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Texas
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001-35410
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27-4662601
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(State or other jurisdiction
of incorporation)
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(Commission
File Number)
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(IRS Employer
Identification No.)
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5400 LBJ Freeway, Suite 1500, Dallas, Texas
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75240
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(Address of principal executive offices)
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(Zip Code)
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o
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Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
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o
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Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
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o
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Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
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o
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Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
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Item 1.01
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Entry into a Material Definitive Agreement.
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Item 2.02
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Results of Operations and Financial Condition.
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Item 2.03
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Creation of a Direct Financial Obligation or an Obligation Under an Off-Balance Sheet Arrangement of a Registrant.
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Item 7.01
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Regulation FD Disclosure.
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Item 9.01
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Financial Statements and Exhibits.
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Exhibit No.
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Description of Exhibit
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10.1
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99.1
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MATADOR RESOURCES COMPANY
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Date: November 1, 2018
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By:
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/s/ Craig N. Adams
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Name:
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Craig N. Adams
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Title:
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Executive Vice President
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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/ Don J. McKinnerney
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Name:
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Don J. McKinnerney
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Title:
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Authorized Signatory
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BANK OF AMERICA, N.A.,
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as a Lender
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By:
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/s/ Raza Jafferi
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Name:
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Raza Jafferi
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Title:
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Director
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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/ Jeffrey M. LaBauve
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Name:
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Jeffrey M. LaBauve
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Title:
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Vice President
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SUNTRUST BANK,
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as a Lender
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By:
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/s/ Benjamin L. Brown
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Name:
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Benjamin L. Brown
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Title:
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Director
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THE BANK OF NOVA SCOTIA, HOUSTON
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BRANCH
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as a Lender
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By:
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/s/ Ryan Knape
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Name:
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RYAN KNAPE
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Title:
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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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Managing Director
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IBERIABANK,
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as a Lender
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By:
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/s/ Moni Collins
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Name:
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Moni Collins
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Title:
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Senior Vice President
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CANADIAN IMPERIAL BANK OF
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COMMERCE, NEW YORK BRANCH,
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as a Lender
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By:
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/s/ Trudy Nelson
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Name:
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Trudy Nelson
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Title:
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Authorized Signatory
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By:
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/s/ Megan Larson
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Name:
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Megan Larson
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Title:
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Authorized Signatory
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THE HUNTINGTON NATIONAL BANK,
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as a Lender
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By:
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/s/ Cameron Hinojosa
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Name:
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Cameron Hinojosa
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Title:
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Vice President
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WELLS FARGO BANK, N.A.,
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as the Departing Lender
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By:
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/s/ Matthew W. Coleman
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Name:
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Matthew W. Coleman
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Title:
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Director
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GUARANTORS:
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MATADOR RESOURCES COMPANY
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MRC ENERGY SOUTHEAST COMPANY, LLC
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MRC ENERGY SOUTH TEXAS COMPANY, LLC
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MRC PERMIAN COMPANY
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MRC ROCKIES COMPANY
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MATADOR PRODUCTION COMPANY
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LONGWOOD GATHERING AND DISPOSAL SYSTEMS GP, INC.
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DELAWARE WATER MANAGEMENT COMPANY, LLC
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LONGWOOD MIDSTREAM DELAWARE, LLC
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LONGWOOD MIDSTREAM HOLDINGS, LLC
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LONGWOOD MIDSTREAM SOUTHEAST, LLC
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LONGWOOD MIDSTREAM SOUTH TEXAS, LLC
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SOUTHEAST WATER MANAGEMENT COMPANY, LLC
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MRC DELAWARE RESOURCES, LLC
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MRC PERMIAN LKE COMPANY, LLC
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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 DISPOSAL SYSTEMS, LP
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By:
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Longwood Gathering and Disposal 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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Basis for Pricing
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Level I
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Level II
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Level III
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Level IV
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Level V
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Borrowing Base Utilization*
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< 25%
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≥ 25% but
< 50%
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≥ 50% but
< 75%
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≥ 75% but
< 90%
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≥ 90% but
<
100%
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Revolving Credit Eurodollar Margin
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125
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150
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175
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200
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225
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Revolving Credit Base Rate Margin
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25
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50
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75
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100
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125
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Commitment Fees
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37.5
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37.5
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50
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50
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50
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Letter of Credit Fees (exclusive of fronting fees)
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125
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150
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175
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200
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225
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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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$70,000,000.00
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14.000000000%
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The Bank of Nova Scotia, Houston Branch
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$66,666,666.67
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13.333333333%
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Bank of America, N.A.
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$66,666,666.67
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13.333333333%
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BMO Harris Financing, Inc.
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$66,666,666.67
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13.333333333%
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Suntrust Bank
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$60,000,000.00
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12.000000000%
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Comerica Bank
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$60,000,000.00
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12.000000000%
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Canadian Imperial Bank of Commerce, New York Branch
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$60,000,000.00
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12.000000000%
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IBERIABANK
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$25,000,000.00
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5.000000000%
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The Huntington National Bank
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$25,000,000.00
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5.000000000%
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TOTALS
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$500,000,000.00
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100.000000000%
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Total Debt to Consolidated EBITDA Ratio
(Section 7.9)
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A.
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The amount equal to (i) total Debt of Parent and its Subsidiaries (other than Unrestricted Subsidiaries) determined on a consolidated basis in accordance with GAAP minus (ii) unrestricted cash and cash equivalents of the Parent and its Subsidiaries (other than Unrestricted Subsidiaries) as of the last day of such Test Period; provided that the aggregate amount of cash and cash equivalents shall not exceed $50,000,000 for purposes of this clause (ii):
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1.
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All obligations of such Person for borrowed money or evidenced by bonds, debentures, notes or other similar instruments (including principal, but excluding interest, fees and charges):
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$
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2.
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All obligations of such Person (whether contingent or otherwise) in respect of bankers’ acceptances, letters of credit, surety or other bonds and similar instruments:
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$
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3.
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All obligations of such Person to pay the deferred purchase price of property or services (other than for borrowed money and other than accounts payable (for the deferred purchase price of property or services) from time to time incurred in the ordinary course of business which, if greater than ninety (90) days past the invoice or billing date, are being contested in good faith by appropriate proceedings and for which reserves adequate under GAAP shall have been established therefor):
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$
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4.
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All obligations under leases which shall have been, or should have been, in accordance with GAAP, recorded as capital leases in respect of which such Person is liable (whether contingent or otherwise including principal but excluding interest, fees and charges):
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$
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5.
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All obligations under operating leases which require such Person or its Affiliate to make payments over the term of such lease, including payments at termination, based on the purchase price or appraisal value of the Property subject to such lease plus a marginal interest rate, and used primarily as a financing vehicle for, or to monetize, such Property:
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$
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6.
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All Debt (as described in the other clauses of this certificate) of others secured by a Lien on any asset of such Person, whether or not such Debt is assumed by such Person, but valued at the lesser of (x) the amount of such Debt and (y) the fair market value of the property securing such Debt:
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$
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7.
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All Debt (as described in the other clauses of this certificate) and other obligations of others guaranteed by such Person or in which such Person otherwise assures a creditor against loss of the debtor or obligations of others:
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$
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8.
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All obligations or undertakings of such Person to maintain or cause to be maintained the financial position or covenants of others or to purchase the Debt of others:
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$
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•
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Third quarter 2018 average daily oil equivalent production increased 3% sequentially to a record quarterly high for the Company of 54,600 barrels of oil equivalent (“BOE”) per day (59% oil) as compared to the second quarter of 2018. Average daily oil production increased 9% sequentially to 32,300 barrels per day and average daily natural gas production decreased 4% sequentially to 133.8 million cubic feet per day, each as compared to the second quarter of 2018.
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•
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Third quarter 2018 Delaware Basin average daily oil equivalent production increased 3% sequentially to a record quarterly high for the Company of 47,800 BOE per day (63% oil) as compared to the second quarter of 2018. Delaware Basin average daily oil production increased 9% sequentially to 29,900 barrels per day and Delaware Basin average daily natural gas production decreased 6% sequentially to 107.4 million cubic feet per day, each as compared to the second quarter of 2018.
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•
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Third quarter 2018 net income (GAAP basis) was $17.8 million, or $0.15 per diluted common share, a decrease of $42.0 million, or 70%, from the second quarter of 2018, and a year-over-year increase of 18% from $15.0 million in the third quarter of 2017. On a GAAP basis, third quarter 2018 net income was negatively impacted by charges of $52.6 million associated with a non-cash unrealized loss on derivatives of $21.3 million and a prepayment premium of $31.2 million resulting from the redemption and refinancing of the Company’s senior unsecured notes during the third quarter.
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•
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Third quarter 2018 adjusted net income (a non-GAAP financial measure) was $55.7 million, or $0.48 per diluted common share, a sequential increase of 21% from $46.1 million in the second quarter of 2018, and a year-over-year increase of 213% from $17.8 million in the third quarter of 2017.
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•
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Third quarter 2018 adjusted earnings before interest expense, income taxes, depletion, depreciation and amortization and certain other items (“Adjusted EBITDA,” a non-GAAP financial measure) were $155.4 million, a sequential increase of 13% from $137.3 million in the second quarter of 2018, and a year-over-year increase of 83% from $84.8 million in the third quarter of 2017.
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•
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In September 2018, Matador successfully acquired approximately 8,400 gross/net leasehold acres for approximately $387 million, or a weighted average cost of approximately $46,000 per net acre, in Lea and Eddy Counties, New Mexico in the Bureau of Land Management New Mexico Oil and Gas Lease Sale (the “BLM Acquisition” or the “BLM Lease Sale”). The Company believes that portions of the BLM Acquisition include some of the most prospective acreage in the Delaware Basin, with the potential to develop as many as seven to nine different formations in certain tracts (please see Matador’s September 12, 2018 press release for additional information).
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•
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In August 2018, Matador closed a private offering of $750 million of 5.875% senior unsecured notes due 2026. A portion of the net proceeds were used to purchase and redeem the entire $575 million aggregate principal amount of its 6.875% senior unsecured notes due 2023. In early October 2018, Matador closed a private
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•
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In mid-October 2018, a subsidiary of San Mateo Midstream, LLC (“San Mateo”), the Company’s midstream joint venture, entered into a long-term agreement with a producer in Eddy County, New Mexico for the gathering and processing of such producer’s natural gas. As a result of this agreement, along with others entered into by San Mateo with Matador and other customers, San Mateo has entered into contracts to provide firm gathering and processing for over 200 million cubic feet of natural gas per day, or over 80% of the designed inlet capacity of 260 million cubic feet of natural gas per day at its Black River cryogenic natural gas processing plant (the “Black River Processing Plant”) in the Rustler Breaks asset area in Eddy County, New Mexico (please see Matador’s October 16, 2018 press release for additional information).
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•
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In late October 2018, Matador and its lenders amended the Company’s revolving credit agreement to, among other items, (i) increase the maximum facility size from $500 million to $1.5 billion, (ii) increase the borrowing base from $725 million to $850 million, (iii) increase the elected borrowing commitment from $400 million to $500 million, (iv) extend the maturity of the credit agreement from October 2020 to October 2023 and (v) reduce borrowing rates by 0.25% per annum.
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•
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The Strong 14-24S-33E AR #214H (Strong #214H) well (turned to sales early in October 2018), Matador’s second Wolfcamp A-Lower test in its Antelope Ridge asset area, flowed 3,670 BOE/d (77% oil), or 760 BOE per day per thousand feet of completed lateral, during a 24-hour initial potential (“IP”) test. The Strong #214H well was Matador’s best 24-hour IP test in the Delaware Basin to date and was a successful follow-up to Matador’s initial Wolfcamp A-Lower well in the Antelope Ridge asset area, the Leo Thorsness 13-24S-33E AR #211H (Leo Thorsness #211H) well, which flowed 2,906 BOE/d (72% oil) during a 24-hour IP test. The Leo Thorsness #211H well has produced approximately 250,000 BOE (73% oil) in its first seven months of production.
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•
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The Irvin Wall State Com #131H well, Matador’s initial Third Bone Spring test in its Antelope Ridge asset area, flowed 2,343 BOE/d (81% oil), or 511 BOE per day per thousand feet of completed lateral, during a 24-hour IP test. This initial test of the Third Bone Spring marks the fourth successful completion target for Matador in the Antelope Ridge asset area, including the First Bone Spring, the Wolfcamp A-XY and the Wolfcamp A-Lower.
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•
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The David Edelstein State Com #203H (Edelstein #203H) well, Matador’s first operated two-mile horizontal well in the Delaware Basin, a Wolfcamp A-XY completion in its Rustler Breaks asset area, flowed 2,378 BOE per day (77% oil), or 247 BOE per day per thousand feet of completed lateral, during a 24-hour IP test. The Edelstein #203H well produced approximately 140,000 BOE (76% oil) in its first three months of production (approximately 1,550 BOE per day). The well continues to clean up and has exhibited a shallower production decline than observed in most of Matador’s one-mile lateral completions in the Rustler Breaks asset area.
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Three Months Ended
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September 30, 2018
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June 30, 2018
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September 30, 2017
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Net Production Volumes:
(1)
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Oil (MBbl)
(2)
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2,973
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2,706
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2,166
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Natural gas (Bcf)
(3)
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12.3
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12.7
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10.2
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Total oil equivalent (MBOE)
(4)
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5,025
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4,817
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3,860
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Average Daily Production Volumes:
(1)
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Oil (Bbl/d)
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32,317
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29,740
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23,538
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Natural gas (MMcf/d)
(5)
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133.8
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139.2
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110.5
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Total oil equivalent (BOE/d)
(6)
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54,625
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52,937
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41,954
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Average Sales Prices:
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Oil, without realized derivatives (per Bbl)
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$
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57.15
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$
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61.44
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$
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46.25
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Oil, with realized derivatives (per Bbl)
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$
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58.97
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$
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60.52
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$
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46.47
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Natural gas, without realized derivatives (per Mcf)
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$
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3.77
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$
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3.38
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$
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3.42
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Natural gas, with realized derivatives (per Mcf)
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$
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3.77
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$
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3.38
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$
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3.42
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Revenues (millions):
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Oil and natural gas revenues
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$
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216.3
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$
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209.0
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$
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134.9
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Third-party midstream services revenues
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$
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6.8
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$
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3.4
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$
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3.2
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Realized gain (loss) on derivatives
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$
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5.4
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$
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(2.5
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)
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$
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0.5
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Operating Expenses (per BOE):
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||||||
Production taxes, transportation and processing
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$
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4.02
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$
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4.17
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$
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4.06
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Lease operating
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$
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4.48
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$
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5.19
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$
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4.32
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Plant and other midstream services operating
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$
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1.45
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$
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1.18
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$
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0.80
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Depletion, depreciation and amortization
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$
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14.02
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$
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13.87
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$
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12.38
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General and administrative
(7)
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$
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3.67
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$
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4.02
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|
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$
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4.19
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Total
(8)
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$
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27.64
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$
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28.43
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$
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25.75
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|
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Net income (millions)
(9)
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$
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17.8
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$
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59.8
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$
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15.0
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Earnings per common share (diluted)
(9)
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$
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0.15
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$
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0.53
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$
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0.15
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Adjusted net income (millions)
(9)(10)
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$
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55.7
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$
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46.1
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$
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17.8
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Adjusted earnings per common share (diluted)
(9)(11)
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$
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0.48
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$
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0.41
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$
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0.18
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Adjusted EBITDA (millions)
(9)(12)
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$
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155.4
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$
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137.3
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$
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84.8
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|
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Completion
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24-hr IP
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BOE/d /
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Oil
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|
Asset Area/Well Name
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Interval
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(BOE/d)
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1,000 ft.
(1)
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(%)
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Comments
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Antelope Ridge, Lea County, NM
|
|
|
|
|
|
Strong 14-24S-33E AR #214H
|
Wolfcamp
A-Lower
|
3,670
|
760
|
77%
|
Second excellent Wolfcamp A-Lower result in the Antelope Ridge asset area.
Matador’s best 24-hr IP in the Delaware Basin
.
|
Leslie Federal 17-25S-35E AR #214H
|
Wolfcamp
A-Lower |
2,322
|
535
|
85%
|
Third strong Wolfcamp A-Lower result.
|
Irvin Wall State Com #131H
|
Third Bone Spring
|
2,343
|
511
|
81%
|
Very encouraging initial Third Bone Spring result in the Antelope Ridge asset area.
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Rustler Breaks, Eddy County, NM
|
|
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David Edelstein State Com #203H
|
Wolfcamp
A-XY
|
2,378
|
247
|
77%
|
Matador’s first operated 2-mile lateral well in the Rustler Breaks asset area;
90-day average production of 1,550 BOE/d
.
|
Brantley State Com 13-24S-27E RB #205H
|
Wolfcamp
A-XY |
1,917
|
418
|
81%
|
Another strong Wolfcamp A-XY result in the Rustler Breaks asset area.
|
Wolf, Loving County, TX
|
|
|
|
|
|
Clare Glassell 71-TTT-B01 #204H
|
Wolfcamp
A-XY |
1,801
|
387
|
54%
|
Another excellent Wolfcamp A-XY well completed in the southern portion of the Wolf asset area.
|
•
|
As noted earlier in this release, in October 2018, a subsidiary of San Mateo entered into a long-term agreement with a producer in Eddy County, New Mexico for the gathering and processing of such producer’s natural gas.
|
•
|
During the third quarter of 2018, San Mateo completed its fourth and fifth commercial salt water disposal wells in the Rustler Breaks asset area in Eddy County, New Mexico, resulting in a total of eight commercial salt water disposal wells (five in the Rustler Breaks asset area and three in the Wolf asset area) and approximately 225,000 barrels per day of total designed salt water disposal capacity. San Mateo expects to dispose of over 200,000 barrels per day of salt water as early as the first quarter of 2019, which includes expected volumes from Matador and San Mateo’s other contracted producers in Eddy County, New Mexico and Loving County, Texas.
|
•
|
During the third quarter of 2018, San Mateo completed its oil gathering system in the Rustler Breaks asset area in Eddy County, New Mexico. The Eddy County oil gathering system and an associated San Mateo oil gathering facility are expected to be connected to an extension of an existing pipeline belonging to a subsidiary of Plains All American Pipeline, L.P. (NYSE: PAA) (“Plains”) being built northward from the Texas state line to Matador’s Rustler Breaks asset area. San Mateo anticipates that the Plains connection to its Eddy County gathering system will be completed in December 2018.
|
•
|
Production taxes, transportation and processing expenses decreased 4% sequentially from $4.17 per BOE in the second quarter of 2018 to $4.02 per BOE in the third quarter of 2018. This decrease was primarily attributable to a reduction in transportation and processing expenses in the Rustler Breaks asset area in the third quarter of 2018 as a result of the expansion of the Black River Processing Plant earlier in the year.
|
•
|
Lease operating expenses per BOE decreased 14% from $5.19 per BOE in the second quarter of 2018 to $4.48 per BOE in the third quarter of 2018. This decrease was primarily attributable to additional volumes of salt water being transported and disposed of via pipeline during the third quarter of 2018, as compared to the second quarter of 2018. Lease operating expenses of $4.48 per BOE were well below the Company’s estimates for the quarter and also reflected fewer workover and maintenance expenses in the third quarter. Matador anticipates that its lease operating expenses on a unit-of-production basis may increase during the fourth quarter of 2018 to levels observed earlier in the year as a result of additional workover and maintenance operations in progress and the onset of fall and winter weather.
|
•
|
General and administrative expenses per BOE decreased 9% from $4.02 per BOE in the second quarter of 2018 to $3.67 per BOE in the third quarter of 2018, better than the Company’s expectations. This decrease resulted from general and administrative expenses capitalized in connection with certain midstream projects and also reflected the 3% increase in quarterly total oil equivalent production
. General and administrative expenses of $3.67 per BOE were the lowest in any quarter since the fourth quarter of 2012.
|
•
|
Depletion, depreciation and amortization expenses per BOE increased 1% sequentially from $13.87 per BOE in the second quarter of 2018 to $14.02 per BOE in the third quarter of 2018. This slight increase was primarily attributable to a small increase in anticipated future development costs associated with the Company’s proved undeveloped reserves at September 30, 2018. Depreciation expenses of $2.6 million, or $0.52 per BOE, associated with midstream operations were also included in the total third quarter depletion, depreciation and amortization expenses.
|
|
Operated
|
|
Non-Operated
|
|
Total
|
Gross Operated
|
|||
Asset/Operating Area
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
Well Completion Intervals
|
Rustler Breaks
|
13
|
10.5
|
|
13
|
1.2
|
|
26
|
11.7
|
2-2BS, 8-WC A-XY, 2-WC A-Lower,
1-WC B-Blair
|
Arrowhead
|
1
|
0.8
|
|
-
|
-
|
|
1
|
0.8
|
1-WC A-XY
|
Ranger
|
-
|
-
|
|
1
|
0.4
|
|
1
|
0.4
|
|
Wolf/Jackson Trust
|
2
|
1.0
|
|
-
|
-
|
|
2
|
1.0
|
1-WC A-XY, 1-WC B
|
Twin Lakes
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
Antelope Ridge
|
3
|
2.7
|
|
3
|
-
|
|
6
|
2.7
|
1-3BS, 2-WC A-Lower
|
Delaware Basin
|
19
|
15.0
|
|
17
|
1.6
|
|
36
|
16.6
|
Six separate intervals tested in Q3 2018
|
Eagle Ford Shale
|
-
|
-
|
|
2
|
0.3
|
|
2
|
0.3
|
|
Haynesville Shale
|
-
|
-
|
|
-
|
-
|
|
-
|
-
|
|
Total
|
19
|
15.0
|
|
19
|
1.9
|
|
38
|
16.9
|
|
|
|
Weighted Average
Price Floor
($/Bbl or $/MMBtu)
|
|
Weighted Average Price Ceiling
($/Bbl or $/MMBtu)
|
|
Volume Hedged
(Bbl or MMBtu)
|
|
2-Way Costless Collars
|
|
|
|
|
|
|
|
Oil (WTI)
|
|
$44.27
|
|
$60.29
|
|
720,000
|
|
Oil (LLS)
|
|
$45.00
|
|
$63.05
|
|
180,000
|
|
Natural Gas
|
|
$2.58
|
|
$3.67
|
|
4,200,000
|
|
|
|
Weighted Average
Price Floor
($/Bbl)
|
|
Weighted Average Price (Short Call) ($/Bbl)
|
|
Weighted Average Price (Long Call) ($/Bbl)
|
|
Volume Hedged
(Bbl)
|
|
3-Way Costless Collars
|
|
|
|
|
|
|
|
|
|
Oil (WTI)
|
|
$50.08
|
|
$63.50
|
|
$66.68
|
|
480,000
|
|
|
|
Weighted Average Price
($/Bbl)
|
|
Volume Hedged
(Bbl)
|
|
Oil Basis Swaps
|
|
|
|
|
|
Midland-Cushing Oil Basis Differential
|
|
($1.02)
|
|
1,305,000
|
|
|
|
Weighted Average
Price Floor
($/Bbl)
|
|
Weighted Average Price Ceiling
($/Bbl)
|
|
Volume Hedged
(Bbl)
|
|
2-Way Costless Collars
|
|
|
|
|
|
|
|
Oil (WTI)
|
|
$53.55
|
|
$72.22
|
|
3,720,000
|
|
|
|
Weighted Average
Price Floor
($/Bbl)
|
|
Weighted Average Price (Short Call) ($/Bbl)
|
|
Weighted Average Price (Long Call) ($/Bbl)
|
|
Volume Hedged
(Bbl)
|
|
3-Way Costless Collars
|
|
|
|
|
|
|
|
|
|
Oil (WTI)
|
|
$60.00
|
|
$75.00
|
|
$78.85
|
|
1,320,000
|
|
|
|
Weighted Average Price
($/Bbl)
|
|
Volume Hedged
(Bbl)
|
|
Oil Basis Swaps
|
|
|
|
|
|
Midland-Cushing Oil Basis Differential
|
|
($0.15)
|
|
1,200,000
|
|
(In thousands, except par value and share data)
|
September 30,
2018 |
|
December 31,
2017 |
|
|||||
|
ASSETS
|
|
|
|
|
||||
|
Current assets
|
|
|
|
|
||||
|
Cash
|
$
|
45,942
|
|
|
$
|
96,505
|
|
|
|
Restricted cash
|
7,066
|
|
|
5,977
|
|
|
||
|
Accounts receivable
|
|
|
|
|
||||
|
Oil and natural gas revenues
|
81,422
|
|
|
65,962
|
|
|
||
|
Joint interest billings
|
55,390
|
|
|
67,225
|
|
|
||
|
Other
|
10,060
|
|
|
8,031
|
|
|
||
|
Derivative instruments
|
4
|
|
|
1,190
|
|
|
||
|
Lease and well equipment inventory
|
18,758
|
|
|
5,993
|
|
|
||
|
Prepaid expenses and other assets
|
6,790
|
|
|
6,287
|
|
|
||
|
Total current assets
|
225,432
|
|
|
257,170
|
|
|
||
|
Property and equipment, at cost
|
|
|
|
|
||||
|
Oil and natural gas properties, full-cost method
|
|
|
|
|
||||
|
Evaluated
|
3,506,479
|
|
|
3,004,770
|
|
|
||
|
Unproved and unevaluated
|
1,241,529
|
|
|
637,396
|
|
|
||
|
Midstream and other property and equipment
|
408,436
|
|
|
281,096
|
|
|
||
|
Less accumulated depletion, depreciation and amortization
|
(2,234,470
|
)
|
|
(2,041,806
|
)
|
|
||
|
Net property and equipment
|
2,921,974
|
|
|
1,881,456
|
|
|
||
|
Other assets
|
6,796
|
|
|
7,064
|
|
|
||
|
Total assets
|
$
|
3,154,202
|
|
|
$
|
2,145,690
|
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
||||
|
Current liabilities
|
|
|
|
|
||||
|
Accounts payable
|
$
|
32,491
|
|
|
$
|
11,757
|
|
|
|
Accrued liabilities
|
178,830
|
|
|
174,348
|
|
|
||
|
Royalties payable
|
67,023
|
|
|
61,358
|
|
|
||
|
Amounts due to affiliates
|
12,998
|
|
|
10,302
|
|
|
||
|
Derivative instruments
|
19,740
|
|
|
16,429
|
|
|
||
|
Advances from joint interest owners
|
12,354
|
|
|
2,789
|
|
|
||
|
Amounts due to joint ventures
|
2,373
|
|
|
4,873
|
|
|
||
|
Other current liabilities
|
942
|
|
|
750
|
|
|
||
|
Total current liabilities
|
326,751
|
|
|
282,606
|
|
|
||
|
Long-term liabilities
|
|
|
|
|
||||
|
Borrowings under Credit Agreement
|
325,000
|
|
|
—
|
|
|
||
|
Senior unsecured notes payable
|
740,063
|
|
|
574,073
|
|
|
||
|
Asset retirement obligations
|
28,706
|
|
|
25,080
|
|
|
||
|
Derivative instruments
|
4,996
|
|
|
—
|
|
|
||
|
Other long-term liabilities
|
6,243
|
|
|
6,385
|
|
|
||
|
Total long-term liabilities
|
1,105,008
|
|
|
605,538
|
|
|
||
|
Shareholders’ equity
|
|
|
|
|
||||
|
Common stock - $0.01 par value, 160,000,000 shares authorized; 116,506,743 and 108,513,597 shares issued; and 116,348,548 and 108,510,160 shares outstanding, respectively
|
1,165
|
|
|
1,085
|
|
|
||
|
Additional paid-in capital
|
1,923,030
|
|
|
1,666,024
|
|
|
||
|
Accumulated deficit
|
(372,990
|
)
|
|
(510,484
|
)
|
|
||
|
Treasury stock, at cost, 158,195 and 3,437 shares, respectively
|
(4,039
|
)
|
|
(69
|
)
|
|
||
|
Total Matador Resources Company shareholders’ equity
|
1,547,166
|
|
|
1,156,556
|
|
|
||
|
Non-controlling interest in subsidiaries
|
175,277
|
|
|
100,990
|
|
|
||
|
Total shareholders’ equity
|
1,722,443
|
|
|
1,257,546
|
|
|
||
|
Total liabilities and shareholders’ equity
|
$
|
3,154,202
|
|
|
$
|
2,145,690
|
|
|
|
|
|
|
|
|
(In thousands, except per share data)
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
|
|||||||||||||
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
||||||||
|
Revenues
|
|
|
|
|
|
|
|
|
||||||||
|
Oil and natural gas revenues
|
$
|
216,282
|
|
|
$
|
134,948
|
|
|
$
|
607,255
|
|
|
$
|
363,559
|
|
|
|
Third-party midstream services revenues
|
6,809
|
|
|
3,218
|
|
|
13,284
|
|
|
6,871
|
|
|
||||
|
Realized gain (loss) on derivatives
|
5,424
|
|
|
485
|
|
|
(1,322
|
)
|
|
(1,176
|
)
|
|
||||
|
Unrealized (loss) gain on derivatives
|
(21,337
|
)
|
|
(12,372
|
)
|
|
(9,492
|
)
|
|
21,449
|
|
|
||||
|
Total revenues
|
207,178
|
|
|
126,279
|
|
|
609,725
|
|
|
390,703
|
|
|
||||
|
Expenses
|
|
|
|
|
|
|
|
|
||||||||
|
Production taxes, transportation and processing
|
20,215
|
|
|
15,666
|
|
|
58,116
|
|
|
40,348
|
|
|
||||
|
Lease operating
|
22,531
|
|
|
16,689
|
|
|
69,685
|
|
|
48,486
|
|
|
||||
|
Plant and other midstream services operating
|
7,291
|
|
|
3,096
|
|
|
17,187
|
|
|
8,379
|
|
|
||||
|
Depletion, depreciation and amortization
|
70,457
|
|
|
47,800
|
|
|
192,664
|
|
|
123,066
|
|
|
||||
|
Accretion of asset retirement obligations
|
387
|
|
|
323
|
|
|
1,126
|
|
|
937
|
|
|
||||
|
General and administrative
|
18,444
|
|
|
16,156
|
|
|
55,739
|
|
|
49,671
|
|
|
||||
|
Total expenses
|
139,325
|
|
|
99,730
|
|
|
394,517
|
|
|
270,887
|
|
|
||||
|
Operating income
|
67,853
|
|
|
26,549
|
|
|
215,208
|
|
|
119,816
|
|
|
||||
|
Other income (expense)
|
|
|
|
|
|
|
|
|
||||||||
|
Net (loss) gain on asset sales and inventory impairment
|
(196
|
)
|
|
16
|
|
|
(196
|
)
|
|
23
|
|
|
||||
|
Interest expense
|
(10,340
|
)
|
|
(8,550
|
)
|
|
(26,835
|
)
|
|
(26,229
|
)
|
|
||||
|
Prepayment premium on extinguishment of debt
|
(31,226
|
)
|
|
—
|
|
|
(31,226
|
)
|
|
—
|
|
|
||||
|
Other (expense) income
|
(976
|
)
|
|
(36
|
)
|
|
(1,275
|
)
|
|
1,956
|
|
|
||||
|
Total other expense
|
(42,738
|
)
|
|
(8,570
|
)
|
|
(59,532
|
)
|
|
(24,250
|
)
|
|
||||
|
Net income
|
25,115
|
|
|
17,979
|
|
|
155,676
|
|
|
95,566
|
|
|
||||
|
Net income attributable to non-controlling interest in subsidiaries
|
(7,321
|
)
|
|
(2,940
|
)
|
|
(18,182
|
)
|
|
(8,034
|
)
|
|
||||
|
Net income attributable to Matador Resources Company shareholders
|
$
|
17,794
|
|
|
$
|
15,039
|
|
|
$
|
137,494
|
|
|
$
|
87,532
|
|
|
|
Earnings per common share
|
|
|
|
|
|
|
|
|
||||||||
|
Basic
|
$
|
0.15
|
|
|
$
|
0.15
|
|
|
$
|
1.22
|
|
|
$
|
0.87
|
|
|
|
Diluted
|
$
|
0.15
|
|
|
$
|
0.15
|
|
|
$
|
1.21
|
|
|
$
|
0.87
|
|
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
||||||||
|
Basic
|
116,358
|
|
|
100,365
|
|
|
112,659
|
|
|
100,141
|
|
|
||||
|
Diluted
|
116,912
|
|
|
100,504
|
|
|
113,208
|
|
|
100,580
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
Nine Months Ended
September 30, |
|
|||||||
|
|
2018
|
|
2017
|
|
||||
|
Operating activities
|
|
|
|
|
||||
|
Net income
|
$
|
155,676
|
|
|
$
|
95,566
|
|
|
|
Adjustments to reconcile net income to net cash provided by operating activities
|
|
|
|
|
||||
|
Unrealized loss (gain) on derivatives
|
9,492
|
|
|
(21,449
|
)
|
|
||
|
Depletion, depreciation and amortization
|
192,664
|
|
|
123,066
|
|
|
||
|
Accretion of asset retirement obligations
|
1,126
|
|
|
937
|
|
|
||
|
Stock-based compensation expense
|
13,787
|
|
|
12,488
|
|
|
||
|
Prepayment premium on extinguishment of debt
|
31,226
|
|
|
—
|
|
|
||
|
Amortization of debt issuance cost
|
851
|
|
|
103
|
|
|
||
|
Net loss (gain) on asset sales and inventory impairment
|
196
|
|
|
(23
|
)
|
|
||
|
Changes in operating assets and liabilities
|
|
|
|
|
||||
|
Accounts receivable
|
(5,654
|
)
|
|
(50,343
|
)
|
|
||
|
Lease and well equipment inventory
|
(15,347
|
)
|
|
(1,666
|
)
|
|
||
|
Prepaid expenses
|
(502
|
)
|
|
(2,224
|
)
|
|
||
|
Other assets
|
—
|
|
|
217
|
|
|
||
|
Accounts payable, accrued liabilities and other current liabilities
|
20,823
|
|
|
35,068
|
|
|
||
|
Royalties payable
|
5,665
|
|
|
29,651
|
|
|
||
|
Advances from joint interest owners
|
9,565
|
|
|
2,646
|
|
|
||
|
Other long-term liabilities
|
(250
|
)
|
|
(1,521
|
)
|
|
||
|
Net cash provided by operating activities
|
419,318
|
|
|
222,516
|
|
|
||
|
Investing activities
|
|
|
|
|
||||
|
Oil and natural gas properties capital expenditures
|
(1,106,556
|
)
|
|
(517,270
|
)
|
|
||
|
Expenditures for midstream and other property and equipment
|
(122,239
|
)
|
|
(80,560
|
)
|
|
||
|
Proceeds from sale of assets
|
8,267
|
|
|
977
|
|
|
||
|
Net cash used in investing activities
|
(1,220,528
|
)
|
|
(596,853
|
)
|
|
||
|
Financing activities
|
|
|
|
|
||||
|
Repayments of borrowings
|
(45,000
|
)
|
|
—
|
|
|
||
|
Borrowings under Credit Agreement
|
370,000
|
|
|
—
|
|
|
||
|
Proceeds from issuance of senior unsecured notes
|
750,000
|
|
|
—
|
|
|
||
|
Cost to issue senior unsecured notes
|
(9,531
|
)
|
|
—
|
|
|
||
|
Purchase of senior unsecured notes
|
(605,780
|
)
|
|
—
|
|
|
||
|
Proceeds from issuance of common stock
|
226,612
|
|
|
—
|
|
|
||
|
Cost to issue equity
|
(146
|
)
|
|
—
|
|
|
||
|
Proceeds from stock options exercised
|
827
|
|
|
2,920
|
|
|
||
|
Contributions related to formation of Joint Venture
|
14,700
|
|
|
171,500
|
|
|
||
|
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries
|
73,500
|
|
|
29,400
|
|
|
||
|
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries
|
(17,395
|
)
|
|
(5,635
|
)
|
|
||
|
Taxes paid related to net share settlement of stock-based compensation
|
(6,051
|
)
|
|
(4,415
|
)
|
|
||
|
Purchase of non-controlling interest of less-than-wholly-owned subsidiary
|
—
|
|
|
(2,653
|
)
|
|
||
|
Net cash provided by financing activities
|
751,736
|
|
|
191,117
|
|
|
||
|
Decrease in cash and restricted cash
|
(49,474
|
)
|
|
(183,220
|
)
|
|
||
|
Cash and restricted cash at beginning of period
|
102,482
|
|
|
214,142
|
|
|
||
|
Cash and restricted cash at end of period
|
$
|
53,008
|
|
|
$
|
30,922
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
||||||||||
(In thousands)
|
September 30, 2018
|
|
June 30, 2018
|
|
September 30, 2017
|
|
||||||
Unaudited Adjusted EBITDA Reconciliation to Net Income:
|
|
|
|
|
|
|
||||||
Net income attributable to Matador Resources Company shareholders
|
$
|
17,794
|
|
|
$
|
59,806
|
|
|
$
|
15,039
|
|
|
Net income attributable to non-controlling interest in subsidiaries
|
7,321
|
|
|
5,831
|
|
|
2,940
|
|
|
|||
Net income
|
25,115
|
|
|
65,637
|
|
|
17,979
|
|
|
|||
Interest expense
|
10,340
|
|
|
8,004
|
|
|
8,550
|
|
|
|||
Depletion, depreciation and amortization
|
70,457
|
|
|
66,838
|
|
|
47,800
|
|
|
|||
Accretion of asset retirement obligations
|
387
|
|
|
375
|
|
|
323
|
|
|
|||
Unrealized loss (gain) on derivatives
|
21,337
|
|
|
(1,429
|
)
|
|
12,372
|
|
|
|||
Stock-based compensation expense
|
4,842
|
|
|
4,766
|
|
|
1,296
|
|
|
|||
Net loss (gain) on asset sales and inventory impairment
|
196
|
|
|
—
|
|
|
(16
|
)
|
|
|||
Prepayment premium on extinguishment of debt
|
31,226
|
|
|
—
|
|
|
—
|
|
|
|||
Consolidated Adjusted EBITDA
|
163,900
|
|
|
144,191
|
|
|
88,304
|
|
|
|||
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
|
(8,508
|
)
|
|
(6,853
|
)
|
|
(3,471
|
)
|
|
|||
Adjusted EBITDA attributable to Matador Resources Company shareholders
|
$
|
155,392
|
|
|
$
|
137,338
|
|
|
$
|
84,833
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
||||||||||
(In thousands)
|
September 30, 2018
|
|
June 30, 2018
|
|
September 30, 2017
|
|
||||||
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
$
|
165,111
|
|
|
$
|
118,059
|
|
|
$
|
101,274
|
|
|
Net change in operating assets and liabilities
|
(11,111
|
)
|
|
18,174
|
|
|
(21,481
|
)
|
|
|||
Interest expense, net of non-cash portion
|
9,900
|
|
|
7,958
|
|
|
8,511
|
|
|
|||
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
|
(8,508
|
)
|
|
(6,853
|
)
|
|
(3,471
|
)
|
|
|||
Adjusted EBITDA attributable to Matador Resources Company shareholders
|
$
|
155,392
|
|
|
$
|
137,338
|
|
|
$
|
84,833
|
|
|
|
|
|
|
|
|
|