Exhibit 99.1
Investor Presentation
May 2013
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.
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Company Summary
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) 55.9 million common shares
Share Price(1) $9.65/share
Market Capitalization(1) $539.1 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(2)
Adjusted EBITDA(3) $115.9 million $155 to $175 million(2)
| (1) |
|
As of May 15, 2013 |
(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) 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
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Matador History
Predecessor Entities
Foran Oil & Matador Petroleum
?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
Matador Today
Matador Resources Company
?Founded by Joe Foran in 2003 with 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
?Relatively early in the play, redeployed capital into the Eagle Ford, acquiring over 30,000 net acres for approximately $100 million, most in 2010 and 2011
?Capital spending focused on developing Eagle Ford and transition to oil
?IPO in February 2012 (NYSE: MTDR) had net cash proceeds of approximately $136.6 million
| (1) |
|
Tom Brown purchased by Encana in 2004 |
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Matador Resources Snapshot
Average Daily Production(1) 10,897 BOE/d
Oil Production(1) (% total) 5,115 Bbl/d (47%)
Gas Production(1) (% total) 34.7 MMcf/d (53%)
Proved Reserves @ 3/31/13 23.6 million BOE
% Proved Developed 60%
% Oil 45%
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) 161,997 acres
Net Acreage(2) 103,480 acres
Engineered Drilling Locations(3)(4) 873 gross / 413 net
| (1) |
|
Average daily production for the three months ended March 31, 2013 |
| (2) |
|
At May 15, 2013 |
| (3) |
|
At December 31, 2012 |
(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.
~78% 2013E CapEx
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Investment Highlights
Strong Financial Position and Prudent Risk Management
High Quality Asset Base in Attractive Areas
Eagle Ford provides immediate oil-weighted value and upside
Expanding acreage position in Southeast New Mexico and West Texas
Other key assets provide long-term option value on natural gas, with Haynesville, Bossier and Cotton Valley assets all essentially held by production (HBP)
Proven Management and Technical Team and Active Board of Directors
Management averaging over 25 years of industry experience
Board with extensive industry experience and expertise as well as significant company ownership
Strong record of stewardship for nearly 30 years
Strong Growth Profile with Increasing Focus on Oil / Liquids
Oil production up almost five-fold in 2011 and up almost eight-fold in 2012
2013E capital expenditure program focused on oil and liquids exploration and development
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Matador’s Continued Growth
TOTAL OIL AND
TOTAL OIL PRODUCTION(1) NATURAL GAS REVENUES(1) ADJUSTED EBITDA(1)(2)
1,900 $230.0 $165.0
$156.0 $115.9 1,214 millionsmillions in in
$67.0 $49.9
$30.6 $34.0 $23.6
$18.4 154 $19.0 $15.2
$14.0 $8.1
22 37 30 33
2007 2008 2009 2010 2011 2012 2013E 2007 2008 2009 2010 2011 2012 2013E 2007 2008 2009 2010 2011 2012 2013E
Growth Since the IPO
(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
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Growth in PV-10(1) from Proved Reserves
millions—10, PV
2008 (2) 2009 (2) 2010 (2) 2011 (2) 2012 (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
9
Haynesville Total Resource Potential – Price Sensitivity
$800
Haynesville—Tier 2 (Undrilled), $millions $700
Haynesville—Tier 1 (Undrilled), $millions $98
$600 Haynesville Proved Producing, $millions
$500 $ millions
, $400
| (1) |
|
10 $489
- $18 PV $300
$200 $258
$142 $100 $84
$26 $76 $110
$50 $59
$25 $42 $0
$3.00 $4.00 $4.50 $5.00 $6.00 $8.00 Gas Price(2), $/Mcf
(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
10
Eagle Ford
South Texas
Eagle Ford and Austin Chalk Overview
Proved Reserves @ 3/31/13 14.5 million BOE
% Proved Developed 50%
% Oil / Liquids 73%
Daily Oil Production(2) 5,047 Bbl/d
Gross Acres(3) 41,302 acres
Net Acres(3) 27,720 acres
Eagle Ford(3)(4) 27,720 acres
Austin Chalk(3)(4) 17,171 acres
2013E Anticipated Drilling 27.4 net wells
2013E CapEx Budget $242.7 million
Engineered Drilling Locations(3)(5) 274 gross / 221 net
| (1) |
|
Total drilled and completed wells operated by Matador as of March 31, 2013 |
| (2) |
|
Average daily oil production for the three months ended March 31, 2013 |
| (3) |
|
At May 15, 2013 |
(4) Some of the same leases cover the net acres shown for Eagle Ford and Austin Chalk. Therefore, the sum for both formations is not equal
to the total net acreage
(5) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and
estimated lateral lengths, costs and well spacing using objective criteria for designation
Drilled and completed 38 gross / 36.5 net operated wells to date(1)
Acreage positioned in some of the most active counties for Eagle Ford and Austin Chalk
One rig running currently, primarily focused on oil and liquids; expect to return to two-rig program in September 2013 2013E capital expenditure program focused on oil and liquids development Proved reserves growth from 4.7 million BOE at December 31, 2011 and less than 0.1 million BOE at December 31, 2010
12
Value of Proved Reserves Up 70% and Shifting to Oil Over Past Year
Cotton Valley SE New Mexico
$5.8 million, 1% $2.0 million, 0%
SE New Mexico
$2.4 million, 1% Haynesville
Cotton Valley $21.8 million, 5%
$19.5 million, 8%
Haynesville Eagle Ford
$96.6 million, 39% $130.2 million, 52% Eagle Ford
$393.6 million, 93%
December 31, 2011 December 31, 2012
PV-10(1): $248.7 million(2) PV-10(1): $423.2 million(3)
(Standardized Measure = $215.5 million) (Standardized Measure = $394.6 million)
Proved Producing Reserves PV-10(1): $154.1 million Proved Producing Reserves PV-10(1): $297.5 million
(1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix
| (2) |
|
Future undiscounted net revenue of $494.8 million using YE 2011 SEC pricing of $94.65/Bbl oil and $3.731/MMBtu gas |
| (3) |
|
Future undiscounted net revenue of $704.2 million using YE 2012 SEC pricing of $91.21/Bbl oil and $2.757/MMBtu gas |
13
Eagle Ford Properties are in Good Neighborhoods
Highlights
?Matador’s acreage in counties with robust transaction activity – “good neighborhoods”
?Transaction values ranging from $10,000 to $30,000 per acre
?Matador’s Eagle Ford position approximately 28,000 net acres
?Acreage in both the eastern and western areas of the play
?Approximately 90% of acreage in prospective oil and liquids windows
?Acreage offers potential for Austin Chalk, Buda, Pearsall and other formations
?Good reputation with land and mineral owners
Note: All Matador acreage at May 15, 2013 and all other acreage based on public information as of April 2013
14
Eagle Ford Properties
EAGLE FORD ACREAGE TOTALS EAGLE FORD EAST Nickel
Ranch
41,302 gross / 27,720 net acres 7,730 gross / 6,330 net acres
Bexar Hennig
Uvalde San Antonio Gonzales Medina
EOG OPERATED, MTDR WI ~21% Lewton 11,588 gross / 2,240 net acres Finney
Keseling Love
Wilson Cowey
GLASSCOCK (WINN) RANCH RCT Wilson
Atascosa Repka Dewitt
8,891 gross / 8,891 net acres
Lyssy
Sickenius Karnes Danysh
Zavala Frio MRC/EOG
Pawelek
Glasscock OIL FAIRWAY
Ranch
Shelton Goliad Pena ZLS Newman Martin Ranch
La Salle
Dimmit Northcut
COMBO LIQUIDS /
GAS FAIRWAY Bee
Troutt
Affleck Live Oak McMullen
Sutton
EAGLE FORD WEST
Matador Resources Acreage
Webb 13,093 gross / 10,259 net acres
DRY GAS FAIRWAY
Note: All acreage at May 15, 2013
15
2012 Operated Eagle Ford Completion Results – 24 Hour IP Tests
Well Name County Completion Date Perforated Length(1) Top Perf(2) Frac Stages Oil IP(3)(4) Gas IP(3)(4) Oil Equiv IP(5) Choke Pressure
Total (ft.) (ft.) (Bbl/day) (Mcf/day) (BOE/day) (inch) (psi)
2012 Wells
Martin Ranch A 8H La Salle 1/28/2012 6,092 9,559 21 1,089 831 1,228 26/64 1,750
Martin Ranch A 6H La Salle 2/8/2012 6,509 9,550 22 689 1,714 975 26/64 1,650
Martin Ranch A 7H La Salle 2/12/2012 4,902 9,502 17 609 481 689 26/64 1,040
Martin Ranch B 4H La Salle 2/18/2012 3,801 9,701 13 595 968 756 26/64 1,320
Matador Sickenius Orca 1H Karnes 3/16/2012 5,712 10,897 19 785 540 875 26/64 820
Northcut A 1H La Salle 3/23/2012 4,446 9,209 15 583 592 682 26/64 1,000
Matador Danysh Orca 1H Karnes 4/1/2012 4,962 11,537 17 1,012 1,126 1,200 26/64 1,175
Northcut A 2H La Salle 5/1/2012 4,503 9,273 15 758 761 885 24/64 950
Matador Pawelek Orca 1H Karnes 6/5/2012 6,103 11,231 20 670 739 793 16/64 2,510
Matador Pawelek Orca 2H Karnes 6/7/2012 6,202 11,240 28 861 755 987 16/64 2,460
Matador Danysh Orca 2H Karnes 6/10/2012 5,115 11,331 17 750 746 874 16/64 2,675
Glasscock Ranch 1H Zavala 6/27/2012 5,352 7,166 18 307 0 307 pump 140
Matador K. Love Orca 1H DeWitt 8/10/2012 5,077 13,048 17 1,793 2,171 2,155 16/64 5,280
Matador K. Love Orca 2H DeWitt 8/11/2012 4,871 12,830 17 1,757 2,126 2,111 16/64 5,900
Northcut B 2H LaSalle 9/6/2012 4,777 9,131 16 410 315 463 16/64 1,175
Northcut B 1H LaSalle 9/12/2012 4,798 9,085 16 423 169 451 16/64 1,500
Matador Sickenius Orca 2H Karnes 9/16/2012 5,982 10,829 25 851 556 944 16/64 2,000
Martin Ranch A 12H LaSalle 10/4/2012 4,897 9,507 21 640 1,955 966 16/64 1,680
Matador K. Love Orca 4H DeWitt 11/4/2012 4,012 12,611 14 1,509 841 1,649 16/64 4,900
Matador K. Love Orca 3H DeWitt 11/6/2012 4,777 12,787 16 1,456 1,585 1,720 16/64 4,775
Martin Ranch B 13H LaSalle 11/22/2012 5,364 9,476 23 519 162 546 14/64 2,125
Martin Ranch B 9RH LaSalle 11/25/2012 5,364 9,428 23 482 240 522 14/64 2,000
Frances Lewton 2H DeWitt 12/5/2012 6,277 13,072 21 1,178 4,203 1,879 14/64 6,150
Matador Cowey Orca 1H DeWitt 12/9/2012 3,332 13,593 13 580 3,325 1,134 12/64 8,000
Northcut A 4H LaSalle 12/18/2012 4,592 9,069 16 395 139 418 14/64 1,580
Average 5,113 18.4 828 Bbl/day 1,082 Mcf/day 1,008 BOE/day
1) Total length of perforated lateral from the first perforation to the last perforation
2) Top perf is measured depth
3) Rates as reported to the Texas Railroad Commission via W-2 or G-1 form
4) Rates are based on actual, stabilized, 24 hour production on a constant choke size
5) Oil equivalent rates are based on a 6:1 ratio of six Mcf of gas per one Bbl of oil
16
Well Improvement with Evolution of Frac Design
Eagle Ford East Offsetting Wells: Example 1
1,000
900
Fourth Generation Design
First Generation Design
800
700
Bbl/d 600
Rate, 500
Production 400
300
200
100
0
0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000
Cumulative Oil Production, Bbl
Eagle Ford Middle Offsetting Wells: Example 2
1,000
900
Third Generation Design
Second Generation Design
800
700
Bbl/d 600
Rate, 500
Production 400
300
200
100
0
0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000
Cumulative Oil Production, Bbl
Eagle Ford Middle Offsetting Wells: Example 3
1,000
900
Fourth Generation Deisgn
Second Generation Design
800
Bbl/d 700
600
Rate, 500
Production 400
300
200
100
0
0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000
Cumulative Oil Production, Bbl
Recent Eagle Ford West Well Performance
with Fourth Generation Frac
Oil Prod Gas Prod Flowing Press
600 1,400
Install Packer
1,200
500
1,000
400
PSI
Mcf/d 800
Gas, 300
and 600 Pressure,
200
Bbl/d 400
Oil,
100
200
0 0
0 5,000 10,000 15,000 20,000 25,000
Cumulative Production, Bbl Oil and Mcf Gas (First 120 Days)
Note: First well on this lease
Vertical Depth: 7,424 ft.
Lateral Length: 4,762 ft.
17
Eagle Ford Well Costs Declined During 2012 – Western Acreage
Note: Wells are displayed in chronological order. Wells drilled and completed using two casing strings. Well drilling and completions costs only; costs do not include pipelines and lease facilities.
18
Eagle Ford Well Costs Declined During 2012 – Eastern Acreage
Note: Wells are displayed in chronological order. Wells drilled and completed using two casing strings. Well drilling and completions costs only; costs do not include pipelines and lease facilities.
19
Average Frac Stage Cost per Well
$450,000
Bauxite White Sand Resin-Coated Sand
$400,000
$350,000
$300,000
Cost $250,000
Stage
Average $200,000 $150,000
$100,000
$50,000
$0
| 1 |
|
2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 |
Note: Wells are displayed in chronological order; includes all Matador operated wells drilled and completed through December 31, 2012
20
Eagle Ford Well Estimated ROR as a Function of EUR and Well Cost
$90.00/Bbl NYMEX oil; $3.00/Mcf NYMEX natural gas
Western Acrege
Eastern Acrege
Note: Individual well economics only. NGL price differential +$1.85/Mcf. Oil price differential +$7.00/Bbl.
21
Recent Technical Advancements in the Eagle Ford
Rotary Steerable Tools
Drilling time in curve and lateral reduced by two days
Measurement While Drilling (MWD) telemetry closer to drill bit
Improves ability to stay in “sweet-spot”
Removes sumps and high-angle curves
Improved frac design
Generation 5 frac design
25 to 40 foot fracture spacing (20% to 100% more fractures than generation 2 design)
40 Bbl/ft frac fluid (100% increase from generation 2 design)
1,700 lbs/ft (50% increase from generation 2 design)
Cut frac stage cost by 20% (compared to generation 2 design)
Zipper fracs
Daily fixed cost reduced by 20%
Increases drainage efficiency
Choke size reduction
Delays effects of pressure-dependent formation permeability
Increases Estimated Ultimate Recovery (EUR)
Delays installation of artificial lift
Lowers bottom-hole pressure differential
Mitigates damage to proppant pack
Artificial lift
Pumping units with pump-off controllers on low gas/oil ratio (GOR) wells
Gas-lift valves on high gas/oil ratio (GOR) wells
22
Drilling Times and Efficiencies
First 4 Wells
Recent Wells
| * |
|
Bold wells utilized rotary steerable systems |
Note: As of January 25, 2013
23
Emerging Multi-Pay Area in Eagle Ford Oil Fairway and MTDR Acreage
Guadalupe
Bexar
San Antonio Gonzales
Uvalde Medina
Multi-Pay Fairway
with Pearsall, Austin Chalk and Buda potential Wilson
Dewitt
Atascosa
Zavala Frio Karnes
Goliad
OIL FAIRWAY
Bee
Dimmit La Salle
McMullen Live Oak
Webb Matador Resources Acreage
DRY GAS FAIRWAY
Note: All acreage at May 15, 2013
24
Delaware Basin
Southeast New Mexico and West Texas
Southeast New Mexico / West Texas
Gross Acres(1) 30,605 acres
Net Acres(1) 20,303 acres
Foothold of existing production and reserves
Acreage position in good neighborhoods,
surrounded by other operators’ ongoing
INDIAN RANGER- drilling
DRAW EDDY LEA QUERECHO ? During March and April 2013, acquired
14,700 gross and 12,500 net acres in Lea
and Eddy Counties, New Mexico
Company considers approximately 22,900
gross and 18,100 net acres to be prospective
for multiple oil and liquids-rich targets,
including the Wolfcamp and Bone Spring
LOVING plays
WOLF
| (1) |
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Total acreage in Southeast New Mexico and West Texas at May 15, 2013 |
26
Wolfbone Play in the Delaware Basin (West Texas) Stratigraphic Column
Horizontal Targets
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
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
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
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%
Note: Information from public sources
27
Ranger Prospect Area: Proposed Wolfbone
Multi-Zone Exploration Program and Surrounding Results
Bone Spring / Upper
Wolfcamp
Concho Concho Type Log
LLS
Condor State #1H 0.2 2000
GR(CTR) LLD
Condor State #1H 0150 0.2 2000
| 2 |
|
2nd ndBoneBone Spring Spring |
AmtexAmtex Energy Energy IPIP (Oct(Oct 2012) 2012)
0
| 5 |
|
| 7 |
|
TeapotTeapot 2H 2H 339339 BOPD BOPD 7
| 2 |
|
2nd ndBoneBone Spring Spring |
0
0
0
11 mo.mo. cum: cum: Concho 8
5252 MBO;MBO;3737 MMcf MMcf AirCobra 12 #2H Bone Spring Lime.
3rd Bone Spring 0
| 5 |
|
| 2 |
|
| 8 |
|
Cimarex Energy 17 mo.cum:
Cimarex Energy 246 MBO; 132 MMcf
Mallon 35 Fed 4H 0
0
| 5 |
|
Mallon 35 Fed 4H 8
| 3 |
|
3rd rdBoneBone Spring Spring |
19 mo.cum:
0
19 mo.cum: 5
| 7 |
|
33 MBO; 20 MMcf 8
33 MBO; 20 MMcf
0
0
XOG Operating Concho Concho 0
33 RiversRivers Oper Oper (Vertical well) HaumeaHaumeaSt.St. #2H #2H 9
EagleEagle22 StateState 6H 6H Jordan B #1 2 2nd ndBoneBone Spring Spring
0
| 5 |
|
| 2 |
|
| 3 |
|
3rd rdBoneBone Spring Spring Wolfcamp CompletedCompleted MarchMarch 2013 2013 9 1st Bone Spring Sand |
22 mo.mo. cum: cum: 20 years cum: NowNow FlowingFlowing Back Back
0
32 MBO; 13 MMcf 0
| 5 |
|
32 MBO; 13 MMcf 386 MBO; 5 Bcf 9
0
| 5 |
|
| 7 |
|
9
0 nd
0
0
Legacy Operating 0 2 Bone Spring Sand
| 1 |
|
Lee Unit 4H
0
3rd Bone Spring 5
| 2 |
|
0
| 1 |
|
16 mo.cum:
63 MBO; 55 MMcf
0
0
| 5 |
|
0
| 1 |
|
Cimarex Energy
0
Lynch 23 Fed #1H 5
| 7 |
|
0
Concho 1
3rd Bone Spring (Vertical well)
13 mo.cum:
0
Neuhaus 14 Fed #2 0
0
| 1 |
|
142 MBO; 99 MMcf 1 3rd Bone Spring Sand
Wolfcamp
0
Concho 8 years cum: 5
| 2 |
|
| 1 |
|
Stratojet 31 State #1H 156 MBO; 2 Bcf 1 Wolfcamp
2nd Bone Spring
0
0
| 5 |
|
| 1 |
|
18 mo.cum: 1
316 MBO; 378 MMcf Proposed location for
Note: All acreage at May 15, 2013. Well information from public sources as of April 2013. Matador 2013 test well
28
Wolf Leasehold: Proposed Wolfbone
Multi-Zone Exploration Program and Surrounding Results
Chesapeake Chesapeake Chesapeake
Johnson 1-86 (1H) Johnson 1-88 Lov #1H Johnson 1-76 (1H)
Wolfcamp Wolfcamp Wolfcamp
17 mo.cum: 10 mo.cum: 22 mo.cum:
122 MBO; 344 MMcf 72 MBO; 295 MMcf 140 MBO; 475 MMcf
Chesapeake
Johnson 1-75 Lov #1H
Wolfcamp
| 6 |
|
mo.cum: |
51 MBO; 120 MMcf
OXY
Reagan-McElvain #1H
Wolf Energy Spud 6/27/2012
Dorothy White #1 IP: 570 BOPD 2.6 MMcf/d
(Vertical well) 2 mo.cum:
3rd BS / Upr Wolfcamp 37 MBO; 92 MMcf
17 years cum:
25 MBO; 92 MMcf Energen
Katie 1-72
Wolf Energy Wolfcamp
Wolf #1 5 mo.cum:
(Vertical well) 40 MBO; 120 MMcf
3rd BS / Upr Wolfcamp
33 years cum:
58 MBO; 620 MMcf Energen
Bushmaster 1-58
Wolfcamp
| 4 |
|
mo.cum: |
Energen 27 MBO; 100 MMcf
Grayling 1-69
IP: 791 BOPD 7.3 MMcf/d
3,500 psi FTP Energen
| 4 |
|
mo.cum: 40 MBO; 370 MMcf Black Mamba 1-57 |
on restricted choke Wolfcamp
| 3 |
|
mo.cum: |
61 MBO; 180 MMcf
Proposed location for
Matador 2013 test well
Note: All acreage at May 15, 2013. Well information from public sources as of April 2013.
29
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
TIER 3: 2 – 4 Bcf
BOSSIER
CADDO TIER 2: 4 – 6 Bcf
BIENVILLE
TIER 1: 6 – 10+ Bcf
MTDR CV
Horizontal
T. Walker #1H
Elm Grove Cotton Valley: Tier 1 Haynesville:
49 Net Locations 50 Net Locations
Matador Operated Acreage: 12,568 gross, 5,737 net
Acreage: 9,980 gross, 9,800 net Locations: 397 gross, 50 net (@ 7
Locations: 71 gross, 49 net (@ 3-4 locations/section)
locations/section) Potential Resource(1): 250 – 310 Bcf net
Potential Resource(1): 135 – 170 Bcf net MTDR Haynesville
L.A. Wildlife #1H RED RIVER
MTDR Haynesville
Williams (BLM) #1H
(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
Note: All acreage at May 15, 2013
31
Haynesville Well Economics – Tier 1 Area
%
Return,
of
Rate
Natural Gas Price, $/Mcf
Note: Individual well economics only. D&C cost = drilling and completion cost. Natural gas price differential = ($0.85)/Mcf.
32
Cotton Valley Horizontal Well Economics
Note: Individual well economics only. D&C cost = drilling and completion cost. Natural gas price differential = (10%)
33
Gracie
Wyoming, Utah and Idaho
Matador Gracie Project Total Prospect Acreage
WYOMING IDAHO UTAH
WYOMING
IDAHO UTAH
Crawford Federal #1H
61,897 gross acres 30,492 net acres
?Crawford Federal #1H WYOMING completion scheduled for summer 2013
Note: All acreage at May 15, 2013
35
Southwest Wyoming Stratigraphy and Target Zones
Crawford Federal #1:
Drilled straight hole in late 2011
2% TOC
Cretaceous Shales 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%
13% TOC
Meade Peak Shale ?Porosity Average: 3.0–5.0%
Micro-Darcy Permeability
Drilled 2,500-ft horizontal lateral in late
2012; plan to complete in summer 2013
Lamberson, Paul, 1982, The Fossil
Basin and its Relationship to
the Absaroka Thrust System,
Wyoming and Utah, RMAG
36
Financial Overview
2013 Financial Expectations
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 Operating Costs(3)
??Estimated average unit costs per BOE
? Production taxes/marketing = $4.30
? Lease operating = $9.50
? G&A = $5.20
? Operating cash costs, excluding interest = $19.00
? DD&A = $30.00
Oil and Natural Gas Revenues(2) (millions)
Adjusted EBITDA(1)(2) (millions)
(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) |
|
Consistent with updated guidance provided on May 8, 2013. |
38
2013 Capital Investment Plan Highlights
?2013 projected capital expenditures of approximately $325 million
??Drill and complete or participate in 48 gross/31.3 net wells in 2013
??Including 31.0 gross/25.8 net Eagle Ford Shale and 3.0 gross/3.0 net Bone Spring/Wolfcamp
??Also includes 3.0 gross/1.6 net exploratory Austin Chalk, Buda and Edwards tests
??Includes approximately $25 million for pipelines/facilities and $40 million for land/seismic acquisition
??Compares to 2012 drilling program of 58 gross / 27.6 net wells for $334.6 million in capital expenditures, including 28 gross / 24.5 net Eagle Ford Shale wells
??2013 expenditures are estimated to be funded 50% through cash flows and 50% through borrowings under revolving credit facility
?2013 Production Expectations
??Oil production of 1.8 to 2.0 million barrels – mid-point up 58% from 1.2 million barrels in 2012
??Natural gas production of 11.0 to 12.0 Bcf – mid-point down 8% from 12.5 Bcf in 2012
?2013 Financial Expectations(1)
??Oil and natural gas revenues of $220 to $240 million – mid-point up 47% from $156.0 million in 2012
??Adjusted EBITDA(2) of $155 to $175 million – mid-point up 42% from $115.9 million in 2012
??Total borrowings outstanding estimated to be $320 to $330 million at YE 2013
?Maintain financial discipline by funding 2013 capital expenditures through operating cash flows and borrowings under revolving credit facility
??2013 oil production volumes well hedged to protect cash flows below about $88/Bbl oil price
??Current borrowings are less than 2x estimated 2013 operational cash flows
(1) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA 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 these 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
39
First Quarter 2013 Earnings Release Highlights
Production Growth
?Oil production of 460,000 Bbl for the quarter ended March 31, 2013, a year-over-year increase of 130% from 200,000 Bbl of oil produced in the quarter ended March 31, 2012 and a sequential increase of 8% from 426,000 Bbl of oil produced in the quarter ended December 31, 2012
?Average daily oil equivalent production of approximately 10,900 BOE per day for the quarter ended March 31, 2013, consisting of about 5,100 Bbl of oil per day and 34.7 MMcf of natural gas per day, a year-over-year BOE increase of 36% from approximately 8,000 BOE per day, consisting of about 2,200 Bbl of oil per day and 34.9 MMcf of natural gas per day, for the quarter ended March 31, 2012
Financial Performance
?Total realized revenues of $59.7 million in the first quarter of 2013, including $0.4 million in realized gain on derivatives, a year-over-year increase of 85% from total realized revenues of $32.2 million, including $3.1 million in realized gain on derivatives, reported in the first quarter of 2012
?Oil and natural gas revenues of $59.3 million for the quarter ended March 31, 2013, a year-over-year increase of 103% from $29.2 million reported for the quarter ended March 31, 2012
?Adjusted EBITDA(1) of $40.7 million for the quarter ended March 31, 2013, a year-over-year increase of 91% from $21.3 million reported for the quarter ended March 31, 2012
Acreage Acquisitions
?During March and April 2013, acquired an additional 14,700 gross and 12,500 net acres in Lea and Eddy Counties, New Mexico
?Consider approximately 22,900 gross and 18,100 net acres to be prospective for multiple oil and liquids-rich targets, including the Wolfcamp and Bone Spring play
(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix
40
Financial Performance
Average Daily Production Oil and Natural Gas Revenues
(BOE/d) ($ in mm)
12,000 $70.0
10,897
$59.3
10,000 $60.0
8,023 $50.0
8,000
6,300 $40.0
6,000 $29.2
$30.0
4,000 3,417
$20.0 $13.7
$9.2
2,000 $10.0
0 $0.0
1Q10 1Q11 1Q12 1Q13 1Q10 1Q11 1Q12 1Q13
Adjusted EBITDA(1) Total Realized Revenues(2)
($ in mm) ($ in mm)
$45.0 $70.0
$40.7
$40.0 $59.7
$60.0
$35.0
$50.0
$30.0
$25.0 $40.0
$21.3 $32.2
$20.0 $30.0
$15.0
$10.1 $20.0 $15.5
$10.0 $6.1 $9.5
$5.0 $10.0
$0.0 $0.0
1Q10 1Q11 1Q12 1Q13 1Q10 1Q11 1Q12 1Q13
(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 |
41
2013 and 2014 Hedging Profile
At May 8, 2013, Matador had: Oil
1.08 million barrels of oil hedged for remainder of 2013 at weighted average floor and ceiling of $88/Bbl and $107/Bbl, respectively
5.8 Bcf of natural gas hedged for remainder of 2013 at weighted average Oil floor and ceiling of $3.25/MMBtu and $4.52/MMBtu, respectively
6.7 million gallons of natural gas liquids hedged for remainder of 2013 at weighted average price of $1.21/gal
1.68 million barrels of oil, 8.4 Bcf of natural gas and 3.7 million gallons of natural gas liquids hedged for 2014
Oil Hedges (Costless Collars)
2013 2014
Total Volume Hedged by Ceiling (Bbl) 920,000 1,680,000
Weighted Average Price ($ / Bbl) $109.30 $98.55
Total Volume Hedged by Floor (Bbl) 920,000 1,680,000
Weighted Average Price ($ / Bbl) $87.39 $87.79
Oil Hedges (Swaps)
2013 2014
Total Volume Hedged (Bbl) 160,000 -
Weighted Average Price ($ / Bbl) $90.43 -
Natural Gas Hedges (Costless Collars)
2013 2014
Total Volume Hedged by Ceiling (Bcf) 5.80 8.40
Weighted Average Price ($ / MMBtu) $4.52 $5.15
Total Volume Hedged by Floor (Bcf) 5.80 8.40
Weighted Average Price ($ / MMBtu) $3.25 $3.32
Natural Gas Liquids (NGLs) Hedges (Swaps)
2013 2014
Total Volume Hedged (gal) 6,739,200 3,708,000
Weighted Average Price ($ / gal) $1.21 $1.44
Note: Hedged volumes shown in table for 2013 are for remainder of 2013; volumes shown in table for 2014 are for full calendar year.
42
Reserves Summary at March 31, 2013
?Total proved reserves: 23.6 million BOE at March 31, 2013, including 10.7 million Bbl of oil and 77.5 Bcf of natural gas
?Oil reserves grew 88% to 10.7 million Bbl from 5.7 million Bbl at March 31, 2012
?PV-10(1) increased 33% to $438.1 million from $329.6 million at March 31, 2012, despite removal of close to 100 Bcf of proved undeveloped Haynesville shale gas reserves at June 30, 2012
?Oil reserves comprised 45% (1 Bbl = 6 Mcf basis) of total proved reserves at March 31, 2013, up from 17% at March 31, 2012
?Eagle Ford reserves comprised 93% of total PV-10(1) at March 31, 2013 as compared to 74% at March 31, 2012 and 93% at December 31, 2012
?Sequential growth:
??Proved developed oil reserves grew 13% to 5.4 million Bbl at March 31, 2013 from 4.8 million Bbl at December 31, 2012
??PV-10(1) increased 4% to $438.1 million at March 31, 2013 from $423.2 million at December 31, 2012
(1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix
43
Appendix
Board of Directors and Special Board Advisors – Expertise and Stewardship
Board Members Professional Experience Business Expertise
and Advisors
Dr. Stephen A. Holditch — Professor Emeritus and Former Head of Dept. of Petroleum Engineering, Texas A&M University
Director — Founder and Former President S.A. Holditch & Associates Oil & Gas Operations
— Past President of Society of Petroleum Engineers
David M. Laney — Past Chairman, Amtrak Board of Directors Law & Investments
Lead Director — Former Partner, Jackson Walker LLP
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 International Business and
— Partner, Berens Capital Management
Director Finance
Margaret B. Shannon — Retired VP and General Counsel, BJ Services Co. Law and
Director — Former Partner, Andrews Kurth LLP Corporate Governance
— Retired President and CEO, Interstate Battery System International, Inc.
Carlos M. Sepulveda, Jr. — Chairman of the Board, Triumph Bancorp, Inc. Business and Finance
Director — Director and Audit Chair, Cinemark Holdings, Inc.
Marlan W. Downey — Retired President, ARCO International
Special Board Advisor — Former President, Shell Pecten International Oil & Gas Exploration
— Past President of American Association of Petroleum Geologists
Wade I. Massad — Managing Member, Cleveland Capital Management, LLC
Special Board Advisor — Former EVP Capital Markets, Matador Resources Company Capital Markets
— Formerly with KeyBanc Capital Markets and RBC Capital Markets
Edward R. Scott, Jr. — Former Chairman, Amarillo Economic Development Corporation Law, Accounting and Real
Special Board Advisor — Law Firm of Gibson, Ochsner & Adkins Estate Development
W.J. “Jack” Sleeper, Jr. Oil & Gas Executive
— Retired President, DeGolyer and MacNaughton (Worldwide Petroleum Consultants)
Special Board Advisor Management
45
Proven Management Team – Experienced Leadership
Management Team Background and Prior Affiliations Industry Matador
Experience Experience
Joseph Wm. Foran —Matador Petroleum Corporation, Foran Oil Company, 33 years Since Inception
Founder, Chairman and CEO J Cleo Thompson Jr. and Thompson Petroleum Corp.
David E. Lancaster —Schlumberger, S.A. Holditch & Associates, Inc., 34 years Since 2003
EVP and COO Diamond Shamrock
Matthew V. Hairford —Samson, Sonat, Conoco 29 years Since 2004
EVP and Head of Operations
David F. Nicklin —ARCO, Senior Geological Assignments in UK, Angola, 42 years Since 2007
Executive Director of Exploration Norway and the Middle East
Bradley M. Robinson —Schlumberger, S.A. Holditch & Associates, Inc., 36 years Since Inception
VP and CTO Marathon
Craig N. Adams —Baker Botts L.L.P., Thompson & Knight LLP 20 years Since 2012
VP and General Counsel
Ryan C. London —Matador Resources Company 9 years Since 2003
VP and General Manager
Kathryn L. Wayne —Matador Petroleum Corporation, Mobil 28 years Since Inception
Controller and Treasurer
46
South Texas: Pearsall Play
CHK – Wilson C #1H
3.2 MMcf/d, 334 Bbl/d Cabot/Osaka JV
97 Bbls/MMcf Osaka 35% ($14,285/ac. – 17,500ac.) Abnd. For EGFD 6 Horiz. Drilled
| 3 |
|
Permits |
Schorp-White Ranch #101H 1st full mo. – 4,535 Bbl, 43MMcf RH Pickens #101H 1st full mo. – 5,339 Bbl, 16MMcf
Liq uid pot
en Cheyenne tia EOG Tests l in Chilipitin LTD #101H Permit crea Cheyenne 500 – 2000 Bbl/mo. ses Rockin S #1H Temp. Abnd. or EGFD Horiz.
Completed 12-21-2012
Valence Oper.
| 4 |
|
drilling wells and |
| 2 |
|
Permits |
Murray #1H CHK
IP: 258Bbl/d, 106Mcf/d Ralph Edwards E #1H Completed- Jan ‘13
IP: 135 Bbl/d, 1752 Mcf/d 17/64” w/ 2797 Ftp 5 mo.cum 6,917 Bbl, 153 MMcf CHK—Avant D #1H
Suspended, waiting on Anadarko further completion work
EOG Rosetta Newfield Robert Hindes #1H
Tom Hanks #1
Chesapeake Completed and IP: 263 Bbl/d, 4.3 MMCF/d
Shell waiting on hook-up. 26/64” w/ 1977 Ftp CHK – Brownlow #1H
Gas Activity Could not test
Cheyenne
Indio Tanks Horiz. program
4 horizs w/ 700 to 450 Bbl/d Top Pearsall Depth Map Plus 4 to 6 MMcf/d CI = 500’ Yields 83 to 63 Bbls/MMcf Cromwell #1H – 5 mo. 4 MBbl, 71 MMcf A Williams B #1H – 5 mo. 20 MBbl, 129 MMcf ZCW #1H – 5 mo. – 17 MBbl, 154 Mcf
Note: All acreage at May 15, 2013. Well data from public information as of April 2013.
47
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.
48
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.
Year Ended December 31, Three Months Ended March 31,
(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) $5,676 ($ 27,596) $3,801 ($ 15,505)
Interest expense ——— 3 683 1,002 — 106 308 1,271
Total income tax provision (benefit) — 20,023 (9,925) 3,521 (5,521) (1,430) 2,975 (6,906) 3,064 46
Depletion, depreciation and amortization 7,889 12,127 10,743 15,596 31,754 80,454 3,362 7,111 11,205 28,232
Accretion of asset retirement obligations 70 92 137 155 209 256 38 39 53 81
Full-cost ceiling impairment — 22,195 25,244 — 35,673 63,475 — 35,673 — 21,230
Unrealized loss (gain) on derivatives 211 (3,592) 2,375 (3,139) (5,138) 4,802 (6,093) 1,668 3,270 4,825
Stock-based compensation expense 220 665 656 898 2,406 140 186 53 (363) 492
Net loss (gain) on asset sales and inventory impairment — (136,977) 379 224 154 485 — —— -
Adjusted EBITDA $8,090 $18,411 $15,184 $23,635 $49,911 $115,923 $6,142 $ 10,148 $21,338 $ 40,672
Year Ended December 31, Three Months Ended March 31,
(In 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 $7,673 $ 12,732 $5,110 $ 32,229
Net change in operating assets and liabilities 209 (17,888) 15,717 (2,230) (12,594) (9,307) (1,531) (2,690) 15,920 7,126
Interest expense ——— 3 683 1,002 — 106 308 1,271
Current income tax provision (benefit) — 10,448 (2,324) (1,411) (46) — 0 0 0 46
Adjusted EBITDA $8,090 $18,411 $15,184 $23,635 $49,911 $115,923 $6,142 $ 10,148 $21,338 $ 40,672
49
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 March 31, 2013, December 31, 2012, March 31, 2012, December 31, 2011, December 31, 2010, December 31, 2009 and December 31, 2008 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 March 31, 2013, December 31, 2012, March 31, 2012, December 31, 2011, December 31, 2010, December 31, 2009 and December 31, 2008 were, in millions, $31.1, $28.6, $42.2, $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.
50