Exhibit 10.1
SECOND AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT
This
SECOND AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT (this “
Amendment
”) is entered into as of June 4, 2013, by and among MRC ENERGY COMPANY, a Texas corporation (the “
Borrower
”), the LENDERS party
hereto and ROYAL BANK OF CANADA, as Administrative Agent for the Lenders (in such capacity, the “
Administrative Agent
”). Unless otherwise expressly defined herein, capitalized terms used but not defined in this Amendment have the
meanings assigned to such terms in the Credit Agreement (as defined below).
WITNESSETH:
WHEREAS,
the Borrower, the Administrative Agent and the Lenders have entered into that certain Third Amended and Restated Credit
Agreement, dated as of September 28, 2012 (as the same has been and may hereafter be amended, restated, supplemented or otherwise modified from time to time, the “
Credit Agreement
”); and
WHEREAS,
the Borrower has requested that the Administrative Agent and the Lenders amend the Credit Agreement in certain respects
and the Administrative Agent and the Lenders have agreed to do so on the terms and conditions hereinafter set forth.
NOW,
THEREFORE,
for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, the Borrower, the Administrative
Agent and the Lenders hereby agree as follows:
SECTION 1. Amendments to Credit Agreement.
Subject to the satisfaction or waiver in
writing of each condition precedent set forth in
Section 3
of this Amendment, and in reliance on the representations, warranties, covenants and agreements contained in this Amendment, the Credit Agreement shall be amended in the manner
provided in this
Section 1
.
1.1
Amended Definition.
The following definition in
Section 1.1
of the Credit Agreement shall be and it hereby is amended and restated in its entirety to read as follows:
“
Indebtedness
” means (a) all indebtedness, obligations and liabilities of every nature, contingent or otherwise, of Borrower or any Guarantor to any of the Lenders, any of the
Lenders’ Affiliates, the Administrative Agent, or the Issuing Lender, individually or collectively, under any Loan Document, whether for principal, interest, reimbursement of amounts drawn under any Letter of Credit, funding indemnification
amounts, fees, expenses, indemnification or otherwise, (b) Lender Hedging Obligations, and (c) Lender Product Obligations, in each case whether existing on the date of this Agreement or arising thereafter, direct or indirect, joint or
several, absolute or contingent, matured or unmatured, liquidated or unliquidated, secured or unsecured, including interest accruing subsequent to the filing of a petition or other action concerning bankruptcy or other similar proceedings, and all
renewals, extensions, refinancings and replacements for the foregoing;
provided
;
however
, that in no event shall the Indebtedness include, with respect to any Guarantor, any Excluded Swap Obligations of such Guarantor.
1.2
Schedule 1.2.
Schedule 1.2
to the Credit Agreement shall be and it
hereby is amended and restated in its entirety and replaced with
Schedule 1.2
attached hereto.
SECTION 2. Redetermined Borrowing
Base and Conforming Borrowing Base.
This Amendment shall constitute notice of a redetermination of the Borrowing Base and the Conforming Borrowing Base pursuant to
Section 4.2
of the Credit Agreement, and the Administrative Agent,
the Lenders and the Borrower hereby acknowledge that effective as of the date hereof, the Borrowing Base shall be $280,000,000 and the Conforming Borrowing Base shall be $245,000,000 and such redetermined Borrowing Base and Conforming Borrowing Base
shall remain in effect until the date the Borrowing Base and the Conforming Borrowing Base are otherwise adjusted pursuant to the terms of the Credit Agreement.
SECTION 3. Conditions.
The amendments to the Credit Agreement contained in
Section 1
of this Amendment and the redetermination of the Borrowing Base and Conforming Borrowing Base
contained in
Section 2
of this Amendment shall be effective upon the satisfaction of each of the conditions set forth in this
Section 3
.
3.1
Execution and Delivery
. The Administrative Agent shall have received a duly executed counterpart of (a) this Amendment signed by the Borrower and the Lenders and (b) the
Consent and Reaffirmation attached hereto signed by each Guarantor.
3.2
No Default.
No Default or Event of
Default shall have occurred and be continuing or shall result from the effectiveness of this Amendment.
3.3
Fees.
The Borrower and the Administrative Agent shall have executed and delivered a fee letter in connection with this Amendment, and the Administrative Agent shall have received the fees separately agreed upon in such fee letter.
3.4
Other Documents.
The Administrative Agent shall have received such other instruments and documents incidental and
appropriate to the transactions provided for herein as the Administrative Agent or its special counsel may reasonably request, and all such documents shall be in form and substance reasonably satisfactory to the Administrative Agent.
SECTION 4. Representations and Warranties.
To induce the Lenders to enter into this Amendment, the Borrower hereby represents and warrants to the
Lenders as follows:
4.1 Reaffirmation of Representations and Warranties.
After giving effect to the amendments herein,
each representation and warranty of the Borrower, the Parent and each other Credit Party contained in the Credit Agreement and in each of the other Loan Documents to which it is a party is true and correct in all material respects as of the date
hereof (without duplication of any materiality qualifier contained therein), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to
be true and correct in all material respects (without duplication of any materiality qualifier contained therein) as of such specified earlier date.
4.2
Corporate Authority; No Conflicts.
The execution, delivery and performance
by the Borrower of this Amendment and all documents, instruments and agreements contemplated herein are within the Borrower’s corporate powers, have been duly authorized by necessary corporate action by the Borrower, require no action by or in
respect of, or filing with, any court or agency of government (except for the recording and filing of Collateral Documents and financing statements) and (a) do not violate in any material respect any Requirement of Law, (b) are not in
contravention of the terms of any material Contractual Obligation, indenture, agreement or undertaking to which the Borrower is a party or by which it or its properties are bound where such violation could reasonably be expected to have a Material
Adverse Effect, and (c) do not result in the creation or imposition of any Lien upon any of the assets of the Borrower except for Liens permitted by
Section 8.2
of the Credit Agreement and otherwise as permitted in the Credit
Agreement.
4.3
Enforceability.
This Amendment constitutes the valid and binding obligation of the Borrower
enforceable in accordance with its terms, except as (i) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor’s rights generally, and (ii) the availability of equitable remedies may be
limited by equitable principles of general application.
4.4
No Default.
As of the date hereof, both before and
immediately after giving effect to this Amendment, no Default or Event of Default has occurred and is continuing.
SECTION 5.
Miscellaneous.
5.1
Reaffirmation of Loan Documents and Liens.
Any and all of the terms and provisions of
the Credit Agreement and the Loan Documents shall, except as amended and modified hereby, remain in full force and effect and are hereby in all respects ratified and confirmed by the Borrower. The Borrower hereby agrees that the amendments and
modifications herein contained shall in no manner affect or impair the liabilities, duties and obligations of the Borrower, the Parent or any other Credit Party under the Credit Agreement and the other Loan Documents or the Liens securing the
payment and performance thereof, except as amended and modified hereby.
5.2
Parties in Interest.
All of the
terms and provisions of this Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns.
5.3
Further Assurances
. The Borrower covenants and agrees from time to time, as and when reasonably requested by the Administrative Agent or the Lenders, to execute and deliver or cause to
be executed or delivered, all such documents, instruments and agreements and to take or cause to be taken such further or other action as the Administrative Agent or the Lenders may reasonably deem necessary or desirable in order to carry out the
intent and purposes of this Amendment.
5.4
Legal Expenses.
The Borrower hereby agrees to pay all reasonable and
documented out-of-pocket fees and expenses of special counsel to the Administrative Agent incurred by the Administrative Agent in connection with the preparation, negotiation and execution of this Amendment and all related documents.
5.5
Counterparts.
This Amendment may be executed in one or more counterparts
and by different parties hereto in separate counterparts each of which when so executed and delivered shall be deemed an original, but all such counterparts together shall constitute but one and the same instrument; signature pages may be detached
from multiple separate counterparts and attached to a single counterpart so that all signature pages are physically attached to the same document. Delivery of photocopies of the signature pages to this Amendment by facsimile or electronic mail shall
be effective as delivery of manually executed counterparts of this Amendment.
5.6 Complete Agreement.
THIS AMENDMENT,
THE CREDIT AGREEMENT, AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN
THE PARTIES.
5.7
Headings.
The headings, captions and arrangements used in this Amendment are, unless specified
otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Amendment, nor affect the meaning thereof.
5.8
Governing Law.
This Amendment shall be construed in accordance with and governed by the laws of the State of Texas.
5.9
Severability.
Any provision of this Amendment held to be invalid, illegal or unenforceable in any jurisdiction shall,
as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in
a particular jurisdiction shall not invalidate such provision in any other jurisdiction.
5.10 Reference to and Effect on
the Loan Documents.
(a) This Amendment shall be deemed to constitute a Loan Document for all purposes and in all
respects. Each reference in the Credit Agreement to “this Agreement,” “hereunder,” “hereof,” “herein” or words of like import, and each reference in the Credit Agreement or in any other Loan Document, or other
agreements, documents or other instruments executed and delivered pursuant to the Credit Agreement to the “Credit Agreement”, shall mean and be a reference to the Credit Agreement as amended by this Amendment.
(b) The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of any Lender
or the Administrative Agent under any of the Loan Documents, nor constitute a waiver of any provision of any of the Loan Documents.
[Signature pages follow.]
IN WITNESS WHEREOF,
the parties have caused this Amendment to be duly
executed by their respective authorized officers to be effective as of the date first above written.
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BORROWER
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MRC ENERGY COMPANY
,
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as Borrower
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By:
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/s/ David E. Lancaster
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Name:
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David E. Lancaster
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Title:
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Executive Vice President
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ROYAL BANK OF CANADA
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as Administrative Agent
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By:
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/s/ Rodica Dutka
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Name:
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Rodica Dutka
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Title:
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Manager, Agency
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ROYAL BANK OF CANADA
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as a Lender and as an Issuing Lender
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By:
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/s/ Jay Sartain
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Name:
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Jay Sartain
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Title:
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Authorized Signatory
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CITIBANK, N.A.
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as a Lender
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By:
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/s/ Ryan Watson
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Name:
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Ryan Watson
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Title:
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Senior Vice President
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COMERICA BANK
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as a Lender and as an Issuing Lender
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By:
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/s/ Brandon M. White
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Name:
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Brandon M. White
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Title:
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Corporate Banking Officer
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SUNTRUST BANK
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as a Lender
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By:
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/s/ Shannon Juhan
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Name:
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Shannon Juhan
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Title:
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Vice President
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THE BANK OF NOVA SCOTIA
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as a Lender
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By:
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/s/ Terry Donovan
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Name:
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Terry Donovan
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Title:
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Managing Director
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BMO Harris Financing, Inc.
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as a Lender
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By:
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/s/ James V. Ducote
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Name:
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James V. Ducote
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Title:
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Director
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CAPITAL ONE, N.A.
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as a Lender
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By:
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/s/ Nancy Mak
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Name:
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Nancy Mak
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Title:
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Senior Vice President
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IBERIABANK
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as a Lender
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By:
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/s/ W. Bryan Chapman
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Name:
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W. Bryan Chapman
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Title:
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Executive Vice President
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Schedule 1.2
Percentages and Allocations
Revolving Credit
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LENDERS
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REVOLVING
CREDIT
ALLOCATIONS
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REVOLVING
CREDIT
PERCENTAGE
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Royal Bank of Canada
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$
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60,392,156.86
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21.5686274510
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%
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Comerica Bank
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$
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46,666,666.67
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16.6666666667
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%
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Citibank, N.A.
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$
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43,921,568.63
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15.6862745098
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%
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SunTrust Bank
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$
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35,686,274.51
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12.7450980392
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%
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The Bank of Nova Scotia
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$
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35,686,274.51
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12.7450980392
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%
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BMO Harris Financing, Inc.
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$
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21,960,784.31
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7.8431372549
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%
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Capital One, N.A.
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$
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21,960,784.31
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7.8431372549
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%
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IBERIABANK
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$
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13,725,490.20
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4.90196078431
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%
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TOTALS
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$
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280,000,000.00
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100.00000000
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%
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CONSENT AND REAFFIRMATION
Each of the undersigned (each a “
Guarantor
”) hereby (i) acknowledges receipt of a copy of the foregoing Second
Amendment to Third Amended and Restated Credit Agreement (the “
Second Amendment
”); (ii) consents to the Borrower’s execution and delivery thereof; (iii) consents to the terms of the Second Amendment; (iv) affirms
that nothing contained therein shall modify in any respect whatsoever its guaranty of the Indebtedness pursuant to the terms of the Guaranty or the Liens granted by it pursuant to the terms of the other Loan Documents to which it is a party securing
payment and performance of the Indebtedness, (v) reaffirms that the Guaranty and the other Loan Documents to which it is a party and such Liens are and shall continue to remain in full force and effect and are hereby ratified and confirmed in
all respects and (vi) represents and warrants to the Administrative Agent and the Lenders that, as of the date hereof, (x) all of the representations and warranties made by it in each of the Loan Documents to which it is a party are true
and correct in all material respects (without duplication of any materiality qualifier contained therein), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and
warranties shall continue to be true and correct in all material respects (without duplication of any materiality qualifier contained therein) as of such specified earlier date, and (y) no Default or Event of Default has occurred and is
continuing. Although each Guarantor has been informed of the matters set forth herein and has acknowledged and agreed to same, each Guarantor understands that neither the Administrative Agent nor any of the Lenders have any obligation to inform any
Guarantor of such matters in the future or to seek any Guarantor’s acknowledgment or agreement to future amendments or waivers for the Guaranty and other Loan Documents to which it is a party to remain in full force and effect, and nothing
herein shall create such duty or obligation.
[SIGNATURE PAGES FOLLOW]
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C
ONSENT
AND
R
EAFFIRMATION
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IN WITNESS WHEREOF, the undersigned has executed this Consent and Reaffirmation on and as of
the date of the Second Amendment.
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GUARANTORS
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MRC PERMIAN COMPANY
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By:
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Name:
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David E. Lancaster
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Title:
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Executive Vice President
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MRC ROCKIES COMPANY
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By:
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Name:
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David E. Lancaster
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Title:
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Executive Vice President
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MATADOR PRODUCTION COMPANY
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By:
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Name:
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David E. Lancaster
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Title:
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Executive Vice President
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LONGWOOD GATHERING AND
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DISPOSAL SYSTEMS GP, INC.
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By:
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Name:
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David E. Lancaster
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Title:
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Executive Vice President
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LONGWOOD GATHERING AND
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DISPOSAL SYSTEMS, LP
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By:
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Longwood Gathering and Disposal
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Systems GP, Inc., its General Partner
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By:
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Name:
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David E. Lancaster
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Title:
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Executive Vice President
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C
ONSENT
AND
R
EAFFIRMATION
S
IGNATURE
P
AGE
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MATADOR RESOURCES COMPANY
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By:
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Name:
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David E. Lancaster
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Title:
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Executive Vice President
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C
ONSENT
AND
R
EAFFIRMATION
S
IGNATURE
P
AGE
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Exhibit 99.1
MATADOR
RESOURCES COMPANY ANNOUNCES INCREASED BORROWING BASE AND ACREAGE ACQUISITIONS AND PROVIDES AN OPERATIONAL UPDATE
DALLAS, Texas,
June 5, 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 with a current focus on its Eagle Ford operations in South Texas and its Delaware Basin operations in Southeast New Mexico and West Texas, today
provided an update on various aspects of its operations.
Matador announced an increase in its borrowing base to $280 million based on its
lenders’ review of the Company’s proved oil and natural gas reserves at March 31, 2013, as well as the results of several recently completed wells. At June 5, 2013, the Company had outstanding borrowings of $230 million. Matador
expects additional increases to its borrowing base as the result of anticipated increases in its proved oil and natural gas reserves throughout 2013.
The Company continues to build its leasehold position in Southeast New Mexico and West Texas. In May 2013, the Company acquired approximately 3,500 gross and 2,300 net acres primarily in Lea and Eddy
Counties, New Mexico. This additional acreage gives Matador a total of 34,100 gross and 22,500 net acres in Southeast New Mexico and West Texas, of which the Company considers approximately 26,400 gross and 20,400 net acres to be prospective for the
Wolfcamp, Bone Spring and other oil and liquids-rich targets.
Matador’s operations are progressing as outlined in the Company’s
first quarter earnings release provided on May 8, 2013. As expected, the Company completed and has begun producing oil and natural gas from seven operated and two non-operated Eagle Ford shale wells in the second quarter of 2013. Three operated
wells on the Company’s Cowey lease in DeWitt County, Texas were completed and turned to sales in mid-May. Four operated wells completed on Matador’s Martin Ranch lease in LaSalle County were placed on production in late May. The Company
has drilled three additional wells from a single pad on its Sickenius lease in Karnes County, but these wells will not be completed until late June and will not be placed on production until early July. Initial production results from the seven
operated wells completed during the second quarter met or exceeded the Company’s expectations, including its first 40-acre infill test at Martin Ranch.
In New Mexico, Matador has drilled its first well in the Delaware Basin in Lea County, where it successfully collected extensive petrophysical data, including a 182-ft whole core in the Wolfcamp section.
The well appears to have multiple completion targets, and the Company plans to complete the well later in the summer once more of its petrophysical and core analyses
have been completed. The Company is currently drilling its second test well in Lea County; the primary target of this well is the Second Bone Spring. At June 5, 2013, Matador had two
contracted drilling rigs operating – one in Lea County, New Mexico and one in LaSalle County, Texas.
Joseph Wm. Foran, Matador’s
Chairman, President and CEO, commented, “We are very pleased that our Eagle Ford wells continue to meet or exceed our expectations. We are also very pleased to continue building our acreage position in the Delaware Basin in New Mexico and West
Texas and are encouraged by the petrophysical data collected on our first well in Lea County. We will continue to execute our initial three-well test program in the Delaware Basin as planned, but are considering whether to leave one rig operating in
New Mexico throughout the remainder of the year given our growing acreage position in the area. We continue to be very satisfied with our recent Eagle Ford results and believe these results reflect the continued progress we are making in our
completion and production operations. Finally, we are pleased to announce the increase in our borrowing base, which will allow us to continue executing our ongoing drilling programs in South Texas and the Delaware Basin. Through the first five
months of 2013, our entire results have exceeded our initial expectations entering the year and remain consistent with our updated guidance released on May 8, 2013. We continue to note, however, that our production and financial results from
period to period are likely to be uneven and subject to various operating conditions and operating practices followed by Matador. That said, we are all excited about our progress and the outlook for the rest of the year.”
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 Southeast New Mexico and West Texas. 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.
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 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
Exhibit 99.2
Searchable text for slide0001:
Investor
Presentation June 2013
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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 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. 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.
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Company Summary
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4 Company Overview
Company Overview 2012 Actual 2013 Guidance 2012 Actual 2013 Guidance 2012 Actual 2013 Guidance Capital Spending $335 million $325 million Total Oil Production 1.214 million barrels 1.8 to 2.0 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 $220 to $240 million(3) Adjusted EBITDA(4) $115.9 million $155 to $175 million(3) As reported in the Form 10-Q for the quarter ended March 31,
2013 filed on May 10, 2013 As of June 4, 2013 Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and
estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December 2013 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
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Founded by Joe
Foran in 1983 Foran Oil funded with $270,000 in contributed capital from 17 friends and family members Sold to Tom Brown, Inc.(1) in June 2003 for an enterprise value of $388 million in an all-cash transaction Foran Oil & Matador Petroleum
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 Tom Brown purchased by Encana in 2004 Matador Today
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6 Matador Resources Snapshot ~78% 2013E CapEx
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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 Southeast New Mexico and 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
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Matador’s
Continued Growth 8 (1) 2013 estimates at midpoint of guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and
natural gas used in revenue and Adjusted EBITDA estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December 2013 (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 in millions in millions Thousand Bbl Growth Since the IPO
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(CHART) 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 PV-10, millions 9
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10 Haynesville
Total Resource Potential – Price Sensitivity (1) PV-10 is a non-GAAP measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. All PV-10 values estimated as of March 31, 2013 (2) NYMEX gas
price, less property-specific differentials
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Eagle Ford South
Texas
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12 Eagle Ford and
Austin Chalk Overview Drilled and completed 45 gross / 42.5 net operated wells to date(1) Acreage positioned in some of the most active counties for Eagle Ford and Austin Chalk One rig running currently, primarily focused on oil and liquids; expect
to return to two-rig program in September 2013 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 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at
December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at
December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010 0.1 million BOE at December 31, 2010
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13 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 $5.8 million, 1% SE New Mexico $2.0 million, 0% December 31, 2012 PV-10(1): $423.2 million(3) (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(2)
(Standardized Measure = $215.5 million) Proved Producing Reserves PV-10(1): $154.1 million PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix Future undiscounted net revenue
of $494.8 million using YE 2011 SEC pricing of $94.65/Bbl oil and $3.731/MMBtu gas Future undiscounted net revenue of $704.2 million using YE 2012 SEC pricing of $91.21/Bbl oil and $2.757/MMBtu gas
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Highlights 14
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 June 1, 2013 and all other acreage based on public information as of April 2013
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15 EAGLE FORD EAST
7,730 gross / 6,330 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 Uvalde Medina Zavala Frio Dimmit La Salle Webb
Bexar Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson EAGLE FORD ACREAGE TOTALS 41,302 gross / 27,720 net acres COMBO LIQUIDS / GAS FAIRWAY DRY GAS FAIRWAY OIL FAIRWAY Glasscock Ranch Shelton Newman ZLS Martin Ranch Northcut Affleck
Troutt Sutton MRC/EOG Pawelek Danysh Sickenius Lyssy Repka RCT Wilson Love Cowey Keseling Finney Lewton Hennig Nickel Ranch Pena Matador Resources Acreage Eagle Ford Properties Note: All acreage at June 1, 2013 Karnes
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2012 Operated
Eagle Ford Completion Results – 24 Hour IP Tests 16
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17 Well
Improvement with Evolution of Frac Design Eagle Ford East Offsetting Wells: Example 1 Eagle Ford Middle Offsetting Wells: Example 2 Eagle Ford Middle Offsetting Wells: Example 3 Recent Eagle Ford West Well Performance with Fourth Generation Frac
Note: First well on this lease Vertical Depth: 7,424 ft. Lateral Length: 4,762 ft.
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Eagle Ford Well
Costs Declined During 2012 – Western Acreage 18 (CHART) 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.
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Eagle Ford Well
Costs Declined During 2012 – Eastern Acreage 19 (CHART) 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.
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Average Frac Stage
Cost per Well 20 Note: Wells are displayed in chronological order; includes all Matador operated wells drilled and completed through December 31, 2012
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Eagle Ford Well
Estimated ROR as a Function of EUR and Well Cost 21 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 Western Acreage Eastern Acreage
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(CHART) Drilling
Times and Efficiencies 22 Note: As of June 5, 2013 First 4 Wells Spudded after 01/01/13 Spudded prior to 01/01/13
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23 Recent
Technical Advancements in the Eagle Ford Pad drilling 5-10% reduction in cost to drill and complete Drilling cycle time reduction of nearly 4 days/well Safer operations with less moving of heavy equipment Provides for consolidated production
operations on multi-well pads Improved frac design Generation 5 frac design 25 to 40 foot fracture spacing (20% to 100% more fractures than generation 2 design) 40 Bbl/ft frac fluid (100% increase from generation 2 design) 1,700 lbs/ft (50% increase
from generation 2 design) Cut frac stage cost by 20% (compared to generation 2 design) Zipper fracs 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 selected lower fluid volume
wells Gas-lift installations on wells with higher fluid volume in fields with existing gas compression Greatly aids in returning producing wells affected by offset fracs to normal production levels as a result of accelerated frac water removal
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24 San Antonio
Multi-Pay Fairway with Pearsall, Austin Chalk and Buda potential OIL FAIRWAY DRY GAS FAIRWAY Matador Resources Acreage Emerging Multi-Pay Area in Eagle Ford Oil Fairway and MTDR Acreage Note: All acreage at June 1, 2013 Medina Zavala Frio
Dimmit La Salle Webb Bexar Atascosa McMullen Dewitt Gonzales Wilson Karnes Live Oak Bee Goliad Guadalupe Uvalde
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Delaware Basin
Southeast New Mexico and West Texas
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26 Gross Acres(1)
34,094 acres Net Acres(1) 22,498 acres Southeast New Mexico / West Texas Foothold of existing production and reserves Acreage position in good neighborhoods, surrounded by other operators’ ongoing drilling Year to date(2) acquired 18,234 gross
and 14,827 net acres in Lea and Eddy Counties, New Mexico Company considers approximately 26,412 gross and 20,429 net acres to be prospective for multiple oil and liquids-rich targets, including the Wolfcamp and Bone Spring plays Total acreage in
Southeast New Mexico and West Texas at June 1, 2013 At June 1, 2013 RANGER- QUERECHO WOLF INDIAN DRAW EDDY LEA LOVING
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27 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 1st 2nd 3rd 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
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Ranger Prospect
Area: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Concho Stratojet 31 State #3H 2nd Bone Spring 20 mo.cum: 329 MBO; 395 MMcf Cimarex Energy Lynch 23 Fed #1H 3rd Bone Spring 17 mo.cum: 157 MBO; 136 MMcf Legacy Operating
Lea Unit 4H 3rd Bone Spring 16 mo.cum: 62 MBO; 64 MMcf Concho AirCobra 12 #2H 3rd Bone Spring 21 mo.cum: 271 MBO; 181 MMcf XOG Operating (Vertical well) Jordan B #1 Wolfcamp 20 years cum: 387 MBO; 5 Bcf Concho (Vertical well) Neuhaus 14 Fed #2
Wolfcamp 8 years cum: 156 MBO; 2 Bcf Bone Spring Lime 1st Bone Spring Sand 2nd Bone Spring Sand Wolfcamp Bone Spring / Upper Wolfcamp Type Log 3rd Bone Spring Sand Location of Matador 2013 test well Note: All acreage at June 1, 2013. Well
information from public sources as of June 2013. 3 Rivers Oper Eagle 2 State 6H 3rd Bone Spring 4 mo.cum: 46 MBO; 21 MMcf Cimarex Energy Mallon 35 Fed 4H 3rd Bone Spring 23 mo.cum: 37 MBO; 27 MMcf Amtex Energy Teapot 2H 2nd Bone Spring 21 mo.cum: 58
MBO; 48 MMcf Concho Condor State #1H 2nd Bone Spring 2 mo.cum: 23 MBO; 9 MMcf Concho Haumea St. #2H 2nd Bone Spring Completed March 2013 Now Flowing Back 28
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Wolf Leasehold:
Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Wolf Energy Wolf #1 (Vertical well) 3rd BS / Upr Wolfcamp 33 years cum: 60 MBO; 637 MMcf Wolf Energy Dorothy White #1 (Vertical well) 3rd BS / Upr Wolfcamp 17 years cum: 25
MBO; 92 MMcf Shell Johnson 1-88 Lov #1H Wolfcamp 13 mo.cum: 53 MBO; 218 MMcf Shell Johnson 1-86 (1H) Wolfcamp 25 mo.cum: 139 MBO; 398 MMcf OXY Reagan-McElvain #1H Spud 6/27/2012 IP: 570 BOPD 2.6 MMcf/d 4 mo.cum: 66 MBO; 169 MMcf Shell Johnson
1-76 (1H) Wolfcamp 30 mo.cum: 160 MBO; 528 MMcf Energen Grayling 1-69 IP: 791 BOPD 7.3 MMcf/d 3,500 psi FTP 8 mo.cum: 54 MBO; 525 MMcf on restricted choke Energen Black Mamba 1-57 Wolfcamp 11 mo.cum: 159 MBO; 400 MMcf Proposed location for
Matador 2013 test well Shell Owens 1-75 Lov #1H Wolfcamp 14 mo.cum: 83 MBO; 191 MMcf Energen Bushmaster 1-58 Wolfcamp 12 mo.cum: 53 MBO; 125 MMcf Energen Katie 1-72 Wolfcamp 13 mo.cum: 69 MBO; 200 MMcf Note: All acreage at June 1, 2013. Well
information from public sources as of June 2013. Bone Spring / Upper Wolfcamp Type Log Bone Spring Lime 1st Bone Spring Sand 2nd Bone Spring Sand Wolfcamp 3rd Bone Spring Sand Avalon Shale Base Avalon Shale 29
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Haynesville & Cotton Valley Northwest Louisiana and East Texas
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Tier 1 Haynesville
and Elm Grove Cotton Valley Acreage Positions – Almost all prospective Haynesville acreage is HBP Note: All acreage at June 1, 2013 CADDO BOSSIER BIENVILLE RED RIVER DESOTO 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 L.A. Wildlife #1H MTDR Haynesville Williams (BLM) #1H TIER 1: 6 – 10+ Bcf TIER 2: 4 – 6 Bcf TIER 3: 2 – 4 Bcf
(1) Potential resource should not be considered proved natural gas reserves. Potential resource may be converted to proved natural gas reserves as a result of successful drilling operations and higher natural gas prices Note: Matador does not
include any of these potential resources in its proved natural gas reserves at March 31, 2013 31
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(CHART) 32
Haynesville Well Economics – Tier 1 Area Rate of Return, % Natural Gas Price, $/Mcf Note: Individual well economics only. D&C cost = drilling and completion cost. Natural gas price differential = ($0.85)/Mcf.
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33 Cotton Valley
Horizontal Well Economics Note: Individual well economics only. D&C cost = drilling and completion cost. Natural gas price differential = (10%) (CHART)
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Gracie Wyoming,
Utah and Idaho
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Matador Gracie
Project Total Prospect Acreage IDAHO UTAH WYOMING WYOMING IDAHO UTAH WYOMING 61,897 gross acres 30,492 net acres Crawford Federal #1H 35 Note: All acreage at June 1, 2013 Crawford Federal #1H completion scheduled for summer 2013
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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 TOCave 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 36
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Financial Overview
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38 2013 Revenue
and Adjusted EBITDA(1)(2) Estimated oil and natural gas revenues of $220 to $240 million Mid-point is an increase of 47% from $156.0 million in 2012 Estimated Adjusted EBITDA(1)(2) of $155 to $175 million Mid-point is an increase of 42% 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(3) Estimated average unit
costs per BOE Production taxes/marketing = $4.30 Lease operating = $9.50 G&A = $5.20 Operating cash costs, excluding interest = $19.00 DD&A = $30.00 2013 Financial Expectations (1) Adjusted EBITDA is a non-GAAP financial measure. For a
definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix (2) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of
production guidance range as updated on May 8, 2013. Guidance includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $99.00/Bbl
and $4.00/Mcf, respectively, for the period April through December 2013. (3) Consistent with updated guidance provided on May 8, 2013. Oil and Natural Gas Revenues(2) (millions) Adjusted EBITDA(1)(2) (millions) (CHART) (CHART)
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2013 Capital
Investment Plan Highlights 39 2013 projected capital expenditures of approximately $325 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 $40 million for land/seismic acquisition Compares to 2012 drilling program of 58 gross /
27.6 net wells for $334.6 million in capital expenditures, including 28 gross / 24.5 net Eagle Ford Shale wells 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 1.8 to 2.0 million barrels – mid-point up 58% 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(1) Oil and natural gas revenues of $220 to $240 million – mid-point up 47% from $156.0 million in 2012 Adjusted EBITDA(2) of $155 to $175 million – mid-point up 42% from $115.9 million in 2012 Total borrowings outstanding
estimated to be $320 to $330 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 less than 2x estimated 2013 operational cash flows Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of guidance range as updated on May 8, 2013. Guidance
includes actual results for 1Q 2013 and estimated results for the remainder of 2013. Estimated average realized prices for oil and natural gas used in these estimates were $99.00/Bbl and $4.00/Mcf, respectively, for the period April through December
2013. (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
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First Quarter 2013
Earnings Release Highlights 40 Production Growth Oil production of 460,000 Bbl for the quarter ended March 31, 2013, a year-over-year increase of 130% from 200,000 Bbl of oil produced in the quarter ended March 31, 2012 and a sequential
increase of 8% from 426,000 Bbl of oil produced in the quarter ended December 31, 2012 Average daily oil equivalent production of approximately 10,900 BOE per day for the quarter ended March 31, 2013, consisting of about 5,100 Bbl of oil
per day and 34.7 MMcf of natural gas per day, a year-over- year BOE increase of 36% from approximately 8,000 BOE per day, consisting of about 2,200 Bbl of oil per day and 34.9 MMcf of natural gas per day, for the quarter ended March 31, 2012
Financial Performance Total realized revenues of $59.7 million in the first quarter of 2013, including $0.4 million in realized gain on derivatives, a year-over-year increase of 85% from total realized revenues of $32.2 million, including $3.1
million in realized gain on derivatives, reported in the first quarter of 2012 Oil and natural gas revenues of $59.3 million for the quarter ended March 31, 2013, a year-over-year increase of 103% from $29.2 million reported for the quarter
ended March 31, 2012 Adjusted EBITDA(1) of $40.7 million for the quarter ended March 31, 2013, a year-over-year increase of 91% from $21.3 million reported for the quarter ended March 31, 2012 Acreage Acquisitions During March and
April 2013, acquired an additional 14,700 gross and 12,500 net acres in Lea and Eddy Counties, New Mexico Consider approximately 22,900 gross and 18,100 net acres to be prospective for multiple oil and liquids- rich targets, including the Wolfcamp
and Bone Spring play (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix
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41 Financial
Performance (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix (2) Includes
realized gain on derivatives Oil and Natural Gas Revenues ($ in mm) Total Realized Revenues(2) ($ in mm) Adjusted EBITDA(1) ($ in mm) Average Daily Production (BOE/d)
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42 2013 and 2014
Hedging Profile At May 8, 2013, Matador had: 1.08 million barrels of oil hedged for remainder of 2013 at weighted average floor and ceiling of $88/Bbl and $107/Bbl, respectively 5.8 Bcf of natural gas hedged for remainder of 2013 at
weighted average floor and ceiling of $3.25/MMBtu and $4.52/MMBtu, respectively 6.7 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.
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Reserves Summary
at March 31, 2013 43 Total proved reserves: 23.6 million BOE at March 31, 2013, including 10.7 million Bbl of oil and 77.5 Bcf of natural gas Oil reserves grew 88% to 10.7 million Bbl from 5.7 million Bbl at
March 31, 2012 PV-10(1) increased 33% to $438.1 million from $329.6 million at March 31, 2012, despite removal of close to 100 Bcf of proved undeveloped Haynesville shale gas reserves at June 30, 2012 Oil reserves comprised 45% (1 Bbl
= 6 Mcf basis) of total proved reserves at March 31, 2013, up from 17% at March 31, 2012 Eagle Ford reserves comprised 93% of total PV-10(1) at March 31, 2013 as compared to 74% at March 31, 2012 and 93% at December 31, 2012
Sequential growth: Proved developed oil reserves grew 13% to 5.4 million Bbl at March 31, 2013 from 4.8 million Bbl at December 31, 2012 PV-10(1) increased 4% to $438.1 million at March 31, 2013 from $423.2 million at
December 31, 2012 (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix
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Appendix
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Board of Directors
and Special Board Advisors – Expertise and Stewardship 45 45
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Proven Management
Team – Experienced Leadership 46 Management Team Background and Prior Affiliations Industry Experience Matador Experience Joseph Wm. ForanFounder, Chairman and CEO Matador Petroleum Corporation, Foran Oil Company, J Cleo Thompson Jr. and
Thompson Petroleum Corp. 33 years Since Inception David E. LancasterEVP and COO Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 34 years Since 2003 Matthew V. HairfordEVP and Head of Operations— Samson, Sonat,
Conoco 29 years Since 2004 David F. NicklinExecutive Director of Exploration— ARCO, Senior Geological Assignments in UK, Angola, Norway and the Middle East 42 years Since 2007 Bradley M. RobinsonVP and CTO— Schlumberger, S.A.
Holditch & Associates, Inc., Marathon 36 years Since Inception Craig N. AdamsVP and General Counsel— Baker Botts L.L.P., Thompson & Knight LLP 20 years Since 2012 Ryan C. LondonVP and General Manager—Matador
Resources Company 9 years Since 2003 Kathryn L. WayneController and Treasurer—Matador Petroleum Corporation, Mobil 28 years Since Inception
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South Texas:
Pearsall Play Anadarko Newfield Chesapeake Shell Gas Activity Top Pearsall Depth Map CI = 500’ Cheyenne Indio Tanks Horiz. program 4 horizs w/ 450 to 700 Bbl/d (all wells) Plus 4 to 6 MMcf/d 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 CHK – Brownlow #1H Could not test Liquid potential increases CHK—Avant D #1H Suspended, waiting on further completion work Cabot/Osaka JV Osaka 35%
($14,285/ac. – $17,500/ac.) 6 Horiz. Drilled 3 Permits Schorp-White Ranch #101H 1st full mo. – 4,535 Bbl, 43 MMcf RH Pickens #101H 1st full mo. – 5,339 Bbl, 16 MMcf Chiliptin #101H IP: 670 Bbl/d, 761 Mcf/d 18/64” CHK –
Wilson C #1H IP: 920 Mcf/d, 93 Bbl/d Abandoned for EGFD Cheyenne Rockin S #1H Completed 12-21-2012 Valence Oper. 4 drilling wells and 2 Permits Murray #1H IP: 258 Bbl/d, 106 Mcf/d Completed—Jan ‘13 Rosetta Tom Hanks #1 Completed and
waiting on hook-up. EOG Tests 500 – 2000 Bbl/mo. Temp. Abnd. or EGFD Horiz. EOG Robert Hindes #1H IP: 263 Bbl/d, 4.3 MMCF/d 26/64” w/ 1977 Ftp 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 47 Note: All acreage at June 1, 2013. Well data from public information as of June 2013.
Searchable text for slide0048:
48 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 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 reconciliation without undue hardship because the
forward-looking Adjusted EBITDA numbers included in this investor presentation 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.
Searchable text for slide0049:
49 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.
Searchable text for slide0050:
50 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. The PV-10 at March 31, 2013, December 31, 2012, March 31, 2012, December 31,
2011, December 31, 2010, December 31, 2009 and December 31, 2008 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by reducing PV-10 by the discounted future income taxes
associated with such reserves. The discounted future income taxes at March 31, 2013, December 31, 2012, March 31, 2012, December 31, 2011, December 31, 2010, December 31, 2009 and
December 31, 2008 were, in millions, $31.1, $28.6, $42.2, $33.2, $8.8, $5.3 and $0.8 respectively. We have not provided a reconciliation of PV-10 to Standardized Measure where references are forward- looking, estimates or prospective in nature.
We could not provide such a reconciliation without undue hardship on account of many unknown variables for the reconciling items. We have not provided a reconciliation of PV-10 to Standardized Measure with respect to proved producing reserves
because such PV- 10 values are subsets of the PV-10 of our total proved reserves.