 Investor Presentation
Exhibit 99.1
January 2013 |
 2
Disclosure Statements
“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, joint venture partners
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 Annual Report on Form 10-K for the
year ended December 31, 2011. 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. 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.
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.
Safe
Harbor
Statement
–
This
presentation
and
statements
made
by
representatives
of
Matador
Resources
Company
(“Matador”
or
the
Cautionary
Note
–
The
Securities
and
Exchange
Commission
(SEC)
permits
oil
and
gas
companies,
in
their
filings
with
the
SEC,
to
disclose |
 Company Summary |
 Foran
Oil & Matador Petroleum 4
Matador History
Matador Resources Company
Predecessor Entities
(1)
Tom Brown purchased by Encana in 2004
Matador Today
Founded by Joe Foran in 1983
Foran Oil funded with $270,000 in contributed capital from 17 friends and family members 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
Sold to Tom Brown, Inc. in June 2003 for an enterprise value of $388 million
in an all-cash transaction |
 5
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 Delaware Basin in 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 over 28 years
Strong Growth Profile with Increasing Focus on Oil / Liquids
Oil production up almost five-fold in 2011 and projected to increase
approximately eight-fold in 2012 2013E capital expenditure program
focused on oil and liquids exploration and development |
 Matador’s Continued Growth
6
TOTAL OIL AND
TOTAL
OIL
PRODUCTION
(1)
NATURAL GAS REVENUES
ADJUSTED
EBITDA
(2)
(1) 2013E Total Oil Production at the mid-point of 2013 guidance of estimated total oil
production of 1.6 to 1.8 million barrels (2) Adjusted EBITDA is a non-GAAP financial
measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see Appendix |
 Growth
in
PV-10
(1)
from
Proved
Reserves
2008
(2)
2009
(2)
2010
(2)
2011
(2)
2012
(2)
(1) PV-10 is a non-GAAP measure. For a reconciliation of Standardized
Measure (GAAP) to PV-10 (non-GAAP), please see Appendix (2) At
December 31 of each respective year 7
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
$41.00 oil
$5.71
$57.65 oil
$3.87 gas
$75.96 oil
$4.38
$92.71 oil
$4.12
$91.21 oil
$2.76
SEC Pricing
Oil, $/Bbl
Gas, $/MMBtu
gas
gas
gas
gas |
 Eagle Ford
South Texas
Key Operating Areas |
 9
Eagle Ford and Austin Chalk Overview
Acreage positioned in some of the
most active counties for Eagle Ford
and Austin Chalk (including
“Chalkleford”)
Two rigs running, primarily focused on
oil and liquids
2013E capital expenditure program
focused on oil and liquids exploration
and development
Proved Reserves @ 12/31/12
14.3 Million BOE
(1)
% Proved Developed
46%
% Oil / Liquids
72%
Daily Oil Production
(2)
3,259 Bbl/d
Gross Acres
(3)
44,326 acres
Net Acres
(3)
29,555 acres
Eagle Ford
(3)(4)
29,555 acres
Austin Chalk
(3)(4)
17,317 acres
2013E Anticipated Drilling
27.4 net wells
2013E CapEx Budget
$242.7 million
(1)
Compared to 4.7 Million BOE Proved Reserves at December 31, 2012
(2)
Estimated average daily oil production for year ended December 31, 2012 compared to 331 Bbl/d for year
ended December 31, 2011
(3)
As of November 30, 2012
(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 |
 Highlights
10
Eagle Ford Properties are in Good Neighborhoods
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
30,000 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
Frio
Medina
Bexar
Guadalupe
Gonzales
Atascosa
Bee
Goliad
Live Oak
McMullen
La Salle
Zavala
Dimmit
Wilson
Dewitt
OIL FAIRWAY
COMBO LIQUIDS /
GAS FAIRWAY
DRY GAS
FAIRWAY
June 2011
+$14,000 / acre
SHELL / HARRISON RANCH
March 2010
~$10,000 / acre
TALISMAN-STATOIL / ENDURING
October 2010
+$13,000 / acre
CNOOC / CHESAPEAKE
October 2010
+$11,000 / acre
HUNT / MARUBENI
January 2012
+$20,000 / acre
MARATHON / HILCORP
June 2011
+$24,000 / acre
KKR / HILCORP
June 2010
~$10,000 / acre
MARATHON / PALOMA
May 2012
+$30,000 / acre
Matador
Anadarko
EOG
Chesapeake
El Paso
Carrizo
Shell
Petrohawk/BHP
SM Energy
Pioneer
Marathon
TALISMAN-
STATOIL / SM ENERGY
Note: All Matador acreage as of November 30, 2012 and all other acreage based on public
information |
 11
EAGLE FORD EAST
7,568 gross / 6,171 net acres
EOG OPERATED, MTDR WI ~21%
13,055 gross / 2,515 net acres
GLASSCOCK (WINN) RANCH
8,891 gross / 8,891 net acres
EAGLE FORD WEST
14,812 gross / 11,978 net acres
San Antonio
Uvalde
Medina
Zavala
Frio
Dimmit
La Salle
Webb
Bexar
Atascosa
McMullen
Live Oak
Bee
Goliad
Dewitt
Gonzales
Wilson
EAGLE FORD ACREAGE TOTALS
44,326 gross / 29,555 net acres
COMBO LIQUIDS /
GAS FAIRWAY
DRY GAS FAIRWAY
OIL FAIRWAY
Glasscock
Ranch
Shelton
Newman
ZLS
Martin Ranch
Northcut
Affleck
Troutt
Sutton
MRC/EOG
Pawelek
Danysh
Sickenius
Lyssy
Repka
RCT Wilson
Love
Cowey
Keseling
Finney
Lewton
Hennig
Nickel
Ranch
Pena
Eagle Ford Properties
Note: All acreage as of November 30, 2012
Karnes
Matador Resources Acreage |
 2012
Operated Eagle Ford Completion Results – 24 Hour IP Tests
12
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 or to be 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 gas per one Bbl oil
|
 Eagle
Ford Well Costs Declined During 2012 – Eastern Acreage
13
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
1
2
3
4
5
6
7
8
9
10
Total Cost
5000' Normalized Cost
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. |
 Eagle
Ford Well Costs Declined During 2012 – Western Acreage
14
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
1
2
3
4
5
6
7
8
9
10
11
12
Total Cost
5000' Normalized Cost
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.
|
 $0
$50,000
$100,000
$150,000
$200,000
$250,000
$300,000
$350,000
$400,000
$450,000
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
Bauxite
White Sand Resin-Coated Sand
Average Frac Stage Cost per Well
15
Note: Wells are displayed in chronological order; includes all Matador operated wells drilled and
completed through December 31, 2012
|
 Eagle
Ford Well Estimated ROR as a Function of EUR and Well Cost 16
Note: Individual well economics only. NGL price differential +$2.50/Mcf.
Oil price differential +$4.30/Bbl. Estimated Ultimate Recovery (EUR), MBOE
$90.00/Bbl NYMEX oil;
$3.00/Mcf NYMEX natural gas
$8.0
$10.0
$12.0
0
20
40
60
80
100
120
140
160
180
200
100
200
300
400
500
600
700
Well Cost,
millions
$7.0 |
 17
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
–
Increases Stimulated Rock Volume (SRV)
–
Tighter fracture spacing (25% more fractures than previous design)
–
35 Bbl/ft. frac fluid (75% increase from previous design)
–
Zipper Fracs (simultaneous frac operations)
–
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
–
Electric Submersible Pumps (ESP) to accelerate unloading frac fluids
|
 Drilling Times and Efficiencies
18
Note: As of January 25, 2013
* Bold wells utilized rotary steerable systems
First 4 Wells |
 Zavala County
Eagle Ford & Pearsall Trend |
 20
South Texas Multi-Pay Petroleum Systems:
Upside Potential in Zavala County
Note: Information for Pearsall Oil Field sourced from public information
Note: All acreage as of November 30, 2012
Olmos/Navarro
Austin Chalk
Oil and Gas Fields:
Buda
Wilcox
Redhawk
Area
8,891 gross / 8,891 net acres
100% Held By Production (HBP)
All Rights, All Depths
Matador Resources Acreage
Edwards |
 21
Multi-Pay Fairway: Productive and Prospective Pay Zones
Historic Conventional Zones
Olmos-Navarro
Gas and oil fields in shallow section
Austin Chalk
Upper Austin horizontal drilling
Fractured reservoir
Buda
Primarily productive on structure
Fractured reservoir
Edwards
Productive on structure
“New”
Unconventional Zones
“Chalkleford”
(Eagle Ford / Austin Chalk transition zone)
Recent results in Pearsall Field from other operators are positive
Eagle Ford
Lower costs combined with better completion techniques have improved initial
results in northern oil window
Horizontal Buda Drilling
Exploratory play developing to exploit fracturing within the Buda both on and
off structure
Pearsall Shale
Exploratory play, initial test wells now being drilled
Austin Chalk
Del Rio
Edwards
Glen Rose
Rodessa
Pearsall
Sligo
Olmos
Navarro
ANCC
Eagle Ford
Buda
Georgetown |
 22
San Antonio
Emerging Multi-Pay Area in Eagle Ford Oil Fairway and MTDR Acreage
OIL FAIRWAY
OIL FAIRWAY
DRY GAS FAIRWAY
DRY GAS FAIRWAY
Note: All acreage as of November 30, 2012
Multi-Pay Fairway
with Pearsall, Austin Chalk and Buda potential
Matador Resources Acreage |
 Delaware Basin
Southeast New Mexico and West Texas
Key Operating Areas |
 24
Matador Today
Gross
Acres
(1)
15,860 acres
Net
Acres
(1)
7,638 acres
Southeast New Mexico / West Texas
Foothold of existing production and reserves
On August 10, 2012, acquired approx. 4,900
gross and 2,900 net acres prospective for the
Wolfbone play in the Delaware Basin in
Loving County, Texas.
(1)
As of November 30, 2012
RANGER-
QUERECHO
WOLF
INDIAN DRAW |
 25
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
1
st
2
nd
3
rd
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 |
 Wolf
Leasehold: Proposed Wolfbone Multi-Zone Exploration Program and
Surrounding Results Proposed location for
Matador 2013 test well
26
Note: All acreage as of November 30, 2012
Chesapeake
Johnson 1-86 (1H)
Wolfcamp
17 mo.cum:
122 MBO; 344 MMcf
Wolf Energy
Dorothy White #1
(Vertical well)
3
BS
/
Upr
Wolfcamp
Cum Prod.:
17 years
25 MBO; 93 MMcf
Wolf Energy
Wolf #1
(Vertical well)
3 BS
/
Upr
Wolfcamp
Cum Prod.:
33 years
58 MBO; 620 MMcf
Chesapeake
Johnson 1-88 Lov #1H
Wolfcamp
10 mo.cum:
72 MBO; 295 MMcf
Chesapeake
Johnson 1-76 (1H)
Wolfcamp
22 mo.cum:
140 MBO; 475 MMcf
OXY
Reagan-McElvain 1H
Status Unknown
Spud 6/27/2012
Energen
Black Mamba 1-57
Wolfcamp
3 mo.cum:
61 MBO; 180 MMcf
Energen Resources
Grayling 1-69
IP: 791 BOPD
7.3 MMCFD
Anadarko
Black Tip Johnson 1-39(1H)
Wolfcamp
29 mo.cum:
234 MBO; 323 MMcf
rd
rd |
 Ranger
Prospect Area: Proposed Wolfbone Multi-Zone Exploration Program and
Surrounding Results 27
Bone Spring / Upper Wolfcamp
Type Log
Proposed location for
Matador 2013 test well
Note: All acreage as of November 30, 2012
Legacy Operating
Lee Unit 4H
3
Bone Spring
13 mo.cum:
57 MBO; 55 MMcf
Cimarex Energy
Lynch 23 Fed #1H
3
Bone Spring
9 mo.cum:
130 MBO; 99 MMcf
Concho
Stratojet 31 State #1H
2
Bone Spring
11 mo.cum:
243 MBO; 276 MMcf
Concho
AirCobra 12 #2H
3
Bone
Spring
12 mo.cum:
196 MBO; 132 MMcf
XOG Operating
(Vertical well)
Jordan B #1
Wolfcamp
20 years cum:
386 MBO; 5 Bcf
Concho
(Vertical well)
Neuhaus 14 Fed #2
Wolfcamp
8 years cum:
156 MBO; 2 Bcf
rd
nd
rd
rd |
 Haynesville & Cotton Valley
Northwest Louisiana and East Texas
Key Operating Areas |
 Tier 1
Haynesville and Elm Grove Cotton Valley Acreage Positions –
Almost all prospective Haynesville acreage is HBP
CADDO
BOSSIER
BIENVILLE
RED RIVER
TIER 1:
6 –
10+ Bcf
TIER 2:
4 –
6 Bcf
TIER 3:
2 –
4 Bcf
29
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:
12,560
gross,
5,730
net
Locations:
397
gross,
50
net
(@
7
locations/section)
Potential
Resource
(1)
:
250
–
310
Bcf
net
MTDR CV Horizontal
T. Walker #1H
MTDR Haynesville
Williams (BLM) #1H
MTDR Haynesville
L.A. Wildlife #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 this potential resource in its proved natural gas reserves
at September 30, 2012 Note:
All acreage as of November 30, 2012 |
 30
Haynesville Well Economics –
Tier 1 Area
Natural Gas Price, $/Mcf
Note: Individual well economics only. D&C cost = drilling and completion
cost. Natural gas price differential = ($0.85)/Mcf. 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 |
 31
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
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
Key Operating Areas |
 Matador Gracie Project Total Prospect Acreage
54,450 gross acres
26,908 net acres
33
Note: All acreage as of November 30, 2012
Crawford Federal #1H
completion scheduled
for summer 2013
IDAHO
UTAH
WYOMING
WYOMING
Crawford Federal #1H |
 Southwest Wyoming Stratigraphy and Target Zones
Lamberson, Paul, 1982, The Fossil Basin
and its Relationship to the
Absaroka Thrust System,
Wyoming and Utah, RMAG
Meade Peak Shale
Cretaceous Shales
2% TOC
Crawford
Federal
#1:
34
13% TOC
Drilled straight hole in late 2011
Encountered 161’
Meade Peak with 46’
of main pay
Recovered 50’
conventional core
across pay zone
TOC
ave
4.52% (Maximum 14.2%)
Thermally mature: Ro 1.69%
Porosity Average: 3.0–
5.0%
Micro-Darcy Permeability |
 2013 Capital Investment Plan |
 2013
Capital Investment Plan Highlights 36
2013 projected capital expenditures of approximately $310 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
test –
Includes approximately
$25 million for pipelines/facilities and $25 million for land/seismic
acquisition 2013 Production Expectations
–
Oil
production
of
1.6
to
1.8
million
barrels
–
up
about
40%
from
2012
–
Natural
gas
production
of
11.0
to
12.0
Bcf
–
down
about
8%
from
2012
2013 Financial Expectations
–
Oil
and
natural
gas
revenues
(1)
of
$200
to
$220
million
–
up
about
40%
from
estimated
in
2012
–
Adjusted
EBITDA
(1)(2)
of
$140
to
$160
million
–
up
about
33%
from
estimated
in
2012
–
Total borrowings outstanding estimated to be $310 to $320 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 (1) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint
of guidance range using late November 2012 strip prices for oil and natural gas, plus property-specific differentials. Estimated average realized prices
for oil and natural gas were $94.00/Bbl and $4.43/Mcf, respectively (2) Adjusted EBITDA is a
non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see Appendix |
 37
2013 Oil Production
Estimated total oil production of 1.6 to
1.8 million barrels
Increase of approximately 40% from
2012
Oil production expected to decline from
year-end 2012 levels in early 2013
Production delays, shut-ins due to pad
drilling, zipper fracs, etc.
Oil production expected to return to
over 5,000 Bbl/d during second half of
2013
2013
Natural
Gas
Production
Estimated total natural gas production
of 11.0 to 12.0 Bcf
Decrease of approximately 8% from
2012
Gas production expected to remain
relatively flat during 2013, but should
include higher percentage of liquids-
rich gas
2013 Production Expectations
(1) Estimated quarterly average oil and natural gas production at midpoint of
guidance range Oil
Production
(1)
(Bbl/d)
Natural
Gas
Production
(1)
(MMcf/d)
0
1,000
2,000
3,000
4,000
5,000
6,000
1Q13
2Q13
3Q13
4Q13
0.0
10.0
20.0
30.0
40.0
1Q13
2Q13
3Q13
4Q13
– |
 38
2013
Revenue
and
Adjusted
EBITDA
(1)(2)
Estimated oil and natural gas revenues of $200
to $220 million
Increase of approximately 40% from
estimated $145 to $155 million in 2012
Estimated
Adjusted
EBITDA
(1)(2)
of
$140
to
$160
million
Increase of approximately 33% from
estimated $110 to $115 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
Estimated average unit costs per BOE
Production taxes/marketing = $4.10
Lease operating = $8.20
G&A = $4.70
Operating cash costs, excluding interest = $17.00
DD&A = $29.50
2013 Financial Expectations
Oil
and
Natural
Gas
Revenues
(2)
(millions)
Adjusted
EBITDA
(1)(2)
(millions)
$19.0
$34.0
$67.0
$150.0
$210.0
$0.0
$50.0
$100.0
$150.0
$200.0
$250.0
2009
2010
2011
2012E
2013E
$15.2
$23.6
$49.9
$112.5
$150.0
$0.0
$40.0
$80.0
$120.0
$160.0
2009
2010
2011
2012E
2013E
(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and
a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see Appendix
(2) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of guidance range
using late November 2012 strip prices for oil and natural gas, plus property-specific differentials. Estimated average
realized prices for oil and natural gas were $94.00/Bbl and $4.43/Mcf, respectively |
 Funding for 2013 Capital Investment Plan
39
Maintain financial discipline by anticipated funding of 2013 capital expenditures
through operating cash flows and borrowings under revolving credit
facility –
Most of 2013 Eagle Ford program is development drilling and largely de-risked
by 2012 results –
1.5 million barrels of 2013 oil production hedged protecting cash flows below
approximately $88/Bbl oil price
Credit facility status at January 25, 2013
–
Borrowing base of $215 million; total facility size of $500 million; facility
matures in December 2016 –
Borrowings outstanding of $165 million
Ability to request quarterly borrowing base increases with growth in oil and natural
gas reserves throughout 2013
–
Estimated borrowings outstanding of $310 to $320 million at YE 2013
Additional flexibility to manage liquidity
–
No long-term drilling rig or service contract commitments
–
$25 million estimated for discretionary land/seismic acquisitions
–
No significant non-operated well obligations
Simple capital structure; no high-yield debt or convertibles on balance
sheet |
  40
Continued Oil/Liquids Focus to Fuel 2013 Growth
2013 Anticipated Drilling
2013E CapEx
Gross Wells
Net Wells
(in millions)
Total
Total
%
Total
%
South Texas
Eagle Ford Shale
31.0
25.8
82.4%
$217.0
70.1%
Austin Chalk, Buda, Edwards
3.0
1.6
5.1%
$5.9
1.9%
Facilities/Pipelines/Etc.
-
-
-
$19.8
6.4%
Area Total
34.0
27.4
87.5%
$242.7
78.4%
West Texas/Southeast New Mexico
Bone Spring/Wolfcamp
3.0
3.0
9.6%
$30.2
9.8%
Facilities/Pipelines/Etc.
-
-
-
$5.4
1.7%
Area Total
3.0
3.0
9.6%
$35.6
11.5%
Northwest Louisiana
Haynesville Shale
10.0
0.5
1.6%
$5.1
1.7%
Southwest Wyoming
Meade Peak Shale
1.0
0.4
1.3%
$1.0
0.3%
Other
Land/Seismic/Etc.
-
-
-
$25.0
8.1%
Total
48.0
31.3
100.0%
$309.4
100.0%
|
 41
EAGLE FORD EAST
7,568 gross / 6,171 net acres
EOG OPERATED, MTDR WI ~21%
13,055 gross / 2,515 net acres
GLASSCOCK (WINN) RANCH
8,891 gross / 8,891 net acres
EAGLE FORD WEST
14,812 gross / 11,978 net acres
San Antonio
Medina
Zavala
Frio
Dimmit
La
Salle
Webb
Bexar
Atascosa
McMullen
Dewitt
Gonzales
Wilson
EAGLE FORD ACREAGE TOTALS
44,326 gross / 29,555 net acres
COMBO LIQUIDS /
GAS FAIRWAY
DRY GAS FAIRWAY
OIL FAIRWAY
Glasscock
Ranch
Shelton
Newman
ZLS
Martin
Ranch
Northcut
Affleck
Troutt
Sutton
MRC/EOG
Pawelek
Danysh
Sickenius
Lyssy
Repka
RCT
Wilson
Love
Cowey
Keseling
Finney
Lewton
Hennig
Nickel
Ranch
Pena
Matador Resources Acreage
2013 South Texas Drilling Plan
Note: All acreage values at November 30, 2012. Net wells reflect
Matador’s working interest ownership Karnes
13
2
2
1
3
4 (Non-Op)
4
1 (Buda –
Non-Op)
1 (Edwards –
Non-Op)
1
1
1 (Austin Chalk)
Potential Remaining Eagle Ford Drilling Locations
214 gross/164 net locations
Tier 1 –
107 gross/78 net locations (80-acre spacing)
Tier 2 –
107 gross/86 net locations (primarily Glasscock Ranch and
Sutton, both HBP, 80 to 120-acre spacing)
No Eagle Ford locations estimated for Atascosa acreage
Numbers do not include any potential locations for other horizons –
e.g., Austin Chalk, “Chalkleford”, Buda, Pearsall
*At December 31, 2012
# -
Gross wells planned in 2013; All Matador
operated Eagle Ford wells unless noted
otherwise
34 gross/27.4 net wells planned in 2013 |
 Delaware Basin Acreage and 2013 Drilling Plan
RANGER
LOVING
WOLF
1
1
1
42
DELAWARE BASIN PROSPECTIVE ACREAGE
7,498 gross / 4,928 net acres
RANGER
1,955 gross / 1,562 net acres
Ranger A2
Primary Target: Wolfcamp Shale
Ranger A1
Primary Target: 2nd Bone Spring Sand
# -
Matador operated wells planned in 2013
3 gross/3 net horizontal wells planned in 2013
Wolf 1
Primary Target: Wolfcamp Shale
WOLF
5,203 gross / 2,977 net acres
Matador’s acreage position as of November 30, 2012 shown in red. Note: Certain
additional Matador acreage in West Texas/Southeast New Mexico not considered prospective
as of November 30, 2012 |
 Financials |
 January 7, 2013 Operational Update
44
Matador announced that its average production rate during the month of December 2012
was approximately 5,800 barrels of oil per day and 34.6 million cubic feet of
gas per day, or approximately 11,500 BOE per day.
The average oil rate for December of 5,800 barrels per day was about 10% higher
than the midpoint of the Company’s 2012 exit rate guidance of 5,000 to
5,500 barrels per day There are no other changes to the Company’s guidance
for its 2012 or 2013 results The Company also announced an increase in its borrowing base to $215
million based on its lenders’ review of the Company’s proved oil and natural gas
reserves at September 30, 2012 |
 Recent
Production and Financial Highlights 45
Record results in Q3 2012
–
Oil production of 303,000 Bbl, a sequential quarterly increase of 6% from 285,000
Bbl produced in Q2 2012 and a year-over-year increase of
7-fold –
25%
sequential
increase
in
oil
reserves
to
8.4
million
Bbl
and
20%
sequential
increase
in
PV-10
(1)
of
proved reserves to $363.6 million (Standardized Measure of $333.9 million)
–
Average daily oil equivalent production of 8,838 BOE per day, including 3,291 Bbl
of oil per day and 33.3 MMcf of natural gas per day
–
Oil production of 3,291 Bbl per day, up 7-fold from 465 Bbl per day in Q3 2011;
gas production of 33.3 MMcf per day down about 14% from Q3 2011 and flat to
Q2 2012 –
Total realized revenues, including hedging, of $41.4 million, a
year-over-year increase of 119%; oil and natural gas revenues of
$38.0 million, a year-over-year increase of 118% –
Adjusted EBITDA
(2)
of $28.6 million, a year-over-year increase of 137%
Nine months ended September 30, 2012
–
Total
realized
revenues,
including
hedging,
of
$114.4
million,
a
year-over-year
increase
of
103%;
oil
and natural gas revenues of $103.3 million, a year-over-year increase of
99% –
Adjusted EBITDA
(2)
of $77.9 million, a year-over-year increase of 107%
(1)
PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10, see Appendix (2)
Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a
reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see Appendix
|
 46
2013 and 2014 Hedging Profile
1.5 million barrels of oil hedged for 2013
at weighted average floor and ceiling of
$88/Bbl and $107/Bbl, respectively
4.7 Bcf of natural gas hedged at weighted
average floor and ceiling of $3.34/MMBtu
and $4.84/MMBtu, respectively
4.9 million gallons of natural gas liquids
hedged at weighted average price of
$0.79/gal
As of January 25, 2013, Matador has
840,000 barrels of oil hedged for 2014 at
weighted average floor and ceiling of
$86/Bbl and $100/Bbl, respectively
Oil Hedges (Costless Collars)
FY 2013
Total Volume Hedged by Ceiling (Bbl)
1,260,000
Weighted Average Price ($ / Bbl)
$110.26
Total Volume Hedged by Floor (Bbl)
1,260,000
Weighted Average Price ($ / Bbl)
$87.14
Oil Hedges (Swaps)
FY 2013
Total Volume Hedged (Bbl)
240,000
Weighted Average Price ($ / Bbl)
$90.43
Natural Gas Hedges (Costless Collars)
FY 2013
Total Volume Hedged by Ceiling (Bcf)
4.65
Weighted Average Price ($ / MMBtu)
$4.84
Total Volume Hedged by Floor (Bcf)
4.65
Weighted Average Price ($ / MMBtu)
$3.34
Natural Gas Liquids (NGLs) Hedges (Swaps)
FY 2013
Total Volume Hedged (gal)
4,864,800
Weighted Average Price ($ / gal)
$0.79 |
 Reserves Summary –
December 31, 2012
47
Total
proved
reserves:
23.8
million
BOE
(142.9
Bcfe)
at
December
31,
2012,
including
10.5
million
Bbl
of
oil and 80.0 Bcf of natural gas
Oil reserves grew 176% to 10.5 million Bbl from 3.8 million Bbl at December 31,
2011 PV-10
(1)
increased
70%
to
$423.2
million
from
$248.7
million
at
December
31,
2011,
despite
removal
of
close to 100 Bcf of proved undeveloped Haynesville shale gas reserves at June 30,
2012 Oil
reserves
comprised
44%
(1
Bbl
=
6
Mcf
basis)
of
total
proved
reserves
at
December
31,
2012,
up
from
12% at December 31, 2011
Eagle
Ford
reserves
comprised
93%
of
total
PV-10
(1)
at December 31, 2012 as compared to 52% at
December 31, 2011
Sequential growth from 9/30/2012 to 12/31/2012
–
Oil reserves grew 25% to 10.5 million Bbl from 8.4 million Bbl at September 30,
2012 –
PV-10
(1)
increased 16% to $423.2 million from $363.6 million at September 30, 2012
(1) PV-10 is a non-GAAP financial measure. Matador is unable to
calculate standardized measure at December 31, 2012 until it completes its audit. For a reconciliation of PV-10, see Appendix |
 48
Value of Proved Reserves Up 70% and Shifting to Oil Over Past Year
Eagle Ford
$393.6 million, 93%
Haynesville
$21.8 million, 5%
Cotton Valley
$5.9 million, 1%
SE New Mexico
$2.0 million, 0%
December 31, 2012
PV-10
(1)
:
$423.2
million
(2)
Proved
Producing
Reserves
PV-10
(1)
:
$297.5
Million
Haynesville
$96.6 million, 39%
Cotton Valley
$19.5 million, 8%
Eagle Ford
$130.2 million, 52%
SE New Mexico
$2.4 million, 1%
December 31, 2011
PV-10
(1)
: $248.7 million
Proved
Producing
Reserves
PV-10
(1)
:
$154.1
Million
(1)
PV-10 is a non-GAAP financial measure. Matador will provide standardized
measure at December 31, 2012 with its December 2012 audited financial results. For a reconciliation of PV-10, see Appendix
(2)
Future undiscounted net revenue of $704.2 million using YE 2012 SEC pricing of
$91.21/Bbl oil and $2.757/MMBtu gas |
 Appendix |
 Board
of
Directors
and
Special
Board
Advisors
–
Expertise
and
Stewardship
50
Board Members
and Advisors
Professional Experience
Business Expertise
Dr. Stephen A. Holditch
Director
-
Professor and Former Head of Dept. of Petroleum Engineering, Texas A&M
University -
Founder / 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 / 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
Margaret B. Shannon
Director
-
Retired VP and General Counsel, BJ Services Co.
-
Former Partner, Andrews Kurth LLP
Law and
Corporate Governance
Mino Capossela
Special Board Advisor
-
Retired partner Goldman Sachs; Charter Financial Analyst; Private Investor
Finance and
Management
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
51
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.
32 years
Since Inception
David E. Lancaster
EVP and COO
-
Schlumberger, S.A. Holditch & Associates, Inc., Diamond
Shamrock
33 years
Since 2003
Matthew V. Hairford
EVP and Head of Operations
-
Samson, Sonat, Conoco
28 years
Since 2004
David F. Nicklin
Executive Director of Exploration
-
ARCO, Senior Geological Assignments in UK, Angola,
Norway and the Middle East
41 years
Since 2007
Bradley M. Robinson
VP, Reservoir Engineering
-
Schlumberger, S.A. Holditch & Associates, Inc.,
Marathon
35 years
Since Inception
Craig N. Adams
VP and General Counsel
-
Baker Botts L.L.P., Thompson & Knight LLP
20 years
Since 2012
Kathryn L. Wayne
Controller and Treasurer
-
Matador Petroleum Corporation, Mobil
28 years
Since Inception
Ryan London
Senior Completion Engineer
Eagle Ford Asset Manager
-
Matador Resources Company
9 years
Since 2003 |
 52
Quarterly Performance Metrics Through Q3 2012
Oil and Natural Gas Revenues
($ in mm)
Total Realized Revenues
($ in mm)
Adjusted
EBITDA
(1)
($ in mm)
Average Daily Equivalent Production
(BOE/d)
$9.2
$7.5
$8.5
$8.9
$13.7
$20.9
$17.4
$15.0
$29.2
$36.1
$38.0
$0.0
$5.0
$10.0
$15.0
$20.0
$25.0
$30.0
$35.0
$40.0
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
$6.1
$5.2
$5.8
$6.5
$10.1
$15.3
$12.1
$12.4
$21.3
$27.9
$28.6
$0.0
$5.0
$10.0
$15.0
$20.0
$25.0
$30.0
$35.0
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
$9.5
$9.1
$9.6
$11.2
$15.5
$21.8
$18.9
$17.9
$32.2
$40.8
$41.4
$0.0
$5.0
$10.0
$15.0
$20.0
$25.0
$30.0
$35.0
$40.0
$45.0
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and
a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see Appendix |
 South
Texas Pearsall Play: Activity & Liquids to Dry Gas Distribution Model
Anadarko
Newfield
Chesapeake
Shell
Gas Activity
EOG Tests
Condensate belt
500 –
2,000 BC/mo.
Temp. Abnd or
EGFD Horiz.
Top Pearsall Depth Map
CI = 500’
Cheyenne
Indio Tanks Horiz. program
4 horizs w/ 700 to 450 BCPD
plus 4-6 MMCFGPD
Chesapeake
Wilson C#1HP
IP 250 BCPD/ 3 MMCFPD
Abnd.
Chesapeake
Brownlow #3H
Abandoned Test
PXP
Chesapeake
Avant D#1HP
300 BC/mo.
Abnd.
Cheyenne
Drilling
Cabot
6 Horiz. Drilled
3 Permits
Blackbrush O&G
Pals Ranch 11H
IP 706 BCPD/ 4 MMCFPD
Valence Op. Co.
53
Note: All acreage as of November 30, 2012
Note: Well data available through public sources and interpretation by Matador Resources
|
 Zavala, Frio, La Salle and Dimmit Counties:
Important Matador and Competitor Wells Since 2011
54
(
ZaZa)
Cenizo
Ranch B 3H
Best 3 Oil –
17,312
(MTDR) GR 1H
6,125’
Lateral
On pump @ 60 BOPD
Best 3 Oil –
9,827
Est. EUR = 100,000 BOE
(Buffco) Howett
1H
OIL IP: 243; GAS IP: 152
22/64”
choke
Best 3 Oil –
13,991
(Crimson) K M Ranch 2H
OIL IP: 457; GAS IP: 326
Last Act. Date –
09/2012
(CHK) Traylor North 2H
OIL IP: 405; GAS IP: 78
14/64”
choke
Best 3 Oil –
19,476
(CHK) Winterbotham
A 4H
OIL IP: 909
13/64”
choke
Best 3 Oil –
25,344
(CHK) Winterbotham
A 1H
OIL IP: 1,448
13/64”
choke
Best 3 Oil –
37,870
(US Enercorp) Rally 1H -
CHKFD
OIL IP: 416; GAS IP: 175
16/64”
choke
Best 3 Oil –
52,058
(Goodrich) Burns A 35H
OIL IP: 736; GAS IP: 589
49/64”
choke
Best 3 Oil –
22,111
(CHK) Brownlow 1H
OIL IP: 764; GAS IP: 437
30/64”
choke
Best 3 Oil –
21,853
(Crimson) K M Ranch 1H
Plug back 3,076’
Lateral
OIL IP: 200; GAS IP: 275
20/64”
choke
Best 3 Oil –
8,038
(Hughes) LANG 1H -
Buda
OIL IP: 165; GAS IP: 200
18/64”
choke
Best 3 Oil –
2,039
(CHK) Bohannam
Dim C 1H
OIL IP: 466; GAS IP: 174
10/64”
choke
Best 3 Oil –
18,031
LEGEND
AUSTIN CHALK
BUDA/DEL RIO
Matador Acreage
Buda Wells
Wells Spudded Since 1/2011
(BBOG)
Nickolson
1H
OIL IP: 218; GAS IP: 2,167
19/64”
choke
Best 3 Oil –
9,520
(BBOG) Oppenheimer A1
OIL IP: 273; GAS IP: 1,400
38/64”
choke
Best 3 Oil –
9,725
(BBOG) Calvert 1H -
Buda
OIL IP: 170; GAS IP: 1,812
28/64”
choke
Best 3 Oil –
14,292
(CHK) Rogers B 2H
OIL IP: 560; GAS IP: 175
12/64”
choke
Best 3 Oil –
31,184
(MTDR) ZLS 1H
4,551’
Comp. Lateral
Post Frac Clean Up Phase
Note: Well data available through public sources and interpretation by Matador Resources Note: All acreage as of
November 30, 2012 |
 55
Adjusted EBITDA Reconciliation
This presentation includes, and certain statements made during this presentation may
include, the non- GAAP financial measure of Adjusted EBITDA. We
believe Adjusted EBITDA helps us evaluate our operating performance and
compare our results of operation from period to period without regard to our
financing methods or capital structure. We define 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, including stock
option and grant expense and restricted stock and restricted stock units
expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not
a measure of net (loss) income or cash flows as determined by GAAP. Adjusted EBITDA
should not be considered an alternative to, or more meaningful than, net
income or cash flows from operating activities as determined in accordance
with GAAP or as an indicator of our operating performance or liquidity. The
following tables present our 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,
prospective
or
estimates
in
nature,
and
not
based
on
historical
fact,
the
table
does
not
provide
a
reconciliation.
We
could
not provide such reconciliations without undue hardship because the Adjusted EBITDA
numbers included in this presentation, and that may be included in certain
statements made during the presentation, are estimations, approximations
and/or ranges. In addition, it would be difficult for us to present a detailed
reconciliation on account of many unknown variables for the reconciling
items. |
 56
Adjusted EBITDA Reconciliation
The following table presents our calculation of Adjusted EBITDA and reconciliation
of Adjusted EBITDA to the GAAP financial measures of net (loss) income and
cash provided by operating activities, respectively. Year Ended December 31,
Nine Months Ended
September 30,
(In thousands)
2007
2008
2009
2010
2011
2012
Unaudited Adjusted EBITDA reconciliation to Net Income (Loss):
Net (loss) income
($300)
$103,878
($14,425)
$6,377
($10,309)
($8,568)
Interest expense
-
-
-
3
683
453
Total income tax provision (benefit)
-
20,023
(9,925)
3,521
(5,521)
(1,152)
Depletion, depreciation and amortization
7,889
12,127
10,743
15,596
31,754
52,799
Accretion of asset retirement obligations
70
92
137
155
209
170
Full-cost ceiling impairment
-
22,195
25,244
-
35,673
33,206
Unrealized loss (gain) on derivatives
211
(3,592)
2,375
(3,139)
(5,138)
1,149
Stock option and grant expense
205
605
622
824
2,362
(585)
Restricted stock grants
15
60
34
74
44
362
Net loss (gain) on asset sales and inventory
impairment -
(136,977)
379
224
154
60
Adjusted EBITDA
$8,090
$18,411
$15,184
$23,635
$49,911
$77,894
Year Ended December 31,
Nine Months Ended
September 30,
(In thousands)
2007
2008
2009
2010
2011
2012
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
$80,325
Net change in operating assets and liabilities
209
(17,888)
15,717
(2,230)
(12,594)
(3,072)
Interest expense
-
-
-
3
683
453
Current income tax provision (benefit)
-
10,448
(2,324)
(1,411)
(46)
188
Adjusted EBITDA
$8,090
$18,411
$15,184
$23,635
$49,911
$77,894 |
 57
Adjusted EBITDA Reconciliation (Cont.)
The following table presents our calculation of Adjusted EBITDA and reconciliation
of Adjusted EBITDA to the GAAP financial measures of net (loss) income and
cash provided by operating activities, respectively. (In thousands)
1Q 2010
2Q 2010
3Q 2010
4Q 2010
1Q 2011
2Q 2011
3Q 2011
4Q 2011
1Q 2012
2Q 2012
3Q 2012
Unaudited Adjusted EBITDA reconciliation to
Net Income (Loss):
Net income (loss)
$ 5,676
$ (984)
$ 2,681
$ (996)
$ (27,596)
$ 7,153
$ 6,194
$ 3,941
$ 3,801
$ (6,676)
$ (9,197)
Interest expense
-
-
-
3
106
184
171
222
308
1
144
Total income tax provision (benefit)
2,975
(516)
1,584
(522)
(6,906)
(46)
-
1,430
3,064
(3,713)
(593)
Depletion, depreciation and amortization
3,362
3,702
3,868
4,665
7,111
8,180
7,287
9,175
11,205
19,914
21,680
Accretion of asset retirement obligations
38
30
39
48
39
57
62
51
53
58
59
Full-cost ceiling impairment
-
-
-
-
35,673
-
-
-
-
33,205
3,596
Unrealized (gain) loss on derivatives
(6,093)
2,822
(2,541)
2,674
1,668
(332)
(2,870)
(3,604)
3,270
(15,114)
12,993
Stock option and grant expense
180
153
133
357
42
117
1,220
983
(374)
41
(252)
Restricted stock grants
6
8
11
49
11
11
14
8
11
150
201
Net (gain)/loss on asset sales and inventory impairment
-
-
-
224
-
-
-
154
-
60
-
Adjusted EBITDA
$ 6,142
$ 5,215
$ 5,776
$ 6,502
$ 10,148
$ 15,324
$ 12,078
$ 12,360
$ 21,338
$ 27,926
$ 28,631
(In thousands)
1Q 2010
2Q 2010
3Q 2010
4Q 2010
1Q 2011
2Q 2011
3Q 2011
4Q 2011
1Q 2012
2Q 2012
3Q 2012
Unaudited Adjusted EBITDA reconciliation to
Net Cash Provided by Operating Activities:
Net cash provided by operating activities
$ 7,673
$ 29,040
$ (15,322)
$ 5,883
$ 12,732
$ 6,799
$ 14,912
$ 27,425
$ 5,110
$ 46,416
$ 28,799
Net change in operating assets and liabilities
(1,531)
(23,824)
22,509
616
(2,690)
8,386
(3,004)
(15,287)
15,920
(18,491)
(500)
Interest expense
-
-
-
3
106
184
171
222
308
1
144
Current income tax (benefit) provision
-
-
(1,411)
-
-
(45)
(1)
-
-
-
188
Adjusted EBITDA
$ 6,142
$ 5,215
$ 5,776
$ 6,502
$ 10,148
$ 15,324
$ 12,078
$ 12,360
$ 21,338
$ 27,926
$ 28,631 |
 58
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 our
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 September 30, 2012, December 31, 2011 and September
30, 2011 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 September 30, 2012, December 31, 2011 and
September 30, 2011 were, in millions, $29.7, $33.2 and $11.8, respectively.
We have not provided a reconciliation of PV-10 to Standardized Measure at December 31, 2012.
We could not provide such a reconciliation without undue hardship because we have not completed
the audit of our 12/31/12 financial statements. In addition, it would be difficult for us
to present a detailed reconciliation on account of many unknown variables for the reconciling
items. |