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.