Matador Resources (MTDR) 8-K Regulation FD Disclosure

Investor Presentation

Exhibit 99.1

October 2012

1

Forward-Looking Statements

This presentation and statements made by representatives of Matador Resources Company (“Matador” or the “Company”)

during the course of this presentation include “forward-looking statements” within the meaning of Section 27A of the

Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. “Forward-

looking statements” are statements related to future, not past, events. Forward-looking statements are based on current

expectations and include any statement that does not directly relate to a current or historical fact.  In this context, forward-

looking statements often address expected future business and financial performance, and often contain words such as

“could,” “believe,” “would,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,” “predict,”

“potential,” “project” and similar expressions that are intended to identify forward-looking statements, although not all

forward-looking statements contain such identifying words. Actual results and future events could differ materially from

those anticipated in such statements. These forward-looking statements involve certain risks and uncertainties and

ultimately may not prove to be accurate, including, but not limited to, the following risks related to our financial  and

operational performance: general economic conditions; Matador’s ability to execute its business plan, including the

success of its drilling program; 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 Matador to execute its 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.

2

Company Overview

Completed IPO of 14,883,334 shares (12,209,167 primary) including overallotment at $12.00/share in March 2012

Exchange: Ticker

NYSE: MTDR

Shares Outstanding

55.51 million common shares

Share Price as of October 5, 2012

$9.79/share

Market Capitalization as of October 5, 2012

$543.4 million

2012 Guidance Summary (updated as of August 14, 2012)

2012 Estimated Capital Spending

$313 million

2012 Estimated Total Oil Production

1.2 to 1.4 million barrels

2012 Estimated Exit Rate for Oil Production

5,000 to 5,500 barrels per day

2012 Estimated Total Natural Gas Production

12.5 to 13.5 billion cubic feet

Matador Oil Facts: Second Quarter 2012

3

On track to double Adjusted EBITDA

(1)

for the second year in a row

Record quarterly oil production of 285,000 Bbl, a sequential

quarterly increase of 43% from 200,000 Bbl produced in first quarter

of 2012

Record six-month oil production of 485,000 Bbl, a year-over-year

increase of almost seven-fold from 70,000 Bbl produced in first half

of 2011

Record average daily oil equivalent production of 8,738 BOE per

day, including 3,130 Bbl of oil per day and 33.6 MMcf of natural

gas

per day

Oil reserves of 6.7 million Bbl at June 30, 2012 up nearly 80% from

3.8 million Bbl at December 31, 2011

Second quarter oil production constitutes 36% of total production

volume and oil revenues constitute 82% of total oil and natural gas

revenues

(1)  Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see slide 29 

Note:  Matador is a two-stream reporting company.  Its oil production and reserves volumes do not include Natural Gas Liquids (NGLs) volumes.

Founded by Joe Foran in 1983

Foran Oil funded with $270,000 in contributed

capital from 17 friends and  family members

Rolled into Matador Petroleum Corporation  in

1988

Grown primarily through acquire and exploit

strategy

Delivered 21% average annual rate of return

over 15 years

Sold

to

Tom

Brown,

Inc.

(1)

in

June

2003

for an

enterprise value of $388 million in an all-cash

transaction

Foran Oil & Matador Petroleum

4

Matador History

Matador Resources Company

Founded by Joe Foran in 2003

Attracted start-up capital from long-time shareholders;

diverse and unique shareholder group including over

400 friends and neighbors

Proven management, technical team and Board of

Directors

Grown entirely through drill bit, with focus on

unconventional reservoir plays

Chesapeake transaction and strong science and

technical teams enabled the strategic transition to the

Eagle Ford play

IPO in February 2012 (NYSE: MTDR)

Strong year-over-year growth

Daily

oil

production

increased

almost

six-fold

(2)

Proved

oil

reserves

increased

almost

eight-fold

(3)

Adjusted EBITDA

(4)

increased 82%

(2)

Predecessor Entities

Matador Today

(1)  Tom Brown purchased by Encana in 2004

(2)  Three months ended June 30, 2012 compared to three months ended June 30, 2011

(3)  At June 30, 2012 as compared to at June 30, 2011

(4)  Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see slide 29

A Year of Growth

5

(1)  Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see slide 29

Year Ended December  31,

Year Ended December  31,

Year Ended December  31,

AVERAGE DAILY OIL

TOTAL REALIZED

EQUIVALENT PRODUCTION

REVENUES

ADJUSTED EBITDA

(1)

(INCLUDING REALIZED GAIN ON DERIVATIVES)

$8.1

$18.4

$15.2

$23.6

$49.9

$21.3

$27.9

2007

2008

2009

2010

2011

2012

1Q

2012

2Q

$14.2

$29.3

$26.7

$39.3

$74.1

$32.2

$40.8

2007

2008

2009

2010

2011

2012

1Q

2012

2Q

911

1,506

2,285

3,926

7,048

8,023

8,738

2007

2008

2009

2010

2011

2012

1Q

2012

2Q

Transition to Oil

6

Year Ended

December

31,

Year Ended

December

31,

TOTAL OIL PRODUCTION

OIL BY VOLUME

OIL BY REVENUE

12%

12%

9%

7%

22%

74%

82%

2007

2008

2009

2010

2011

2012

1Q

2012

2Q

7%

7%

4%

2%

6%

27%

36%

2007

2008

2009

2010

2011

2012

1Q

2012

2Q

22

37

30

33

154

200

285

2007

2008

2009

2010

2011

2012

1Q

2012

2Q

Year Ended

December

31,

7

Financial Performance: Proven Management Team

Oil and Natural Gas Revenues

($ in mm)

Total Realized

Revenues

(2)

($ in mm)

Adjusted

EBITDA

(1)

($ in mm)

Average Daily Production

(BOE/d)

3,729

8,004

8,738

0

2,000

4,000

6,000

8,000

10,000

2Q10

2Q11

2Q12

$7.5

$20.9

$36.1

$0.0

$10.0

$20.0

$30.0

$40.0

2Q10

2Q11

2Q12

$5.2

$15.3

$27.9

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

2Q10

2Q11

2Q12

$9.1

$21.8

$40.8

$0.0

$10.0

$20.0

$30.0

$40.0

$50.0

2Q10

2Q11

2Q12

CAGR: 119%

CAGR: 132%

CAGR: 112%

CAGR: 53%

(1)  Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see slide 29

(2)  Includes realized gain on derivatives

Liquids Focused CapEx in 2012E

Commentary

Oil Production Growth Over Time (Bbl/d)

8

Q2 2012 oil production

approximately 285,000 barrels

Six-month oil production of

485,000 Bbl up almost   

seven-fold year-over-year at

June 30, 2012

Approximately 88% of 2012E

capital budget focused on

Eagle Ford (84%) and

Austin Chalk (4%)

All 2012 Eagle Ford and

Austin Chalk drilling locations

targeting oil and liquids

Oil production expected to

increase 8x to 9x in 2012

Strong Growth Profile Focused on Liquids

91

422

2,200

3,130

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2010

2011

1Q 2012

2Q 2012

2012 Anticipated Drilling

2012E CapEx

Gross Wells

Net Wells

(in millions)

Total

Total

%

Total

%

South Texas

Eagle Ford

28.0

25.6

86.8%

$257.2

82.2%

Austin Chalk

2.0

2.0

6.8%

$11.3

3.6%

Area Total

30.0

27.6

93.6%

$268.5

85.8%

NW LA / E Texas

Haynesville

25.0

1.5

5.1%

$13.5

4.3%

Cotton Valley

-

-

-

-

-

Area Total

25.0

1.5

5.1%

$13.5

4.3%

SW WY, NE UT, SE ID

1.0

0.4

1.3%

$2.5

0.8%

Other

-

-

-

$28.5

9.1%

Total

56.0

29.5

100.0%

$313.0

100.0%

Leverage to Eagle Ford (Net Eagle Ford Acres / EV)

(Net Acres / $mm)

9

Leading Eagle Ford Exposure

Matador offers significant leverage

and focus to the Eagle Ford

Approximately 90% of Eagle Ford

acreage is in the prospective oil

and liquids window

All 2012E Eagle Ford drilling

focused in the prospective oil and

liquids window

84% of 2012 estimated CapEx

allocated to Eagle Ford

One rig running in the eastern and

one in the western portions of the

Eagle Ford play

Eagle Ford acreage well-

positioned throughout the play

51.0

48.1

36.7

34.9

33.3

32.1

26.1

25.7

24.3

21.9

14.9

9.3

6.7

4.3

4.0

SFY

MTDR

GDP

FST

SM

NFX

CRZO

PVA

ROSE

CHK

MHR

PXD

PXP

APA

APC

64%

84%

45%

30%

57%

63%

36%

7%

40%

93%

92%

N/A

N/A

N/A

N/A

2012E

Capex

% Eagle Ford

(1)

Note:  Reflects companies with greater than 50 Bcfe of proved reserves. Data sourced from public filings; stock price data as of October 5, 2012 close

(1)  Per operational guidance

Highlights

10

Eagle Ford Properties are in Good Neighborhoods

MTDR acreage in counties

with robust transaction activity

–

“good neighborhoods”

Transaction values ranging

from $10,000 to $30,000 per

acre

Our Eagle Ford position has

grown to over 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

More than 80% of Eagle Ford acreage HBP or not burdened with lease expirations before 2013

Note:  All Matador acreage at June 30, 2012 and all other acreage based on public information

11

San Antonio

Uvalde

Medina

Zavala

Frio

Dimmit

La Salle

Webb

Bexar

Atascosa

McMullen

Live Oak

Bee

Goliad

Dewitt

Gonzales

Wilson

COMBO LIQUIDS /

GAS FAIRWAY

DRY GAS FAIRWAY

OIL FAIRWAY

Eagle Ford and Austin Chalk Properties

GLASSCOCK (WINN) RANCH

8,891 gross / 8,891 net acres

EAGLE FORD WEST

14,242 gross / 11,380 net acres

EAGLE FORD EAST

7,567 gross / 6,170 net acres

EOG OPERATED, MTDR WI ~21%

18,998 gross / 3,709 net acres

Note:  All acreage at June 30, 2012

EAGLE FORD ACREAGE TOTALS

49,698 gross / 30,150 net acres

Matador Resources Acreage

Karnes

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

Eagle Ford 24-Hour Stabilized Rates

12

Well Name

County

Completion Date

Perforated Length

(1)

Frac Stages

Oil IP

(2)(3)

Gas IP

(2)(3)

Oil Equiv IP

(4)

Choke

Pressure

Total  (ft.)

(Bbl/day)

(Mcf/day)

(BOE/day)

(inch)

(psi)

2011 Wells

JCM Jr. Minerals 1H

La Salle

11/10/2010

3,774

15

164

3,648

772

15/64

3,365

Martin Ranch A 1H

La Salle

1/20/2011

4,201

17

1,129

2,821

1,599

34/64

1,550

Affleck 1H

Dimmit

2/22/2011

4,711

16

456

5,247

1,331

36/64

1,435

Frances Lewton 1H

DeWitt

11/16/2011

5,041

17

1,021

2,574

1,450

13/64

5,000

Martin Ranch A 2H

La Salle

11/19/2011

6,772

22

1,318

1,845

1,626

26/64

1,800

Martin Ranch A 3H

La Salle

11/26/2011

4,476

15

802

510

887

26/64

1,510

Martin Ranch A 5H

La Salle

12/17/2011

4,518

15

893

545

984

26/64

1,250

2012 Wells

Martin Ranch A 8H

La Salle

1/28/2012

6,092

21

1,089

831

1,228

26/64

1,750

Martin Ranch A 6H

La Salle

2/8/2012

6,509

22

689

1,714

975

26/64

1,650

Martin Ranch A 7H

La Salle

2/12/2012

4,902

17

609

481

689

26/64

1,040

Martin Ranch B 4H

La Salle

2/18/2012

3,551

13

595

968

756

26/64

1,320

Matador Sickenius Orca 1H

Karnes

3/16/2012

5,712

19

785

540

875

26/64

820

Northcut A 1H

La Salle

3/23/2012

4,446

15

583

592

682

26/64

1,000

Matador Danysh Orca 1H

Karnes

4/1/2012

4,962

17

1,012

1,126

1,200

26/64

1,175

Northcut A 2H

La Salle

5/1/2012

4,503

15

758

761

885

24/64

950

Matador Pawelek Orca 1H

Karnes

6/5/2012

6,103

20

670

739

793

16/64

2,510

Matador Pawelek Orca 2H

Karnes

6/7/2012

6,202

28

861

755

987

16/64

2,460

Matador Danysh Orca 2H

Karnes

6/10/2012

5,115

17

750

746

874

16/64

2,675

Glasscock Ranch 1H

Zavala

6/27/2012

5,352

18

307

0

307

pump

140

Matador K. Love Orca 1H

DeWitt

8/10/2012

5,077

17

1,793

2,171

2,155

16/64

5,280

Matador K. Love Orca 2H

DeWitt

8/11/2012

4,871

17

1,757

2,126

2,111

16/64

5,900

Average

5,090

18

859  Bbl/day

1,464  Mcf/day

1,103 BOE/day

(1)  Total length of perforated lateral from the first perforation to the last perforation

(2)  Rates as reported to the Texas Railroad Commission via W-2 or G-1 form

(3)  Rates are based on actual, stabilized, 24 hour production on a constant choke size

(4)  Oil equivalent rates are based on a 6:1 ratio of six Mcf gas per one Bbl oil

13

South Texas Multi-Pay Petroleum Systems:

Petroleum Charge focus towards Glasscock Ranch

Note:  Information for Pearsall Oil Field sourced from public information

Redhawk

Area

Note:  All acreage at June 30, 2012

Olmos/Navarro

Austin Chalk

Edwards

Oil

and

Gas

Fields:

Buda

Wilcox

Matador Resources Acreage

14

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

Eagle

Ford

Buda

Georgetown

Del

Rio

Edwards

Glen Rose

Rodessa

Pearsall

Sligo

Olmos

Navarro

ANCC

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

Budgeted Cost

Actual Cost

Eagle Ford Well Costs Averaging 15% Less than 2012 Budget Estimates

15

Western Acreage

Eastern Acreage

Note: 2012 Eagle Ford well drilling and completions costs only compared to budget estimates; costs do not include pipelines and lease facilities

Eagle Ford Well Costs –

East Side

16

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

1

2

3

4

5

6

7

8

Well Cost

5000' Normalized Cost

Note: Wells are displayed in chronological order.  Well drilling and completions costs only; costs do not include pipelines and lease facilities.

Eagle Ford Well Costs –

West Side

17

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

1

2

3

4

5

6

7

8

9

10

11

Well Cost

5000' Normalized Cost

Note: Wells are displayed in chronological order.  Well drilling and completions costs only; costs do not include pipelines and lease facilities.

Average Frac Stage Cost per Well

18

Note: Wells are displayed in chronological order

$0

$50,000

$100,000

$150,000

$200,000

$250,000

$300,000

$350,000

$400,000

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

Bauxite

Resin Coated Sand        White Sand

Eagle Ford Well Estimated ROR as a Function of EUR and Well Cost

19

Note: Individual well economics only.  NGL price differential +$2.50/Mcf.  Oil price differential +$4.30/Bbl.

$8.0

$10.0

$12.0

0

20

40

60

80

100

120

140

160

180

200

100

200

300

400

500

600

700

Estimated Ultimate Recovery (EUR), MBOE

Well Cost,

millions

$7.0

$90.00/Bbl NYMEX oil;

$3.00/Mcf NYMEX natural gas

20

San Antonio

Multi-Pay Fairway

with Eagle Ford, Pearsall, Austin Chalk and Buda potential

Emerging Multi-Pay Area in Eagle Ford Oil Fairway and MTDR

Acreage

OIL FAIRWAY

OIL FAIRWAY

Note:  All acreage at June 30, 2012

Matador Resources Acreage

21

Wolfbone Play in the Delaware Basin (West Texas)

Major Operator Index

Matador Resources

Anadarko Petroleum Corp.

Chesapeake Operating

Cimarex Energy

Clayton Williams Energy

Devon Energy Production

Energen Resources Corp.

Oxy USA Inc.

Matador Resources

~4,900 gross / ~2,900 net acres

C U L B E R S O N

P E C O S

C R A N E

W A R D

W I N K L E R

U P T O N

R E E V E S

M A R T I N

M I D L A N D

L O V I N G

E C T O R

G A I N E S

G

D A W S O N

A N D R E W S

JEFF DAVIS

R.S. JOHNSON

BLK C27

PSL

FEET

0

7,214

Chesapeake Operated

IP’s:

260

–

750

Bbl/d

600 –

3,300 Mcf/d

Anadarko Operated

IP’s:

162

–

931

Bbl/d

466 –

2,400 Mcf/d

Energen Operated

IP’s:

117

–

902

Bbl/d

500 –

1,500 Mcf/d

Devon Operated

IP’s:

121

–

725

Bbl/d

1,100 –

1,300 Mcf/d

Cimarex Operated

IP’s:

240

–

608

Bbl/d

255 –

2,000 Mcf/d

Note:  As of August 23, 2012 and only wells with total depths greater than 7,000’posted.  Third-party information from public sources.

22

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’

Thickness: 200-300 ft.

Total Organic Carbon (TOC) 2-4%

Density Porosity: 12-15%

Geopressure (0.7psi/ft.)

Upper Wolfcamp

Depth: 10,500’

–

10,600’

(Oil Window)

Density Porosity: >10%

Gross Thickness: 280-350 ft.

IP: 121-900 Bbl/d   250-3,300 Mcf/d

Geopressure (0.7psi/ft.)

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

23

Hedging Profile

Oil Hedges (Costless Collars)

4Q 2012

FY 2013

Total Volume Hedged by Ceiling (Bbl)

360,000

1,260,000

Weighted Average Price ($ / Bbl)

$110.31

$110.26

Total Volume Hedged by Floor (Bbl)

360,000

1,260,000

Weighted Average Price ($ / Bbl)

$90.83

$87.14

Natural Gas Hedges (Costless Collars)

4Q 2012

FY 2013

Total Volume Hedged by Ceiling (Bcf)

2.31

4.65

Weighted Average Price ($ / MMBtu)

$5.30

$4.84

Total Volume Hedged by Floor (Bcf)

2.31

4.65

Weighted Average Price ($ / MMBtu)

$4.07

$3.34

Natural Gas Liquids (NGLs) Hedges (Swaps)

4Q 2012

FY 2013

Total Volume Hedged (gal)

601,200

4,720,800

Weighted Average Price ($ / gal)

$0.75

$0.75

Net NGL production of 163 Bbl/d and 476 Bbl/d for the first quarter and second quarter of 2012

respectively.

Matador has recently finalized a natural gas gathering, transportation and processing agreement,

including firm transportation and processing, for most of its operated natural gas production in South

Texas.

163

476

0

100

200

300

400

500

1Q 2012

2Q 2012

24

Natural Gas Liquids (NGLs)

Net NGL Production

(Bbl/d)

25

Financial Flexibility

Plan to fund 2012 capital budget with a portion of IPO net proceeds, anticipated cash flows from

operations and available borrowings under credit facility

Closed an amended and restated credit facility to increase the Company’s borrowing capacity to $200

million primarily as a result of increased oil reserves at June 30, 2012

Expanded bank group to 5 banks

Total facility size increased from $400 million to $500 million

Borrowing base of $200 million, increased from $125 million

37%

of

current

market

capitalization

$120 million in debt outstanding as of October 9, 2012

(1)  As of October 5, 2012 close

(1)

Liquids Focused CapEx in 2012E

Commentary

Oil Production Growth Over Time (Bbl/d)

26

Q2 2012 oil production

approximately 285,000 barrels

Six-month oil production of

485,000 Bbl up almost   

seven-fold year-over-year at

June 30, 2012

Approximately 88% of 2012E

capital budget focused on

Eagle Ford (84%) and

Austin Chalk (4%)

All 2012 Eagle Ford and

Austin Chalk drilling locations

targeting oil and liquids

Oil production expected to

increase 8x to 9x in 2012

Strong Growth Profile Focused on Liquids

91

422

2,200

3,130

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2010

2011

1Q 2012

2Q 2012

2012 Anticipated Drilling

2012E CapEx

Gross Wells

Net Wells

(in millions)

Total

Total

%

Total

%

South Texas

Eagle Ford

28.0

25.6

86.8%

$257.2

82.2%

Austin Chalk

2.0

2.0

6.8%

$11.3

3.6%

Area Total

30.0

27.6

93.6%

$268.5

85.8%

NW LA / E Texas

Haynesville

25.0

1.5

5.1%

$13.5

4.3%

Cotton Valley

-

-

-

-

-

Area Total

25.0

1.5

5.1%

$13.5

4.3%

SW WY, NE UT, SE ID

1.0

0.4

1.3%

$2.5

0.8%

Other

-

-

-

$28.5

9.1%

Total

56.0

29.5

100.0%

$313.0

100.0%

27

Investment Highlights

Strong Growth Profile with Increasing Focus on Oil / Liquids

High Quality Asset Base in Attractive Areas

Significant Multi-year Drilling Inventory

Strong Financial Position and Long-Term Institutional, Industry and Individual

Shareholders

Proven Management and Technical Team and Active Board of Directors

Active Exploration Effort Using Science and Technology

Appendix

Year Ended December 31,

(In thousands)

2007

2008

2009

2010

2011

2010

2011

2012

Unaudited Adjusted EBITDA reconciliation to Net Income (Loss):

Net (loss) income

($300)

$103,878

($14,425)

$6,377

($10,309)

($984)

$7,153

($6,676)

Interest expense

-

-

-

3

683

-

184

1

Total income tax provision (benefit)

-

20,023

(9,925)

3,521

(5,521)

(516)

(46)

(3,713)

Depletion, depreciation and amortization

7,889

12,127

10,743

15,596

31,754

3,702

8,180

19,914

Accretion of asset retirement obligations

70

92

137

155

209

30

57

58

Full-cost ceiling impairment

-

22,195

25,244

-

35,673

-

-

33,205

Unrealized loss (gain) on derivatives

211

(3,592)

2,375

(3,139)

(5,138)

2,821

(332)

(15,114)

Stock option and grant expense

205

605

622

824

2,362

154

117

41

Restricted stock grants

15

60

34

74

44

7

11

150

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

$5,216

$15,324

$27,926

Year Ended December 31,

(In thousands)

2007

2008

2009

2010

2011

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

$24,624

$6,799

$46,416

Net change in operating assets and liabilities

209

(17,888)

15,717

(2,230)

(12,594)

(19,408)

8,387

(18,491)

Interest expense

-

-

-

3

683

-

184

1

Current income tax provision (benefit)

-

10,448

(2,324)

(1,411)

(46)

-

(46)

-

Adjusted EBITDA

$8,090

$18,411

$15,184

$23,635

$49,911

$5,216

$15,324

$27,926

Three Months Ended June 30,

Three Months Ended June 30,

29

Adjusted EBITDA Reconciliation

The following table presents our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the GAAP financial measures of net income

(loss) and net cash provided by operating activities, respectively.

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 income (loss) 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.

Board

of

Directors

and

Special

Board

Advisors

–

Expertise

and

Stewardship

30

Board Members

and Advisors

Professional Experience

Business Expertise

Dr. Stephen A. Holditch

Director

-

Professor and Former Head of the Department 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

Director

-

Past Chairman, Amtrak Board of Directors

-

Former Partner, Jackson Walker LLP

Law

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

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

31

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, COO and CFO

-

Schlumberger, S.A. Holditch & Associates, Inc., Diamond

Shamrock

33 years

Since 2003

Matthew V. Hairford

EVP, Operations

-

Samson, Sonat, Conoco

28 years

Since 2004

David F. Nicklin

Executive Director, 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, General Counsel

-

Baker Botts L.L.P.

20 years

Since 2012

Kathryn L. Wayne

Controller and Treasurer

-

Matador Petroleum Corporation, Mobil

28 years

Since Inception

32

Daily Production

(1)

8,738 BOE/d

Oil Production (% total)

3,130 Bbl/d (36%)

Proved Reserves @ 6/30/12

19.1 Million BOE

% Proved Developed

64%

% Oil

35% (and growing)

2012E CapEx

$313 million

% Eagle Ford

84%

% Oil and Liquids

94%

2012E Anticipated Drilling

29.5 net wells

Eagle Ford / Austin Chalk

27.6 net wells

Haynesville

1.5 net wells

Gross Acreage

(2)

195,838 acres

Net Acreage

(2)

160,516 acres

(1)

Average daily production for the three months ended June 30, 2012

(2)

At June 30, 2012

Matador Resources Snapshot

Note:  Loving County acreage added August 10, 2012 and is not reflected in acreage totals at June 30, 2012 (see slide 21)

33

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

2012E capital expenditure program

focused on oil and liquids exploration

and development

Anticipate oil production to constitute

approx. 35-40% of total production

volume and oil revenues to constitute

approx. 75-80% of total oil and natural

gas revenues in 2012

Drilling locations are based on 120

acre spacing

Currently testing 80-acre spacing on

one Eagle Ford property and plan

additional tests on other properties

before end of 2012

Proved Reserves @ 6/30/12

8.8 Million BOE

% Proved Developed

47%

% Oil / Liquids

75%

Daily Oil Production

(1)

3,178 BOE/d

Gross Acres

(2)

49,698 acres

Net Acres

(2)

30,150 acres

Eagle Ford

(2),(3)

30,150 acres

Austin Chalk

(2),(3)

17,343 acres

2012E Anticipated Drilling

27.6 net wells

2012E CapEx Budget

$268.5 million

% HBP or no short term expirations

(4)

~80%

(1)

Average daily oil production for the six months ended June 30, 2012 

(2)

At June 30, 2012

(3)

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

(4)

80% of Eagle Ford acreage HBP or not burdened with lease expirations before 2013

34

Reducing Drilling & Completion Costs Increases ROR in Eagle Ford

Wells

Note: Individual well economics only. D&C cost = drilling and completion cost. 

Note: Natural gas price = $3.00/Mcf.  NGL price differential +$2.50/Mcf.  Oil price differential +$4.30/Bbl.

$80 NYMEX Oil

$70 NYMEX Oil

$90 NYMEX Oil

$100 NYMEX Oil

$8 MM D&C Cost

$7 MM D&C Cost

$8 MM D&C Cost

$7 MM D&C Cost

$8 MM D&C Cost

$7 MM D&C Cost

$8 MM D&C Cost

$7 MM D&C Cost

Highlights

35

Haynesville Positioning

Approximately 12,500 gross

and 5,800 net acres in

Haynesville Tier 1 core area

Almost all prospective

Haynesville acreage is HBP –

provides “natural gas bank”

for future development

MTDR active as both operator

and non-operator in

Haynesville play

Approximately 1,700 net

acres with Bossier potential

Haynesville acreage also

prospective for shallower

targets –

Cotton Valley,

Hosston –

in many areas

Approximately 10,000 net

HBP acres prospective for

Cotton Valley Horizontal play

at Elm Grove / Caspiana

Note:  Matador operates two sections, including the LA Wildlife and the BLM sections, in Tier 1; all other acreage in Tier 1 is non-operated.

Note:  All acreage at June 30, 2012

TIER 3

TIER 2

TIER 1

Bossier

Caddo

Webster

De Soto

Red River

Bienville

Southwest

Pine Island

Central

Pine Island

Fee Minerals

Rudd #1H

Samson

Petrohawk

Shell

Encana

Petrohawk

Petrohawk

Shell

Encana

Questar

Petrohawk

Petrohawk

J-W

Tigner

Walker H#1 Alt (CV)

LA Wildlife H#1 Alt. (HV)

Williams 17 H#1 (HV)

LA Wildlife (MPC)

BLM (MPC)

36

Haynesville Well Economics –

Tier 1 Area

Natural Gas Price, $/Mcf

0

25

50

75

100

125

150

175

200

225

250

3

3.5

4

4.5

5

5.5

6

8 Bcf - $8.5 MM D&C Cost

9 Bcf - $8.5 MM D&C Cost

10 Bcf - $8.5 MM D&C Cost

8 Bcf - $9.5 MM D&C Cost

9 Bcf - $9.5 MM D&C Cost

10 Bcf - $9.5 MM D&C Cost

Note: Individual well economics only.  D&C cost = drilling and completion cost.  Natural gas price differential = $(0.85)/Mcf.

Business Strategy to Deliver Growth and Value

37

Exploration and Development

2012E CapEx program focused on oil and liquids opportunities

Balanced Portfolio

Growing Eagle Ford and Delaware Basin contributes to a diversified portfolio mix between oil

and natural gas

Active,

ongoing

exploration

effort

continues

to

identify

new

oil

prospects

and

opportunities

Pursue Opportunistic Acquisitions

Ability to identify high return, operated opportunities at attractive prices

History of significant acquisitions and joint ventures

Maintain Financial Discipline

Keep balance sheet strong and control expenses

Work with industry participants to control costs for non-operated properties

Leverage Industry Relationships

Leverage expertise of our industry partners, exchange data and information and build upon

existing relationships

Continue active participation in industry consortia and professional societies

Build Upon Director and Management Team Experience and Success in Unconventional

Plays

38

Matador Today

Gross

Acres

(1),(2)

107,122 acres

Net

Acres

(1),(2)

100,670 acres

2012E CapEx Budget

$2.5 million

Matador Today

Gross

Acres

(1),(3)

10,714 acres

Net

Acres

(1),(3)

4,717 acres

Wyoming, Utah and Idaho (Meade Peak Shale)

Option Value in Large Unevaluated Acreage Positions

Initial test well drilled and cored through the Meade Peak

shale

Detailed petrophysical and rock property testing concluded

Carried participation interest provided by industry partner

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.

Southeast New Mexico / West Texas

(1)

At June 30, 2012

(2)

While we and our partners continue to evaluate the results from the initial test well and plan for its completion and further testing, we expect a portion of our acreage will be allowed  to expire during 2012

(3)

We believe approximately 8,000 gross and 2,000 net acres are no longer prospective, and we plan to let them expire without drilling during 2012

39

Selected Historical Financials

(Revenues and Adjusted EBITDA in millions)

Year Ended December 31,

Three Months Ended June 30,

2009

2010

2011

2011

2012

Production Summary

Oil Production (MBbl)

30

33

154

51

285

Gas Production (Bcf)

4.8

8.4

14.5

4.1

3.1

Total Production (MBOE)

830

1,433

2,571

728

795

Realized Prices (Including hedges)

Oil ($/ Bbl)

$57.72

$76.39

$93.80

$99.72

$105.82

Natural Gas ($/ Mcf)

$5.17

$4.38

$4.11

$4.11

$3.48

Revenues

Oil and Natural Gas Revenues

$19.0

$34.0

$67.0

$20.9

$36.1

Realized Gain on Derivatives

7.6

5.3

7.1

1.0

4.7

Unrealized Gain (Loss) on Derivatives

(2.4)

3.1

5.1

0.3

15.1

Total Revenues

$24.3

$42.5

$79.2

$22.1

$55.9

Operating Expenses ($/ BOE)

   Production Taxes and Marketing

$1.30

$1.38

$2.44

$2.27

$3.29

   Lease Operating

5.69

3.69

2.82

2.70

8.02

   Depletion, Depreciation and Amortization

12.94

10.89

12.35

11.23

25.04

   General and Administrative

8.57

6.77

5.21

4.25

5.15

Total Expenses

$28.50

$22.73

$22.82

$20.45

$41.50

Adjusted EBITDA

(1)

$15.2

$23.6

$49.9

$15.3

$27.9

(1)

Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see slide 29

40

Investment Highlights

Strong Growth Profile with Increasing Focus on Oil / Liquids

Oil production up almost five-fold in 2011 and projected to increase 8x to 9x in 2012

2012E capital expenditure program focused on oil and liquids exploration and development

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 HBP

Significant Multi-year Drilling Inventory

Strong Financial Position and Long-Term Institutional, Industry and Individual Shareholders

Proven Management, 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

Active Exploration Effort Using Science and Technology

Ongoing pipeline of new oil and natural gas opportunities, with strong emphasis on science and

technology to create value

Diversified Investor Composition Before July 31, 2012 Lock-up Expiration

41

Given management’s significant equity position, interests are well aligned with public shareholders

Unique and diverse investor base includes institutional and industry shareholders with significant

experience investing in the oil and gas sector

Most initial capital was provided by investor base of predecessor company, Matador Petroleum

Corporation

Investor composition prior to July 31, 2012 lock-up expiration:

(1)  Approximate ownership at the time of the IPO

(2)  Public Float percentage also includes shares purchased by Management and Legacy Shareholders on or after the IPO

Management

13%

of shares

(1)

Legacy Shareholders

60%

of shares

(1)

Public Float

27%

of shares

(2)

Matador Resources Company (“MTDR”)

42