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) October 1, 2015
 
  _________________________________
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:
o
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))






Item 1.01
Entry into a Material Definitive Agreement.
On October 1, 2015, in connection with the sale of certain natural gas gathering and processing assets located in Loving County, Texas (the “Sale”) by Matador Resources Company (the “Company”), the Company entered into a First Supplemental Indenture (the “First Supplemental Indenture”) with Wells Fargo Bank, National Association, as trustee (the “Trustee”), which supplements the Indenture, dated as of April 14, 2015 (the “Indenture”), among the Company, the Guarantors named therein and the Trustee. Pursuant to the First Supplemental Indenture, DLK Wolf Midstream, LLC, a wholly-owned subsidiary of the Company (“DLK”), was released as a party to and as a guarantor under the Indenture, effective upon the consummation of the Sale.
The foregoing description of the First Supplemental Indenture does not purport to be complete and is qualified in its entirety by reference to the First Supplemental Indenture, which is attached hereto as Exhibit 4.1 and is incorporated herein by reference.
Item 7.01
Regulation FD Disclosure.
On October 1, 2015, the Company issued a press release announcing the consummation of the Sale. The Sale was effected pursuant to the sale of all of the outstanding membership interests in DLK. A copy of the press release is furnished as Exhibit 99.1 to this Current Report on Form 8-K.
The Company expects to make presentations concerning its business to potential investors. The materials to be utilized during the presentations are furnished as Exhibit 99.2 hereto and incorporated herein by reference.
The information furnished pursuant to this Item 7.01, including Exhibit 99.1 and Exhibit 99.2, shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.    
Item 9.01
Financial Statements and Exhibits.
(d) Exhibits
 
Exhibit No.

  
Description of Exhibit
4.1

 
First Supplemental Indenture, dated as of October 1, 2015, by and among Matador Resources Company, DLK Wolf Midstream, LLC, the Guarantors named therein, and Wells Fargo Bank, National Association, as trustee.
99.1

  
Press Release, dated October 1, 2015.
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: October 5, 2015
 
 
 
By:
 
/s/ Craig N. Adams
 
 
 
 
Name:
 
Craig N. Adams
 
 
 
 
Title:
 
Executive Vice President




Exhibit Index
Exhibit No.

  
Description of Exhibit
4.1

 
First Supplemental Indenture, dated as of October 1, 2015, by and among Matador Resources Company, DLK Wolf Midstream, LLC, the Guarantors named therein, and Wells Fargo Bank, National Association, as trustee.
99.1

  
Press Release, dated October 1, 2015.
99.2

 
Presentation Materials.



Exhibit 4.1

MATADOR RESOURCES COMPANY
FIRST SUPPLEMENTAL INDENTURE
This FIRST SUPPLEMENTAL INDENTURE, dated as of October 1, 2015 (the “ First Supplemental Indenture ”), among DLK Wolf Midstream, LLC, a Texas limited liability company (“ DLK ”), Matador Resources Company, a Texas corporation (the “ Company ”), each of the Guarantors (as defined in the Indenture referred to herein) party hereto and Wells Fargo Bank, National Association (the “ Trustee ”).
W I T N E S S E T H :
WHEREAS, the Company, as issuer, certain of its Subsidiaries (including DLK), as Guarantors, and the Trustee heretofore executed and delivered an Indenture, dated as of April 14, 2015 (the “ Indenture ”), providing for the issuance of the Company’s 6.875% Senior Notes due 2023;
WHEREAS, the Company issued $400,000,000 aggregate principal amount of Initial Securities pursuant to the Indenture;
WHEREAS, DLK is a party to and a Guarantor under the Indenture;
WHEREAS, Section 10.9 of the Indenture permits the release of the Subsidiary Guarantee of a Guarantor in connection with the sale or other disposition of the Capital Stock of such Guarantor other than to the Company or another Guarantor, if such transaction at the time of such disposition does not violate Section 4.7 of the Indenture and such Guarantor ceases to be a Restricted Subsidiary of the Company as a result of such transaction; and
WHEREAS, the Company proposes to sell the Capital Stock of DLK after which DLK will no longer be a Restricted Subsidiary of the Company and such sale will not violate Section 4.7 of the Indenture;
WHEREAS, pursuant to Section 9.1 of the Indenture, the Company, the Guarantors (including DLK) and the Trustee are authorized to amend or supplement the Indenture without the consent of any Holder to release DLK as a Guarantor and from its obligations under its Subsidiary Guarantee thereunder;
NOW THEREFORE, to comply with the provisions of the Indenture and in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, DLK, the Company, the Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Securities as follows:
1.     CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.
2.     RELEASE OF GUARANTOR. On the date hereof and effective upon the disposition of Capital Stock of DLK such that it is no longer a Subsidiary of the Company, the



parties agree that DLK is released as a party to and as a Guarantor under the Indenture and that DLK has no further obligations or liabilities under its Subsidiary Guarantee or the provisions of the Indenture.
3.    SUPPLEMENTAL INDENTURE INCORPORATED INTO INDENTURE. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This First Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of a Security heretofore or hereafter authenticated and delivered shall be bound hereby.
3.     NEW YORK LAW TO GOVERN. THE LAWS OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS FIRST SUPPLEMENTAL INDENTURE.
4.     COUNTERPARTS. The parties may sign any number of copies of this First Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement. This First Supplemental Indenture may be executed in multiple counterparts which, when taken together, shall constitute one instrument. The exchange of copies of this First Supplemental Indenture and of signatures by facsimile or PDF transmission shall constitute effective execution and delivery of this First Supplemental Indenture as to the parties hereto and may be used in lieu of the original First Supplemental Indenture for all purposes. Signatures of the parties hereto transmitted by facsimile or PDF shall be deemed to be their original signatures for all purposes.
5.     EFFECT OF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof.
6.     THE TRUSTEE. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this First Supplemental Indenture. This First Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.

[signature page follows]


2

IN WITNESS WHEREOF, the parties hereto have caused this First Supplemental Indenture to be duly executed and attested, all as of the date first above written.
MATADOR RESOURCES COMPANY


By:     /s/ Matthew V. Hairford            
Name: Matthew V. Hairford
Title:    President


DLK WOLF MIDSTREAM, LLC


By:     /s/ Matthew V. Hairford            
Name: Matthew V. Hairford
Title:    President

GUARANTORS:

DELAWARE WATER MANAGEMENT COMPANY, LLC
DLK BLACK RIVER MIDSTREAM, LLC
LONGWOOD GATHERING AND DISPOSAL SYSTEMS GP, INC.
LONGWOOD MIDSTREAM SOUTH TEXAS, LLC
LONGWOOD MIDSTREAM SOUTHEAST, LLC
LONGWOOD MIDSTREAM DELAWARE, LLC
MATADOR PRODUCTION COMPANY
MRC ENERGY COMPANY
MRC DELAWARE RESOURCES, LLC
MRC ENERGY SOUTHEAST COMPANY, LLC
MRC ENERGY SOUTH TEXAS COMPANY, LLC
MRC PERMIAN COMPANY
MRC ROCKIES COMPANY
SOUTHEAST WATER MANAGEMENT COMPANY, LLC


By:     /s/ Matthew V. Hairford            
Name: Matthew V. Hairford
Title: President

Signature Page
First Supplemental Indenture


LONGWOOD GATHERING AND DISPOSAL SYSTEMS, LP

By: Longwood Gathering and Disposal Systems GP, Inc.,
its general partner

By:     /s/ Matthew V. Hairford            
Name: Matthew V. Hairford
Title:    President

Signature Page
First Supplemental Indenture


WELLS FARGO BANK, NATIONAL ASSOCIATION, as Trustee

By:     /s/ Patrick Giordano                
Name:    Patrick Giordano
Title:    Vice President


Signature Page
First Supplemental Indenture

Exhibit 99.1

MATADOR RESOURCES COMPANY ANNOUNCES CLOSING OF SALE OF
LOVING COUNTY GAS GATHERING AND PROCESSING ASSETS

DALLAS, Texas, October 1, 2015 -- 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 an emphasis on oil and natural gas shale and other unconventional plays and with a current focus on its Permian (Delaware) Basin operations in Southeast New Mexico and West Texas, today closed the previously announced sale of its wholly-owned subsidiary that owns certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County System”), to a subsidiary of EnLink Midstream Partners, LP (NYSE: ENLK) (“EnLink”). The Loving County System includes a cryogenic natural gas processing plant with approximately 35 million cubic feet per day of inlet capacity (the “Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects a Matador-owned gathering system to the Processing Plant.

Pursuant to the terms of the transaction, a subsidiary of EnLink paid Matador consideration of approximately $143 million excluding customary purchase price adjustments. In conjunction with the sale of the Loving County System, Matador is dedicating its current leasehold interests in Loving County pursuant to a 15-year, fixed-fee gathering and processing agreement and providing a volume commitment in exchange for priority one service. Matador can, at its option, dedicate any future leasehold acquisitions in Loving County to a subsidiary of EnLink. In addition, Matador is retaining its natural gas gathering system up to a central delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water disposal wells.

With the closing of the transaction, Matador has a net debt to trailing 12-month Adjusted EBITDA ratio of approximately 1.0x and has over $500 million in liquidity including nothing drawn against its revolving credit facility borrowing base of $375 million. Thus, the Company has ample liquidity and cash flow to execute its capital plans in 2015 and 2016 and to consider other opportunities in its various operating areas that may enhance Matador’s asset base.

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 an emphasis on oil and natural gas shale and other unconventional plays. Its current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Permian (Delaware) Basin in Southeast New Mexico and West Texas. Matador also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas.

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

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

1

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; the Company’s ability to execute its business plan, including whether its 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; its 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; its ability to make acquisitions on economically acceptable terms; its ability to integrate acquisitions, including the HEYCO merger; availability of sufficient capital to execute its business plan, including from future cash flows, increases in its 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 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.

Contact Information              

Mac Schmitz
Investor Relations
(972) 371-5225
mschmitz@matadorresources.com

2
October 2015 Investor Presentation NYSE: MTDR Exhibit 99.2

 
2 Disclosure Statements Safe Harbor Statement – 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 Matador’s financial and operational performance: general economic conditions; Matador’s ability to execute its business plan, including whether Matador’s 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; Matador’s ability to replace reserves and efficiently develop its current reserves; Matador’s costs of operations, delays and other difficulties related to producing oil, natural gas and natural gas liquids; Matador’s ability to integrate the assets, employees and operations of Harvey E. Yates Company following its merger with one of Matador’s wholly-owned subsidiaries on February 27, 2015; Matador’s ability to make other acquisitions on economically acceptable terms; availability of sufficient capital to execute Matador’s business plan, including from its future cash flows, increases in Matador’s 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. Cautionary Note – 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. Definitions – Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Matador’s production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where Matador produces liquids-rich natural gas, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. Estimated ultimate recovery (EUR) is a measure that by its nature is more speculative than estimates of proved reserves prepared in accordance with SEC definitions and guidelines and is accordingly less certain.

 
Company Summary

 
2012, 2013 and 2014 capital spending focused primarily on developing Eagle Ford and transitioning to oil February 2012 IPO at $12.00; net cash proceeds of ~$136 million May 2014 Follow-on Offering at $25.00; net cash proceeds of ~$181 million September 2013 Follow-on Offering at $15.25; net cash proceeds of ~$142 million 2012 2014 Matador has grown almost entirely through the drill bit, with a focus on unconventional reservoir plays Assembling Permian acreage position; begin delineation drilling program  Founded by Joe Foran in 1983 – most participants are still shareholders today  Foran Oil funded with $270,000 in contributed capital from 17 friends and family members; evolved into Matador Petroleum Corporation  Sold Matador Petroleum Corporation to Tom Brown, Inc.(1) in June 2003 for an enterprise value of $388 million in an all-cash transaction Foran Oil & Matador Petroleum 4 Matador History Matador Resources Company Timeline Predecessor Entities (1) Tom Brown acquired by Encana in 2004. (2) Excluding customary purchase price adjustments Matador Today 2003 2008 2003 Founded by Joe Foran with $6 million, a proven management and technical team and board of directors 2008 Sold Haynesville rights in ~9,000 net acres to CHK for ~$180 million; retained 25% participation interest, carried working interest and overriding royalty interest 2010-2011 Redeployed capital into the Eagle Ford early in the play, acquiring over 30,000 net acres for ~$100 million 2012, 2013 and 2014 capital spending focused primarily on developing Eagle Ford and transitioning to oil February 2012 IPO at $12.00; net cash proceeds of ~$136 million May 2014 Follow-on Offering at $25.00; net cash proceeds of ~$181 million September 2013 Follow-on Offering at $15.25; net cash proceeds of ~$142 million 2010 2012 2014 Matador has grown almost entirely through the drill bit, with focus on unconventional reservoir plays, initially in Cotton Valley and Haynesville Assembling Permian acreage position; begin delineation drilling program 2015 February 2015 HEYCO Combination 2015 February 2015 HEYCO Combination 2013 April 2015 Inaugural High-Yield Offering of $400 million; Follow-on Offering at $26.96; net cash proceeds of ~$187 million 2003 2008 2009 2010 2011 2012 2003 Founded by Joe Foran with $6 million, a proven management and technical team and board of directors 2008 Sold Haynesville rights in ~9,000 net acres to CHK for ~$180 million; retained 25% participation interest, carried working interest and overriding royalty interest 2010-2011 Redeployed capital into the Eagle Ford early in the play, acquiring over 30,000 net acres for ~$100 million Pre – IPO Post – IPO October 2015 Sale of certain Loving County midstream assets for ~$143 million(2)

 
5 Company Overview Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 85.4 million common shares Share Price(1) $23.05/share Market Capitalization(1) $2.0 billion (1) Shares outstanding as reported in the Form 10-Q for the quarter ended June 30, 2015 and share price as of October 2, 2015. (2) The Company raised its full-year 2015 guidance estimates on August 4, 2015. (3) The Company raised its 2015 oil production guidance from 4.0 to 4.2 million Bbl to 4.1 to 4.3 million Bbl on May 6, 2015. (4) Estimated 2015 oil and natural gas revenues and Adjusted EBITDA based upon the midpoint of 2015 guidance range as revised on August 4, 2015. Prices for oil and natural gas used in these estimates were $50.00/Bbl (WTI oil price of $55.00/Bbl less $5.00/Bbl differentials and transportation costs) and $3.00/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period July through December 2015 and weighted average realized prices for the period January through June 2015 of $49.48/Bbl and $2.80/Mcf. (5) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. 2014 Prior Updated % Actual 2015 Guidance 2015 Guidance(2) Change Capital Spending $610 million $350 million $425 million - 30% Total Oil Production 3.3 million Bbl 4.1 to 4.3 million Bbl(3) 4.4 to 4.5 million Bbl + 34% Total Natural Gas Production 15.3 Bcf 24.0 to 26.0 Bcf 26.0 to 27.0 Bcf + 73% Oil and Natural Gas Revenues $367.7 million $270 to $290 million $290 to $300 million(4) - 20% Adjusted EBITDA(5) $262.9 million $200 to $220 million $220 to $230 million(4) - 14%

 
Matador Resources Company – Operations Overview Market Capitalization(1) $2.0 billion Avg. Daily Production – Q2 2015(2) 26,601 BOE/d Oil (% total) 13,847 Bbl/d (52%) Natural Gas (% total) 76.5 MMcf/d (48%) Proved Reserves @ 6/30/2015 87.0 million BOE % Proved Developed 39% % Oil 47% 2015E CapEx(3) $425 million Gross Acreage(4) 223,655 acres Net Acreage(4) 143,800 acres Engineered Drilling Locations(5) 2,265 gross / 1,362 net Eagle Ford 278 gross / 240 net Permian 1,445 gross / 960 net Haynesville/Cotton Valley 542 gross / 162 net *Note: Represents increase as compared to each respective figure at or for the three months ended June 30, 2014. **Note: Represents increase as compared to each respective figure at December 31, 2013. (1) Market capitalization based on closing share price as of October 2, 2015 and shares outstanding as reported in the Form 10- Q for the quarter ended June 30, 2015. (2) Average daily production for the three months ended June 30, 2015. (3) 2015 estimated capital expenditures for operations only. Revised upwards from $350 million on August 4, 2015; does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. (4) Presented as of August 31, 2015. Excludes 75,674 gross (35,732 net) acres still under lease in Wyoming, Utah and Idaho. (5) Identified and engineered locations for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Locations identified as of December 31, 2014, but including no locations at Twin Lakes and no locations associated with the HEYCO transaction or two associated joint ventures. 6 +440%** +139%** +52%* +72%* 32% of total production Almost no oil 65% of total natural gas 45% of total production 68% of total oil 22% of total natural gas 23% of total production 32% of total oil 13% of total natural gas

 
Matador’s Execution History – “Doing What We Say” Oil Production  414 Bbl/d of oil  6% oil  4,916 Bbl/d of oil  46% oil  13,847 Bbl/d of oil  52% oil Proved Reserves  27 MMBOE  1.1 MMBbl of oil  4% oil  39 MMBOE  12.1 MMBbl of oil  31% oil  87 MMBOE  40.6 MMBbl of oil  47% oil PV-10(2) and Asset Coverage  $155.2 million  24% of PV-10 in Eagle Ford  PV-10 / debt of 2.0x  $522.3 million  90% of PV-10 in Eagle Ford  PV-10 / debt of 2.1x  $942.8 million  90% of PV-10 in Eagle Ford / Permian  PV-10 / debt of 2.4x LTM Adjusted EBITDA(3)  $50 million(4)  $148 million  $254 million Leverage(5)  1.5x(4)  1.6x  1.4x  1.0x(11) after midstream sale Acreage  ~7,500 net Permian acres  ~32,900 net Permian acres  ~89,700 net Permian acres(12) Enterprise Value (“EV”)(6)  $0.65 billion(7)  $1.2 billion(9)  $2.4 billion(13) 12x growth in oil production 11x growth in oil reserves ~200% growth Doubled EV Over 4x growth in Permian acres At IPO(1) September 2013 Follow-On(8) Over 3x growth in PV-10 (1) Unless otherwise noted, at or for the nine months ended September 30, 2011. (2) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. (3) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. (4) At or for the twelve months ended December 31, 2011. (5) Calculated as debt divided by LTM Adjusted EBITDA. (6) Enterprise value equals market capitalization plus long-term debt. (7) As of February 7, 2012 at time of IPO. (8) Unless otherwise noted, at or for the three months ended June 30, 2013. (9) As of September 1, 2013. (10) Unless otherwise noted, at or for the three months ended June 30, 2015. (11) Net debt at October 1, 2015 and LTM Adjusted EBITDA at June 30, 2015. (12) As of August 31, 2015. (13) Market capitalization based on closing share price as of October 2, 2015 and shares outstanding as reported in the Form 10-Q for the quarter ended June 30, 2015. 182% growth in oil production 3.3x growth in oil reserves 72% growth Doubled EV 2.7x growth in Permian acres 81% growth June 30, 2015(10) Matador continues to execute on its core strategy of acquiring great assets, developing a highly professional, committed workforce, maintaining a strong balance sheet and generating significant shareholder returns 7 Remained conservative Improved

 
8 Eagle Ford $603.8 million, 58% Eagle Ford $540.4 million, 82% Haynesville/CV $193.4 million, 18% Permian $246.2 million, 24% Haynesville/CV $82.9 million, 13% Permian $31.9 million, 5% Eagle Ford $424.6 million, 45% Haynesville/CV $93.3 million, 10% Permian $424.8 million, 45% December 31, 2013 Total proved reserves = 51.7 million BOE PV-10(1): $655.2 million $93.42 oil / $3.67 natural gas Total proved reserves = 68.7 million BOE PV-10(1): $1,043.4 million $91.48 oil / $4.35 natural gas December 31, 2014 Total proved reserves = 87.0 million BOE PV-10(1): $942.8 million $68.17 oil / $3.39 natural gas June 30, 2015 Oil and Natural Gas Proved Reserves and PV-10(1) Growth By Area (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix.

 
Average Daily Oil Production (Bbl/d) Average Daily Natural Gas Production (MMcf/d) Average Daily Total Production (MBOE/d) Oil Production Mix (% of Average Daily Production) 9 Growth since IPO Growth since IPO Growth since IPO Growth since IPO 91 422 3,317 5,843 9,095 11,206 13,847 2010 2011 2012 2013 2014 Q1 2015 Q2 2015 23.0 39.8 34.1 35.4 41.9 73.8 76.5 2010 2011 2012 2013 2014 Q1 2015 Q2 2015 3.9 7.0 9.0 11.7 16.1 23.5 26.6 2010 2011 2012 2013 2014 Q1 2015 Q2 2015 2% 6% 37% 50% 57% 48% 52% 2010 2011 2012 20 3 2014 Q1 2015 Q2 2015 Matador’s Continued Production Growth Through June 30, 2015

 
0.0x 0.0x 0.1x 1.5x 0.2x 0.7x 1.1x 1.3x 1.5x 1.6x 0.8x 1.0x 1.2x 0.6x 1.0x 1.3x 1.6x 1.4x 1.0x 2008 2009 2010 2011 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 Today Net Debt / LTM EBITDA $76 $240 $256 $416 In itial P u b lic O ff e rin g  Preserved and enhanced liquidity through April 2015 equity and Senior Notes offerings and sale of Loving County midstream assets for ~$143 million(1) in October 2015 – substantial liquidity to execute planned drilling program through 2016  Strong financial position with Net Debt/LTM Adjusted EBITDA(2)(3) of 1.0x after close of midstream sale  Target leverage at less than 2.0x Adjusted EBITDA(2), though profile typically more conservative Committed to Maintaining Strong Balance Sheet 10 (1) Excluding customary purchase price adjustments. (2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. (3) LTM Adjusted EBITDA at June 30, 2015 and Net Debt at October 1, 2015. (4) LTM Adjusted EBITDA and Net Debt at June 30, 2015. (4) E q u it y Rais e E q u it y Rais e No te s O ff e rin g + E q u it y Rais e (2) Net Debt ($ millions) (3) M ids tr e a m S a le

 
11 Previous Oil Price Declines Have Created Opportunities for Matador(1) Comparison of Major Oil Corrections and Major Matador Turning Points Since 1980 Date Event % Change in Oil Price Length of Oil Price Decline (in trading days) % Increase in Oil Price – 1-Year Post-Low 1986 Saudi Market Share War -67.2% 82 79.0% A number of Mesa’s top technical staff join Matador I 1988 Oil Glut -43.7% 295 58.4% Matador I buys key waterflood properties and New Mexico natural gas acreage 1991 Global Recession / End of Gulf War -57.2% 90 5.4% First interests in Amaker-Tippett acquired; becomes Matador I’s largest field 1998 Asian Crisis -59.6% 484 134.5% Unocal exchanges NM properties for Matador I’s stock 2001 Global Recession -53.1% 290 46.2% Matador I shifts to unconventionals (Marlan Downey joins Board) 2008 Great Recession -78.4% 119 134.8% Matador II builds Eagle Ford position and drills first Haynesville wells Average -59.9% 227 76.4% 2014- 2015 Current Dip(2) -59.8% ~300 ? -MTDR and HEYCO join forces -MTDR sells midstream assets to EnLink (1) Includes Matador Resources Company, Foran Oil and Matador Petroleum Corporation and other predecessor entities. (2) Length of oil price decline in trading days using high of $107.26 on June 20, 2014 and low of $38.24 on August 24, 2015.

 
Keys to Matador’s Success Over Last 35 Years(1) 12  People  We have a strong, committed technical and financial team in place, and we continue to make additions and improvements to our staff, our capabilities and our processes  Board and Special Advisor additions have strengthened Board skills and stewardship  Properties  Matador’s acreage positions and multi-year drilling inventory are significant and located in three of the industry’s best plays – Permian, Eagle Ford and Haynesville  Our property mix provides us with a balanced opportunity set for both oil and natural gas  Process  Continuous improvement in all aspects of our business leading to more efficient operations, improved financial results and increased shareholder value  Gaining momentum as a successful publicly-held company  Execution  Increase total production by ~51%, with oil production expected to increase to ~4.45 million barrels and natural gas production expected to increase to ~26.5 Bcf in 2015  Maintain quality acreage positions in the Permian, Eagle Ford and Haynesville – successfully integrate HEYCO acreage in Permian  Reduce drilling and completion times and costs – improve operational efficiencies  Maintain strong financial position and technical and administrative teams (1) Includes Matador Resources Company and its predecessor entities.

 
Permian (Delaware) Basin Southeast New Mexico and West Texas

 
14 Delaware Basin – A “World Class” Hydrocarbon System DELAWARE BASIN CENTRAL BASIN PLATFORM MIDLAND BASIN Wolfcamp Simpson ~23,000’ Sediment Fill East West Source “Kitchens” Now Unconventional Resource Plays  70,000 square mile area  Up to 25,000 feet of multiple, stacked, petroleum systems  Extensive drilling, coring and geological studies since 1920s  >1,500 conventional reservoirs with cumulative production >1.0 million Bbl each  Cumulative production from 1,500 conventional reservoirs, as of year 2000 (pre- horizontal drilling) >30.0 billion Bbl(1) (1) Dutton et al, AAPG 2005

 
Task at Hand – Understanding the Opportunities 3rd Bone Spring Lower Avalon 800’ Objective: We want to drill and complete the best wells at the lowest cost. Challenge: How do we identify the best targets within multiple prospective intervals across a geologically complex basin? Matador’s geoscience staff is committed to bringing the best targets forward! Most current unconventional plays target one or two zones across a trend area. The Permian Basin has roughly two dozen unique targets within the Midland and Delaware sub-basins. All logs plotted at same scale Delaware Basin Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D Strawn Atoka Barnett Miss. Lime Woodford Upper Avalon 1st Bone Spring 2nd Bone Spring 15 Brushy Cyn. O verp ressur e Tested by MTDR Tested by others

 
Spectrum of Unconventional Play Types In general there is no consensus on the what an “unconventional” reservoir is… At Matador, we think of an unconventional reservoir as a spectrum of play types. The distribution and quality of these play types are both spatially and temporally variable. Play types from Bishop 2014. Block diagram modified from Hanford (1981). 16

 
 Determining “Good, Better, Best” important as potential exceeds inter-formational stacked pay  2015 program will expand on intra-formational stacked pay tests performed in each asset area Wolf Area Type Log – Wolfcamp X/Y X Test Y Test 80 acre 100’ Rustler Breaks Type Log Wolfcamp B 350’ X Test Y Test 160 acre Ranger Type Log 2nd Bone Spring DPHI > 8% LLD > 10 ohm INTRA-Formational Stacked Pays Decoupled – Coupled – Micro-coupled Bone Spring Lime Upper Avalon Shale Lower Avalon Shale First Bone Spring Sand Second Bone Spring Carbonate Third Bone Spring Carbonate Wolfcamp “D” / Penn Strawn Wolfcamp “C” Third Bone Spring Sand INTER-Formational Stacked Pay Second Bone Spring Sand Wolfcamp “A” Wolfcamp “B” 100’ Wolfcamp “X-Y” 17 Gamma Ray Resistivity 4,000 feet of Hydrocarbon Column Creates Opportunity Horizon tested by MTDR

 
Cumulative Production Recent Production Oil Eq. % Oil Natural Gas EUR(2) Well Months (BOE) Oil (Bbl/d) (Mcf/d) (MBOE) Ranger State 33-20S-35E RN #121H (2nd Bone Spring) 22 221,400 91% 160 150 650 Dorothy White #1H (Wolfcamp "A"/"X") 20.5 429,500 68% 320 620 1,050 Rustler Breaks 12-24S-27E RB #224H (Wolfcamp "B") 16.5 209,000 41% 90 1,000 700 Norton Schaub 84-TTT-B33 WF #201H (Wolfcamp "A"/"X") 14 278,000 68% 540 1,850 750 Pickard State 20-18S-34E RN #121H (2nd Bone Spring) 14 155,200 91% 350 150 500 Johnson 44-02S-B53 #204H (Wolfcamp "A"/"X") 12 229,000 65% 250 830 900 Pickard State 20-18-34 #2H (Wolfcamp "D") 14.5 91,200 85% 80 120 200 Jim Rolfe 22-18-34 RN State #131Y(3) (3rd Bone Spring) 6.5 16,100 73% 40 100 65 Norton Schaub 84-TTT-B33 WF #2010H (Wolfcamp "A") 9 106,500 73% 200 600 600 Guitar 10-24S-28E RB #202H (Wolfcamp "A"/"X") 6 114,500 79% 370 600 700 Tiger 14-24S-28E RB #224H (Wolfcamp "B") 6 163,000 45% 260 2,300 1,000 Billy Burt 90-TTT-B33 WF #202H (Wolfcamp "A"/"X") 5 81,000 75% 300 950 700 Billy Burt 90-TTT-B33 WF #203H (Wolfcamp "A"/"X") 5 90,000 75% 450 1,340 700 Tiger 14-24S-28E RB #204H (Wolfcamp "A/X-Y") 2.5 73,000 78% 640 680 700 Oil Eq. Oil Natural Gas % Pf (4) Choke Well Date (BOE/d) (Bbl/d) (Mcf/d) Oil (psi) (inches) Arno #1H (Wolfcamp "A"/"X") Mid-Sept 2014 1,110 300 4,900 27% 4,100 26/64th Barnett 90-TTT-B01-WF #201H (Wolfcamp "A"/"X") Early Mar 2015 1,268 720 3,300 57% 3,225 26/64th Barnett 90-TTT-B01-WF #205H ( olfca p " "/" ") Mid-Feb 2015 1,377 738 3,800 54% 3,475 26/64th Cimarron 16-19S-34E RN #134H (3rd Bone Spring) Early May 2015 804 754 303 94% 725 26/64th Ranger State 33-20S-35E RN #122H (2nd Bone Spring) Cleaned up to ~300 BOE/d in last 60 days (5) with almost no decline Tiger 14-24S-28E RB #124H (2nd Bone Spring) Early July 2015 800 650 880 81% 810 34/64th Permian Basin Acreage Position and Recent Test Results Note: All acreage at August 31, 2015. Some tracts not shown on map. (1) As of mid-September 2015 unless otherwise noted. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. (3) As of April 28, 2015. (4) Flowing surface pressure. (5) As of August 4, 2015. 18 L E A LOVING WARD 2 4 1 3 15 6 5 9 7 16 10 11 17 12 13 18 19 # Matador Resources Acreage Location of Matador Well 14 20 TWIN LAKES ~42,900 gross / ~30,000 net acres WOLF / LOVING AREA ~11,300 gross / ~7,300 net acres Successful performance of initial horizontal wells(1) Recent activity and 24-hour initial potential tests 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 19 20 17 18 Jackson Trust RANGER ~31,000 gross / ~18,600 net acres ARROWHEAD ~47,400 gross / ~17,100 net acres 8 E D D Y RUSTLER BREAKS ~19,000 gross / ~12,300 net acres

 
Matador is a Significant Delaware Basin Player MTDR MTDR MTDR  Matador’s 89,700 net acres place it among the largest operators in the Delaware Basin − Matador holds largest Delaware Basin acreage position among small and mid-cap publicly traded energy companies(1) − Matador is the second largest operator in terms of the ratio of Delaware Basin acreage to enterprise value or market capitalization among all public traded energy companies(1)  Key Operators in the Delaware Basin(2): − Oxy 1,500,000 net acres − Chevron 1,000,000 net acres − Shell 618,000 net acres − Concho 425,000 net acres − Cimarex 400,000 net acres − EOG 307,000 net acres − Anadarko 255,000 net acres − Apache 230,000 net acres − Conoco 150,000 net acres − Energen 113,000 net acres − Matador 156,600 gross / 89,700 net acres (1) Based on an independent market analysis prepared by BMO Capital Markets in January 2015. Small and mid-cap publicly traded energy companies defined as those companies with an enterprise value between $500 million and $3.5 billion. Companies below $100 million in market capitalization were excluded in determining the ratio of Delaware Basin acreage to market capitalization. Matador acreage at August 31, 2015. (2) Goldman Sachs Equity Research report dated April 1, 2015 (Singer). 19 MTDR MTDR

 
Wolf Inventory – Multi-Pay Development Potential ~660’ Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp X/Y Wolfcamp A 4 66 Eval. Ongoing 34 66 66 66 302 Full Development Location Gross Wells Development Well D&C(1) CapEx EUR(2) (MBOE) Bone Spring $5.5 – $6.5 million 450 – 600 Wolfcamp $7.0 – $8.5 million 650 – 1,100 1 mile MRC Spacing Test Completed Full Development Spacing Pattern (Cross-Section View) 20 (1) Drilling and completion. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. Matador Well Location Wolfcamp X/Y Wolfcamp A 2nd Bone Spring Matador Acreage

 
10 100 1,000 10,000 0 50 100 150 200 250 300 350 400 450 500 550 600 650 Production R ate, BO E/ d Time, Days Dorothy White #1H Norton Schaub #201H Norton Schaub #2010H Billy Burt #202H Billy Burt #203H 500 MBOE Type Curve 700 MBOE Type Curve 1,000 MBOE Type Curve Wolfcamp "A"/"X" horizontals in Loving County, Texas Dorothy White #1H has produced 429,500 BOE (68% oil) in 20.5 months - "X" Norton Schaub 84-TTT-B33 WF #201H has produced 278,000 BOE (68% oil) in 14 months - "X" Norton Schaub 84-TTT-B33 WF #2010H has produced 106,500 BOE (73% oil) in 9 months - "A" Billy Burt 90-TTT-B33 WF #202H has produced 81,000 BOE (75% oil) in 5 months - "X" Billy Burt 90-TTT-B33 WF #203H has produced 90,000 BOE (75% oil) in 5 months - "X" Well put on compressor Well put on ESP Production increase due to offset frac 21 Wolf Area Wolfcamp “A”/“X” Wells Performing Above Expectations 500 MBOE Type Curve 1,000 MBOE Type Curve Note: Production as of mid-September 2015. 700 MBOE Type Curve

 
Rustler Breaks Inventory – Multi-Pay Development Potential Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring X/Y Wolfcamp B ~8 0 0 ’ 65 73 73 77 69 77 65 499 Full Development Location Gross Wells Development Well D&C(1) CapEx EUR(2) (MBOE) Bone Spring $4.5 – $5.5 million 300 – 600 Wolfcamp $5.5 – $7.5 million 500 – 1,000 For clarity only 160 gross ac. well slots shown 1 mile MRC Horizontal Drilled Full Development Spacing Pattern (Cross-Section View) 22 (1) Drilling and completion. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. Matador Well Location Wolfcamp X/Y Wolfcamp B 2nd Bone Spring Matador Acreage

 
Historically oil productive interval. Matador’s First Three-Zone Stacked Lateral Test at Rustler Breaks Bone Spring Lime Upper Avalon Shale Lower Avalon Shale First Bone Spring Sand Second Bone Spring Carbonate Third Bone Spring Carbonate Wolfcamp / Pennsylvanian Strawn Wolfcamp “C” Third Bone Spring Sand Gamma Ray INTER-Formational Stacked Pay Second Bone Spring Sand Wolfcamp “A” Wolfcamp “B” Wolfcamp “X-Y” Tiger 14-24S-28E RB #224H IP: 1,525 BOE/d (43% oil) TVD: 10,500 feet Lateral Length: 4,376 feet Tiger 14-24S-28E RB #204H IP: 1,405 BOE/d (75% oil) TVD: 9,600 feet Lateral Length: 4,656 feet Tiger 14-24S-28E RB #124H IP: 800 BOE/d (81% oil) TVD: 8,200 feet Lateral Length: 4,364 feet Multi-Well Pad Resistivity 23 4th zone tested in Upper Wolfcamp B in Rustler Breaks 12- 24S-27E RB #224H

 
10 100 1,000 10,000 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360 380 400 420 440 460 480 500 520 Production R ate, BO E/ d Time, Days Rustler Breaks #224H Tiger #224H 500 MBOE Type Curve 600 MBOE Type Curve 700 MBOE Type Curve 1000 MBOE Type Curve Wolfcamp "B" horizontals in Eddy County, NM Rustler Breaks 12-24S-27E RB #224H has produced 209,000 BOE (41% oil) in 16.5 months Tiger 14-24S-28E RB #224H has produced 163,000 BOE (45% oil) in 6 months Well shut in for offset frac 24 Rustler Breaks Wolfcamp “B” Wells Performing Above Expectations 500 MBOE Type Curve 600 MBOE Type Curve Note: Production as of mid-September 2015. 700 MBOE Type Curve 1,000 MBOE Type Curve

 
10 100 1,000 10,000 0 20 40 60 80 100 120 140 160 180 200 Production R ate, BO E/ d Time, Days Guitar #202H Tiger #204H 500 MBOE Type Curve 700 MBOE Type Curve Wolfcamp "A"/"X-Y" horizontals in Eddy County, NM Guitar 10-24S-28E RB #202H produced 114,500 BOE (79% oil) in 6 months - "X-Y" Tiger 14-24S-28E RB #204H produced 73,000 BOE (78%) in 2.5 months - "X-Y" Well shut in for offset frac 25 Rustler Breaks Wolfcamp “A”/“X-Y” Wells, Off to Strong Start Note: Production as of mid-September 2015. 700 MBOE Type Curve 500 MBOE Type Curve

 
Ranger Inventory – Multi-Well Development Potential ~1,320’ 1st Bone Spring 2nd Bone Spring 3rd Bone Spring X/Y Wolfcamp A-D ~7 5 0 ’ 43 55 30 70 6 204 1 mile MRC Horizontal Drilled Full Development Location Full Development Spacing Pattern (Cross-Section View) Gross Wells Development Well D&C(1) CapEx EUR(2) (MBOE) Bone Spring $5.5 – $6.5 million 400 – 600 Wolfcamp $7 – $9 million 200 – 800* * Based on Volumetrics and 4-8% Recovery Factor 26 (1) Drilling and completion. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. For clarity only 160 gross ac. well slots shown Matador Well Location 2nd Bone Spring 3rd Bone Spring Wolfcamp D Matador Acreage Location estimates do not include HEYCO acreage.

 
10 100 1,000 10,000 0 100 200 300 400 500 600 P roduction R a te, BO E /d Time, Days Ranger #121H Pickard #121H 400 MBOE Type Curve 600 MBOE Type Curve 2nd Bone Spring horizontals in Ranger Area – Lea County, NM Ranger State 33-20S-35E RN #121H(1) produced 221,400 BOE (91% oil) in 22 months Pickard State 20-18S-34E RN #121H(2) produced 155,200 BOE (91% oil) in 14 months Well shut in for offset frac 27 Ranger Area Second Bone Spring Wells Performing Above Expectations Note: Production as of mid-September 2015. (1) Formerly the Ranger 33 State Com #1H. (2) Formerly the Pickard State 20-18-34 #1H. 400 MBOE Type Curve 600 MBOE Type Curve

 
28 Matador Acreage 2nd Bone Spring Non-Op Activity Matador Well Plans 2nd Bone Spring  Most HEYCO acreage is Federal acreage  Most held by production by older, vertical wells  Typically 87.5% NRI on most Federal acreage  Contiguous acreage aids in full development and minimizes costs for pads, facilities and LOE  Matador Operated Horizontal Plans (Q1 2016)  SST State 06-19S-29E AH #123H & #124H • 2nd Bone Spring laterals • Offset to Mewbourne Gobbler wells (non-op)  Non-Operated Well Activity  CTA State Com #3H: IP(30) 992 BOE/d (84% Oil); 143,000 BOE in first 7 months(1)  CTA State Com #4H: IP(30) 830 BOE/d (84% Oil); 126,000 BOE in first 6 months(1)  Gobbler 5 B2PM #1H: IP(30) 2,309 BOE/d (81% Oil); 140,000 BOE in first 4 months(1)  Mewbourne, Concho, Cimarex wells provide operational data and reference points across Matador acreage CTA State Com 3H - IP(30): 992 BOE/d (84% Oil) CTA State Com 4H - IP(30): 830 BOE/d (84% Oil) SST State Gobbler 5 B2PM 1H - IP(30): 2,309 BOE/d (81% Oil) Arrowhead – HEYCO Acreage Provides Unique Opportunities (1) As of mid-September 2015.

 
Future Bit Technology – The Evolution of the PDC bit 29  Matador continues to be at the forefront of new bit technology  Smith Bits latest technology StingBlade design  StingBlade design features  Alternating Stinger/PDC cutters  Stinger cutters cut troughs in the formation with the PDC cutters coming behind and removing the ridges  Stinger cutters do the hard work, PDC cutters keep the speed  Ultimate combination of speed, durability and steerability

 
 7,500 psi Pressure Rating  Estimated reduction in drilling time of 20 to 25% in the lateral on Wolfcamp wells  Telescoping Flex-joint  Estimated reduction in drilling time of 12 to 18 hours per well  Integrated Mud-Gas Separator  Estimated savings of 50% compared to rental separator  BOP Wrangler  Estimated reduction in drilling time of 12 hours per well  Walking System & V-door turned 90°  Allows for batch-drilling and simultaneous operations  Reduced Downtime 30 New Rig Technology for Horizontal Drilling – Saving Time and Money!

 
Latest Technology: Simultaneous Operations (Sim-Ops) Capable Rigs 31 Conventional Drilling Configuration Sim-Ops Capable with V-door turned 90° Space available for frac operations while simultaneously drilling on the same pad Drilling rig must leave location prior to frac operations

 
43 32 35 26 22 15 0 5 10 15 20 25 30 35 40 45 50 Loving County Wolfcamp Eddy County Wolfcamp Dr illin g Da y s Historical Well 2015 Planned Well Recent Well Improving Wolfcamp Drilling Times Significantly in 2015 32 *Historical days averaged from 2014 wells *Recent days from Billy Burt 90-TTT-B33 WF #204H & Tiger 14-24S-28E RB #204H

 
Completion  Overall cost reduced by 50% since first well  Cost of pumping and drill out has driven down costs  Drill out days down from using micro trips  Lowers the overall time per plug Cost Reduction Metrics (Drilling and Completion) 33 Drilling  Overall cost reduced by 43% since first well  Days down from 43 to 22 in the Wolfcamp  Cost improvements that can stay with us moving forward Matador Wells Matador Wells Drilling Costs per Foot – Loving County Completion Cost per Foot – Loving County

 
34 Flowing Rod Pumping Gas Lifting 300 Bbl/d 100 Bbl/d Accelerated Production Benefits of Gas Lift • Accelerates production • Reduces LOE • Lower maintenance • Helps wells recover faster from offset fracs Artificial Lift Reducing Natural Production Declines Time Note: Graph and data is for illustrative purposes only and not meant to reflect historical or forecasted data from actual well.

 
35 7,500 Bbl 9,000 Bbl 8,400 Bbl 600 Mlbs 420 Mlbs 500 Mlbs 375 ft. 300 ft. 50 ft. 75 ft. 210 ft. 35 ft. Gen 1 Gen 2 2,000 lbs/ft 1,333 lbs/ft 40 Bbl/ft 20 Bbl/ft 50’ cluster spacing 75’ cluster spacing Gen 1 Gen 2 2,000 lbs/ft 2,000 lbs/ft 40 Bbl/ft 30 Bbl/ft 35’ cluster spacing 50’ cluster spacing Bone Spring Upper Wolfcamp Lower Wolfcamp C o u p le d M ic ro -C o u p le d S o u rce R o c k Gen 1 Gen 2 2,000 lbs/ft 40 Bbl/ft 35’ cluster spacing TESTING SOON Evolution of Permian Basin Frac Design – Reservoir Specific

 
0 20 40 60 80 100 120 140 160 180 200 40 45 50 55 60 65 70 75 80 ROR , % Realized Oil Price, $ Rustler Breaks (Wolfcamp A-X/Y) 500 - 700 MBOE 700 MBOE, $6.5 MM D&C 700 MBOE, $5.5 MM D&C 500 MBOE, $6.5 MM D&C 500 MBOE, $5.5 MM D&C uses $3 flat Gas price 0 20 40 60 80 100 120 140 40 45 50 55 60 65 7 75 80 ROR , % Realized Oil Price, $ Rustler Breaks (Wolfcamp B) 700 - 1,000 MBOE 1000 MBOE, $7.5 MM D&C 1000 MBOE, $6.5 MM D&C 700 MBOE, $7.5 MM D&C 700 MBOE, $6.5 MM D&C uses $3 flat Gas pric 20 40 60 80 100 120 140 160 40 45 50 55 60 65 70 75 80 ROR , % Realized Oil Price, $ Dorothy White (Wolfcamp X/Y) 700 - 1,000 MBOE 1,000 MBOE, $8.5 MM D&C 1,000 MBOE, $7 MM D&C 700 MBOE, $8.5 MM D&C 700 MBOE, $7 MM D&C uses $3 flat Gas price 0 50 100 5 200 250 300 350 400 40 45 50 55 60 65 70 75 80 ROR , % Realized Oil Price, $ Ranger 33 (2nd Bone Spring) 400 - 700 MBOE 700 MBOE, $7 MM D&C 700 MBOE, $5.5 MM D&C 400 MBOE, $7 MM D&C 400 MBOE, $5.5 MM D&C uses $3 flat Gas price 36 Permian Basin Economics – Oil Price Sensitivities /Bbl /Bbl /Bbl /Bbl

 
Significant Delaware Basin Inventory  Matador has identified 1,445 gross (960 net) locations(1)  This inventory does not yet include the HEYCO properties (mostly Arrowhead prospect area) or Twin Lakes locations Formation Gross Locations Net Locations Delaware Group 109 67 Avalon 160 112 1st Bone Spring 146 96 2nd Bone Spring 210 141 3rd Bone Spring 224 148 Wolfcamp X/Y 152 104 Wolfcamp A 207 134 Wolfcamp B 92 62 Wolfcamp D 145 96 TOTAL 1,445 960 37 (1) Identified and engineered locations for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Locations identified as of December 31, 2014, but including no locations at Twin Lakes and no locations associated with the HEYCO transaction or two associated joint ventures. Note: Inventory only includes wells with >30% working interest. Note: All acreage at August 31, 2015. Some tracts not shown on map. Delaware Basin E d d y L e a Lo v in g W in k le r Ward Texas New Mexico Chaves WOLF / LOVING AREA RANGER TWIN LAKES Potash Mine Matador Resources Acreage RUSTLER BREAKS ARROWHEAD Jackson Trust

 
Midstream

 
39  Loving County, Texas  Natural gas gathering and compression  Water gathering  Salt water disposal  Oil gathering  Cryogenic natural gas processing plant  Sold to EnLink for ~$143 million(2)  Eddy County, New Mexico  Natural gas gathering and compression  Water gathering  Salt water disposal (under evaluation) (1) Longwood Gathering and Disposal Systems, LP is an indirect wholly owned subsidiary of Matador Resources Company. (2) Excluding customary purchase price adjustments. SWD = Salt Water Disposal Longwood Gathering and Disposal Systems Activities Longwood Gathering and Disposal Systems(1) in Delaware Basin

 
40 Loving County, Texas – Biggest Midstream Project to Date  Cryogenic natural gas processing plant – sold to EnLink for ~$143 million(1)  Natural gas gathering and compression  Water gathering  Oil gathering  Salt water disposal SWD = Salt Water Disposal Retained Sold to EnLink (1) Excluding customary purchase price adjustments.

 
Summary: Sale of Loving County Gas Gathering & Processing Assets (1) A subsidiary of EnLink Midstream Partners, LP (NYSE: ENLK) (2) Excluding customary purchase price adjustments. (3) Net Debt at October 1, 2015. LTM Adjusted EBITDA at June 30, 2015. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. Matador sold certain Delaware Basin natural gas gathering and processing assets in Loving County, Texas to EnLink(1) for ~$143 million(2) in cash.  Matador sold a wholly owned subsidiary whose assets include:  Cryogenic natural gas processing plant with ~35 MMcf per day of inlet capacity  Six miles of high-pressure gathering pipeline which connects a Matador-owned gathering system to the plant  Consideration for Sale  $143 million(2) in cash  Matador has ability to defer taxes through potential like-kind exchanges  Matador enters into 15-year, fixed fee gathering and processing agreement with EnLink(1)  Matador retains “priority one” service in exchange for a volume commitment  Matador dedicates current Loving County leasehold interests to EnLink – future leasehold acquisitions can be dedicated to EnLink at Matador’s option  Matador retains its natural gas gathering system up to a central delivery point and other Loving County midstream assets, including oil and water gathering systems and salt water disposal wells  Solidifies Matador’s already strong balance sheet and enhances its ample liquidity to execute its capital plans in 2015 and 2016 and further capitalize on its current opportunities in the Delaware Basin  Net Debt/LTM EBITDA(3) of ~1.0x following closing  Liquidity of over $500 million including nothing drawn against credit facility as of closing 41

 
Eagle Ford “Oil Bank”

 
43 Eagle Ford Is Still a Valuable Asset – 12,000 BOE/d in Q2 2015 Note: All acreage at August 31, 2015. Some tracts not shown on map. (1) At December 31, 2014. Karnes Uvalde Medina Zavala Frio Dimmit La Salle Webb Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson San Antonio Glasscock Ranch Martin Ranch Northcut Affleck Troutt Sutton Love Cowey Lewton Hennig Nickel Ranch COMBO LIQUIDS / GAS FAIRWAY DRY GAS FAIRWAY OIL FAIRWAY EAGLE FORD ACREAGE TOTALS 39,786 gross / 29,657 net acres Harris Newman Pena ZLS Carroll Lloyd Hurt Sojourner Sickenius Lyssy Repka Falls City Pawelek Danysh Bishop-Brogan Campbellton-Haverlah 8 5 2 2 Matador Resources Acreage Gross wells turned to sales in 2015 Planned operated D&C operations completed for 2015 17 gross (17.0 net) operated wells turned to sales “Oil Bank” for future development – Over 95% HBP or not burdened by lease expirations before 12/31/16(1) Pursuing acreage additions # EAGLE FORD “EAST” ~3,700 gross / ~2,900 net acres Measured Depth: 17,000’ – 18,000’ Well Costs: $7.5-9.5 million 80-acre spacing EAGLE FORD “CENTRAL” ~3,900 gross / ~3,900 net acres Measured Depth: 15,500’ – 16,500’ Well Costs: $5.5-7.0 million 40-50 acre spacing EAGLE FORD “WEST” ~14,800 gross / ~12,100 net acres Measured Depth: 12,500’ – 14,500’ Well Costs: $4.5-5.0 million 40-50 acre spacing

 
Gen 2 Gen 3 Gen 4 Gen 5 5,770 Bbl 7,825 Bbl 9,550 Bbl 11,750 Bbl 375 Mlbs 500 Mlbs 405 Mlbs 515 Mlbs 11,750 Bbl 650 Mlbs Gen 6 44 Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal wellbore. (1) Mlbs = thousands of pounds of proppant pumped. Fluid Volume Pumped Proppant Pumped(1) Gen 7 650 Mlbs 11,750 Bbl 3 0 0 f t. Evolution of Matador Eagle Ford Frac Design

 
Haynesville Shale “Gas Bank”

 
46 2015 Haynesville Non-Op Program  Estimated capital expenditures of ~$25 million for non-operated well participation interests ˗ Only ~6% of 2015 estimated capital expenditures ˗ Originally budgeted ~$15 million for 2015  Haynesville & Cotton Valley average daily natural gas production up over 3-fold to 50.5 MMcf/d in Q2 2015 from 18.3 MMcf/d in Q2 2014  31 gross (3.8 net) wells turned to sales throughout Tier 1 Haynesville in 2015  Includes 18 gross (3.5 net) wells turned to sales on Elm Grove properties operated by Chesapeake in 2015 (shown on map at left)  Chesapeake placed two additional wells on production in mid-July 2015 ˗ Initial rates of ~12-15 MMcf/d of natural gas with drilling and completion costs of $7 to $8 million  Currently 9 gross (1.9 net) Chesapeake wells are in progress on our Elm Grove area Haynesville – Chesapeake Elm Grove Operations

 
47 Note: Individual well economics only. Excludes costs prior to drilling (i.e. acquisition or acreage costs). Economics use a NRI / WI of 85% but actual interests vary. D&C cost = drilling and completion cost. 0 50 100 150 200 250 300 350 400 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 R a te o f R e turn (% ) Natural Gas Price ($/Mcf) $6MM D&C Cost $7MM D&C Cost $8MM D&C Cost Matador’s Advantaged Economics  NRI’s of 85 to 90% on many properties due to ORRI’s  Improved pricing: increase of ~$0.70/MMBtu due to taking natural gas in kind  Longer laterals and better completion techniques Economics of Tier 1 Wells (10 Bcf) Haynesville at Elm Grove

 
2015 Updated Capital Investment Plan

 
49 2015 Updated Capital Investment Plan  At the beginning of 2015, reduced drilling program from 5 rigs to 2 rigs due to lower commodity prices, with primary focus on Permian (Delaware) Basin  In late July 2015, took delivery of a third rig in the Delaware Basin  Currently operating 3 rigs – all in the Delaware Basin  New-build rigs, latest technology and designed for simultaneous operations (Sim-Ops) # o f RIg s 5 4 3 2 2 2 2 3 Nu m be r o f Ope rated R ig s Eagle Ford Rig Permian Rig 3 3 3 3 3 3

 
0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2011 2012 2013 2014 2015E Eagle Ford Permian 422 3,318 5,843 9,095 12,192 (1)(2) 0 10 20 30 40 50 60 70 80 2011 2012 2013 2014 2015E Haynesville/CV Eagle Ford Permian 39.8 34.1 35.4 41.9 72.6 (1)(3) 2015E Oil Production  Estimated oil production of 4.4 to 4.5 million barrels − 34% increase from 2014 despite decreased drilling  Average daily oil production of 12,200 Bbl/d, up from 9,100 Bbl/d in 2014 − Eagle Ford ~7,850 Bbl/d (64%) − Permian ~4,350 Bbl/d (36%)  Quarterly production peaks in Q2; Q4 2015 oil production up 4 to 5% as compared to Q4 2014 and Q1 2015 − Permian production increases over three-fold in 2015; Eagle Ford production relatively flat 2015E Natural Gas Production  Estimated natural gas production of 26 to 27 Bcf − 73% increase from 2014 despite decreased drilling; significant Haynesville impact − Quarterly production peaks in Q2 2015; Q4 2015 natural gas production up ~20% over Q4 2014  Average daily natural gas production of 72.6 MMcf/d, up from 41.9 MMcf/d in 2014 − Haynesville ~46.4 MMcf/d (64%) − Eagle Ford ~15.0 MMcf/d (21%) − Permian ~11.2 MMcf/d (15%) 2015 Updated Production Estimates – Oil Equivalent Growth of ~51%(1) 50 Oil Production Growth (Bbl/d) Natural Gas Production Growth (MMcf/d) (1) At midpoint of 2015 guidance range as revised on August 4, 2015. (2) The Company raised its 2015 oil production guidance to 4.4 to 4.5 million Bbl on August 4, 2015 from 4.1 to 4.3 million Bbl. The Company had previously raised its 2015 oil production guidance to 4.1 to 4.3 million Bbl from 4.0 to 4.2 million Bbl on May 6, 2015. (3) The Company raised its 2015 natural gas production guidance range to 26.0 to 27.0 Bcf from 24.0 to 26.0 Bcf on August 4, 2015.

 
$23.6 $49.9 $115.9 $191.8 $262.9 $225.0 $0.0 $100.0 $200.0 $300.0 2010 2011 2012 2013 2014 2015E $34.0 $67.0 $156.0 $269.0 $367.7 $295.0 $0.0 $100.0 2 . $300.0 $400.0 2010 2011 2012 2013 2014 2015E $76.39 $93.80 $101.86 $99.79 $87.37 $49.73 $3.75 $3.62 $2.59 $4.35 $5.08 $2.92 Realized Oil and Natural Gas Prices, $/Bbl and $/Mcf 2015E Revenues and Adjusted EBITDA(1)(2)  Revenues and Adjusted EBITDA(1)(2) growth significantly impacted by lower estimated 015 realized oil and natural gas prices − 2015E realized oil price of ~$50/Bbl vs ~$87/Bbl realized in 2014 − 2015E realized natural gas price of ~$3.00/Mcf vs ~$5.00/Mcf in 2014  Estimated oil and natural gas revenues of $290 to $300 million − Increased guidance on August 4, 2015 from $270 to $290 million − Decrease of ~20% from $367.7 million in 2014 − Oil and natural gas hedges estimated to contribute $66 million in additional revenues in 2015, as compared to $5 million in 2014  Estimated Adjusted EBITDA(1)(2) of $220 to $230 million − Increased guidance on August 4, 2015 from $200 to $220 million − Decrease of ~14% from $262.9 million in 2014  ~50% oil by volume, ~74% oil by revenue in 2015(2); compared to ~57% oil by volume, ~79% oil by revenue in 2014 2015 Updated Capital Investment Plan (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 2015 oil and natural gas revenues, Adjusted EBITDA and production based upon the midpoint of 2015 guidance range as revised on August 4, 2015. Prices for oil and natural gas used in these estimates were $50.00/Bbl (WTI oil price of $55.00/Bbl less $5.00/Bbl differentials and transportation costs) and $3.00/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period July through December 2015 and weighted average realized prices for the period January through June 2015 of $49.48/Bbl and $2.80/Mcf. 51 Oil and Natural Gas Revenues(2) (millions) Adjusted EBITDA(1)(2) (millions)

 
 2015E CapEx of ~$425 million − Revised from $350 million on August 4, 2015 − Excluding CapEx associated with HEYCO merger or associated JVs  2015E CapEx was highest in Q1 2015 – falls quickly thereafter − Q1 at $159 million (37%); Q2 at $107 million (25%); Q3 and Q4 at $159 million total (remaining 38%) − Reduced drilling program from 5 rigs at YE 2014 to 2 rigs by end of Q1 due to lower commodity prices, with primary focus on Permian (Delaware) Basin  Eagle Ford operated drilling and completion operations completed for 2015 – over 95% of acreage held by production or not subject to near-term expirations(1)  Delaware Basin drilling program focused on Wolf development, further delineation of Ranger and Rustler Breaks areas and integration of HEYCO acreage − $5 to $10 million increase in CapEx due to beginning to drill wells faster, higher working interests and increased focus on Wolfcamp wells (vs. shallower Bone Spring wells)  Added third Delaware Basin drilling rig in July 2015 due to success and progress with Delaware Basin program in 2015 − $25 to $30 million increase in CapEx but minimal production impact in 2015 − Starting with three well “stack” in Jackson Trust (NE Loving County) prospect area  Haynesville development includes continued selective participation in non-operated wells, primarily CHK drilling at Elm Grove; Haynesville acreage ~100% held by production − $10 million increase in CapEx due to increased drilling by Chesapeake on Elm Grove properties; $25 million represents only ~6% of 2015E CapEx  $25 to $30 million increase in CapEx for land opportunities in the Delaware Basin and increased midstream initiatives  $5 million increase in CapEx due to additional non-op well participation in the Delaware Basin 2015 Updated Capital Investment Summary 52 (1) At December 31, 2014.

 
53 Summary and 2015 Guidance  Moved from 5 rigs to 2 rigs in early 2015; currently operating 3 rigs in Delaware Basin − Added third drilling rig in the Delaware Basin in late July 2015  Delaware drilling focused on Wolf development and further delineation of Ranger and Rustler Breaks prospect areas, plus integration of HEYCO acreage  Eagle Ford drilling temporarily suspended as over 95% of acreage held-by-production or not subject to near-term expiration(1) 2014 Prior Updated % Actual 2015 Guidance 2015 Guidance(2) Change Capital Spending $610 million $350 million $425 million - 30% Total Oil Production 3.3 million Bbl 4.1 to 4.3 million Bbl(3) 4.4 to 4.5 million Bbl + 34% Total Natural Gas Production 15.3 Bcf 24.0 to 26.0 Bcf 26.0 to 27.0 Bcf + 73% Oil and Natural Gas Revenues $367.7 million $270 to $290 million $290 to $300 million(4) - 20% Adjusted EBITDA(5) $262.9 million $200 to $220 million $220 to $230 million(4) - 14% (1) At December 31, 2014. (2) The Company raised its full-year 2015 guidance estimates on August 4, 2015. (3) The Company raised its 2015 oil production guidance from 4.0 to 4.2 million Bbl to 4.1 to 4.3 million Bbl on May 6, 2015. (4) Estimated 2015 oil and natural gas revenues and Adjusted EBITDA based upon the midpoint of 2015 guidance range as revised on August 4, 2015. Prices for oil and natural gas used in these estimates were $50.00/Bbl (WTI oil price of $55.00/Bbl less $5.00/Bbl differentials and transportation costs) and $3.00/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period July through December 2015 and weighted average realized prices for the period January through June 2015 of $49.48/Bbl and $2.80/Mcf. (5) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix.

 
Appendix

 
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, James Cleo Thompson Jr. 34 years Since Inception Matthew V. Hairford President, Chair of Operating Committee - Samson, Sonat, Conoco 30 years Since 2004 David E. Lancaster EVP and CFO - Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 35 years Since 2003 Craig N. Adams EVP – Land, Legal & Administration - Baker Botts L.L.P., Thompson & Knight LLP 22 years Since 2012 Van H. Singleton, II EVP – Land - Southern Escrow & Title, VanBrannon & Associates 18 years Since 2007 Bradley M. Robinson VP – Reservoir Engineering and CTO - Schlumberger, S.A. Holditch & Associates, Inc., Marathon 37 years Since Inception Billy E. Goodwin VP – Drilling - Samson, Conoco 30 years Since 2010 G. Gregg Krug VP – Marketing - Williams Companies, Samson, Unit Corporation 31 years Since 2005 Trent W. Green VP – Production - HEYCO, Bass Enterprises, Schlumberger, S.A. Holditch & Associates, Inc., Amerada Hess 26 years Since 2015 Robert T. Macalik VP and CAO - Pioneer Natural Resources, PricewaterhouseCoopers (PwC) 13 years Since 2015 Kathryn L. Wayne Controller and Treasurer - Matador Petroleum Corporation, Mobil 30 years Since Inception 55

 
Board of Directors – Expertise and Stewardship Board Members Professional Experience Business Expertise David M. Laney Lead Director - Past Chairman, Amtrak Board of Directors - Former Partner, Jackson Walker LLP Law and Investments Reynald A. Baribault Director - Vice President / Engineering and Co-founder, North Plains Energy, LLC - President and CEO, IPR Energy Partners, LLC - Former Vice President, Netherland, Sewell & Associates, Inc. Oil and Gas Exploration & Development Gregory E. Mitchell Director - President and CEO, Toot’n Totum Food Stores Petroleum Retailing Dr. Steven W. Ohnimus Director - Retired Vice President and General Manager, Unocal Indonesia Oil and Gas Operations Carlos M. Sepulveda, Jr. Director - Executive Chairman of the Board, Triumph Bancorp, Inc. - Retired President and CEO, Interstate Battery System International, Inc. - Director and Audit Chair, Cinemark Holdings, Inc. Business and Finance Margaret B. Shannon Director - Retired Vice President and General Counsel, BJ Services Co. - Former Partner, Andrews Kurth LLP Law and Corporate Governance Don C. Stephenson Director - Retired Partner, Baker Botts L.L.P. Law and Tax Strategy George M. Yates Director - Chairman & CEO of HEYCO Energy Group, Inc. Oil and Gas Exploration & Development 56

 
Special Board Advisors Professional Experience Business Expertise Ronney F. Coleman - Retired President – North America, Archer - Former Vice President North America Pumping, BJ Services Co. Oilfield Services Marlan W. Downey - Retired President, ARCO International - Former President, Shell Pecten International - Past President of American Association of Petroleum Geologists Oil and Gas Exploration John R. Gass - VP, Eastern Hemisphere Operations, Nabors Drilling International Limited based in Dubai, UAE - Previously spent 28 years with Parker Drilling Company in various management roles Oil and Gas Drilling David F. Nicklin - Retired Executive Director of Exploration, Matador Resources Company Oil and Gas Exploration Wade I. Massad - Managing Member, Cleveland Capital Management, LLC - Formerly with KeyBanc Capital Markets and RBC Capital Markets Capital Markets Greg L. McMichael - Retired Vice President and Group Leader – Energy Research of A.G. Edwards Capital Markets Dr. James D. Robertson - Retired VP Exploration, Chief Geophysicist, ARCO International Oil and Gas Exploration Michael C. Ryan - Partner, Berens Capital Management - Former Director, Matador Resources Company International Business and Finance W.J. “Jack” Sleeper, Jr. - Retired President, DeGolyer and MacNaughton (Worldwide Petroleum Consultants) Oil and Gas Executive Management Special Board Advisors – Expertise and Stewardship 57

 
420,000 680,000 810,000 810,000 390,000 390,000 390,000 390,000 $99.75 $87.72 $84.60 $84.60 $74.64 $74.64 $74.64 $74.64 $83.00 $70.38 $67.11 $67.11 $47.46 $47.46 $47.46 $47.46 $0 $50 $100 $150 $200 $250 $300 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Oil Vol ume He dg ed (B bl) 4.65 4.35 4.35 4.05 2.10 2.10 2.10 2.10 $4.65 $3.94 $3.94 $3.99 $3.80 $3.80 $3.80 $3.80 $3.73 $3.26 $3.26 $3.30 $2.75 $2.75 $2.75 $2.75 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.00 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Na tu ra l G as Vol umes He dg ed (B cf) Hedging Profile 2015 Hedges(1)  Oil: 0.8 million barrels of oil hedged for remainder of 2015 at weighted average floor and ceiling prices of $67/Bbl and $85/Bbl, respectively – Approximately 75% of oil hedged for remainder of 2015(2)  Natural Gas: 4.1 Bcf of natural gas hedged for remainder of 2015 at weighted average floor and ceiling of $3.30/MMBtu and $3.99/MMBtu, respectively – Approximately 65% of natural gas hedged for remainder of 2015(2)  Natural Gas Liquids: 1.0 million gallons of natural gas liquids hedged for remainder of 2015 at weighted average price of $1.02/gal  Oil and natural gas hedges estimated to add $66 million to projected oil and natural gas revenues in 2015 2016 Hedges  Oil: 1.6 million Bbl of oil ($47/Bbl floor and $75/Bbl ceiling)  Natural Gas: 8.4 Bcf of natural gas ($2.75/MMBtu floor and $3.80/MMBtu ceiling) 58 2015 Oil Hedges (Costless Collars) 2015 Natural Gas Hedges (Costless Collars) (1) At October 2, 2015. (2) Based upon the midpoint of 2015 guidance range of 4.4 to 4.5 million Bbl of oil as revised upward on August 4, 2015 and 26.0 to 27.0 Bcf of natural gas as revised upward on August 4, 2015. Ceiling Floor Ceiling Floor

 
 Strong, supportive bank group led by Royal Bank of Canada  Borrowing base at $375 million based on December 31, 2014 reserves  Bank group affirmed $375 million conforming borrowing base in April 2015  Retained full $375 million conforming borrowing base upon closing of Senior Notes offering  No borrowings outstanding at October 1, 2015  Net Debt/Adjusted EBITDA(1)(2) of 1.0x  Financial covenants  Maximum Total Debt to Adjusted EBITDA(2) Ratio of not more than 4.25:1.00  Under this covenant, Total Debt could be ~$1.1 billion based on LTM Adjusted EBITDA(1) 59 Credit Agreement Status (1) Net Debt at October 1, 2015 and LTM Adjusted EBITDA at June 30, 2015. (2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA an a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. TIER Conforming Borrowing Base Utilization LIBOR Margin BASE Margin Commitment Fee Tier One x < 25% 150 bps 50 bps 37.5 bps Tier Two 25% < or = x < 50% 175 bps 75 bps 37.5 bps Tier Three 50% < or = x < 75% 200 bps 100 bps 50 bps Tier Four 75% < or = x < 90% 225 bps 125 bps 50 bps Tier Five 90% < or = x < 100% 250 bps 150 bps 50 bps

 
North Ranger-Twin Lakes Area Pennsylvanian/Wolfcamp Production Distribution 60 A A’ MATADOR RESOURCES COMPANY PICKARD STATE 20-18-34 #2H Northern Delaware Horizontal Pennsylvanian/Wolfcamp Shale Test Vacuum Field Townsend Field 166 wells 25 million Bbl, 49 Bcf Sanmal & Leamex Fields Corbin Field Kemnitz Field 94 wells 19 million Bbl, 78 Bcf Sanmal and Leamex Fields 40 wells 3.4 million Bbl, 5.4 Bcf Vacuum Field 135 wells 19 million Bbl, 48 Bcf Airstrip Field Corbin Field 77 wells 7.6 million Bbl, 18 Bcf Airstrip Field 14 wells 0.26 million Bbl, 0.17 Bcf Wolfcamp/ Upper Pennsylvanian Production ~74 million Bbl, 190 Bcf ~526 vertical wells ~141,000 Bbl per vertical well Matador Resources Acreage Note: Information from public sources available as of November 2014. Vacuum N and NW Fields Kemnitz & Lea Fields Bcf = billions of cubic feet of natural gas.

 
0 1 5 0 G R (C TR ) 2 2 0 0 0 0 L L D 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 GR (C TR ) 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 G R (C TR ) 2 2 0 0 0 0 ILM 2 2 0 0 0 0 L L D 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 GR (C TR ) 2 2 0 0 0 0 ILM 2 2 0 0 0 0 L L D 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 G R (C T R ) 2 2 0 0 0 0 ILM 0 .3 0 D P H I 0 .3 0 N P H I 0 1 5 0 G R (C TR ) 2 2 0 0 0 0 ILM 2 2 0 0 0 0 L L D 0 .3 0 D P H I 0 .3 0 N P H I 95 00 10 00 0 10 50 0 11 00 0 11 50 0 10 00 0 10 50 0 11 00 0 11 50 0 12 00 0 10 00 0 10 50 0 11 00 0 11 50 0 12 00 0 10 50 0 11 00 0 11 50 0 10 50 0 11 00 0 11 50 0 12 00 0 12 50 0 10 50 0 11 00 0 11 50 0 12 00 0 12 50 0 Pennsylvanian/Wolfcamp “Hybrid” Production Target Interval 30025300490000 AVRA OIL COMPANY 30025257790000 ELK OIL COMPANY 30025346940000 Legacy Reserves Oper. Co. 30025397370000 CML EXPLORATION 30025414070000 CML EXPLORATION 30025416140000 MATADOR PRODUCTION A B E N A KI 1 0 S T A T E # 1 S T A T E ` 7 ` # 1 NOR T H E A S T K E M NI T Z # 3 O S C A S T A T E CO M # 1 B E A M S 1 5 S T A T E # 3 P ICK A R D S T A T E # 2 H P IL O T TOP OF WOLFCAMP LWTS GR Res. Dens. Neut. 10 MBbl 48 MMcf 197 MBbl 356 MMcf 140 MBbl 296 MMcf 90 MBbl 410 MMcf 11 MBbl 60 MMcf First Horizontal Landing Zone in source rock play: overpressured 0.7 psi/ft Produced 91,200 BOE – 14.5 mo. IP (24 hr.) from source rock: • 232 Bbl/d, 225 Mcf/d (86% oil) • 1,150 psi surface pressure • 18/64th inch choke A North A’ South Pickard #2H Future horizontal landing zones (oil on pits while drilling) in “hybrid” reservoirs: porous, sandstone/limestone and source rock. ~6 0 0 ’ – 8 0 0 ’ Th ic k Cumulative volumes produced from older vertical wells Flowed oil on test Re g io n a ll y pro d u c ti v e “ Hy brid ” Ta rge t In te rv a l 61 MMBbl = millions of barrels of oil. Bcf = billions of cubic feet of natural gas. MMcf = millions of cubic feet of natural gas.

 
62 Adjusted EBITDA Reconciliation This investor presentation includes the non-GAAP financial measure of Adjusted EBITDA. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. “GAAP” means Generally Accepted Accounting Principles in the United States of America. The Company believes Adjusted EBITDA helps it evaluate its operating performance and compare its results of operations from period to period without regard to its financing methods or capital structure. The Company defines 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, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents the calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively, that are of a historical nature. Where references are pro forma, forward-looking or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. The Company could not provide such reconciliations without undue hardship because such Adjusted EBITDA numbers are estimations, approximations and/or ranges. In addition, it would be difficult for the Company to present a detailed reconciliation on account of many unknown variables for the reconciling items.

 
Adjusted EBITDA Reconciliation The following table presents our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. 63 (In thousands) 1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 4Q 2014 1Q 2015 2Q 2015 Unaudited Adjusted EBITDA reconciliation to Net (loss) Income: Net (loss) income $ 3,801 $ (6,676) $ (9,197) $ (21,188) $ (15,505) $ 25,119 $ 20,105 $ 15,374 $ 16,363 $ 18,226 $ 29,619 $ 46,563 $ (50,234) $ (157,091) Interest expense 308 1 144 549 1,271 1,609 2,038 768 1,396 1,616 673 1,649 2,070 5,869 Total income tax provision (benefit) 3,064 (3,713) (593) (188) 46 32 2,563 7,056 9,536 10,634 16,504 27,701 (26,390) (89,350) Depletion, depreciation and amortization 11,205 19,914 21,680 27,655 28,232 20,234 26,127 23,802 24,030 31,797 35,143 43,767 46,470 51,768 Accretion of asset retirement obligations 53 58 59 86 81 80 86 100 117 123 130 134 112 132 Full-cost ceiling impairment - 33,205 3,596 26,674 21,230 - - - - - - - 67,127 229,026 Unrealized (gain) loss on derivatives 3,270 (15,114) 12,993 3,653 4,825 (7,526) 9,327 606 3,108 5,234 (16,293) (50,351) 8,557 23,532 Stock-based compensation expense (363) 191 (51) 363 492 1,032 1,239 1,134 1,795 1,834 1,038 857 2,337 2,794 Net loss on asset sales and inventory impairment - 60 - 425 - 192 - - - - - - 97 - Adjusted EBITDA $ 21,338 $ 27,926 $ 28,631 $ 38,029 $ 40,672 $ 40,772 $ 61,485 $ 48,840 $ 56,345 $ 69,464 $ 66,814 $ 70,320 $ 50,146 $ 66,680 (In thousands) 1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 4Q 2014 1Q 2015 2Q 2015 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $ 5,110 $ 46,416 $ 28,799 $ 43,903 $ 32,229 $ 51,684 $ 43,280 $ 52,278 $ 31,945 $ 81,530 $ 66,883 $ 71,123 $ 93,346 $ 20,043 Net change in operating assets and liabilities 15,920 (18,491) (500) (6,235) 7,126 (12,553) 15,265 (3,630) 21,729 (15,221) (586) 56 (45,234) 40,843 Interest expense 308 1 144 549 1,271 1,609 2,038 768 1,396 1,616 673 1,649 2,070 5,869 Current income tax (benefit) provision - - 188 (188) 46 32 902 (576) 1,275 1,539 (156) (2,525) - - Net (income) loss attributable to non-controlling interest in subsidiary - - - - - - - - - - - 17 (36) (75) Adjusted EBITDA $ 21,338 $ 27,926 $ 28,631 $ 38,029 $ 40,672 $ 40,772 $ 61,485 $ 48,840 $ 56,345 $ 69,464 $ 66,814 $ 70,320 $ 50,146 $ 66,680

 
Adjusted EBITDA Reconciliation The following table presents our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. 64 Note: LTM is last 12 months. LTM at LTM at LTM at (In thousands) 2008 2009 2010 2011 2012 2013 2014 6/30/2013 9/30/2014 6/30/2015 Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): Net income (loss) $103,878 ($14,425) $6,377 ($10,309) ($33,261) $45,094 $110,771 ($20,771) $79,582 ($131,143) Interest expense - - 3 683 1,002 5,687 5,334 3,574 4,453 10,261 Total income tax (benefit) provision 20,023 (9,925) 3,521 (5,521) (1,430) 9,697 64,375 (703) 43,730 (71,535) Depletion, depreciation and amortization 12,127 10,743 15,596 31,754 80,454 98,395 134,737 97,801 114,772 177,148 Accretion of asset retirement obligations 92 137 155 209 256 348 504 307 470 508 Full-cost ceiling impairment 22,195 25,244 - 35,673 63,475 21,229 - 51,499 - 296,153 Unrealized loss (gain) on derivatives (3,592) 2,375 (3,139) (5,138) 4,802 7,232 (58,302) 13,945 (7,345) (34,555) Stock-based compensation expense 665 656 898 2,406 140 3,897 5,524 1,836 5,801 7,026 Net (gain) loss on asset sales and inventory impairment (136,977) 379 224 154 485 192 - 617 - 97 Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $262,943 $148,105 $241,463 $253,960 LTM at LTM at LTM at (In housands) 2008 2009 2010 2011 2012 2013 2014 6/30/2013 9/30/2014 6/30/2015 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $25,851 $1,791 $27,273 $61,868 $124,228 $179,470 $251,481 $156,614 $232,636 $251,395 Net change in operating assets and liabilities (17,888) 15,717 (2,230) (12,594) (9,307) 6,210 5,978 (12,161) 2,292 (4,921) Interest expense - - 3 683 1,002 5,687 5,334 3,574 4,453 10,261 Current income tax (benefit) provision $10,448 ($2,324) (1,411) (46) - 404 133 78 2,082 (2,681) Net (income) loss attributable to non-controlling interest in subsidiary - - - - - - 17 - - (94) Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $262,943 $148,105 $241,463 $253,960 Year Ended December 31, Year Ended December 31,

 
65 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 the Company's 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. PV-10 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. At December 31, 2009 At December 31, 2010 At September 30, 2011 At December 31, 2011 At March 31, 2012 At June 30, 2012 At September 30, 2012 At December 31, 2012 At March 31, 2013 PV-10 (in millions) $70.4 $119.9 $155.2 $248.7 $329.6 $303.4 $363.6 $423.2 $438.1 Discounted Future Income Taxes (in millions) $(5.3) $(8.8) $(11.8) $(33.2) $(42.2) $(21.9) $(29.7) $(28.6) $(31.1) Standardized Measure (in millions) $65.1 $111.1 $143.4 $215.5 $287.4 $281.5 $333.9 $394.6 $407.0 At June 30, 2013 At September 30, 2013 At December 31, 2013 At March 31, 2014 At June 30, 2014 At September 30, 2014 At December 31, 2014 At March 31, 2015 At June 30, 2015 PV-10 (in millions) $522.3 $538.6 $655.2 $739.8 $826.0 $952.0 $1,043.4 $1,070.1 $942.8 Discounted Future Income Taxes (in millions) $(44.7) $(52.5) $(76.5) $(86.2) $(103.0) $(116.9) $(130.1) $(120.9) $(78.7) Standardized Measure (in millions) $477.6 $486.1 $578.7 $653.6 $723.0 $835.1 $913.3 $949.2 $864.1