Antonio Glasscock Ranch Shelton Newman Martin Ranch Northcut Affleck Troutt Sutton MRC/EOG Pawelek Danysh Sickenius Lyssy Repka RCT Wilson Love Cowey Keseling Lewton Hennig Nickel Ranch Pena COMBO LIQUIDS / GAS FAIRWAY DRY GAS FAIRWAY OIL FAIRWAY EAGLE FORD “WEST” (p. 14) Well Costs: $6-7 million EUR: 300-500 MBOE EAGLE FORD “EAST” (p. 16) Well Costs: $8-10 million EUR: 600-1,000 MBOE EAGLE FORD “CENTRAL” (p. 15) Well Costs: $7-8 million EUR: 400-500 MBOE
14 Eagle Ford “West” 8,000’ – 9,000’ True Vertical Depth ~240°F DRILLING DAYS (1) FRAC STAGE COST (2) TOTAL WELL COST (3) ($ in thousands) ($ in millions) $9.9 $7.8 $6.8 $6.3 2011 2012 2013 YTD Last Well $247.9 $126.2 $123.4 $105.5 2011 2012 2013 YTD Last Well 19.2 12.6 11.4 8.3 2011 2012 2013 YTD Last Well (4) 2-String Casing Design White Sand Note: “2013 YTD” and “Last Well” – As of August 7, 2013 (1) Excludes any/all wells drilled with a pilot hole. Drilling days are from spud to total depth. Year Classification is based on spud date. (2) Year classification is based on spud date. (3) Excludes any/all wells drilled with a pilot hole. Year classification is based on spud date. (4) Most recent development well – used to exclude a well that is burdened with extra costs associated with drilling the first well on any given lease, for example: constructing a frac pit, building the lease road, etc.
15 Eagle Ford “Central” DRILLING DAYS (1) FRAC STAGE COST (2) TOTAL WELL COST (3) ($ in thousands) ($ in millions) $11.0 $9.4 $7.5 $7.1 2011 2012 2013 YTD Last Well $159.5 $130.1 $119.3 $120.4 2011 2012 2013 YTD Last Well 18.8 20.1 15.4 13.9 2011 2012 2013 YTD Last Well (4) 10,500’ – 11,500’ True Vertical Depth ~300°F 2-String Casing Design White Sand Note: “2013 YTD” and “Last Well” – As of August 7, 2013 (1) Excludes any/all wells drilled with a pilot hole. Drilling days are from spud to total depth. Year Classification is based on spud date. (2) Year classification is based on spud date. (3) Excludes any/all wells drilled with a pilot hole. Year classification is based on spud date. (4) Most recent development well – used to exclude a well that is burdened with extra costs associated with drilling the first well on any given lease, for example: constructing a frac pit, building the lease road, etc.
16 Eagle Ford “East” DRILLING DAYS (1) FRAC STAGE COST (2) TOTAL WELL COST (3) ($ in thousands) ($ in millions) $10.4 $8.4 $8.3 2012 2013 YTD Last Well $219.7 $215.3 $214.6 2012 2013 YTD Last Well 24.7 18.2 16.6 2012 2013 YTD Last Well (4) 12,500’ – 13,500’ True Vertical Depth ~330°F 2-String or 3-String Casing Design Premium Proppant(5) Note: “2013 YTD” and “Last Well” – As of August 7, 2013 (1) Excludes any/all wells drilled with a pilot hole. Drilling days are from spud to total depth. Year Classification is based on spud date. (2) Year classification is based on spud date. (3) Excludes any/all wells drilled with a pilot hole. Year classification is based on spud date. (4) Most recent development well – used to exclude a well that is burdened with extra costs associated with drilling the first well on any given lease, for example: constructing a frac pit, building the lease road, etc. (5) Premium proppant typically used is resin-coated sand which is more expensive than white sand.
Batch Drilling – Reducing Well Costs and Well Times Further 17 Time Savings •Rig Moves ~2 Days •Drilling Efficiencies ~1 Day Total Per Well Time Savings ~3 Days Cost Savings •Rig Moves ~$115,000 •Location ~$60,000 •Drilling Efficiencies ~$125,000 Total Per Well Cost Savings ~$300,000 Approx. $300,000 cost reduction per well when going from single well pad to a 4-well batch drilled pad! Single Well Pad versus Average 4-Well Batch Drilled Pad Note: Company to begin 4-well batch pad drilling on its Martin Ranch lease in late August 2013.
18 Evolution of Matador Frac Design Gen 2 Gen 3 Gen 4 Gen 5 5,770 Bbl 7,825 Bbl 9,550 Bbl 11,750 Bbl 375 Mlbs 500 Mlbs 405 Mlbs 515 Mlbs Fluid Volume Pumped Proppant Pumped 0 ft. 300 ft. Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal wellbore. (1) Mlbs = thousands of pounds of proppant pumped (1)
19 Well Improvement with Evolution of Frac Design Eagle Ford “East” Offsetting Wells: Example 1 Eagle Ford “Central” Offsetting Wells: Example 2 Eagle Ford “Central” Offsetting Wells: Example 3 Eagle Ford “West” Offsetting Wells: Example 4 0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 Pr od uctio n R ate, B bl/ d Cumulative Oil Production, Bbl First Generation Design Third Generation Desgin 0 100 200 300 400 500 600 700 800 0 10,00 20,00 30,00 40,000 50,000 60,000 70,000 80,000 90,000 100,000 Pr od uctio n R ate, B bl/ d Cumulative Oil Production, Bbl Second Generation Design Third Generatio Desgin 0 100 200 3 400 500 600 700 900 1,000 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 Pr od uctio n R ate, B bl/ d Cumulative Oil Production, Bbl Second Generation Design Third Generation Desgin 0 100 200 300 400 500 600 700 800 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 Pr od uctio n R ate, B bl/ d Cumulative Oil Production, Bbl) Second Generation Design Third Generation Desgin Fourth Generation Design
Eagle Ford Well Estimated ROR as a Function of EUR and Well Cost 20 Note: Individual well economics only. NGL price differential +$1.85/Mcf. Oil price differential +$7.00/Bbl. $90.00/Bbl NYMEX oil; $3.00/Mcf NYMEX natural gas
Permian Basin Southeast New Mexico and West Texas
22 Gross Acres(1) 45,964 acres Net Acres(1) 28,340 acres Southeast New Mexico / West Texas Foothold of existing production and reserves Acreage position in good neighborhoods, surrounded by other operators’ ongoing drilling Year to date(2) acquired approximately 30,200 gross and 20,700 net acres primarily in Lea and Eddy Counties, New Mexico Company considers approximately 38,300 gross and 26,300 net acres to be prospective for multiple oil and liquids-rich targets, including the Wolfcamp and Bone Spring plays (1) Total acreage in Southeast New Mexico and West Texas at August 7, 2013, including some tracts not shown on map (2) At August 7, 2013 RANGER- QUERECHO WOLF INDIAN DRAW E D D Y L E A LOVING
23 Wolfbone Play in the Delaware Basin (West Texas) Stratigraphic Column Avalon Shale Depth: 7,900’ – 8,300’ (Oil Window) Density Porosity: 12-14% Thickness: 300-500 ft. Normal Pressure (0.45 psi/ft.) Total Organic Carbon (TOC) 5-8% XRD: 15-20% clay and 40-60% silica IP: 100-270 Bbl/d 200-1,200 Mcf/d Middle Wolfcamp Depth: 11,500’ – 12,000’ Density Porosity: 12-15% Thickness: 200-300 ft. Geopressure (0.7psi/ft.) Total Organic Carbon (TOC) 2-4% Upper Wolfcamp Depth: 10,500’ – 10,600’ (Oil Window) Density Porosity: >10% Thickness: 280-350 ft. Geopressure (0.7psi/ft.) IP: 121-900 Bbl/d 250-3,300 Mcf/d Horizontal Targets 1st 2nd 3rd Bone Spring Depth: 8,500’ – 10,600’ (Oil Window) Density Porosity: >10% Thickness: 10-100 ft. Normal Pressure (0.45 psi/ft.) IP: 10-600 Bbl/d 500-2,500 Mcf/d Note: Information from public sources
Ranger Prospect Area: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Concho Stratojet 31 State #3H 2nd Bone Spring 21 mo.cum: 336 MBbl; 405 MMcf Cimarex Energy Lynch 23 Fed #1H 3rd Bone Spring 18 mo.cum: 163 MBbl; 139 MMcf Legacy Operating Lea Unit 4H 3rd Bone Spring 20 mo.cum: 72 MBbl; 72 MMcf Concho AirCobra 12 #2H 3rd Bone Spring 22 mo.cum: 276 MBbl; 183 MMcf XOG Operating (Vertical well) Jordan B #1 Wolfcamp 20 years cum: 387 MBbl; 5 Bcf Concho (Vertical well) Neuhaus 14 Fed #2 Wolfcamp 8 years cum: 156 MBbl; 2 Bcf 7 7 5 0 8 0 0 0 8 2 5 0 8 5 0 0 8 7 5 0 9 0 0 0 9 2 5 0 9 5 0 0 9 7 5 0 1 0 0 0 0 1 0 2 5 0 1 0 5 0 0 1 0 7 5 0 1 1 0 0 0 1 1 2 5 0 1 1 5 0 0 0 150 GR (CTR) 0.2 2000 LLD 0.2 2000 LLS Log Depth(ft) Log Depth(ft) 7500 7500 7750 7750 8000 8000 8250 8250 8500 8500 8750 8750 9000 9000 9250 9250 9500 9500 9750 9750 10000 10000 10250 10250 10500 10500 10750 10750 11000 11000 11250 11250 11500 11500 Wells 9,000' > HS=0 PETRA 11/28/2012 5:33:57 PM Bone Spring Lime 1st Bone Spring Sand 2nd Bone Spring Sand Wolfcamp Bone Spring / Upper Wolfcamp Type Log 3rd Bone Spring Sand Location of Matador 2013 test well Note: All acreage at August 7, 2013. Well information from public sources as of August 2013. 3 Rivers Oper Eagle 2 State 6H 3rd Bone Spring 5 mo.cum: 54 MBbl; 26 MMcf Cimarex Energy Mallon 35 Fed 4H 3rd Bone Spring 24 mo.cum: 38 MBbl; 29 MMcf Amtex Energy Teapot 2H 2nd Bone Spring 22 mo.cum: 60 MBbl; 50 MMcf Concho Condor State #1H 2nd Bone Spring 3 mo.cum: 38 MBbl; 21 MMcf 24 Devon Ironhouse 19 State #1H 2nd Bone Spring IP: 603 Bbl/d; 298 Mcf
Wolf Leasehold: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Wolf Energy Wolf #1 (Vertical well) 3rd BS / Upr Wolfcamp 33 years cum: 60 MBbl; 640 MMcf Wolf Energy Dorothy White #1 (Vertical well) 3rd BS / Upr Wolfcamp 17 years cum: 25 MBbl; 92 MMcf Shell Johnson 1-88 Lov #1H Wolfcamp 15 mo.cum: 57 MBbl; 239 MMcf Shell Johnson 1-86 (1H) Wolfcamp 27 mo.cum: 158 MBbl; 455 MMcf OXY Reagan-McElvain #1H Wolfcamp IP: 570 Bbl/d 2.6 MMcf/d 6 mo.cum: 81 MBbl; 202 MMcf Shell Johnson 1-76 (1H) Wolfcamp 32 mo.cum: 165 MBbl; 536 MMcf Energen Grayling 1-69 Wolfcamp IP: 791 Bbl/d 7.3 MMcf/d 3,500 psi FTP 10 mo.cum: 70 MBbl; 605 MMcf on restricted choke Energen Black Mamba 1-57 Wolfcamp 13 mo.cum: 178 MBbl; 439 MMcf Proposed location for Matador 2013 test well Shell Owens 1-75 Lov #1H Wolfcamp 15 mo.cum: 89 MBbl; 199 MMcf Energen Bushmaster 1-58 1H Wolfcamp 13 mo.cum: 121 MBbl; 332 MMcf Energen Katie 1-72 Wolfcamp 15 mo.cum: 72 MBbl; 207 MMcf Note: All acreage at August 7, 2013. Well information from public sources as of August 2013. Bone Spring / Upper Wolfcamp Type Log Bone Spring Lime 1st Bone Spring Sand 2nd Bone Spring Sand Wolfcamp 3rd Bone Spring Sand Avalon Shale Base Avalon Shale 25
Haynesville & Cotton Valley Northwest Louisiana and East Texas
Tier 1 Haynesville and Elm Grove Cotton Valley Acreage Positions – Almost all prospective Haynesville acreage is HBP Note: All acreage at August 7, 2013 CADDO BOSSIER BIENVILLE RED RIVER DESOTO Elm Grove Cotton Valley: 49 Net Locations Matador Operated Acreage: 9,980 gross, 9,800 net Locations: 71 gross, 49 net (@ 3-4 locations/section) Potential Resource(1): 135 – 170 Bcf net Tier 1 Haynesville: 50 Net Locations Acreage: 12,568 gross, 5,737 net Locations: 397 gross, 50 net (@ 7 locations/section) Potential Resource(1): 250 – 310 Bcf net MTDR CV Horizontal T. Walker #1H MTDR Haynesville L.A. Wildlife #1H MTDR Haynesville Williams (BLM) #1H TIER 1: 6 – 10+ Bcf TIER 2: 4 – 6 Bcf TIER 3: 2 – 4 Bcf (1) Potential resource should not be considered proved natural gas reserves. Potential resource may be converted to proved natural gas reserves as a result of successful drilling operations and higher natural gas prices Note: Matador does not include any of these potential resources in its proved natural gas reserves at March 31, 2013 27
28 Haynesville Total Resource Potential – Price Sensitivity (1) PV-10 is a non-GAAP measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. All PV-10 values estimated as of March 31, 2013 (2) NYMEX gas price, less property-specific differentials $25 $42 $50 $59 $76 $110$26 $84 $142 $258 $489 $18 $98 $0 $100 $200 $300 $400 $500 $600 $700 $800 $3.00 $4.00 $4.50 $5.00 $6.00 $8.00 PV -1 0( 1) , $ m ill ion s Gas Price(2), $/Mcf Haynesville - Tier 2 (Undrilled), $millions Haynesville - Tier 1 (Undrilled), $millions Haynesville Proved Producing, $millions
0 25 50 75 100 125 150 175 200 225 250 275 300 3 3.5 4 4.5 5 5.5 6 8 Bcf - $8.0 MM D&C Cost 9 Bcf - $8.0 MM D&C Cost 10 Bcf - $8.0 MM D&C Cost 8 Bcf - $9.0 MM D&C Cost 9 Bcf - $9.0 MM D&C Cost 10 Bcf - $9.0 MM D&C Cost 29 Haynesville Well Economics – Tier 1 Area Rate o f Ret u rn, % Natural Gas Price, $/Mcf Note: Individual well economics only. D&C cost = drilling and completion cost. Natural gas price differential = ($0.85)/Mcf.
30 Cotton Valley Horizontal Well Economics Note: Individual well economics only. D&C cost = drilling and completion cost. Natural gas price differential = (10%) 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 R O R, % Natural Gas Price, $/Mcf 4.0 Bcf - $5.6 MM D&C Cost 5.0 Bcf - $5.6 MM D&C Cost 6.0 Bcf - $5.6 MM D&C Cost 4.0 Bcf - $6.6 MM D&C Cost 5.0 Bcf - $6.6 MM D&C Cost 6.0 Bcf - $6.6 MM D&C Cost
Gracie Wyoming, Utah and Idaho
Matador Gracie Project Total Prospect Acreage IDAHO UTAH W YO M IN G W Y O M IN G ID A H O U T A H WYOMING 61,897 gross acres 30,492 net acres Crawford Federal #1H 32 Note: All acreage at August 7, 2013 Crawford Federal #1H completion scheduled for summer 2013
Southwest Wyoming Stratigraphy and Target Zones Lamberson, Paul, 1982, The Fossil Basin and its Relationship to the Absaroka Thrust System, Wyoming and Utah, RMAG 13% TOC Meade Peak Shale Cretaceous Shales 2% TOC Crawford Federal #1: Drilled straight hole in late 2011 Encountered 161’ Meade Peak with 46’ of main pay Recovered 50’ conventional core across pay zone TOCave 4.52% (Maximum 14.2%) Thermally mature: Ro 1.69% Porosity Average: 3.0–5.0% Micro-Darcy Permeability Drilled 2,500-ft horizontal lateral in late 2012; plan to complete in summer 2013 33
Financial Overview
35 2013 Revenue and Adjusted EBITDA(1)(2) Estimated oil and natural gas revenues of $220 to $240 million − Mid-point is an increase of 47% from $156.0 million in 2012 Estimated Adjusted EBITDA(1)(2) of $155 to $175 million − Mid-point is an increase of 42% from $115.9 million in 2012 Adjusted EBITDA(1)(2) growth expected to be impacted by lower oil price realizations and an estimated decrease of approximately $13 million in realized hedging gains compared to 2012 2013 Financial Expectations (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix (2) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December 2013. (3) Midpoint of 2013 annual guidance. Oil and Natural Gas Revenues(2) (millions) Adjusted EBITDA(1)(2) (millions) $19.0 $34.0 $67.0 $156.0 $230.0 $0.0 $50.0 $100.0 $150.0 $200.0 $250.0 2009 2010 2011 2012 2013E $15.2 $23.6 $49.9 $115.9 $165.0 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 $140.0 $160.0 $180.0 2009 2010 2011 2012 2013E (3) (3)
Second Quarter 2013 Earnings Release Highlights 36 Production Growth Increasing Oil Production: Oil production of 447,000 Bbl for the quarter ended June 30, 2013, resulting in a year-over-year increase of 57% from 285,000 Bbl produced in the quarter ended June 30, 2012, and a sequential quarterly decrease of 3% from 460,000 Bbl produced in the quarter ended March 31, 2013. Step-Change in Current Production: Oil and natural gas production for the first five months of 2013 averaged 4,825 Bbl per day and 33.8 MMcf per day, respectively, but increased to an average oil and natural gas production rate for June and July 2013 of 6,200 Bbl per day and 38.4 MMcf per day, respectively, despite an average of 10% to 12% of total production capacity shut in during the first six months of 2013 as a result of pad drilling and simultaneous fracturing operations. BOE Trends: Average daily oil equivalent production of 10,739 BOE per day for the six months ended June 30, 2013, consisting of 5,015 Bbl of oil per day and 34.3 MMcf of natural gas per day, a year-over- year BOE increase of 28% from 8,380 BOE per day, consisting of 2,670 Bbl of oil per day and 34.3 MMcf of natural gas per day, for the six months ended June 30, 2012. Financial Performance Revenue Growth: Oil and natural gas revenues of $58.2 million for the quarter ended June 30, 2013, a year-over-year increase of 61% from $36.1 million reported for the quarter ended June 30, 2012. Increasing Cash Flow: Adjusted EBITDA(1) of $40.8 million for the second quarter of 2013, a year-over- year increase of 46% from $27.9 million reported for the second quarter of 2012. (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix
Second Quarter 2013 Earnings Release Highlights (Cont.) 37 Acreage Acquisitions Acquired approximately 30,200 gross and 20,700 net acres primarily in Lea and Eddy Counties, New Mexico between January 1 and August 7, 2013, bringing the Company’s total acreage position in Southeast New Mexico and West Texas to approximately 46,000 gross and 28,300 net acres. Reserves Total proved oil and natural gas reserves of 38.9 million BOE at June 30, 2013, including 12.1 million Bbl of oil and 160.8 Bcf of natural gas, with a PV-10(1) of $522.3 million (Standardized Measure of $477.6 million). Proved oil reserves increased 80% to 12.1 million Bbl at June 30, 2013, as compared to 6.7 million Bbl at June 30, 2012, and increased 16%, as compared to 10.5 million Bbl at December 31, 2012. Credit Facility Increased the borrowing base to $350.0 million at August 7, 2013 based on the lenders’ review of Matador’s June 30, 2013 oil and natural gas reserves, up from the previous borrowing base of $280.0 million and compared to $245.0 million in borrowings outstanding at June 30, 2013. Downspacing Early results from 40-acre and 50-acre downspacing in the Eagle Ford are very encouraging, and the Company plans additional downspaced wells in the fall of 2013. Annual Guidance Reaffirmed its 2013 annual guidance as revised upwards on May 8, 2013. (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix
38 Financial Performance (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix (2) Includes realized gain on derivatives Oil and Natural Gas Revenues ($ in mm) Total Realized Revenues(2) ($ in mm) Adjusted EBITDA(1) ($ in mm) Average Daily Production (BOE/d) $7.5 $20.9 $36.1 $58.2 $0.0 $10.0 $20.0 $30.0 $40.0 $50.0 $60.0 $70.0 2Q10 2Q11 2Q12 2Q13 $9.1 $21.8 $40.8 $58.4 $0.0 $10.0 $20.0 $30.0 $40.0 $50.0 $60.0 $70.0 2Q10 2Q11 2Q12 2Q13 $5.2 $15.3 $27.9 $40.8 $0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 $35.0 $40.0 $45.0 2Q10 2Q1 2Q12 2Q13 3,733 8,004 8,738 10,582 0 2,000 4,000 6,000 8,000 10,000 12,000 2Q10 2Q11 2Q12 2Q13
39 2013 and 2014 Hedging Profile At August 19, 2013, Matador had: 0.8 million barrels of oil hedged for remainder of 2013 at weighted average floor and ceiling of $88/Bbl and $106/Bbl, respectively 3.3 Bcf of natural gas hedged for remainder of 2013 at weighted average floor and ceiling of $3.19/MMBtu and $4.45/MMBtu, respectively 4.2 million gallons of natural gas liquids hedged for remainder of 2013 at weighted average price of $1.21/gal 2.3 million barrels of oil, 8.4 Bcf of natural gas and 3.7 million gallons of natural gas liquids hedged for 2014 Note: Hedged volumes shown in table for 2013 are for remainder of 2013; volumes shown in table for 2014 are for full calendar year. Oil Hedges (Costless Collars) 2013 2014 Total Volume Hedged by Ceiling (Bbl) 661,200 2,294,000 Weighted Average Price ($ / Bbl) $108.23 $98.92 Total Volume Hedged by Floor (Bbl) 661,200 2,294,000 Weighted Average Price ($ / Bbl) $87.27 $87.75 Oil Hedges (Swaps) 2013 2014 Total Volume Hedged (Bbl) 100,000 - Weighted Average Price ($ / Bbl) $90.43 - Natural Gas Hedges (Costless Collars) 2013 2014 Total Volume Hedged by Ceiling (Bcf) 3.32 8.40 Weighted Average Price ($ / MMBtu) $4.45 $5.15 Total Volume Hedged by Floor (Bcf) 3.32 8.40 Weighted Average Price ($ / MMBtu) $3.19 $3.32 Natural Gas Liquids (NGLs) Hedges (Swaps) 2013 2014 Total Volume Hedged (gal) 4,212,000 3,708,000 Weighted Average Price ($ / gal) $1.21 $1.44
Appendix
Board of Directors and Special Board Advisors – Expertise and Stewardship 41 Board Members and Advisors Professional Experience Business Expertise Dr. Stephen A. Holditch Director - Professor Emeritus and Former Head of Dept. of Petroleum Engineering, Texas A&M University - Founder and Former President, S.A. Holditch & Associates - Past President of Society of Petroleum Engineers Oil & Gas Operations David M. Laney Lead Director - Past Chairman, Amtrak Board of Directors - Former Partner, Jackson Walker LLP Law & Investments Gregory E. Mitchell Director - President and CEO, Toot’n Totum Food Stores Petroleum Retailing Dr. Steven W. Ohnimus Director - Retired VP and General Manager, Unocal Indonesia Oil & Gas Operations Michael C. Ryan Director - Partner, Berens Capital Management International Business and Finance Carlos M. Sepulveda, Jr. Director - Retired President and CEO, Interstate Battery System International, Inc. - Chairman of the Board, Triumph Bancorp, Inc. - Director and Audit Chair, Cinemark Holdings, Inc. Business and Finance Margaret B. Shannon Director - Retired VP and General Counsel, BJ Services Co. - Former Partner, Andrews Kurth LLP Law and Corporate Governance Marlan W. Downey Special Board Advisor - Retired President, ARCO International - Former President, Shell Pecten International - Past President of American Association of Petroleum Geologists Oil & Gas Exploration Wade I. Massad Special Board Advisor - Managing Member, Cleveland Capital Management, LLC - Former EVP Capital Markets, Matador Resources Company - Formerly with KeyBanc Capital Markets and RBC Capital Markets Capital Markets Edward R. Scott, Jr. Special Board Advisor - Former Chairman, Amarillo Economic Development Corporation - Law Firm of Gibson, Ochsner & Adkins Law, Accounting and Real Estate Development W.J. “Jack” Sleeper, Jr. Special Board Advisor - Retired President, DeGolyer and MacNaughton (Worldwide Petroleum Consultants) Oil & Gas Executive Management
Proven Management Team – Experienced Leadership 42 Management Team Background and Prior Affiliations Industry Experience Matador Experience Joseph Wm. Foran Founder, Chairman and CEO - Matador Petroleum Corporation, Foran Oil Company, J Cleo Thompson Jr. and Thompson Petroleum Corp. 33 years Since Inception David E. Lancaster EVP and COO - Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 34 years Since 2003 Matthew V. Hairford EVP and Head of Operations - Samson, Sonat, Conoco 29 years Since 2004 David F. Nicklin Executive Director of Exploration - ARCO, Senior Geological Assignments in UK, Angola, Norway and the Middle East 42 years Since 2007 Craig N. Adams EVP – Land & Legal - Baker Botts L.L.P., Thompson & Knight LLP 20 years Since 2012 Bradley M. Robinson VP and CTO - Schlumberger, S.A. Holditch & Associates, Inc., Marathon 36 years Since Inception Ryan C. London VP and General Manager - Matador Resources Company (Began as intern) 9 years Since 2004 Kathryn L. Wayne Controller and Treasurer - Matador Petroleum Corporation, Mobil 28 years Since Inception
Reserves Summary at June 30, 2013 43 At June 30,(1) At December 31,(1) At June 30,(1) 2013 2012 2012 Estimated proved reserves:(2) Oil (MBbl) 12,128 10,485 6,728 Natural Gas (Bcf) 160.8 80.0 73.9 Total (MBOE)(3) 38,931 23,819 19,052 Estimated proved developed reserves: Oil (MBbl) 6,591 4,764 3,133 Natural Gas (Bcf) 57.8 54.0 54.0 Total (MBOE)(3) 16,221 13,771 12,130 Percent developed 41.7% 57.8% 63.7% Estimated proved undeveloped reserves: Oil (MBbl) 5,537 5,721 3,595 Natural Gas (Bcf) 103.0 26.0 20.0 Total (MBOE)(3) 22,710 10,048 6,922 PV-10(4) (in millions) 522.3$ 423.2$ 303.4$ Standardized Measure (in millions) 477.6$ 394.6$ 281.5$ (1) Numbers in table may not total due to rounding. (2) Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. (3) Thousands of barrels of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. (4) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix.
Southwest Glasscock Ranch Buda Production History Global Geophysical 3D Seismic Survey Area Outline Dan Hughes Heitz 302 3H 6/24/2012 IP: 350 Bbl/d 500 Mcf/d 13 mo.cum: 215,772 Bbl 147 MMcf Dan Hughes Buchanan 1H 4/1/2013 IP: 756 Bbl/d 556 Mcf/d 2 mo.cum: 38,348 Bbl 16 MMcf Dan Hughes Heitz 302 5H 8/1/2012 10 mo.cum: 125,396 Bbl 152 MMcf Crimson Beeler 2H 6/20/2013 IP: 761 Bbl/d 253 Mcf/d Sage Energy Mills-Wood Unit 1H 4/4/2013 IP: 585 Bbl/d 0 Mcf/d 2.5 mo.cum: 12,199 Bbl 26 MMcf Sage Energy Mills 2H 11/28/2012 IP: 889 Bbl/d 650 Mcf/d 8 mo.cum: 57,507 Bbl 30 MMcf Sage Energy Mills 1H 3/5/2013 IP: 959 Bbl/d 541 Mcf/d 2.5 mo.cum: 30,743 Bbl 26 MMcf Dan Hughes Heitz 303 2H 4/21/2012 IP: 351 Bbl/d 665 Mcf/d 14 mo.cum: 180,455 Bbl 168 MMcf Dan Hughes Heitz 1H 12/2/2011 IP: 200 Bbl/d 150 Mcf/d 14 mo.cum: 204,817 Bbl 251 MMcf Dan Hughes Heitz-Fehrenbach 1H 1/25/2013 IP: 85 Bbl/d 200 Mcf/d 6 mo.cum: 4,215 Bbl 210 MMcf US Enercorp Lang 1H 7/4/2012 IP: 165 Bbl/d 200 Mcf/d 15 mo.cum: 3,236 Bbl 29 MMcf Note: All acreage at August 7, 2013. Well information from public sources as of August 2013. 44
45 Adjusted EBITDA Reconciliation This investor presentation includes the non-GAAP financial measure of Adjusted EBITDA. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. “GAAP” means Generally Accepted Accounting Principles in the United States of America. The Company believes Adjusted EBITDA helps it evaluate its operating performance and compare its results of operations from period to period without regard to its financing methods or capital structure. The Company defines Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents the calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively, that are of a historical nature. Where references are forward-looking or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. The Company could not provide such reconciliation without undue hardship because the forward-looking Adjusted EBITDA numbers included in this investor presentation are estimations, approximations and/or ranges. In addition, it would be difficult for the Company to present a detailed reconciliation on account of many unknown variables for the reconciling items.
46 Adjusted EBITDA Reconciliation The following table presents our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. (In thousands) 2007 2008 2009 2010 2011 2012 2010 2011 2012 2013 Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): Net (loss) income ($300) $103,878 ($14,425) $6,377 ($10,309) ($33,261) ($984) $7,153 ($6,676) $25,119 Interest expense - - - 3 683 1,002 - 184 1 1,609 Total income tax provision (benefit) - 20,023 (9,925) 3,521 (5,521) (1,430) (516) (46) (3,713) 32 Depletion, depreciation and amortization 7,889 12,127 10,743 15,596 31,754 80,454 3,702 8,180 19,914 20,234 Accretion of asset retirement obligations 70 92 137 155 209 256 30 57 58 80 Full-cost ceiling impairment - 22,195 25,244 - 35,673 63,475 - - 33,205 - Unrealized loss (gain) on derivatives 211 (3,592) 2,375 (3,139) (5,138) 4,802 2,822 (332) (15,114) (7,526) Stock-based compensation expense 220 665 656 898 2,406 140 161 128 191 1,032 Net loss (gain) on asset sales and inventory impairment - (136,977) 379 224 154 485 - - 60 192 Adjusted EBITDA $8,090 $18,411 $15,184 $23,635 $49,911 $115,923 $5,215 $15,324 $27,926 $40,772 I thousands) 2007 2008 2009 2010 2011 2012 2010 2011 2012 2013 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $7,881 $25,851 $1,791 $27,273 $61,868 $124,228 $29,040 $6,799 $46,416 $51,684 Net change in operating assets and liabilities 209 (17,888) 15,717 (2,230) (12,594) (9,307) (23,824) 8,386 (18,491) (12,553) Interest expense - - - 3 683 1,002 - 184 1 1,609 Current income tax provision (benefit) - 10,448 (2,324) (1,411) (46) - 0 (45) 0 32 Adjusted EBITDA $8,090 $18,411 $15,184 $23,635 $49,911 $115,923 $5,215 $15,324 $27,926 $40,772 Year Ended December 31, Three Months Ended June 30, Year Ended December 31, Three Months Ended June 30,
47 PV-10 Reconciliation PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of the Company’s properties. Matador and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. The PV-10 at June 30, 2013, December 31, 2012, June 30, 2012, December 31, 2011, December 31, 2010, December 31, 2009 and December 31, 2008 were, in millions, $522.3, $423.2, $303.4, $248.7, $119.9, $70.4 and $44.1 respectively, and may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by reducing PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at June 30, 2013, December 31, 2012, June 30, 2012, December 31, 2011, December 31, 2010, December 31, 2009 and December 31, 2008 were, in millions, $44.7, $28.6, $21.9, $33.2, $8.8, $5.3 and $0.8 respectively. We have not provided a reconciliation of PV-10 to Standardized Measure where references are forward- looking, estimates or prospective in nature. We could not provide such a reconciliation without undue hardship on account of many unknown variables for the reconciling items.