8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

Date of Report (Date of Earliest Event Reported) April 11, 2013

Matador Resources Company

(Exact name of registrant as specified in its charter)

Texas	001-35410	27-4662601
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)
5400 LBJ Freeway, Suite 1500, Dallas, Texas		75240
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (972) 371-5200

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition.

Attached hereto as Exhibit 99.1 is a Press Release issued by Matador Resources Company (the “Company”) on April 15, 2013 regarding an update on various aspects of its business.

The Company expects to make presentations concerning its business to potential investors. The materials to be utilized during the presentations (the “Materials”) are furnished as Exhibit 99.2 hereto and incorporated herein by reference.

The information furnished pursuant to this Item 2.02, including Exhibits 99.1 and 99.2, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended (the “Securities Act”), unless specifically identified therein as being incorporated therein by reference.

In the Materials, the Company has included as “non-GAAP financial measures,” as defined in Item 10 of Regulation S-K of the Exchange Act, (i) 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”) and (ii) present value discounted at 10% (pre-tax) of estimated total proved reserves (“PV-10”). In the Materials, the Company has provided reconciliations of the non-GAAP financial measures to the most directly comparable financial measures calculated and presented in accordance with generally-accepted accounting principles (“GAAP”) in the United States. In addition, in the Materials, the Company has provided the reasons why the Company believes those non-GAAP financial measures provide useful information to investors.

Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

On April 11, 2013, the Board of Directors (the “Board”) of the Company appointed Carlos M. Sepulveda, Jr. to the Board. Mr. Sepulveda is retiring as President and CEO of Interstate Battery System International, Inc. — a position he has held since March 2004 — in May 2013 but will remain on that company’s board of directors. He serves as Chairman of the Board of Triumph Bancorp, Inc. and also serves on the Board of Directors and is Chair of the Audit Committee of Cinemark Holdings, Inc. The Company anticipates that Mr. Sepulveda will be appointed to the Audit Committee of the Board at the Board’s next regularly scheduled meeting in May 2013.

Mr. Sepulveda was appointed to serve as a Class I director and will stand for election as a Class I director at the 2013 Annual Meeting of Shareholders to serve for a term of office until the Company’s 2015 Annual Meeting of Shareholders and until the election and qualification of his successor or until his earlier death, retirement, resignation or removal.

Mr. Sepulveda will be compensated according to the director compensation program described in the Director Compensation section of the Company’s Proxy Statement for the Annual Meeting of Shareholders held on June 7, 2012 and incorporated herein by reference. He will also enter into an indemnification agreement with the Company in the form included as Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011 and incorporated herein by reference.

On February 7, 2012, upon the closing of our initial public offering, Mr. Sepulveda purchased $600,000 of the Company’s common stock in the directed share program from the underwriters in the offering at the initial price to the public.

Item 7.01 Regulation FD Disclosure.

Item 2.02 is incorporated herein by reference.

The information furnished pursuant to this Item 7.01, including Exhibits 99.1 and 99.2, shall not be deemed to be “filed” for the purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any filing under the Securities Act unless specifically identified therein as being incorporated therein by reference.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit No.	Description of Exhibit
99.1	Press Release, dated April 15, 2013.
99.2	Presentation Materials.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	MATADOR RESOURCES COMPANY
Date: April 15, 2013	By:	/s/ David E. Lancaster
	Name:	David E. Lancaster
	Title:	Executive Vice President

Exhibit Index

Exhibit No.	Description of Exhibit
99.1	Press Release, dated April 15, 2013.
99.2	Presentation Materials.

EX-99.1

Exhibit 99.1

NEWS RELEASE

MATADOR RESOURCES COMPANY ANNOUNCES FIRST QUARTER 2013

PRODUCTION RESULTS AND ADDITION OF NEW DIRECTOR

DALLAS, Texas, April 15, 2013 – Matador Resources Company (NYSE:MTDR) (“Matador” or the “Company”), an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources, with a particular emphasis on oil and natural gas shale plays and other unconventional plays and currently focused on its Eagle Ford operations in South Texas, today provided this operational update and announced the appointment of a new member to its Board of Directors.

Matador announced first quarter 2013 oil and natural gas production of approximately 460,000 Bbl and 3.1 Bcf, respectively, compared to approximately 200,000 Bbl of oil and 3.2 Bcf of natural gas produced in the first quarter of 2012 and compared to guidance provided on Analyst Day on December 6, 2012 of approximately 360,000 Bbl of oil and 2.8 Bcf of natural gas. This increase was due primarily to the improved performance and productivity of its recent Eagle Ford wells as well as production increases resulting from the initiation of artificial lift operations on various producing wells. More specifically, Matador’s first quarter oil equivalent production was approximately 10,900 BOE per day, including approximately 5,100 Bbl of oil per day and 34.7 MMcf of natural gas per day, which was above the Company’s estimates of approximately 4,000 Bbl of oil per day and 31.1 MMcf of natural gas per day for the quarter as announced at Analyst Day on December 6, 2012. Matador’s first quarter oil production of 460,000 Bbl was a sequential increase of approximately 8% from 426,000 Bbl of oil produced in the fourth quarter of 2012. Notably, this increase has occurred despite the fact that about 10% of the Company’s Eagle Ford productive capacity was shut-in at various times during the quarter and that Matador has not added a new producing well since early February, due to its practice of pad drilling and simultaneous hydraulic fracturing operations.

Matador completed and began producing oil and natural gas from four operated Eagle Ford shale wells, all in LaSalle County, during January and early February 2013 and anticipates completing and initiating production from seven operated Eagle Ford shale wells during the second quarter, three in DeWitt County in late April and four in LaSalle County in late May. Beginning in late April, Matador plans to have one contracted drilling rig operating in LaSalle County in South Texas, while a second contracted drilling rig will initiate a three-well testing program of its acreage position in Southeast New Mexico and West Texas. The Company currently plans to resume its two-rig Eagle Ford drilling program in the third quarter of 2013.

The Company is also pleased to announce the addition of Mr. Carlos M. Sepulveda, Jr. to its Board of Directors. Carlos is currently the President and CEO of Interstate Battery System International, Inc., Chairman of the Board of Triumph Bancorp, Inc. and Director and Chairman of the Audit Committee of Cinemark Holdings, Inc. He will be retiring in May 2013 from Interstate Battery System International,

Inc., but will continue serving as a director of the company. Carlos holds a Bachelor of Business Administration degree, majoring in accounting and graduating with highest honors, from The University of Texas at Austin.

Joseph Wm. Foran, Matador’s Chairman, President and CEO commented, “We are very pleased by the strong production results achieved in early 2013 in our Eagle Ford program in South Texas and have been particularly encouraged by the performance of several of our recent wells, which reflects the continued improvements we are making in all aspects of our drilling, completion and production operations in South Texas. We are also looking forward to having Carlos, a long-time shareholder, on our Board with his experience not only in building a company but also his financial expertise and familiarity with the Company. We know that he will make immediate contributions in a number of areas.”

Forward-Looking Statements

This press release includes “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 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 current reserves; 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 future cash flows, increases in our borrowing base and otherwise; weather and environmental concerns; 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, 2012. 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 press release, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release. All forward-looking statements are qualified in their entirety by this cautionary statement.

About Matador Resources Company

Matador is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Its current operations are focused primarily on the oil and liquids rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in West Texas and Southeast New Mexico. Matador also operates in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas.

For more information visit Matador Resources Company at www.matadorresources.com.

Contact Information

Mac Schmitz

Investor Relations

mschmitz@matadorresources.com

(972) 371-5225

EX-99.2

Investor Presentation

April 2013

Exhibit 99.2

2

Disclosure 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, and such

forward-looking statements may not prove to be accurate. These forward-looking statements involve certain risks and uncertainties, including, but

not limited to, the following risks related to our financial and operational performance: general economic conditions; our ability to execute our

business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for

oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop our current reserves; our costs of operations, delays

and other difficulties related to producing oil, natural gas and natural gas liquids; our ability to make acquisitions on economically acceptable

terms; availability of sufficient capital to execute our business plan, including from our future cash flows, increases in our borrowing base  and

otherwise; weather and environmental conditions; and other important factors which could cause actual results to differ materially from those

anticipated or implied in the forward-looking statements. For further discussions of risks and uncertainties, you should refer to Matador’s SEC

filings, including the “Risk Factors” section of Matador’s most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form

10-Q. Matador undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances

occurring after the date of this presentation, except as required by law, including the securities laws of the United States and the rules and

regulations of the SEC. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of

this presentation.  All forward-looking statements are qualified in their entirety by this cautionary statement.

The Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only

proved, probable and possible reserves.  Potential resources are not proved, probable or possible reserves.  The SEC’s guidelines prohibit

Matador from including such information in filings with the SEC. 

Safe Harbor Statement –

Cautionary Note –

Company Summary

4

Company Overview

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

Exchange: Ticker

NYSE: MTDR

Shares Outstanding

(1)

55.84 million common shares

Share Price

(1)

$8.83/share

Market Capitalization

(1)

$493.1 million

2012 Actual                                2013 Guidance

Capital Spending

$335 million

$310 million

Total Oil Production

1.214 million barrels

1.6 to 1.8 million barrels

Total Natural Gas Production

12.5 billion cubic feet

11.0 to 12.0 billion cubic feet

Oil and Natural Gas Revenues

$156.0 million

$200

to

$220

million

(2)

Adjusted EBITDA

(3)

$115.9 million

$140

to

$160

million

(2)

(1)

As of April 11, 2013

(2)

Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production 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 used in these estimates were $94.00/Bbl and $4.43/Mcf, respectively

(3)

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

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

5

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

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

Predecessor Entities

(1)

Tom Brown purchased by Encana in 2004

Matador Today

Sold to Tom Brown, Inc.

(1)

in June 2003 for an enterprise value of $388 million in an all-cash transaction

6

Daily

Production

@

3/31/13

(1)

10,900 BOE/d

Oil Production (% total)

5,100 Bbl/d (47%)

Gas Production (% total)

34.7 MMcf/d (53%)

Proved Reserves @ 12/31/12

23.8 million BOE

% Proved Developed

58%

% Oil

44%

2013E CapEx

$310 million

% South Texas

~82%

% Oil and Liquids

~98%

2013E Anticipated Drilling

31.3 net wells

South Texas

27.4 net wells

West Texas / New Mexico

3.0 net wells

Gross

Acreage

(2)

156,846 acres

Net

Acreage

(2)

98,271 acres

Identified

Drilling

Locations

(3)(4)

873 gross / 413 net

(1)

Estimated average daily production for the three months ended March 31, 2013

(2)

At April 9, 2013

(3)

At December 31, 2012

(4)

Engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and

estimated lateral lengths, costs and well spacing using objective criteria for designation.

Matador Resources Snapshot

7

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 nearly 30 years

Strong Growth Profile with Increasing Focus on Oil / Liquids

Oil production up almost five-fold in 2011 and up almost eight-fold in 2012

2013E capital expenditure program focused on oil and liquids exploration and development

Matador’s Continued Growth

8

(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

Note: 2013E at the mid-point of 2013 guidance, respectively

TOTAL OIL AND

TOTAL OIL PRODUCTION

NATURAL GAS REVENUES

ADJUSTED EBITDA

(1)

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 financial measure.  For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix

(2)  At December 31 of each respective year

9

$41.00 oil

$5.71  gas

$57.65 oil

$3.87  gas

$75.96 oil

$4.38  gas

$92.71 oil

$4.12  gas

$91.21 oil

$2.76  gas

SEC Pricing

Oil, $/Bbl

Gas, $/MMBtu

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

Eagle Ford

South Texas

Proved Reserves @ 12/31/12

14.3 million BOE

% Proved Developed

46%

% Oil / Liquids

72%

Daily Oil Production

(2)

5,050 Bbl/d

Gross Acres

(3)

41,279 acres

Net Acres

(3)

27,697 acres

Eagle Ford

(3)(4)

27,697 acres

Austin Chalk

(3)(4)

17,171 acres

2013E Anticipated Drilling

27.4 net wells

2013E CapEx Budget

$242.7 million

Identified Drilling Locations

(3)(5)

274 gross / 221 net

11

Eagle Ford and Austin Chalk Overview

Drilled and completed 38 gross / 36.5 net

operated

wells

to

date

(1)

Acreage positioned in some of the most

active counties for Eagle Ford and Austin

Chalk

Two rigs running, primarily focused on oil

and liquids

2013E capital expenditure program

focused on oil and liquids development

Proved reserves growth from 4.7 million

BOE at December 31, 2011 and less

than 0.1 million BOE at December 31,

2010

(1)

Total drilled and completed wells operated by Matador as of March 31, 2013

(2)

Estimated average daily oil production for the three months ended March 31, 2013 

(3)

At April 9, 2013

(4)

Some of the same leases cover the net acres shown for Eagle Ford and Austin Chalk. Therefore, the sum for both formations is not equal to 

the total net acreage

(5)

Engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well

spacing using objective criteria for designation.

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)

(Standardized Measure = $394.6 million)

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

(Standardized Measure = $215.5 million)

Proved Producing Reserves PV-10

(1)

: $154.1 million

(1)

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

(2)

Future undiscounted net revenue of $704.2 million using YE 2012 SEC pricing of $91.21/Bbl oil and $2.757/MMBtu gas

12

Highlights

13

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

28,000 net acres

Acreage in both the eastern

and western areas of the

play

Approximately 90% of

acreage in prospective oil

and liquids windows

Acreage offers potential for

Austin Chalk, Buda, Pearsall

and other formations

Good reputation with land and mineral owners

Note:  All Matador acreage at April 9, 2013 and all other acreage based on public information

Eagle Ford Properties

EAGLE FORD ACREAGE TOTALS

41,279 gross / 27,697 net acres

EAGLE FORD EAST

7,707 gross / 6,307 net acres

EOG OPERATED, MTDR WI ~21%

11,588 gross / 2,240 net acres

GLASSCOCK (WINN) RANCH

8,891 gross / 8,891 net acres

EAGLE FORD WEST

13,093 gross / 10,259 net acres

Matador Resources Acreage

San Antonio

Uvalde

Medina

Zavala

Frio

Dimmit

Webb

Bexar

Atascosa

McMullen

Live Oak

Bee

Goliad

Dewitt

Gonzales

Wilson

DRY GAS FAIRWAY

OIL FAIRWAY

Karnes

La Salle

COMBO LIQUIDS /

GAS FAIRWAY

14

Note:  All acreage at April 9, 2013

2012 Operated Eagle Ford Completion Results –

24 Hour IP Tests

15

Well Name

County

Completion Date

Perforated Length

(1)

Top Perf

(2)

Frac Stages

Oil IP

(3)(4)

Gas IP

(3)(4)

Oil Equiv IP

(5)

Choke

Pressure

Total  (ft.)

(ft.)

(Bbl/day)

(Mcf/day)

(BOE/day)

(inch)

(psi)

2012 Wells

Martin Ranch A 8H

La Salle

1/28/2012

6,092

9,559

21

1,089

831

1,228

26/64

1,750

Martin Ranch A 6H

La Salle

2/8/2012

6,509

9,550

22

689

1,714

975

26/64

1,650

Martin Ranch A 7H

La Salle

2/12/2012

4,902

9,502

17

609

481

689

26/64

1,040

Martin Ranch B 4H

La Salle

2/18/2012

3,801

9,701

13

595

968

756

26/64

1,320

Matador Sickenius Orca 1H

Karnes

3/16/2012

5,712

10,897

19

785

540

875

26/64

820

Northcut A 1H

La Salle

3/23/2012

4,446

9,209

15

583

592

682

26/64

1,000

Matador Danysh Orca 1H

Karnes

4/1/2012

4,962

11,537

17

1,012

1,126

1,200

26/64

1,175

Northcut A 2H

La Salle

5/1/2012

4,503

9,273

15

758

761

885

24/64

950

Matador Pawelek Orca 1H

Karnes

6/5/2012

6,103

11,231

20

670

739

793

16/64

2,510

Matador Pawelek Orca 2H

Karnes

6/7/2012

6,202

11,240

28

861

755

987

16/64

2,460

Matador Danysh Orca 2H

Karnes

6/10/2012

5,115

11,331

17

750

746

874

16/64

2,675

Glasscock Ranch 1H

Zavala

6/27/2012

5,352

7,166

18

307

0

307

pump

140

Matador K. Love Orca 1H

DeWitt

8/10/2012

5,077

13,048

17

1,793

2,171

2,155

16/64

5,280

Matador K. Love Orca 2H

DeWitt

8/11/2012

4,871

12,830

17

1,757

2,126

2,111

16/64

5,900

Northcut B 2H

LaSalle

9/6/2012

4,777

9,131

16

410

315

463

16/64

1,175

Northcut B 1H

LaSalle

9/12/2012

4,798

9,085

16

423

169

451

16/64

1,500

Matador Sickenius Orca 2H

Karnes

9/16/2012

5,982

10,829

25

851

556

944

16/64

2,000

Martin Ranch A 12H

LaSalle

10/4/2012

4,897

9,507

21

640

1,955

966

16/64

1,680

Matador K. Love Orca 4H

DeWitt

11/4/2012

4,012

12,611

14

1,509

841

1,649

16/64

4,900

Matador K. Love Orca 3H

DeWitt

11/6/2012

4,777

12,787

16

1,456

1,585

1,720

16/64

4,775

Martin Ranch B 13H

LaSalle

11/22/2012

5,364

9,476

23

519

162

546

14/64

2,125

Martin Ranch B 9RH

LaSalle

11/25/2012

5,364

9,428

23

482

240

522

14/64

2,000

Frances Lewton 2H

DeWitt

12/5/2012

6,277

13,072

21

1,178

4,203

1,879

14/64

6,150

Matador Cowey Orca 1H

DeWitt

12/9/2012

3,332

13,593

13

580

3,325

1,134

12/64

8,000

Northcut A 4H

LaSalle

12/18/2012

4,592

9,069

16

395

139

418

14/64

1,580

Average

5,113

18.4

828  Bbl/day

1,082  Mcf/day

1,008 BOE/day

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

2) Top perf is measured depth

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

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

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

Eagle Ford Well Costs Declined During 2012 –

Western Acreage

16

$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.

Eagle Ford Well Costs Declined During 2012 –

Eastern Acreage

17

$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.

Average Frac Stage Cost per Well

18

$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

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

19

Note: Individual well economics only.  NGL price differential +$1.85/Mcf.  Oil price differential +$7.00/Bbl.

$90.00/Bbl NYMEX oil;

$3.00/Mcf NYMEX natural gas

20

Recent Technical Advancements in the Eagle Ford

Rotary Steerable Tools

Drilling time in curve and lateral reduced by two days

Measurement While Drilling (MWD) telemetry closer to drill bit

Improves ability to stay in “sweet-spot”

Removes sumps and high-angle curves

Improved frac design

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

21

Note: As of January 25, 2013

* Bold wells utilized rotary steerable systems

First 4 Wells

Recent Wells

22

San Antonio

Multi-Pay Fairway

with Pearsall, Austin Chalk and Buda potential

OIL FAIRWAY

OIL FAIRWAY

DRY GAS FAIRWAY

DRY GAS FAIRWAY

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

Note:  All acreage at April 9, 2013

Medina

Zavala

Frio

Dimmit

La Salle

Webb

Bexar

Atascosa

McMullen

Dewitt

Gonzales

Wilson

Karnes

Live Oak

Bee

Goliad

Guadalupe

Uvalde

Matador Resources Acreage

Delaware Basin

Southeast New Mexico and West Texas

24

Gross

Acres

(1)

25,477 acres

Net

Acres

(1)

15,117 acres

Southeast New Mexico / West Texas

Foothold of existing production and

reserves

Acreage position in good neighborhoods,

surrounded

by

other

operators’

ongoing

drilling

In March and April 2013, acquired

approximately 9,617 gross and 7,446 net

acres in Lea and Eddy Counties, New

Mexico for approximately $11.3 million

Company considers 17,795 gross and

13,049 net acres to be prospective for the

Wolfcamp, Bone Spring and other oil and

liquids-rich targets

(1)

Acreage at April 9, 2013

RANGER-

QUERECHO

WOLF

INDIAN

DRAW

LOVING

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

Ranger Prospect Area: Proposed Wolfbone

Multi-Zone Exploration Program and Surrounding Results

Concho

Stratojet 31 State #1H

2

Bone

Spring

18 mo.cum:

316 MBO; 378 MMcf

Cimarex Energy

Lynch 23 Fed #1H

3

Bone

Spring

13 mo.cum:

142 MBO; 99 MMcf

Legacy Operating

Lee Unit 4H

3

Bone

Spring

16 mo.cum:

63 MBO; 55 MMcf

Concho

AirCobra 12 #2H

3

Bone

Spring

17 mo.cum:

246 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

26

Proposed location for

Matador 2013 test well

3 Rivers Oper

Eagle 2 State 6H

3

Bone Spring

2 mo.cum:

32 MBO; 13 MMcf

Cimarex Energy

Mallon 35 Fed 4H

3

Bone

Spring

19 mo.cum:

33 MBO; 20 MMcf

Amtex Energy

Teapot 2H

2

Bone Spring

1 mo.cum:

52 MBO; 37 MMcf

Concho

Condor State #1H

2

Bone

Spring

IP (Oct 2012)

339 BOPD

Concho

Haumea St. #2H

2

Bone

Spring

Completed March 2013

Now Flowing Back

nd

rd

rd

rd

nd

nd

nd

rd

rd

Note: All acreage at April 9, 2013.  Well information from public sources.

Wolf Leasehold:  Proposed Wolfbone

Multi-Zone Exploration Program and Surrounding Results

Wolf Energy

Wolf #1

(Vertical well)

3

BS / Upr Wolfcamp

33 years cum:

58 MBO; 620 MMcf

Wolf Energy

Dorothy White #1

(Vertical well)

3

BS / Upr Wolfcamp

17 years  cum:

25 MBO; 92 MMcf

Chesapeake

Johnson 1-88 Lov #1H

Wolfcamp

10 mo.cum:

72 MBO; 295 MMcf

Chesapeake

Johnson 1-86 (1H)

Wolfcamp

17 mo.cum:

122 MBO; 344 MMcf

Chesapeake

Johnson 1-76 (1H)

Wolfcamp

22 mo.cum:

140 MBO; 475 MMcf

Energen

Grayling 1-69

IP: 791 BOPD 7.3 MMcf/d

3,500 psi FTP

4 mo.cum: 40 MBO; 370 MMcf on

restricted choke

Energen

Black Mamba 1-57

Wolfcamp

3 mo.cum:

61 MBO; 180 MMcf

Proposed location for

Matador 2013 test well

27

Note: All acreage at April 9, 2013.  Well information from public sources.

Chesapeake

Johnson 1-75 Lov #1H

Wolfcamp

6 mo.cum:

51 MBO; 120 MMcf

Energen

Bushmaster 1-58

Wolfcamp

4 mo.cum:

27 MBO; 100 MMcf

Energen

Katie 1-72

Wolfcamp

5 mo.cum:

40 MBO; 120 MMcf

OXY

Reagan-McElvain #1H

Spud 6/27/2012

IP: 570 BOPD 2.6 MMcf/d

2 mo.cum:

37 MBO; 92 MMcf

rd

rd

Haynesville & Cotton Valley

Northwest Louisiana and East Texas

Tier 1 Haynesville and Elm Grove Cotton Valley Acreage Positions

–

Almost all prospective Haynesville acreage is HBP

Note: All acreage at April 9, 2013

CADDO

BOSSIER

BIENVILLE

RED RIVER

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: 12,568 gross, 5,737 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

TIER 1:

6 –

10+ Bcf

TIER 2:

4 –

6 Bcf

TIER 3:

2 –

4 Bcf

29

Note: Matador does not include any of this potential resource inits proved natural gas reserves at December 31, 2012

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

30

Haynesville Well Economics –

Tier 1 Area

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

Natural Gas Price, $/Mcf

31

Cotton Valley Horizontal Well Economics

Note: Individual well economics only.  D&C cost = drilling and completion cost.  Natural gas price differential = (10%)

Natural Gas Price, $/Mcf

Gracie

Wyoming, Utah and Idaho

Matador Gracie Project Total Prospect Acreage

IDAHO

UTAH

WYOMING

61,897 gross acres

30,492 net acres

Crawford Federal  #1H

33

Note: All acreage at April 9, 2013

Crawford Federal #1H

completion scheduled

for summer 2013

Southwest Wyoming Stratigraphy and Target Zones

Lamberson, Paul, 1982, The Fossil Basin

and its Relationship to the

Absaroka Thrust System,

Wyoming and Utah, RMAG

13% TOC

Meade Peak Shale

Cretaceous Shales

2% TOC

Crawford Federal #1:

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

Drilled 2,500-ft horizontal lateral in late

2012; plan to complete in summer 2013

34

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 tests

Includes approximately $25 million for pipelines/facilities and $25 million for land/seismic acquisition

Compares to 2012 Drilling Program of 28 gross / 24.5 net wells for $334.6 million in capital expenditures

2013 expenditures are estimated to be funded 50% through cash flows and 50% through borrowings

under revolving credit facility

2013 Production Expectations

Oil

production

of

1.6

to

1.8

million

barrels

–

mid-point

up

40%

from

1.2

million

barrels

in

2012

Natural

gas

production

of

11.0

to

12.0

Bcf

–

mid-point

down

8%

from

12.5

Bcf

in

2012

2013 Financial Expectations

Oil

and

natural

gas

revenues

(1)

of

$200

to

$220

million

–

mid-point

up

35%

from

$156.0

million

in

2012

Adjusted

EBITDA

(1)(2)

of

$140

to

$160

million

–

mid-point

up

29%

from

$115.9

million

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

Current borrowings are about 1.5x estimated 2013 operational cash flows

(1)  Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production 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 used in these estimates 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 andnet cash provided by operating activities, see Appendix

37

2013 Oil Production

Estimated total oil production of 1.6 to

1.8 million barrels

Mid-point is an increase of 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.

Q1 2013 production of approx. 5,100

Bbl/d exceeded guidance estimates of

approx. 4,000 Bbl/d

2013 Natural Gas Production

Estimated total natural gas production of

11.0 to 12.0 Bcf

Mid-point is a decrease of 8% from 2012

Gas production expected to remain

relatively flat during 2013, but should

include higher percentage of liquids-rich

gas

2013 Production Expectations

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

First Quarter 2013

First Quarter 2013

(1) Estimated (as of December 6, 2012) quarterly average oil and natural gas production at midpoint of guidance range

Funding for 2013 Capital Investment Plan

38

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

As of April 9, 2013, 1.2 million barrels of 2013 oil production hedged protecting cash flows below

approximately $88/Bbl oil price

Credit facility status at April 9, 2013

Borrowing base of $255 million; total facility size of $500 million; facility matures in December 2016

Borrowings outstanding of $215 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

39

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%

40

EAGLE FORD EAST

7,707 gross / 6,307 net acres

EOG OPERATED, MTDR WI ~21%

11,588 gross / 2,240 net acres

GLASSCOCK (WINN) RANCH

8,891 gross / 8,891 net acres

EAGLE FORD WEST

13,093 gross / 10,259 net acres

San Antonio

Zavala

Frio

Dimmit

La

Salle

Webb

Bexar

Atascosa

McMullen

Dewitt

Gonzales

Wilson

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

Karnes

13

2

2

1

3

4 (Non-Op)

4

1 (Buda –

Non-Op)

1 (Edwards –

Non-Op)

1

1

1 (Austin Chalk)

2013 South Texas Drilling Plan

EAGLE FORD ACREAGE TOTALS

41,279 gross / 27,697 net acres

Potential Remaining Eagle Ford Drilling Locations*

274 gross/221 net locations

Tier 1 –

155 gross/125 net locations (40 to 80-acre spacing)

Tier 2 –

119 gross/96 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

(1)  We define Tier 1 Eagle Ford locations as those locations that we anticipate to have estimated ultimate recoveries of 225,000 Bbl of oil or greater.

(2)  We define Tier 2 Eagle Ford locations as those locations that we anticipate to have estimated ultimate recoveries of between 150,000 Bbl and 225,000 Bbl of oil or locations that are primarily prospective for natural gas.

Note:  All acreage values at April 9, 2013.  Net wells reflect Matador’s working interest ownership.

# -

Gross wells planned in 2013;  All Matador

operated Eagle Ford wells unless noted

otherwise

34 gross/27.4 net wells planned in 2013

dina

Matador’s acreage position at April 9, 2013 shown in red.  Note:  Certain additional Matador acreage in Southeast

New Mexico/West Texas not considered prospective as of December 31, 2012.

41

Southeast NM / West Texas Acreage and 2013 Drilling Plan

RANGER

LOVING

WOLF

SOUTHEAST NM / WEST TEXAS

PROSPECTIVE ACREAGE

17,795 gross / 13,049 net acres

RANGER

4,308 gross / 2,727 net acres

Ranger A2

Primary Target: 2nd Bone Spring Sand

Ranger A1

Primary Targets: Wolfcamp/Bone Spring

WOLF

5,203 gross / 3,057 net acres

# -

Matador operated wells planned in 2013

3 gross/3 net horizontal wells planned in 2013

Wolf 1

Primary Target: Wolfcamp Shale

Recent Production and Operational Updates

42

First Quarter 2013 Production

Q1 2013 oil and natural gas production of approximately 460,000 Bbl and 3.1 Bcf, respectively,

compared to approximately 200,000 Bbl of oil and 3.2 Bcf of natural gas produced in Q1 2012

Q1 2013 production was approximately 10,900 BOE per day, including approximately 5,100 Bbl of oil

per day and 34.7 MMcf of natural gas per day

-

Above the Company’s estimates of approximately 4,000 Bbl of oil per day and 31.1 MMcf of

natural gas per day for the quarter as announced at Analyst Day on December 6, 2012

Increase occurred despite about 10% of the Company’s Eagle Ford productive capacity being shut-in

and no additional producing wells being added since early February, due to pad drilling and

simultaneous hydraulic fracturing operations

March and April 2013 Acreage Acquisitions

Acquired approximately 9,617 gross and 7,446 net acres in Lea and Eddy Counties, New Mexico for

approximately $11.3 million

Approximately

17,795

gross

and

13,049

net

acres

of

Southeast

New

Mexico

and

West

Texas

acreage

considered

prospective

for

the

Wolfcamp,

Bone

Spring

and

other

oil

and

liquids-rich

targets

Expect to begin testing acreage beginning in late April 2013

Filed Universal Shelf Registration Statement on Form S-3

Under the registration statement, when declared effective by the SEC, the Company may offer to the public

from time to time in one or more offerings up to $300 million of its senior and subordinated debt securities,

common stock, preferred stock, warrants or any combination of the foregoing at prices and on terms that

Matador will decide at the time of any offering

43

2013

Revenue

and

Adjusted

EBITDA

(1)(2)

Estimated oil and natural gas revenues of $200 to

$220 million

Mid-point is an increase of 35% from $156.0

million in 2012

Estimated Adjusted EBITDA

(1)(2)

of $140 to $160

million

Mid-point is an increase of 29% from $115.9

million in 2012

Adjusted EBITDA

(1)(2)

growth expected to be

impacted by lower oil price realizations and an

estimated decrease of approximately $13 million in

realized hedging gains compared to 2012

2013

Operating

Costs

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)

(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 production 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 used in these estimates were $94.00/Bbl and $4.43/Mcf, respectively

Appendix

Board

of

Directors

and

Special

Board

Advisors

–

Expertise

and

Stewardship

45

Board Members

and Advisors

Professional Experience

Business Expertise

Dr. Stephen A. Holditch

Director

-

Professor Emeritus and Former Head of Dept. of Petroleum Engineering, Texas A&M University

-

Founder and Former 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 and CEO, Toot’n Totum Food Stores

Petroleum Retailing

Dr. Steven W. Ohnimus

Director

-

Retired VP and General Manager, Unocal Indonesia

Oil & Gas Operations

Michael C. Ryan

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

Carlos M. Sepulveda, Jr.

Director

-

President

and

CEO,

Interstate

Battery

System

International,

Inc.

(retiring

May

2013)

-

Chairman of the Board, Triumph Bancorp, Inc.

-

Director and Audit Chair, Cinemark Holdings, Inc.

Business and Finance

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

46

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

Ryan C. London

VP and General Manager

-

Matador Resources Company

9 years

Since 2003

Kathryn L. Wayne

Controller and Treasurer

-

Matador Petroleum Corporation, Mobil

28 years

Since Inception

47

2013 and 2014 Hedging Profile

1.20 million barrels of oil hedged for

remainder of 2013 at weighted average

floor and ceiling of $88/Bbl and $107/Bbl,

respectively

6.6 Bcf of natural gas hedged for

remainder of 2013 at weighted average

floor and ceiling of $3.27/MMBtu and

$4.55/MMBtu, respectively

7.6 million gallons of natural gas liquids

hedged for remainder of 2013 at weighted

average price of $1.21/gal

1.68 million barrels of oil, 8.4 Bcf of natural

gas and 3.7 million gallons of natural gas

liquids hedged for 2014

Note: Hedged volumes shown in table for 2013 are for remainder of 2013; volumes shown in table for 2014 are for full calendar year.

At April 9, 2013, Matador has:

Oil Hedges (Costless Collars)

2013

2014

Total Volume Hedged by Ceiling (Bbl)

1,020,000

1,680,000

Weighted Average Price ($ / Bbl)

$109.39

$98.55

Total Volume Hedged by Floor (Bbl)

1,020,000

1,680,000

Weighted Average Price ($ / Bbl)

$87.35

$87.79

Oil Hedges (Swaps)

2013

2014

Total Volume Hedged (Bbl)

180,000

-

Weighted Average Price ($ / Bbl)

$90.43

-

Natural Gas Hedges (Costless Collars)

2013

2014

Total Volume Hedged by Ceiling (Bcf)

6.55

8.40

Weighted Average Price ($ / MMBtu)

$4.55

$5.15

Total Volume Hedged by Floor (Bcf)

6.55

8.40

Weighted Average Price ($ / MMBtu)

$3.27

$3.32

Natural Gas Liquids (NGLs) Hedges (Swaps)

2013

2014

Total Volume Hedged (gal)

7,581,600

3,708,000

Weighted Average Price ($ / gal)

$1.21

$1.44

Reserves Summary at December 31, 2012

48

Total proved reserves: 23.8 million BOE 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

Sequential growth from September 30, 2012 to December 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.  For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix

December 31, 2011

49

Financial Performance

Oil and Natural Gas Revenues

($ in mm)

Total Realized Revenues

(2)

($ in mm)

Adjusted EBITDA

(1)

($ in mm)

Average Daily Production

(BOE/d)

(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)  Includes realized gain on derivatives

South Texas: Pearsall Play

Anadarko

Newfield

Chesapeake

Shell

Gas Activity

Top Pearsall Depth Map

CI = 500’

Cheyenne

Chilipitin LTD #101H Permit

Note: All acreage at April 9, 2013.  Well data from public information.

CHK –

Wilson C #1H

3.2 MMcf/d, 334 Bbl/d

97 Bbls/MMcf

Abnd. For EGFD

Cabot/Osaka JV

Osaka 35% ($14,285/ac. –

17,500ac.)

6 Horiz. Drilled

3 Permits

Schorp-White Ranch #101H

1 

full mo. –

4,535 Bbl, 43MMcf

RH Pickens #101H

1

full mo. –

5,339 Bbl, 16MMcf

EOG Tests

500 –

2000 Bbl/mo.

Temp. Abnd.  or EGFD Horiz.

CHK

Ralph Edwards E #1H

IP: 135 Bbl/d, 1752 Mcf/d

17/64”

w/ 2797 Ftp

5 mo.cum 6,917 Bbl, 153 MMcf

EOG

Robert Hindes #1H

IP: 263 Bbl/d, 4.3 MMCF/d

26/64”

w/ 1977 Ftp

Cheyenne

Indio Tanks Horiz. program

4 horizs w/ 700 to 450 Bbl/d

Plus 4 to 6 MMcf/d

Yields 83 to 63 Bbls/MMcf

Cromwell #1H –

5 mo. 4 MBbl, 71 MMcf

A Williams B #1H –

5 mo. 20 MBbl, 129 MMcf

ZCW #1H –

5 mo. –

17 MBbl, 154 Mcf

Rosetta

Tom Hanks #1

Completed and

waiting on hook-up.

Valence Oper.

4 drilling wells and

2 Permits

Murray #1H

IP: 258Bbl/d, 106Mcf/d

Completed-

Jan ‘13

Cheyenne

Rockin S #1H

Completed 12-21-2012

CHK -

Avant D #1H

Suspended, waiting on

further completion work

CHK –

Brownlow #1H

Could not test

50

st

st

Pearsall Field Area Buda / Eagle Ford / Chalkleford Activity

51

Note: All acreage at April 9, 2013.  Well data from public information.

52

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

operations

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

(loss)

income

and

net

cash

provided

by

operating

activities,

respectively,

that

are

of

a

historical

nature.

Where

references

to

Adjusted

EBITDA

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.

53

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.

(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)

($33,261)

Interest expense

-

-

-

3

683

1,002

Total income tax provision (benefit)

-

20,023

(9,925)

3,521

(5,521)

(1,430)

Depletion, depreciation and amortization

7,889

12,127

10,743

15,596

31,754

80,454

Accretion of asset retirement obligations

70

92

137

155

209

256

Full-cost ceiling impairment

-

22,195

25,244

-

35,673

63,475

Unrealized loss (gain) on derivatives

211

(3,592)

2,375

(3,139)

(5,138)

4,802

Stock option and grant expense

205

605

622

824

2,362

(589)

Restricted stock grants

15

60

34

74

44

729

Net loss (gain) on asset sales and inventory impairment

-

(136,977)

379

224

154

485

Adjusted EBITDA

$8,090

$18,411

$15,184

$23,635

$49,911

$115,923

(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

$124,228

Net change in operating assets and liabilities

209

(17,888)

15,717

(2,230)

(12,594)

(9,307)

Interest expense

-

-

-

3

683

1,002

Current income tax provision (benefit)

-

10,448

(2,324)

(1,411)

(46)

-

Adjusted EBITDA

$8,090

$18,411

$15,184

$23,635

$49,911

$115,923

Year Ended December 31,

Year Ended December 31,

54

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 December 31, 2008, December 31, 2009,

December 31, 2010, December 31, 2011, September 30, 2012 and December 31, 2012 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 PV-10 at December 31, 2008,

December 31, 2009, December 31, 2010, December 31, 2011, September 30, 2012 and December 31,

2012

were,

in

millions,

$44.1,

$70.4,

$119.9,

$248.7,

$363.6

and

$423.2,

respectively.

The

discounted

future income taxes at December 31, 2008, December 31, 2009, December 31, 2010, December 31, 2011,

September 30, 2012 and December 31, 2012 were, in millions, $0.8, $5.3, $8.8, $33.2, $29.7 and $28.6,

respectively.