Presentation Materials

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.

Founded by Joe Foran in 1983

Foran Oil funded with $270,000 in contributed capital from 17 friends and family members

Foran Oil & Matador Petroleum

Matador History

Matador Resources Company

Founded by Joe Foran in 2003 with a proven management and technical team and board of directors

Grown through the drill bit, with focus on unconventional reservoir plays, initially in Haynesville

In 2008, sold Haynesville rights in approximately 9,000 net acres to Chesapeake for approximately

$180 million; retained 25% participation interest, carried working interest and overriding royalty interest

Relatively early in the play, redeployed capital into the Eagle Ford, acquiring over 30,000 net acres for

approximately $100 million, most in 2010 and 2011

IPO in February 2012 (NYSE: MTDR) had net cash proceeds of approximately $136.6 million

Predecessor Entities

(1)

Tom Brown purchased by Encana in 2004

Matador Today

Capital spending focused on developing Eagle Ford and transition to oil

Sold to Tom Brown, Inc. in June 2003 for an enterprise value of $388 million in an all-cash transaction

(1)

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 Prudent Risk Management

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

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 @ 9/30/12

11.1 Million BOE

% Proved Developed

46%

% Oil / Liquids

75%

Daily Oil Production

(1)

3,448 BOE/d

Gross Acres

(2)

47,956 acres

Net Acres

(2)

29,872 acres

Eagle Ford

(2),(3)

29,872 acres

Austin

Chalk

(2),(3)

17,191 acres

2012E Anticipated Drilling

27.6 net wells

2012E CapEx Budget

$268.5 million

Average daily oil production for the nine months ended September 30, 2012

At September 30, 2012

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

(1)

(2)

(3)

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

(Net Acres / $mm)

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

2012E Capex

(1)

% Eagle Ford

53.4

51.8

38.6

35.5

35.3

28.9

25.5

23.9

23.1

23.0

16.1

9.1

4.6

4.0

SFY

MTDR

FST

NFX

GDP

CRZO

PVA

CHK

ROSE

MHR

PXD

APA

PXP

APC

64%

84%

45%

30%

57%

63%

36%

40%

93%

92%

N/A

Note: Reflects companies with greater than 50 Bcfe of proved reserves. Data sourced from public filings; stock price data as of November 7, 2012 close

(1) Per operational guidance

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 / 11,409 net acres

EAGLE FORD EAST

7,567 gross / 6,170 net acres

EOG OPERATED, MTDR WI ~21%

17,256 gross / 3,402 net acres

Note: All acreage at September 30, 2012

EAGLE FORD ACREAGE TOTALS

47,956 gross / 29,872 net acres

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

Matador Resources Acreage

Eagle Ford 24-Hour Stabilized Rates

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

164

3,648

772

15/64

3,365

Martin Ranch A 1H

La Salle

1/20/2011

4,201

1,129

2,821

1,599

34/64

1,550

Affleck 1H

Dimmit

2/22/2011

4,711

456

5,247

1,331

36/64

1,435

Frances Lewton 1H

DeWitt

11/16/2011

5,041

1,021

2,574

1,450

13/64

5,000

Martin Ranch A 2H

La Salle

11/19/2011

6,772

1,318

1,845

1,626

26/64

1,800

Martin Ranch A 3H

La Salle

11/26/2011

4,476

802

510

887

26/64

1,510

Martin Ranch A 5H

La Salle

12/17/2011

4,518

893

545

984

26/64

1,250

2012 Wells

Martin Ranch A 8H

La Salle

1/28/2012

6,092

1,089

831

1,228

26/64

1,750

Martin Ranch A 6H

La Salle

2/8/2012

6,509

689

1,714

975

26/64

1,650

Martin Ranch A 7H

La Salle

2/12/2012

4,902

609

481

689

26/64

1,040

Martin Ranch B 4H

La Salle

2/18/2012

3,551

595

968

756

26/64

1,320

Matador Sickenius Orca 1H

Karnes

3/16/2012

5,712

785

540

875

26/64

820

Northcut A 1H

La Salle

3/23/2012

4,446

583

592

682

26/64

1,000

Matador Danysh Orca 1H

Karnes

4/1/2012

4,962

1,012

1,126

1,200

26/64

1,175

Northcut A 2H

La Salle

5/1/2012

4,503

758

761

885

24/64

950

Matador Pawelek Orca 1H

Karnes

6/5/2012

6,103

670

739

793

16/64

2,510

Matador Pawelek Orca 2H

Karnes

6/7/2012

6,202

861

755

987

16/64

2,460

Matador Danysh Orca 2H

Karnes

6/10/2012

5,115

750

746

874

16/64

2,675

Glasscock Ranch 1H

Zavala

6/27/2012

5,352

307

pump

140

Matador K. Love Orca 1H

DeWitt

8/10/2012

5,077

1,793

2,171

2,155

16/64

5,280

Matador K. Love Orca 2H

DeWitt

8/11/2012

4,871

1,757

2,126

2,111

16/64

5,900

Average

5,090

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

Technical Advancements in the Eagle Ford

Rotary Steerable Tools

Drilling time in curve and lateral reduced by 2 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 created 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

Multi-Pay Fairway: Productive and Prospective Pay Zones

Austin Chalk

Eagle Ford

Buda

Georgetown

Del Rio

Edwards

Glen Rose

Rodessa

Pearsall

Olmos

Navarro

ANCC

Sligo

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

Zavala, Frio, La Salle and Dimmit Counties: Important Matador and

Competitor Eagle Ford Wells Since 2011

Note: Well data available through public sources and interpretation by Matador Resources

(ZaZa) Cenizo Ranch B 3H

OIL IP: 208; GAS IP: 260

17/64”

choke

Best 3 Oil -

8,460

(CHK) Rogers B 2H

OIL IP: 560; GAS IP: 175

12/64”

choke

Best 3 Oil –

31,184

(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 Eagle 1H

OIL IP: 756 ; GAS IP: 943

48/64”

choke

Best 3 Oil -

25,138

(Goodrich) Burns A 35H

OIL IP: 736; GAS IP: 589

49/64”

choke

Best 3 Oil –

16,766

(CHK) Brownlow 1H

OIL IP: 764; GAS IP: 437

30/64”

choke

Best 3 Oil –

21,853

(Crimson) K M Ranch 1H

Plug back 3076’

Lateral

OIL IP: 200; GAS IP: 275

20/64”

choke

Best 3 Oil –

8,038

(Hughes) LANG 1H

OIL IP: 165; GAS IP: 200

18/64”

choke

Last

Act.

Date

–

09/2012

(Hughes) Heitz 1H

OIL IP: 200; GAS IP: 150

26/64”

choke

(CHK) Bohannam Dim C 1H

OIL IP: 466; GAS IP: 174

10/64”

choke

Best 3 Oil –

18,031

(CHK) Yarbrough B 2H

OIL IP: 776; GAS IP: 81

14/64”

choke

Marketing Issues

(BBOG) Coppadge 1H

OIL IP: 19; GAS IP: 271

19/64”

choke

Best 3 Oil -

655

(BBOG) Nickolson 1H

OIL IP: 218; GAS IP: 2167

19/64”

choke

Best 3 Oil -

6,927

(BBOG) Oppenheimer A1

OIL

IP:

273;

GAS

IP:

1400

38/64”

choke

Best 3 Oil –

9,725

(BBOG) Calvert 1H

OIL IP: 170; GAS IP: 1812

28/64”

choke

Best 3 Oil –

14,292

LEGEND

AUSTIN CHALK

BUDA/DEL RIO

Matador Acreage

Buda Wells

Wells Spudded Since 1/2011

Highlights

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

–

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 September 30, 2012; HBP = Held by production

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

Shell

Encana

Questar

Petrohawk

-W

Tigner

Walker H#1 Alt (CV)

LA Wildlife H#1 Alt. (HV)

Williams 17 H#1 (HV)

LA Wildlife (MPC)

BLM (MPC)

Wolfbone Play in the Delaware Basin (West Texas) Stratigraphic Column

Note: Information from public sources

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

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

Wolfbone Play in the Delaware Basin (West Texas)

Major Operator Index

Matador Resources

Anadarko Petroleum Corp.

SWEPI LP

Cimarex Energy

Clayton Williams Energy

Devon Energy Production

Energen Resources Corp.

Oxy USA Inc.

Matador Resources

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

Wolfcamp

17 mo.cum:

122 MBO, 344 MMcf

Wolfcamp

22 mo.cum:

140 MBO, 475 MMcf

Wolfcamp

4 mo.cum:

27 MBO, 100 MMcf

OXY –

Currently drilling.

Bonespring

mo.cum:

MBO,

MMcf

Wolfcamp

cum:

23 MBO, 80 MMcf

Wolfcamp

6 mo.cum:

51 MBO, 120 MMcf

Wolfcamp

8 mo.cum:

38 MBO, 85 MMcf

Dorothy

White

Upr

Wolfcamp

Cum

MBO,

MMcf

Wolf

Upr

Wolfcamp

Cum

MBO,

620

MMcf

Wolfcamp

8 mo.cum:

14 MBO, 150 MMcf

Wolfcamp

5 mo.cum:

40 MBO, 120 MMcf

Wolfcamp

10 mo.cum:

72 MBO, 295 MMcf

Note: As of November 5, 2012 and only wells with total depths greater than 7,000’ posted. Third-party information from public sources.

Ranger-Querecho Prospect Area, Lea County, New Mexico: ~1,700 acres

Queen Producer

San Andres Producer

Delaware Producer

Bone Spring Producer

Wolfcamp Producer

Producing Zone Legend

Penn Producer

Strawn Producer

Atoka Producer

Morrow Producer

BS Cum 238,827 Bo, 479,129 Mcf

BS Cum 48,400 Bo, 126,233 Mcf

BS Cum 580,897 Bo, 454,415 Mcf

BS Cum 254,689 Bo, 342,676 Mcf

BS Cum 624,841 Bo,

539,756 Mcf

IP: 68 Bopd 84 Mcfd

5 Month Cum: 34,045 Bo

16,313 Mcf

IP: 230 Bopd 349 Mcfd

18 Month Cum: 79,989 Bo

101,356 Mcf

IP: 850 Bopd 1,839 Mcfd

5 Month Cum: 105,141 Bo

72,414 Mcf

IP: 318 Bopd 288 Mcfd

8 Month Cum: 101,111 Bo

139,692 Mcf

IP: 1,470 Bopd 750 Mcfd

Cum: not Rept.

IP: 342 Bopd 500 Mcfd

Cum: not Rept.

IP: 511 Bopd

293 Mcfd

IP: 480 Bopd 617 Mcfd

9 Month Cum: 158,754 Bo

106,038 Mcf

IP: 148 Bopd 270 Mcfd

7 Month Cum: 28,550 Bo

23,026 Mcf

IP: 107 Bopd 295 Mcfd

10 Month Cum: 41,946 Bo

56,912 Mcf

IP: 107 Bopd 23 Mcfd

13 Month Cum: 23,147 Bo 14,541 Mcf

BS Cum 296 Bo,

5,145 Mcf

WC Cum: 27,817 Bo,

156,298 Mcf

WC Cum: 385,560 Bo, 5,001,073 Mcf

BS Cum 305,626 Bo 206,352 Mcf

WC Cum: 155,751 Bo, 2,009,587 Mcf

BS Cum 95,399 Bo, 174,936 Mcf

BS Cum 77,261 Bo, 149,591 Mcf

BS Cum 16,918 Bo, 28,097 Mcf

BS Cum 141 Bo, 67 Mcf

IP: 1,392 Bopd 1,130 Mcfd

8 Month Cum: 197,651 Bo

209,755 Mcf

IP: 195 Bopd 236 Mcfd

12 Month Cum: 25,051 Bo 52,889 Mcf

Note: Only wells with TDs greater than 7,000’ posted; Well data available through public sources and interpretation by Matador Resources

Continued Growth

Note: YTD 2012 is through September 30, 2012

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

Year Ended December 31,

(INCLUDING REALIZED GAIN ON DERIVATIVES)

$8.1

$18.4

$15.2

$23.6

$49.9

$77.9

2007

2008

2009

2010

2011

YTD

2012

$14.2

$29.3

$26.7

$39.3

$74.1

$114.4

2007

2008

2009

2010

2011

YTD

2012

911

1,506

2,285

3,926

7,048

8,023

8,738

8,838

2007

2008

2009

2010

2011

2012

AVERAGE DAILY OIL

TOTAL REALIZED

EQUIVALENT PRODUCTION

REVENUES

ADJUSTED

EBITDA

(1)

Recent Production and Financial Highlights

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

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 of $28.6 million, a year-over-year increase of 137%

Nine months ended September 30, 2012

Adjusted EBITDA 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

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%

25%

sequential

increase

oil

reserves

8.4

million

Bbl

and

20%

sequential

increase

PV-10

(1)

proved reserves to $363.6 million (Standardized Measure of $333.9 million)

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)

625,200

4,864,800

Weighted Average Price ($ / gal)

$0.81

$0.79

Reserves Summary –

September 30, 2012

Total proved reserves: 20.9 million BOE (125.4 Bcfe) at September 30, 2012, including 8.4 million Bbl of

oil and 74.9 Bcf of natural gas

Oil

reserves

grew

25%

8.4

million

Bbl

from

6.7

million

Bbl

June

30,

2012

Oil reserves grew 122% from December 31, 2011

PV-10

(1)

increased

20%

$363.6

million

(Standardized

Measure

$333.9

million)

from

$303.4

million

(Standardized Measure of $281.5 million) at June 30, 2012

PV-10

(1)

increased 46% from $248.7 million (Standardized Measure of $215.5 million) at December

31, 2011, despite removal of close to 100 Bcf of proved undeveloped Haynesville shale gas reserves

at June 30, 2012

(1) PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10, see Appendix

Oil reserves comprised 40% (1 Bbl = 6 Mcf basis) of total proved reserves at September 30, 2012, up

from 12% at December 31, 2011 and 4% at September 30, 2011

Eagle

Ford

reserves

comprised

90%

total

PV-10

(1)

September

30,

2012

compared

24%

September 30, 2011

September 30,

December 31,

2012

2011

ASSETS

Current assets

Cash and cash equivalents

4,178

10,284

Certificates of deposit

266

1,335

Accounts receivable

Oil and natural gas revenues

17,046

9,237

Joint interest billings

4,252

2,488

Other

591

1,447

Derivative instruments

6,395

8,989

Lease and well equipment inventory

1,478

1,343

Prepaid expenses

974

1,153

Total current assets

35,180

36,276

Property and equipment, at cost

Oil and natural gas properties, full-cost method

Evaluated

654,292

423,945

Unproved and unevaluated

164,514

162,598

Other property and equipment

24,597

18,764

Less accumulated depletion, depreciation and amortization

(295,042)

(205,442)

Net property and equipment

548,361

399,865

Other assets

Derivative instruments

1,880

847

Deferred income taxes

1,878

1,594

Other assets

1,537

887

Total other assets

5,295

3,328

Total assets

588,836

439,469

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED

(In thousands, except par value and share data)

Financial Statements –

Quarterly Period Ended September 30, 2012

$4.4 million cash

September 30,

December 31,

2012

2011

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities

Accounts payable

17,364

18,841

Accrued liabilities

50,262

25,439

Royalties payable

5,920

1,855

Borrowings under Credit Agreement

25,000

Derivative instruments

171

Advances from joint interest owners

1,782

Income taxes payable

188

Deferred income taxes

1,878

3,024

Dividends payable - Class B

Other current liabilities

177

Total current liabilities

77,450

74,576

Long-term liabilities

Borrowings under Credit Agreement

106,000

88,000

Asset retirement obligations

4,551

3,935

Derivative instruments

142

383

Other long-term liabilities

1,465

1,060

Total long-term liabilities

112,158

93,378

Shareholders' equity

Common stock - Class A, $0.01 par value, 80,000,000 shares

567

429

authorized; 56,697,718 and 42,916,668 shares issued;

55,502,209 and 41,737,493 shares outstanding, respectively

Common stock - Class B, $0.01 par value, zero and 2,000,000 shares

authorized; zero and 1,030,700 shares issued and outstanding, respectively

Additional paid-in capital

403,248

263,562

Retained earnings

6,178

18,279

Treasury stock, at cost, 1,192,509 and 1,179,175, respectively

(10,765)

Total shareholders' equity

399,228

271,515

Total liabilities and shareholders' equity

588,836

439,469

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED

(In thousands, except par value and share data)

Financial Statements –

Quarterly Period Ended September 30, 2012

9/30/2012 borrowings

at $106 million;

11/9/12 borrowings

at $135 million

2012

2011

2012

2011

Revenues

Oil and natural gas revenues

38,008

17,447

103,250

52,009

Realized gain on derivatives

3,371

1,435

11,147

4,237

Unrealized (loss) gain on derivatives

(12,993)

2,870

(1,149)

1,534

Total revenues

28,386

21,752

113,248

57,780

Expenses

Production taxes and marketing

2,822

1,848

7,605

4,801

Lease operating

6,491

2,065

17,511

5,639

Depletion, depreciation and amortization

21,680

7,288

52,799

22,578

Accretion of asset retirement obligations

170

158

Full-cost ceiling impairment

3,596

36,801

35,673

General and administrative

3,439

4,207

11,321

9,919

Total expenses

38,087

15,469

126,207

78,768

Operating (loss) income

(9,701)

6,283

(12,959)

(20,988)

Other income (expense)

Net loss on asset sales and inventory impairment

(60)

Interest expense

(144)

(171)

(453)

(461)

Interest and other income

157

248

Total other expense

(89)

(356)

(213)

(Loss) income before income taxes

(9,790)

6,194

(13,315)

(21,201)

Income tax provision (benefit)

Current

188

(46)

Deferred

(781)

(1,430)

(6,906)

Total income tax benefit

(593)

(1,242)

(6,952)

Net (loss) income

(9,197)

6,194

(12,073)

(14,249)

Earnings (loss) per common share

Basic

Class A

(0.17)

0.14

(0.23)

(0.34)

Class B

0.21

(0.03)

(0.14)

Diluted

Class A

(0.17)

0.14

(0.23)

(0.34)

Class B

0.21

(0.03)

(0.14)

Weighted average common shares outstanding

Basic

Class A

55,271

41,720

53,379

41,671

Class B

1,031

140

1,031

Total

55,271

42,751

53,519

42,702

Diluted

Class A

55,271

41,848

53,379

41,671

Class B

1,031

140

1,031

Total

55,271

42,879

53,519

42,702

Three Months Ended September 30,

Nine Months Ended September 30,

Financial Statements –

Quarterly Period Ended September 30, 2012

Production

Up 28% Q3/Q3; up 21% YTD/YTD

Oil up 7x Q3/Q3; up 7x YTD/YTD

Gas down 14% Q3/Q3; down 15% YTD/YTD

O&G Revenues

Up 118% Q3/Q3

Oil revenue = $30.1 million

2012 YTD Unit Costs

PTM = $3.25/BOE

LOE = $7.49/BOE

G&A = $4.84/BOE

DD&A = $22.58/BOE

Operating costs* = $15.58/BOE

2011 YTD Unit Costs

PTM = $2.48/BOE

LOE = $2.92/BOE

G&A = $5.13/BOE

DD&A = $11.68/BOE

Operating costs* = $10.53/BOE

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED

(In thousands, except per share data)

* Operating costs defined as = PTM + LOE + G&A

2012

2011

Operating activities

Net loss

(12,073)

(14,249)

Adjustments to reconcile net loss to net cash

provided by operating activities

Unrealized loss (gain) on derivatives

1,149

(1,534)

Depletion, depreciation and amortization

52,799

22,578

Accretion of asset retirement obligations

170

158

Full-cost ceiling impairment

36,801

35,673

Stock option and grant expense

(585)

1,379

Restricted stock and restricted stock units expense

362

Deferred income tax benefit

(1,430)

(6,906)

Loss on asset sales and inventory impairment

Changes in operating assets and liabilities

Accounts receivable

(8,718)

(2,411)

Lease and well equipment inventory

(285)

(1)

Prepaid expenses

179

240

Other assets

(650)

Accounts payable, accrued liabilities and other liabilities

6,105

(2,360)

Income taxes payable

188

Royalties payable

4,065

2,548

Advances from joint interest owners

1,782

(723)

Other long-term liabilities

406

Net cash provided by operating activities

80,325

34,443

Investing activities

Oil and natural gas properties capital expenditures

(212,702)

(104,733)

Expenditures for other property and equipment

(5,297)

(3,303)

Purchases of certificates of deposit

(416)

(3,721)

Maturities of certificates of deposit

1,485

3,985

Net cash used in investing activities

(216,930)

(107,772)

Financing activities

Repayments of borrowings under Credit Agreement

(123,000)

Borrowings under Credit Agreement

116,000

60,000

Proceeds from issuance of common stock

146,510

592

Swing sale profit contribution

Cost to issue equity

(11,599)

(1,185)

Proceeds from stock options exercised

2,660

837

Payment of dividents - Class B

(96)

(206)

Net cash provided by financing activities

130,499

60,038

Decrease in cash and cash equivalents

(6,106)

(13,291)

Cash and cash equivalents at beginning of period

10,284

21,059

Cash and cash equivalents at end of period

4,178

7,768

Nine Months Ended September 30,

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED

(In thousands, except par value and share data)

Financial Statements –

Quarterly Period Ended September 30, 2012

Total CAPEX incurred at 9/30/12

$237.6 million

76% of 2012 budget

Includes $21.2 million acreage

EBITDA

Q3 2012 = $28.6 million

Q3 2011 = $12.1 million

EBITDA up 137% Q3/Q3

YTD 2012 = $77.9 million

YTD 2011 = $37.6 million

EBITDA up 107% Y/Y

Statements of Operations -

Selected Quarterly Periods in 2012 and 2011

Matador Resources Company and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED

(In thousands, except per share data)

2012

2011

2012

2011

2012

2011

Revenues

Oil and natural gas revenues

38,008

17,447

36,078

20,864

29,164

13,698

Realized gain on derivatives

3,371

1,435

4,713

952

3,063

1,850

Unrealized (loss) gain on derivatives

(12,993)

2,870

15,114

332

(3,270)

(1,668)

Total revenues

28,386

21,752

55,905

22,148

28,957

13,880

Expenses

Production taxes and marketing

2,822

1,848

2,619

1,654

2,164

1,300

Lease operating

6,491

2,065

6,375

1,969

4,645

1,605

Depletion, depreciation and amortization

21,680

7,288

19,913

8,179

11,206

7,111

Accretion of asset retirement obligations

Full-cost ceiling impairment

3,596

33,205

35,673

General and administrative

3,439

4,207

4,093

3,094

3,789

2,619

Total expenses

38,087

15,469

66,263

14,953

21,857

48,347

Operating (loss) income

(9,701)

6,283

(10,358)

7,195

7,100

(34,467)

Other income (expense)

Net loss on asset sales and inventory impairment

(60)

Interest expense

(144)

(171)

(1)

(183)

(308)

(106)

Interest and other income

Total other expense

(89)

(31)

(89)

(235)

(35)

(Loss) income before income taxes

(9,790)

6,194

(10,389)

7,106

6,865

(34,502)

Income tax provision (benefit)

Current

188

(46)

Deferred

(781)

(3,713)

3,064

(6,906)

Total income tax benefit (provision)

(593)

(3,713)

(46)

3,064

(6,906)

Net (loss) income

(9,197)

6,194

(6,676)

7,152

3,801

(27,596)

Earnings (loss) per common share

Basic

Class A

(0.17)

0.14

(0.12)

0.17

0.08

(0.65)

Class B

0.21

0.23

0.15

(0.58)

Diluted

Class A

(0.17)

0.14

(0.12)

0.17

0.08

(0.65)

Class B

0.21

0.23

0.15

(0.58)

Weighted average common shares outstanding

Basic

Class A

55,271

41,720

55,271

41,667

49,597

41,624

Class B

1,031

419

1,031

Total

55,271

42,751

55,271

42,698

50,016

42,655

Diluted

Class A

55,271

41,848

55,271

41,782

49,666

41,624

Class B

1,031

419

1,031

Total

55,271

42,879

55,271

42,813

50,085

42,655

Three Months Ended March 31,

Three Months Ended September 30,

Three Months Ended June 30,

Board

Directors

and

Special

Board

Advisors

–

Expertise

and

Stewardship

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

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

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

Oil & Gas Executive

Management

Retired President, DeGolyer and MacNaughton (Worldwide Petroleum Consultants)

Proven Management Team –

Experienced Leadership

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

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

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

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

362

Net loss (gain) on asset sales and inventory impairment

(136,977)

379

224

154

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

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

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.

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

106

184

171

222

308

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

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

117

1,220

983

(374)

(252)

Restricted stock grants

150

201

Net (gain)/loss on asset sales and inventory impairment

224

154

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

106

184

171

222

308

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

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.

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.