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ý
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from
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to
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Commission file number 001-34574
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Texas
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27-4662601
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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5400 LBJ Freeway, Suite 1500
Dallas, Texas 75240
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75240
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(Address of principal executive offices)
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(Zip Code)
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Title of each class
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Name of each exchange on which registered
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Common Stock, par value $0.01 per share
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New York Stock Exchange
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Large accelerated filer
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ý
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Accelerated filer
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¨
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Non-accelerated filer
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¨
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(Do not check if a smaller reporting company)
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Smaller reporting company
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¨
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DOCUMENTS INCORPORATED BY REFERENCE
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Page
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PART I
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I
TEM
1.
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I
TEM
1A.
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I
TEM
1B.
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I
TEM
2.
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I
TEM
3.
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I
TEM
4.
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PART II
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I
TEM
5.
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I
TEM
6.
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I
TEM
7.
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I
TEM
7A.
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I
TEM
8.
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I
TEM
9.
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I
TEM
9A.
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I
TEM
9B.
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PART III
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I
TEM
10.
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I
TEM
11.
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I
TEM
12.
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I
TEM
13.
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I
TEM
14.
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PART IV
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I
TEM
15.
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•
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our business strategy;
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•
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our reserves;
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•
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our technology;
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•
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our cash flows and liquidity;
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•
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our financial strategy, budget, projections and operating results;
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•
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our oil and natural gas realized prices;
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•
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the timing and amount of future production of oil and natural gas;
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•
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the availability of drilling and production equipment;
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•
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the availability of oil field labor;
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•
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the amount, nature and timing of capital expenditures, including future exploration and development costs;
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•
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the availability and terms of capital;
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•
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our drilling of wells;
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•
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our ability to negotiate and consummate acquisition and divestiture opportunities;
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government regulation and taxation of the oil and natural gas industry;
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•
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our marketing of oil and natural gas;
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•
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our exploitation projects or property acquisitions;
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•
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the integration of acquisitions with our business;
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•
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our ability and the ability of our midstream joint venture to construct and operate midstream facilities, including the expansion of our Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells;
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•
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our costs of exploiting and developing our properties and conducting other operations;
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•
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general economic conditions;
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•
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competition in the oil and natural gas industry, including in both the exploration and production and midstream segments;
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the effectiveness of our risk management and hedging activities;
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environmental liabilities;
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counterparty credit risk;
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developments in oil-producing and natural gas-producing countries;
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our future operating results;
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•
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estimated future reserves and the present value thereof; and
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•
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our plans, objectives, expectations and intentions contained in this Annual Report that are not historical.
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focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas;
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identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties;
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continue to improve operational and cost efficiencies;
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identify and develop midstream opportunities that support and enhance our exploration and development activities;
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•
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maintain our financial discipline; and
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pursue opportunistic acquisitions, divestitures and joint ventures.
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our continued improvement in operational efficiencies throughout the Delaware Basin, particularly in our Rustler Breaks and Wolf asset areas, as we achieved improvements in both drilling times and well costs;
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in our Rustler Breaks asset area, the continued delineation and development of previously tested horizons—the Second Bone Spring, the Wolfcamp A-XY and two benches of the Wolfcamp B—and the successful testing of a new, deeper bench of the Wolfcamp B interval, which is sometimes referred to as the Blair Shale;
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•
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in our Wolf asset area, continued development of the Wolfcamp A-XY interval as well as the significant improvement in well results in the Second Bone Spring, as compared to our initial tests in that interval;
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•
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in our Ranger asset area, the initial results from three wells completed in the Third Bone Spring formation on our Mallon leasehold, which tested at the highest 24-hour initial potential flow rates of any wells we have drilled to date in the Delaware Basin and which illustrate the potential of our northern Delaware Basin acreage position;
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•
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a positive test of the Strawn formation in our Twin Lakes asset area from the Olivine State 5-16S-37E TL #1, a vertical well; and
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•
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the significant progress made with our midstream operations including the start-up of our Black River cryogenic natural gas processing plant (the “Black River Processing Plant”) and associated natural gas gathering system in our Rustler Breaks asset area, our initial salt water disposal well and facility and associated water gathering lines in our Rustler Breaks asset area and two additional salt water disposal wells and facilities in our Wolf asset area.
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Producing
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Total Identified
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Estimated Net Proved
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|||||||||||||||
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Wells
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Drilling Locations
(1)
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Reserves
(2)
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Avg. Daily
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|||||||||||||||||||
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Gross
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Net
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Gross
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Net
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Gross
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Net
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%
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Production
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Acreage
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Acreage
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MBOE
(3)
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Developed
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(BOE/d)
(3)
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Southeast New Mexico/West Texas:
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Delaware Basin
(4)
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163,703
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94,312
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312
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135.1
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4,162
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1,660.2
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79,388
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35.5
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15,941
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South Texas:
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Eagle Ford
(5)
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30,669
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27,777
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136
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115.1
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249
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214.2
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13,298
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55.0
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4,952
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Northwest Louisiana/East Texas:
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Haynesville
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20,105
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12,452
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204
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19.8
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431
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103.0
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12,414
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61.1
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6,517
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Cotton Valley
(6)
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21,614
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19,071
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81
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54.2
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71
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50.1
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652
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100.0
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403
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Area Total
(7)
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26,062
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23,278
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285
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74.0
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502
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153.1
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13,066
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63.0
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6,920
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Total
(8)
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220,434
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145,367
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733
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324.2
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4,913
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2,027.5
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105,752
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41.4
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27,813
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(1)
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Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at
December 31, 2016
. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At
December 31, 2016
, these engineered drilling locations included only 163 gross (90.3 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Delaware and Strawn formations in the Delaware Basin, 21 gross (21.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 12 gross (4.0 net) locations to which we have assigned proved undeveloped reserves in the Haynesville.
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(2)
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These estimates were prepared by our engineering staff and audited by
Netherland, Sewell & Associates, Inc.
, independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference.
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(3)
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Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
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(4)
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Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Delaware, Strawn and Avalon plays on our acreage in the Delaware Basin at
December 31, 2016
.
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(5)
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Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.
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(6)
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Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
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(7)
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Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.
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(8)
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During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho.
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Year Ended December 31,
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2016
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2015
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2014
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Unaudited Production Data:
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Net Production Volumes:
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Oil (MBbl)
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5,096
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4,492
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3,320
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Natural gas (Bcf)
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30.5
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27.7
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15.3
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Total oil equivalent (MBOE)
(1)
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10,180
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9,109
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5,870
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Average daily production (BOE/d)
(1)
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27,813
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24,955
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16,082
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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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41.19
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$
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45.27
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$
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87.37
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Oil, with realized derivatives (per Bbl)
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$
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42.34
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$
|
59.13
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|
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$
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88.94
|
|
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Natural gas, without realized derivatives (per Mcf)
|
|
$
|
2.66
|
|
|
$
|
2.71
|
|
|
$
|
5.08
|
|
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Natural gas, with realized derivatives (per Mcf)
|
|
$
|
2.78
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|
|
$
|
3.24
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$
|
5.06
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|
|
Operating Expenses (per BOE):
|
|
|
|
|
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|
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||||||
Production taxes, transportation and processing
|
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$
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4.23
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$
|
3.91
|
|
(2)
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$
|
5.65
|
|
|
Lease operating
|
|
$
|
5.52
|
|
|
$
|
6.01
|
|
(3)
|
$
|
8.51
|
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(3)
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Plant and other midstream services operating
|
|
$
|
0.53
|
|
|
$
|
0.38
|
|
|
$
|
0.24
|
|
|
Depletion, depreciation and amortization
|
|
$
|
11.99
|
|
|
$
|
19.63
|
|
|
$
|
22.95
|
|
|
General and administrative
|
|
$
|
5.41
|
|
|
$
|
5.50
|
|
|
$
|
5.48
|
|
|
(1)
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Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
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(2)
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$0.01 per BOE reclassified to third-party midstream services revenues due to our midstream business becoming a reportable segment in the third quarter of 2016.
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(3)
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$0.38 and $0.24 per BOE reclassified to plant and other midstream services operating expenses for the years ended December 31, 2015 and 2014, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016.
|
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Southeast New Mexico/West Texas
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South Texas
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Northwest Louisiana/East Texas
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||||||||||||
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Delaware Basin
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Eagle Ford
(1)
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Haynesville
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Cotton Valley
(2)
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Total
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||||||||||
Annual Net Production Volumes
|
|
|
|
|
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||||||||||
Oil (MBbl)
|
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3,805
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|
1,286
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|
|
—
|
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|
5
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|
|
5,096
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|
|||||
Natural gas (Bcf)
|
|
12.2
|
|
|
3.1
|
|
|
14.3
|
|
|
0.9
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|
|
30.5
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|
|||||
Total oil equivalent (MBOE)
(3)
|
|
5,834
|
|
|
1,813
|
|
|
2,385
|
|
|
148
|
|
|
10,180
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|
|||||
Percentage of total annual net production
|
|
57.3
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%
|
|
17.8
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%
|
|
23.4
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%
|
|
1.5
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%
|
|
100.0
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%
|
|||||
Average Net Daily Production Volumes
|
|
|
|
|
|
|
|
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||||||||||
Oil (Bbl/d)
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10,395
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|
|
3,517
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|
|
—
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|
|
12
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|
|
13,924
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|
|||||
Natural gas (MMcf/d)
|
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33.3
|
|
|
8.6
|
|
|
39.1
|
|
|
2.3
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|
|
83.3
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|
|||||
Total oil equivalent (BOE/d)
|
|
15,941
|
|
|
4,952
|
|
|
6,517
|
|
|
403
|
|
|
27,813
|
|
|||||
Average Sales Prices
(4)
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|
|
|
|
|
|
|
|
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|
||||||||||
Oil (per Bbl)
|
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$
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41.76
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|
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$
|
39.49
|
|
|
$
|
—
|
|
|
$
|
38.78
|
|
|
$
|
41.19
|
|
Natural gas (per Mcf)
|
|
$
|
3.15
|
|
|
$
|
3.11
|
|
|
$
|
2.17
|
|
|
$
|
2.27
|
|
|
$
|
2.66
|
|
Total oil equivalent (per BOE)
|
|
$
|
33.81
|
|
|
$
|
33.46
|
|
|
$
|
13.04
|
|
|
$
|
14.39
|
|
|
$
|
28.60
|
|
Production Costs
(5)
|
|
|
|
|
|
|
|
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|
||||||||||
Lease operating, transportation and processing (per BOE)
|
|
$
|
7.32
|
|
|
$
|
12.74
|
|
|
$
|
4.73
|
|
|
$
|
17.07
|
|
|
$
|
7.82
|
|
(1)
|
Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.
|
(2)
|
Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
|
(3)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
(4)
|
Excludes impact of derivative settlements.
|
(5)
|
Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.
|
|
|
Southeast New Mexico/West Texas
|
|
South Texas
|
|
Northwest Louisiana/East Texas
|
|
|
||||||||||||
|
|
|
|
|
|
|||||||||||||||
|
|
Delaware Basin
|
|
Eagle Ford
(1)
|
|
Haynesville
|
|
Cotton Valley
(2)
|
|
Total
|
||||||||||
Annual Net Production Volumes
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MBbl)
|
|
1,697
|
|
|
2,789
|
|
|
—
|
|
|
6
|
|
|
4,492
|
|
|||||
Natural gas (Bcf)
|
|
4.1
|
|
|
5.7
|
|
|
16.9
|
|
|
1.0
|
|
|
27.7
|
|
|||||
Total oil equivalent (MBOE)
(3)
|
|
2,379
|
|
|
3,746
|
|
|
2,822
|
|
|
162
|
|
|
9,109
|
|
|||||
Percentage of total annual net production
|
|
26.1
|
%
|
|
41.1
|
%
|
|
31.0
|
%
|
|
1.8
|
%
|
|
100.0
|
%
|
|||||
Average Net Daily Production Volumes
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (Bbl/d)
|
|
4,648
|
|
|
7,642
|
|
|
—
|
|
|
16
|
|
|
12,306
|
|
|||||
Natural gas (MMcf/d)
|
|
11.2
|
|
|
15.7
|
|
|
46.4
|
|
|
2.6
|
|
|
75.9
|
|
|||||
Total oil equivalent (BOE/d)
|
|
6,518
|
|
|
10,263
|
|
|
7,731
|
|
|
443
|
|
|
24,955
|
|
|||||
Average Sales Prices
(4)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
|
$
|
43.54
|
|
|
$
|
46.33
|
|
|
$
|
—
|
|
|
$
|
43.68
|
|
|
$
|
45.27
|
|
Natural gas (per Mcf)
|
|
$
|
3.00
|
|
|
$
|
3.17
|
|
|
$
|
2.49
|
|
|
$
|
2.45
|
|
|
$
|
2.71
|
|
Total oil equivalent (per BOE)
|
|
$
|
36.21
|
|
|
$
|
39.35
|
|
|
$
|
14.97
|
|
|
$
|
15.69
|
|
|
$
|
30.56
|
|
Production Costs
(5)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating, transportation and processing (per BOE)
(6)
|
|
$
|
8.84
|
|
|
$
|
9.25
|
|
|
$
|
4.91
|
|
|
$
|
19.23
|
|
|
$
|
7.90
|
|
(1)
|
Includes one wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.
|
(2)
|
Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
|
(3)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
(4)
|
Excludes impact of derivative settlements.
|
(5)
|
Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.
|
(6)
|
Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016.
|
|
|
Southeast New Mexico/West Texas
|
|
South Texas
|
|
Northwest Louisiana/East Texas
|
|
|
||||||||||||
|
|
|
|
|
|
|||||||||||||||
|
|
Delaware Basin
|
|
Eagle Ford
(1)
|
|
Haynesville
|
|
Cotton Valley
(2)
|
|
Total
|
||||||||||
Annual Net Production Volumes
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MBbl)
|
|
480
|
|
|
2,834
|
|
|
—
|
|
|
6
|
|
|
3,320
|
|
|||||
Natural gas (Bcf)
|
|
1.0
|
|
|
6.0
|
|
|
7.2
|
|
|
1.1
|
|
|
15.3
|
|
|||||
Total oil equivalent (MBOE)
(3)
|
|
653
|
|
|
3,833
|
|
|
1,201
|
|
|
183
|
|
|
5,870
|
|
|||||
Percentage of total annual net production
|
|
11.1
|
%
|
|
65.3
|
%
|
|
20.5
|
%
|
|
3.1
|
%
|
|
100.0
|
%
|
|||||
Average Net Daily Production Volumes
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (Bbl/d)
|
|
1,314
|
|
|
7,764
|
|
|
—
|
|
|
17
|
|
|
9,095
|
|
|||||
Natural gas (MMcf/d)
|
|
2.9
|
|
|
16.4
|
|
|
19.7
|
|
|
2.9
|
|
|
41.9
|
|
|||||
Total oil equivalent (BOE/d)
|
|
1,790
|
|
|
10,501
|
|
|
3,290
|
|
|
501
|
|
|
16,082
|
|
|||||
Average Sales Prices
(4)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
|
$
|
80.16
|
|
|
$
|
88.58
|
|
|
$
|
—
|
|
|
$
|
91.24
|
|
|
$
|
87.37
|
|
Natural gas (per Mcf)
|
|
$
|
4.75
|
|
|
$
|
6.72
|
|
|
$
|
3.87
|
|
|
$
|
4.30
|
|
|
$
|
5.08
|
|
Total oil equivalent (per BOE)
|
|
$
|
66.41
|
|
|
$
|
75.99
|
|
|
$
|
23.27
|
|
|
$
|
27.92
|
|
|
$
|
62.64
|
|
Production Costs
(5)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating, transportation and processing (per BOE)
(6)
|
|
$
|
13.08
|
|
|
$
|
10.34
|
|
|
$
|
8.13
|
|
|
$
|
17.58
|
|
|
$
|
10.29
|
|
(1)
|
Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.
|
(2)
|
Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
|
(3)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
(4)
|
Excludes impact of derivative settlements.
|
(5)
|
Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.
|
(6)
|
Amounts have been adjusted to reflect the reclassification of certain lease operating expenses to plant and other midstream services operating expenses due to our midstream business becoming a reportable segment in the third quarter of 2016.
|
|
|
Oil Wells
|
|
Natural Gas Wells
|
|
Total Wells
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Southeast New Mexico/West Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Delaware Basin
(1)
|
|
261
|
|
|
116.0
|
|
|
51
|
|
|
19.1
|
|
|
312
|
|
|
135.1
|
|
South Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Eagle Ford
(2)
|
|
132
|
|
|
111.1
|
|
|
4
|
|
|
4.0
|
|
|
136
|
|
|
115.1
|
|
Northwest Louisiana/East Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Haynesville
|
|
—
|
|
|
—
|
|
|
204
|
|
|
19.8
|
|
|
204
|
|
|
19.8
|
|
Cotton Valley
(3)
|
|
2
|
|
|
2.0
|
|
|
79
|
|
|
52.2
|
|
|
81
|
|
|
54.2
|
|
Area Total
|
|
2
|
|
|
2.0
|
|
|
283
|
|
|
72.0
|
|
|
285
|
|
|
74.0
|
|
Total
|
|
395
|
|
|
229.1
|
|
|
338
|
|
|
95.1
|
|
|
733
|
|
|
324.2
|
|
(1)
|
Includes 176 gross (50.5 net) wells acquired in February 2015 as part of the HEYCO Merger.
|
(2)
|
Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.
|
(3)
|
Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
|
|
|
At December 31,
(1)
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Estimated Proved Reserves Data:
(2)
|
|
|
|
|
|
|
||||||
Estimated proved reserves:
|
|
|
|
|
|
|
||||||
Oil (MBbl)
|
|
56,977
|
|
|
45,644
|
|
|
24,184
|
|
|||
Natural Gas (Bcf)
(3)
|
|
292.6
|
|
|
236.9
|
|
|
267.1
|
|
|||
Total (MBOE)
(4)
|
|
105,752
|
|
|
85,127
|
|
|
68,693
|
|
|||
Estimated proved developed reserves:
|
|
|
|
|
|
|
||||||
Oil (MBbl)
|
|
22,604
|
|
|
17,129
|
|
|
14,053
|
|
|||
Natural Gas (Bcf)
(3)
|
|
126.8
|
|
|
101.4
|
|
|
102.8
|
|
|||
Total (MBOE)
(4)
|
|
43,731
|
|
|
34,037
|
|
|
31,185
|
|
|||
Percent developed
|
|
41.4
|
%
|
|
40.0
|
%
|
|
45.4
|
%
|
|||
Estimated proved undeveloped reserves:
|
|
|
|
|
|
|
||||||
Oil (MBbl)
|
|
34,373
|
|
|
28,515
|
|
|
10,131
|
|
|||
Natural Gas (Bcf)
(3)
|
|
165.9
|
|
|
135.5
|
|
|
164.3
|
|
|||
Total (MBOE)
(4)
|
|
62,021
|
|
|
51,090
|
|
|
37,508
|
|
|||
Standardized Measure
(5)
(in millions)
|
|
$
|
575.0
|
|
|
$
|
529.2
|
|
|
$
|
913.3
|
|
PV-10
(6)
(in millions)
|
|
$
|
581.5
|
|
|
$
|
541.6
|
|
|
$
|
1,043.4
|
|
(1)
|
Numbers in table may not total due to rounding.
|
(2)
|
Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended
December 31, 2016
were
$39.25
per Bbl for oil and
$2.48
per MMBtu for natural gas, for the 12 months ended
December 31, 2015
were
$46.79
per Bbl for oil and
$2.59
per MMBtu for natural gas, and for the 12 months ended
December 31, 2014
were
$91.48
per Bbl for oil and
$4.35
per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.
|
(3)
|
Primarily as a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously classified proved undeveloped natural gas reserves from our total proved reserves in 2015, most of which were attributable to non-operated properties in the Haynesville shale.
|
(4)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Primarily as a result of the lower weighted average oil and natural gas prices used to estimate proved oil and natural gas reserves in 2016, we removed approximately 11.6 million BOE of previously classified proved undeveloped reserves from our total proved reserves in 2016.
|
(5)
|
Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.
|
(6)
|
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We 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. Our PV-10 at
December 31, 2016, 2015 and 2014
may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at
December 31, 2016, 2015 and 2014
were, in millions,
$6.5
,
$12.4
and
$130.1
, respectively.
|
|
|
Proved Developed Reserves
|
|
|
|
||
|
|
(MBOE)
(1)
|
|
As of December 31, 2015
|
|
34,037
|
|
Extensions and discoveries
|
|
12,583
|
|
Revisions of prior estimates
|
|
408
|
|
Production
|
|
(10,180
|
)
|
Conversion of proved undeveloped to proved developed
|
|
6,883
|
|
As of December 31, 2016
|
|
43,731
|
|
(1)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
|
|
Proved Undeveloped Reserves
|
|
|
|
||
|
|
(MBOE)
(1)
|
|
As of December 31, 2015
|
|
51,090
|
|
Extensions and discoveries
|
|
29,408
|
|
Revisions of prior estimates
|
|
(11,594
|
)
|
Conversion of proved undeveloped to proved developed
|
|
(6,883
|
)
|
As of December 31, 2016
|
|
62,021
|
|
(1)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
|
|
|
|
|
|
|
|
Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
|
|||||
|
|
Proved Undeveloped Reserves
Converted to Proved Developed Reserves |
|
||||||||||
|
|
|
|||||||||||
|
|
Oil
|
|
Natural Gas
|
|
Total
|
|
||||||
|
|
(MBbl)
|
|
(Bcf)
|
|
(MBOE)
(1)
|
|
||||||
2013
|
|
2,944
|
|
|
8.3
|
|
|
4,334
|
|
|
$
|
115,699
|
|
2014
|
|
3,780
|
|
|
44.7
|
|
|
11,223
|
|
|
201,950
|
|
|
2015
|
|
2,854
|
|
|
23.4
|
|
|
6,747
|
|
|
104,989
|
|
|
2016
|
|
4,705
|
|
|
13.1
|
|
|
6,883
|
|
|
94,579
|
|
|
Total
|
|
14,283
|
|
|
89.5
|
|
|
29,187
|
|
|
$
|
517,217
|
|
(1)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
|
|
Net Proved Reserves
(1)
|
|
|
|
|
|||||||||||
|
|
Oil
|
|
Natural Gas
|
|
Oil Equivalent
|
|
Standardized Measure
(2)
|
|
PV-10
(3)
|
|||||||
|
|
(MBbl)
|
|
(Bcf)
|
|
(MBOE)
(4)
|
|
(in millions)
|
|
(in millions)
|
|||||||
Southeast New Mexico/West Texas:
|
|
|
|
|
|
|
|
|
|
|
|||||||
Delaware Basin
|
|
46,873
|
|
|
195.1
|
|
|
79,388
|
|
|
$
|
446.0
|
|
|
$
|
451.0
|
|
South Texas:
|
|
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
(5)
|
|
10,066
|
|
|
19.3
|
|
|
13,298
|
|
|
85.6
|
|
|
86.6
|
|
||
Northwest Louisiana/East Texas:
|
|
|
|
|
|
|
|
|
|
|
|||||||
Haynesville
|
|
—
|
|
|
74.5
|
|
|
12,414
|
|
|
41.5
|
|
|
42.0
|
|
||
Cotton Valley
(6)
|
|
38
|
|
|
3.7
|
|
|
652
|
|
|
1.9
|
|
|
1.9
|
|
||
Area Total
|
|
38
|
|
|
78.2
|
|
|
13,066
|
|
|
43.4
|
|
|
43.9
|
|
||
Total
|
|
56,977
|
|
|
292.6
|
|
|
105,752
|
|
|
$
|
575.0
|
|
|
$
|
581.5
|
|
(1)
|
Numbers in table may not total due to rounding.
|
(2)
|
Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.
|
(3)
|
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We 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. Our PV-10 at
December 31, 2016
may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at
December 31, 2016
were approximately $
6.5 million
.
|
(4)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
(5)
|
Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.
|
(6)
|
Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
|
|
|
Developed Acres
|
|
Undeveloped Acres
|
|
Total Acres
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Southeast New Mexico/West Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Delaware Basin
|
|
79,087
|
|
|
33,699
|
|
|
84,616
|
|
|
60,613
|
|
|
163,703
|
|
|
94,312
|
|
South Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Eagle Ford
|
|
26,402
|
|
|
23,682
|
|
|
4,267
|
|
|
4,095
|
|
|
30,669
|
|
|
27,777
|
|
Northwest Louisiana/East Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Haynesville
|
|
16,739
|
|
|
9,088
|
|
|
3,366
|
|
|
3,364
|
|
|
20,105
|
|
|
12,452
|
|
Cotton Valley
|
|
18,108
|
|
|
16,078
|
|
|
3,506
|
|
|
2,993
|
|
|
21,614
|
|
|
19,071
|
|
Area Total
(1)
|
|
22,030
|
|
|
19,761
|
|
|
4,032
|
|
|
3,517
|
|
|
26,062
|
|
|
23,278
|
|
Total
(2)
|
|
127,519
|
|
|
77,142
|
|
|
92,915
|
|
|
68,225
|
|
|
220,434
|
|
|
145,367
|
|
(1)
|
Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas.
|
(2)
|
During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho.
|
|
|
Acres
|
|
Acres
|
|
Acres
|
||||||||||||
|
|
Expiring 2017
|
|
Expiring 2018
|
|
Expiring 2019
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Southeast New Mexico/West Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Delaware Basin
(1)
|
|
17,604
|
|
|
7,987
|
|
|
39,704
|
|
|
25,294
|
|
|
15,404
|
|
|
9,086
|
|
South Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Eagle Ford
|
|
1,435
|
|
|
1,375
|
|
|
896
|
|
|
753
|
|
|
204
|
|
|
156
|
|
Northwest Louisiana/East Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Haynesville
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
326
|
|
|
324
|
|
Cotton Valley
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Area Total
(2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
326
|
|
|
324
|
|
Total
|
|
19,039
|
|
|
9,362
|
|
|
40,600
|
|
|
26,047
|
|
|
15,934
|
|
|
9,566
|
|
(1)
|
Approximately 54% of the acreage expiring in the next three years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. Most of these leases can be extended for an additional two years, should we choose to do so, by paying an additional lease bonus. We also expect to hold or extend portions of the remaining expiring acreage outside of our Twin Lakes asset area in 2017 through our 2017 drilling activities or by paying an additional lease bonus, where applicable.
|
(2)
|
Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas.
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|||||||
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
44
|
|
|
23.5
|
|
|
53
|
|
|
26.7
|
|
|
89
|
|
|
39.9
|
|
Dry
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploration Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
28
|
|
|
15.6
|
|
|
28
|
|
|
17.5
|
|
|
12
|
|
|
10.6
|
|
Dry
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
72
|
|
|
39.1
|
|
|
81
|
|
|
44.2
|
|
|
101
|
|
|
50.5
|
|
Dry
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
•
|
the domestic and foreign supply of, and demand for, oil and natural gas;
|
•
|
the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls;
|
•
|
the prices and availability of competitors’ supplies of oil and natural gas;
|
•
|
the price and quantity of foreign imports;
|
•
|
the impact of U.S. dollar exchange rates on oil and natural gas prices;
|
•
|
domestic and foreign governmental regulations and taxes;
|
•
|
speculative trading of oil and natural gas futures contracts;
|
•
|
the availability, proximity and capacity of gathering, processing and transportation systems for natural gas;
|
•
|
the availability of refining capacity;
|
•
|
the prices and availability of alternative fuel sources;
|
•
|
weather conditions and natural disasters;
|
•
|
political conditions in or affecting oil and natural gas producing regions or countries, including the United States, Middle East, South America and Russia;
|
•
|
the continued threat of terrorism and the impact of military action and civil unrest;
|
•
|
public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;
|
•
|
the level of global oil and natural gas inventories and exploration and production activity;
|
•
|
the impact of energy conservation efforts;
|
•
|
technological advances affecting energy consumption; and
|
•
|
overall worldwide economic conditions.
|
•
|
our estimated proved oil and natural gas reserves;
|
•
|
the amount of oil and natural gas we produce from existing wells;
|
•
|
the prices at which we sell our production;
|
•
|
the costs of developing and producing our oil and natural gas reserves;
|
•
|
the costs of constructing, operating and maintaining our midstream facilities;
|
•
|
our ability to acquire, locate and produce new reserves;
|
•
|
the ability and willingness of banks to lend to us; and
|
•
|
our ability to access the equity and debt capital markets.
|
•
|
general economic and industry conditions, including the prices received for oil and natural gas;
|
•
|
shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel;
|
•
|
potential drainage of oil and natural gas from our properties by adjacent operators;
|
•
|
loss of or damage to oilfield development and service tools;
|
•
|
accidents, equipment failures or mechanical problems;
|
•
|
title defects of the underlying properties;
|
•
|
increases in severance taxes;
|
•
|
adverse weather conditions that delay drilling activities or cause producing wells to be shut in;
|
•
|
domestic and foreign governmental regulations; and
|
•
|
proximity to and capacity of gathering, processing and transportation facilities.
|
•
|
landing our wellbore in the desired drilling zone;
|
•
|
staying in the desired drilling zone while drilling horizontally through the formation;
|
•
|
running our casing the entire length of the wellbore;
|
•
|
fracture stimulating the planned number of stages; and
|
•
|
being able to run tools and other equipment consistently through the horizontal wellbore.
|
•
|
incur or guarantee additional debt or issue certain types of preferred stock;
|
•
|
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;
|
•
|
transfer or sell assets;
|
•
|
make certain investments;
|
•
|
create certain liens;
|
•
|
enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us;
|
•
|
consolidate, merge or transfer all or substantially all of our assets;
|
•
|
engage in transactions with affiliates; and
|
•
|
create unrestricted subsidiaries.
|
•
|
requiring a significant portion of our cash flows to be used for servicing our indebtedness;
|
•
|
increasing our vulnerability to general adverse economic and industry conditions;
|
•
|
placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing;
|
•
|
restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and
|
•
|
increasing the risk that we may default on our debt obligations.
|
•
|
natural disasters;
|
•
|
adverse weather conditions;
|
•
|
loss of drilling fluid circulation;
|
•
|
blowouts where oil or natural gas flows uncontrolled at a wellhead;
|
•
|
cratering or collapse of the formation;
|
•
|
pipe or cement leaks, failures or casing collapses;
|
•
|
damage to pipelines, processing plants and disposal wells and associated facilities;
|
•
|
fires or explosions;
|
•
|
releases of hazardous substances or other waste materials that cause environmental damage;
|
•
|
pressures or irregularities in formations; and
|
•
|
equipment failures or accidents.
|
•
|
the quality and quantity of available data;
|
•
|
the interpretation of that data;
|
•
|
the judgment of the persons preparing the estimate; and
|
•
|
the accuracy of the assumptions used.
|
•
|
actual prices we receive for oil and natural gas;
|
•
|
actual costs and timing of development and production expenditures;
|
•
|
the amount and timing of actual production; and
|
•
|
changes in governmental regulations or taxation.
|
•
|
timing and amount of capital expenditures;
|
•
|
the operator’s expertise and financial resources;
|
•
|
the rate of production of reserves, if any;
|
•
|
approval of other participants in drilling wells; and
|
•
|
selection and implementation or execution of technology.
|
•
|
downward adjustments to our estimated proved reserves;
|
•
|
increases in our estimates of development costs; or
|
•
|
deterioration in our exploration and development results.
|
•
|
personal injuries;
|
•
|
property damage;
|
•
|
containment and clean-up of oil and other spills;
|
•
|
management and disposal of hazardous materials;
|
•
|
remediation, clean-up costs and natural resource damages; and
|
•
|
other environmental damages.
|
•
|
our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates;
|
•
|
quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us;
|
•
|
changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts;
|
•
|
speculation in the press or investment community;
|
•
|
announcement or consummation of acquisitions or dispositions by us;
|
•
|
public reaction to our press releases, announcements and filings with the SEC;
|
•
|
sales of our common stock by us or shareholders, or the perception that such sales may occur;
|
•
|
general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and natural gas liquids;
|
•
|
the realization of any of the risk factors presented in this Annual Report;
|
•
|
the recruitment or departure of key personnel;
|
•
|
commencement of or involvement in litigation;
|
•
|
the success of our exploration and development operations, our midstream business and the marketing of any oil, natural gas and natural gas liquids we produce;
|
•
|
changes in market valuations of companies similar to ours; and
|
•
|
domestic and international economic, legal and regulatory factors unrelated to our performance.
|
•
|
authorization for our Board of Directors to issue preferred stock without shareholder approval;
|
•
|
a classified Board of Directors so that not all members of our Board of Directors are elected at one time;
|
•
|
the prohibition of cumulative voting in the election of directors; and
|
•
|
a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock.
|
|
|
2016
|
|
2015
|
||||||||||||
|
|
High
|
|
Low
|
|
High
|
|
Low
|
||||||||
First Quarter
|
|
$
|
20.94
|
|
|
$
|
11.13
|
|
|
$
|
25.08
|
|
|
$
|
18.28
|
|
Second Quarter
|
|
$
|
25.54
|
|
|
$
|
18.03
|
|
|
$
|
29.90
|
|
|
$
|
22.01
|
|
Third Quarter
|
|
$
|
24.71
|
|
|
$
|
18.56
|
|
|
$
|
26.07
|
|
|
$
|
19.08
|
|
Fourth Quarter
|
|
$
|
27.71
|
|
|
$
|
20.45
|
|
|
$
|
28.25
|
|
|
$
|
18.87
|
|
Equity Compensation Plan Information
|
||||||||||
Plan Category
|
|
Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights
|
|
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights
|
|
Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans
|
||||
Equity compensation plans approved by security holders
(1) (2)
|
|
2,872,954
|
|
|
$
|
15.59
|
|
|
3,963,427
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
2,872,954
|
|
|
$
|
15.59
|
|
|
3,963,427
|
|
(1)
|
Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan.
|
(2)
|
The Amended and Restated 2012 Long-Term Incentive Plan was adopted by our Board of Directors in April 2015 and approved by our shareholders on June 10, 2015. For a description of our Amended and Restated 2012 Long-Term Incentive Plan, see Note 8 to the consolidated financial statements in this Annual Report.
|
Period
|
|
Total Number of Shares Purchased
(1)
|
|
Average Price Paid Per Share
|
|
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
|
|
Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs
|
|||||
October 1, 2016 to October 31, 2016
|
|
1,131
|
|
|
$
|
23.66
|
|
|
—
|
|
|
—
|
|
November 1, 2016 to November 30, 2016
|
|
1,288
|
|
|
21.45
|
|
|
—
|
|
|
—
|
|
|
December 1, 2016 to December 31, 2016
|
|
1,306
|
|
|
25.65
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
3,725
|
|
|
$
|
23.59
|
|
|
—
|
|
|
—
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas revenues
|
|
$
|
291,156
|
|
|
$
|
278,340
|
|
|
$
|
367,712
|
|
|
$
|
269,030
|
|
|
$
|
155,998
|
|
Third-party midstream services revenue
|
|
5,218
|
|
|
1,864
|
|
|
1,213
|
|
|
207
|
|
|
183
|
|
|||||
Realized gain (loss) on derivatives
|
|
9,286
|
|
|
77,094
|
|
|
5,022
|
|
|
(909
|
)
|
|
13,960
|
|
|||||
Unrealized (loss) gain on derivatives
|
|
(41,238
|
)
|
|
(39,265
|
)
|
|
58,302
|
|
|
(7,232
|
)
|
|
(4,802
|
)
|
|||||
Total revenues
|
|
264,422
|
|
|
318,033
|
|
|
432,249
|
|
|
261,096
|
|
|
165,339
|
|
|||||
Expenses
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production taxes, transportation and processing
(1)
|
|
43,046
|
|
|
35,650
|
|
|
33,172
|
|
|
20,973
|
|
|
11,672
|
|
|||||
Lease operating
(2)
|
|
56,202
|
|
|
54,704
|
|
|
49,945
|
|
|
37,971
|
|
|
27,868
|
|
|||||
Plant and other midstream services operating
|
|
5,389
|
|
|
3,489
|
|
|
1,408
|
|
|
749
|
|
|
316
|
|
|||||
Depletion, depreciation and amortization
|
|
122,048
|
|
|
178,847
|
|
|
134,737
|
|
|
98,395
|
|
|
80,454
|
|
|||||
Accretion of asset retirement obligations
|
|
1,182
|
|
|
734
|
|
|
504
|
|
|
348
|
|
|
256
|
|
|||||
Full-cost ceiling impairment
|
|
158,633
|
|
|
801,166
|
|
|
—
|
|
|
21,229
|
|
|
63,475
|
|
|||||
General and administrative
|
|
55,089
|
|
|
50,105
|
|
|
32,152
|
|
|
20,779
|
|
|
14,543
|
|
|||||
Total expenses
|
|
441,589
|
|
|
1,124,695
|
|
|
251,918
|
|
|
200,444
|
|
|
198,584
|
|
|||||
Operating (loss) income
|
|
(177,167
|
)
|
|
(806,662
|
)
|
|
180,331
|
|
|
60,652
|
|
|
(33,245
|
)
|
|||||
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net gain (loss) on asset sales and inventory impairment
|
|
107,277
|
|
|
908
|
|
|
—
|
|
|
(192
|
)
|
|
(485
|
)
|
|||||
Interest expense
|
|
(28,199
|
)
|
|
(21,754
|
)
|
|
(5,334
|
)
|
|
(5,687
|
)
|
|
(1,002
|
)
|
|||||
Other (expense) income
(3)
|
|
(4
|
)
|
|
616
|
|
|
132
|
|
|
18
|
|
|
42
|
|
|||||
Total other income (expense)
|
|
79,074
|
|
|
(20,230
|
)
|
|
(5,202
|
)
|
|
(5,861
|
)
|
|
(1,445
|
)
|
|||||
Net (loss) income
|
|
(97,057
|
)
|
|
(679,524
|
)
|
|
110,754
|
|
|
45,094
|
|
|
(33,261
|
)
|
|||||
Net (income) loss attributable to non-controlling interest in subsidiaries
|
|
(364
|
)
|
|
(261
|
)
|
|
17
|
|
|
—
|
|
|
—
|
|
|||||
Net (loss) income attributable to
Matador Resources Company shareholders |
|
$
|
(97,421
|
)
|
|
$
|
(679,785
|
)
|
|
$
|
110,771
|
|
|
$
|
45,094
|
|
|
$
|
(33,261
|
)
|
Earnings (loss) per common share
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Class A
(4)
|
|
$
|
(1.07
|
)
|
|
$
|
(8.34
|
)
|
|
$
|
1.58
|
|
|
$
|
0.77
|
|
|
$
|
(0.62
|
)
|
Class B
(4)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.35
|
)
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Class A
(4)
|
|
$
|
(1.07
|
)
|
|
$
|
(8.34
|
)
|
|
$
|
1.56
|
|
|
$
|
0.77
|
|
|
$
|
(0.62
|
)
|
Class B
(4)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.35
|
)
|
Class B dividend declared, per share
(4)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.27
|
|
(1)
|
$0.1 million was reclassified to third-party midstream services revenues for the year ended December 31, 2015 due to our midstream business becoming a reportable segment in the third quarter of 2016. There were no such reclassifications made in any other periods presented.
|
(2)
|
$3.5 million, $1.4 million, $0.7 million and $0.3 million were reclassified to plant and other midstream services operating expenses for the years ended December 31, 2015, 2014, 2013 and 2012, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016.
|
(3)
|
$1.7 million, $1.2 million, $0.2 million and $0.2 million were reclassified to midstream services revenues for the years ended December 31, 2015, 2014, 2013 and 2012, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016.
|
(4)
|
Our Class B common stock converted into Class A common stock upon the consummation of our initial public offering on February 7, 2012 and the Class A common stock then became the only class of common stock authorized. The term “Class A common stock” refers to shares of our Class A
|
|
|
At December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
|
$
|
212,884
|
|
|
$
|
16,732
|
|
|
$
|
8,407
|
|
|
$
|
6,287
|
|
|
$
|
2,095
|
|
Restricted cash
|
|
1,258
|
|
|
44,357
|
|
|
609
|
|
|
—
|
|
|
—
|
|
|||||
Certificates of deposit
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
230
|
|
|||||
Net property and equipment
|
|
1,184,525
|
|
|
1,012,406
|
|
|
1,322,072
|
|
|
845,877
|
|
|
591,090
|
|
|||||
Total assets
|
|
1,464,665
|
|
|
1,140,861
|
|
|
1,434,490
|
|
|
890,330
|
|
|
632,029
|
|
|||||
Current liabilities
|
|
169,505
|
|
|
136,830
|
|
|
142,036
|
|
|
100,327
|
|
|
96,492
|
|
|||||
Long-term liabilities
|
|
603,715
|
|
|
515,072
|
|
|
425,913
|
|
|
221,079
|
|
|
156,433
|
|
|||||
Total Matador Resources Company shareholders’ equity
|
|
$
|
690,125
|
|
|
$
|
488,003
|
|
|
$
|
866,408
|
|
|
$
|
568,924
|
|
|
$
|
379,104
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other financial data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
134,086
|
|
|
$
|
208,535
|
|
|
$
|
251,481
|
|
|
$
|
179,470
|
|
|
$
|
124,228
|
|
Net cash used in investing activities
|
|
(405,640
|
)
|
|
(425,154
|
)
|
|
(570,531
|
)
|
|
(366,939
|
)
|
|
(306,916
|
)
|
|||||
Oil and natural gas properties capital expenditures
|
|
(379,067
|
)
|
|
(432,715
|
)
|
|
(560,849
|
)
|
|
(363,192
|
)
|
|
(300,689
|
)
|
|||||
Expenditures for other property and equipment
|
|
(74,845
|
)
|
|
(64,499
|
)
|
|
(9,152
|
)
|
|
(3,977
|
)
|
|
(7,332
|
)
|
|||||
Net cash provided by financing activities
|
|
467,706
|
|
|
224,944
|
|
|
321,170
|
|
|
191,661
|
|
|
174,499
|
|
|||||
Adjusted EBITDA
(1)
|
|
$
|
157,928
|
|
|
$
|
223,155
|
|
|
$
|
262,943
|
|
|
$
|
191,771
|
|
|
$
|
115,923
|
|
(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 “
–
Non-GAAP Financial Measures” below.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Unaudited Adjusted EBITDA Reconciliation to Net (Loss) Income:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net (loss) income attributable to Matador Resources Company shareholders
|
|
$
|
(97,421
|
)
|
|
$
|
(679,785
|
)
|
|
$
|
110,771
|
|
|
$
|
45,094
|
|
|
$
|
(33,261
|
)
|
Interest expense
|
|
28,199
|
|
|
21,754
|
|
|
5,334
|
|
|
5,687
|
|
|
1,002
|
|
|||||
Total income tax (benefit) provision
|
|
(1,036
|
)
|
|
(147,368
|
)
|
|
64,375
|
|
|
9,697
|
|
|
(1,430
|
)
|
|||||
Depletion, depreciation and amortization
|
|
122,048
|
|
|
178,847
|
|
|
134,737
|
|
|
98,395
|
|
|
80,454
|
|
|||||
Accretion of asset retirement obligations
|
|
1,182
|
|
|
734
|
|
|
504
|
|
|
348
|
|
|
256
|
|
|||||
Full-cost ceiling impairment
|
|
158,633
|
|
|
801,166
|
|
|
—
|
|
|
21,229
|
|
|
63,475
|
|
|||||
Unrealized loss (gain) on derivatives
|
|
41,238
|
|
|
39,265
|
|
|
(58,302
|
)
|
|
7,232
|
|
|
4,802
|
|
|||||
Stock-based compensation expense
|
|
12,362
|
|
|
9,450
|
|
|
5,524
|
|
|
3,897
|
|
|
140
|
|
|||||
Net (gain) loss on asset sales and inventory impairment
|
|
(107,277
|
)
|
|
(908
|
)
|
|
—
|
|
|
192
|
|
|
485
|
|
|||||
Adjusted EBITDA
|
|
$
|
157,928
|
|
|
$
|
223,155
|
|
|
$
|
262,943
|
|
|
$
|
191,771
|
|
|
$
|
115,923
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by
Operating Activities: |
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
134,086
|
|
|
$
|
208,535
|
|
|
$
|
251,481
|
|
|
$
|
179,470
|
|
|
$
|
124,228
|
|
Net change in operating assets and liabilities
|
|
(1,809
|
)
|
|
(8,980
|
)
|
|
5,978
|
|
|
6,210
|
|
|
(9,307
|
)
|
|||||
Interest expense, net of non-cash portion
|
|
27,051
|
|
|
20,902
|
|
|
5,334
|
|
|
5,687
|
|
|
1,002
|
|
|||||
Current income tax (benefit) provision
|
|
(1,036
|
)
|
|
2,959
|
|
|
133
|
|
|
404
|
|
|
—
|
|
|||||
Net (income) loss attributable to non-controlling interest in subsidiaries
|
|
(364
|
)
|
|
(261
|
)
|
|
17
|
|
|
—
|
|
|
—
|
|
|||||
Adjusted EBITDA
|
|
$
|
157,928
|
|
|
$
|
223,155
|
|
|
$
|
262,943
|
|
|
$
|
191,771
|
|
|
$
|
115,923
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Operating Data:
|
|
|
|
|
|
|
||||||
Revenues (in thousands):
(1)
|
|
|
|
|
|
|
||||||
Oil
|
|
$
|
209,908
|
|
|
$
|
203,355
|
|
|
$
|
290,026
|
|
Natural gas
|
|
81,248
|
|
|
74,985
|
|
|
77,686
|
|
|||
Total oil and natural gas revenues
|
|
291,156
|
|
|
278,340
|
|
|
367,712
|
|
|||
Third-party midstream services revenues
|
|
5,218
|
|
|
1,864
|
|
|
1,213
|
|
|||
Realized gain on derivatives
|
|
9,286
|
|
|
77,094
|
|
|
5,022
|
|
|||
Unrealized (loss) gain on derivatives
|
|
(41,238
|
)
|
|
(39,265
|
)
|
|
58,302
|
|
|||
Total revenues
|
|
$
|
264,422
|
|
|
$
|
318,033
|
|
|
$
|
432,249
|
|
Net Production Volumes:
(1)
|
|
|
|
|
|
|
||||||
Oil (MBbl)
|
|
5,096
|
|
|
4,492
|
|
|
3,320
|
|
|||
Natural gas (Bcf)
|
|
30.5
|
|
|
27.7
|
|
|
15.3
|
|
|||
Total oil equivalent (MBOE)
(2)
|
|
10,180
|
|
|
9,109
|
|
|
5,870
|
|
|||
Average daily production (BOE/d)
(2)
|
|
27,813
|
|
|
24,955
|
|
|
16,082
|
|
|||
Average Sales Prices:
|
|
|
|
|
|
|
||||||
Oil, without realized derivatives (per Bbl)
|
|
$
|
41.19
|
|
|
$
|
45.27
|
|
|
$
|
87.37
|
|
Oil, with realized derivatives (per Bbl)
|
|
$
|
42.34
|
|
|
$
|
59.13
|
|
|
$
|
88.94
|
|
Natural gas, without realized derivatives (per Mcf)
|
|
$
|
2.66
|
|
|
$
|
2.71
|
|
|
$
|
5.08
|
|
Natural gas, with realized derivatives (per Mcf)
|
|
$
|
2.78
|
|
|
$
|
3.24
|
|
|
$
|
5.06
|
|
(1)
|
We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues.
|
(2)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
(In thousands, except expenses per BOE)
|
|
|
||||||||||
Expenses:
|
|
|
|
|
|
|
||||||
Production taxes, transportation and processing
(1)
|
|
$
|
43,046
|
|
|
$
|
35,650
|
|
|
$
|
33,172
|
|
Lease operating
(2)
|
|
56,202
|
|
|
54,704
|
|
|
49,945
|
|
|||
Plant and other midstream services operating
|
|
5,389
|
|
|
3,489
|
|
|
1,408
|
|
|||
Depletion, depreciation and amortization
|
|
122,048
|
|
|
178,847
|
|
|
134,737
|
|
|||
Accretion of asset retirement obligations
|
|
1,182
|
|
|
734
|
|
|
504
|
|
|||
Full-cost ceiling impairment
|
|
158,633
|
|
|
801,166
|
|
|
—
|
|
|||
General and administrative
|
|
55,089
|
|
|
50,105
|
|
|
32,152
|
|
|||
Total expenses
|
|
441,589
|
|
|
1,124,695
|
|
|
251,918
|
|
|||
Operating (loss) income
|
|
(177,167
|
)
|
|
(806,662
|
)
|
|
180,331
|
|
|||
Other income (expense):
|
|
|
|
|
|
|
||||||
Net gain on asset sales and inventory impairment
|
|
107,277
|
|
|
908
|
|
|
—
|
|
|||
Interest expense
|
|
(28,199
|
)
|
|
(21,754
|
)
|
|
(5,334
|
)
|
|||
Other (expense) income
(3)
|
|
(4
|
)
|
|
616
|
|
|
132
|
|
|||
Total other income (expense)
|
|
79,074
|
|
|
(20,230
|
)
|
|
(5,202
|
)
|
|||
(Loss) income before income taxes
|
|
(98,093
|
)
|
|
(826,892
|
)
|
|
175,129
|
|
|||
Total income tax (benefit) provision
|
|
(1,036
|
)
|
|
(147,368
|
)
|
|
64,375
|
|
|||
Net (income) loss attributable to non-controlling interest in subsidiaries
|
|
(364
|
)
|
|
(261
|
)
|
|
17
|
|
|||
Net (loss) income attributable to Matador Resources Company shareholders
|
|
$
|
(97,421
|
)
|
|
$
|
(679,785
|
)
|
|
$
|
110,771
|
|
Expenses per BOE:
|
|
|
|
|
|
|
||||||
Production taxes, transportation and processing
(1)
|
|
$
|
4.23
|
|
|
$
|
3.91
|
|
|
$
|
5.65
|
|
Lease operating
(2)
|
|
$
|
5.52
|
|
|
$
|
6.01
|
|
|
$
|
8.51
|
|
Plant and other midstream services operating
|
|
$
|
0.53
|
|
|
$
|
0.38
|
|
|
$
|
0.24
|
|
Depletion, depreciation and amortization
|
|
$
|
11.99
|
|
|
$
|
19.63
|
|
|
$
|
22.95
|
|
General and administrative
|
|
$
|
5.41
|
|
|
$
|
5.50
|
|
|
$
|
5.48
|
|
(1)
|
$0.1 million, or $0.01 per BOE, was reclassified to third-party midstream revenues for the year ended December 31, 2015, due to our midstream business becoming a reportable segment in the third quarter of 2016. There was no such reclassification made in 2014.
|
(2)
|
$3.5 million, or $0.38 per BOE, and $1.4 million, or $0.24 per BOE, were reclassified to plant and other midstream services operating expenses for the years ended December 31, 2015 and 2014, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016.
|
(3)
|
$1.7 million and $1.2 million were reclassified to midstream services revenues for the years ended December 31, 2015 and 2014, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
(In thousands)
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
134,086
|
|
|
$
|
208,535
|
|
|
$
|
251,481
|
|
Net cash used in investing activities
|
|
(405,640
|
)
|
|
(425,154
|
)
|
|
(570,531
|
)
|
|||
Net cash provided by financing activities
|
|
467,706
|
|
|
224,944
|
|
|
321,170
|
|
|||
Net change in cash
|
|
$
|
196,152
|
|
|
$
|
8,325
|
|
|
$
|
2,120
|
|
|
|
Payments Due by Period
|
||||||||||||||||||
|
|
Total
|
|
Less Than 1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than 5 Years
|
||||||||||
(In thousands)
|
|
|
|
|
|
|
||||||||||||||
Contractual Obligations:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revolving credit borrowings, including letters of credit
(1)
|
|
$
|
821
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
821
|
|
|
$
|
—
|
|
Senior unsecured notes
(2)
|
|
575,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
575,000
|
|
|||||
Office leases
|
|
25,063
|
|
|
2,443
|
|
|
5,023
|
|
|
5,262
|
|
|
12,335
|
|
|||||
Non-operated drilling commitments
(3)
|
|
11,053
|
|
|
11,053
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Drilling rig contracts
(4)
|
|
46,295
|
|
|
26,017
|
|
|
20,278
|
|
|
—
|
|
|
—
|
|
|||||
Asset retirement obligations
|
|
20,641
|
|
|
915
|
|
|
982
|
|
|
558
|
|
|
18,186
|
|
|||||
Natural gas processing and transportation agreements
(5)
|
|
12,877
|
|
|
10,599
|
|
|
2,278
|
|
|
—
|
|
|
—
|
|
|||||
Total contractual cash obligations
|
|
$
|
691,750
|
|
|
$
|
51,027
|
|
|
$
|
28,561
|
|
|
$
|
6,641
|
|
|
$
|
605,521
|
|
(1)
|
At
December 31, 2016
, we had
no
borrowings outstanding under the Credit Agreement and approximately
$0.8 million
in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2020.
|
(2)
|
The amounts included in the table above represent principal maturities only.
|
(3)
|
At
December 31, 2016
, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and certain of these wells were in progress at
December 31, 2016
. If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately
$11.1 million
at
December 31, 2016
, which we expect to incur within the next year.
|
(4)
|
We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.
|
(5)
|
Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement for a significant portion of our operated natural gas production in South Texas. Effective October 1, 2015, we entered into a 15-year fixed-fee natural gas gathering and processing agreement for a significant portion of our operated natural gas production in Loving County, Texas. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.
|
Exhibit
Number
|
|
Description
|
|
|
|
2.1
|
|
Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company), Matador Holdco, Inc. (now known as Matador Resources Company) and Matador Merger Co., dated August 8, 2011 (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 filed on August 12, 2011).
|
|
|
|
2.2
|
|
Agreement and Plan of Merger, dated as of January 19, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 20, 2015).*
|
|
|
|
2.3
|
|
Amendment No. 1 to Agreement and Plan of Merger, dated as of January 26, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.3 to our Annual Report on Form 10-K for the year ended December 31, 2014).
|
|
|
|
2.4
|
|
Amendment No. 2 to Agreement and Plan of Merger, dated as of February 2, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.4 to our Annual Report on Form 10-K for the year ended December 31, 2014).
|
|
|
|
2.5
|
|
Amendment No. 3 to Agreement and Plan of Merger, dated as of February 6, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.5 to our Annual Report on Form 10-K for the year ended December 31, 2014).*
|
|
|
|
2.6
|
|
Amendment No. 4 to Agreement and Plan of Merger, dated as of February 27, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed on March 2, 2015).*
|
|
|
|
2.7
|
|
Amendment No. 5 to Agreement and Plan of Merger, dated as of April 15, 2015, by and among HEYCO Energy Group, Inc., Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on April 15, 2015).
|
|
|
|
2.8
|
|
Amendment No. 6 to Agreement and Plan of Merger, dated as of July 20, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).
|
|
|
|
2.9
|
|
Amendment No. 7 to Agreement and Plan of Merger, dated as of August 24, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).
|
|
|
|
2.10
|
|
Amendment No. 8 to Agreement and Plan of Merger, dated as of September 18, 2015, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).
|
|
|
|
2.11
|
|
Amendment No. 9 to Agreement and Plan of Merger, dated as of March 1, 2016, by and among HEYCO Energy Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2016).
|
|
|
|
2.12
|
|
Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 24, 2017).*
|
|
|
|
3.1
|
|
Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration Statement on Form S-1 filed on August 12, 2011).
|
|
|
|
3.2
|
|
Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 13, 2012).
|
|
|
|
3.3
|
|
Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2015).
|
|
|
|
3.4
|
|
Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 23, 2016).
|
|
|
|
3.5
|
|
Statement of Resolutions for Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on March 2, 2015).
|
|
|
|
4.1
|
|
Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to our Registration Statement on Form S-1 filed on January 19, 2012).
|
|
|
|
4.2
|
|
Registration Rights Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 2, 2015).
|
|
|
|
4.3
|
|
Voting Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc. (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on March 2, 2015).
|
|
|
|
4.4
|
|
Indenture, dated as of April 14, 2015, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 14, 2015).
|
|
|
|
4.5
|
|
First Supplemental Indenture, dated as of October 1, 2015, by and among Matador Resources Company, DLK Wolf Midstream, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on October 5, 2015).
|
|
|
|
4.6
|
|
Second Supplemental Indenture, dated as of November 4, 2015, by and among Matador Resources Company, MRC Permian LKE Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).
|
|
|
|
4.7
|
|
Third Supplemental Indenture, dated as of June 8, 2016, by and among Matador Resources Company, Black River Water Management Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on June 14, 2016).
|
|
|
|
4.8
|
|
Registration Rights Agreement, dated as of December 9, 2016, by and among Matador Resources Company, the subsidiary guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on December 9, 2016).
|
|
|
|
4.9
|
|
Fourth Supplemental Indenture, dated as of February 17, 2017, by and among Matador Resources Company, Black River Water Management Company, LLC, DLK Black River Midstream, LLC, Longwood Midstream Holdings, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on February 24, 2017).
|
|
|
|
10.1†
|
|
Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.2†
|
|
Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.3†
|
|
Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.4†
|
|
Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.5†
|
|
First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.6†
|
|
First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.7†
|
|
First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.8†
|
|
First Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.9†
|
|
Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).
|
|
|
|
10.10†
|
|
Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).
|
|
|
|
10.11†
|
|
Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).
|
|
|
|
10.12†
|
|
Second Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).
|
|
|
|
10.13†
|
|
Matador Resources Company Amended and Restated Annual Incentive Plan for Management and Key Employees (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 14, 2016).
|
|
|
|
10.14†
|
|
Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.15†
|
|
First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.16†
|
|
Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.17†
|
|
Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.18†
|
|
Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.19†
|
|
Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.20†
|
|
Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.21†
|
|
Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011).
|
|
|
|
10.22†
|
|
Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated March 8, 2013 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K for the year ended December 31, 2012).
|
|
|
|
10.23†
|
|
Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.24
|
|
Purchase, Sale and Participation Agreement, by and between Matador Resources Company (now known as MRC Energy Company) and Orca ICI Development, JV, dated at May 16, 2011 (incorporated by reference to Exhibit 10.25 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011).
|
|
|
|
10.25
|
|
First Amendment to Purchase Sale and Participation Agreement, dated as of June 12, 2013, by and between MRC Energy Company and Orca/ICI Development (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013).
|
|
|
|
10.26†
|
|
Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the year ended December 31, 2011).
|
|
|
|
10.27†
|
|
Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K for the year ended December 31, 2011).
|
|
|
|
10.28†
|
|
Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.38 to the Annual Report on Form 10-K for the year ended December 31, 2011).
|
|
|
|
10.29†
|
|
Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2011).
|
|
|
|
10.30†
|
|
Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the year ended December 31, 2011).
|
|
|
|
10.31†
|
|
Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012).
|
|
|
|
10.32†
|
|
Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012).
|
|
|
|
10.33†
|
|
Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012).
|
|
|
|
10.34†
|
|
Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012).
|
|
|
|
10.35†
|
|
Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012).
|
|
|
|
10.36†
|
|
Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012).
|
|
|
|
10.37
|
|
Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012).
|
|
|
|
10.38
|
|
Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012).
|
|
|
|
10.39
|
|
Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012).
|
|
|
|
10.40
|
|
First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012).
|
|
|
|
10.41
|
|
Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013).
|
|
|
|
10.42
|
|
Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013).
|
|
|
|
10.43
|
|
Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013).
|
|
|
|
10.44
|
|
Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014).
|
|
|
|
10.45
|
|
Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015).
|
|
|
|
10.46
|
|
Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 21, 2015).
|
|
|
|
10.47
|
|
Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 2, 2016).
|
|
|
|
10.48
|
|
Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 9, 2016).
|
|
|
|
10.49†
|
|
Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013).
|
|
|
|
10.50†
|
|
Letter Agreement between Matador Resources Company, David F. Nicklin and David F. Nicklin International Consulting, Inc., dated February 26, 2015 (incorporated by reference to Exhibit 10.51 to our Annual Report on Form 10-K for the year ended December 31, 2014).
|
|
|
|
10.51†
|
|
Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to our Annual Report on Form 10-K for the year ended December 31, 2014).
|
|
|
|
10.52†
|
|
Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to our Annual Report on Form 10-K for the year ended December 31, 2014).
|
|
|
|
10.53†
|
|
Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.55 to our Annual Report on Form 10-K for the year ended December 31, 2014).
|
|
|
|
10.54†
|
|
Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to our Annual Report on Form 10-K for the year ended December 31, 2015).
|
|
|
|
10.55†
|
|
Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to our Annual Report on Form 10-K for the year ended December 31, 2015).
|
|
|
|
10.56†
|
|
Amended and Restated Independent Contractor Agreement by and among Matador Resources Company, David F. Nicklin and David F. Nicklin International Consulting, Inc., effective as of April 1, 2015 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 11, 2015).
|
|
|
|
|
|
MATADOR RESOURCES COMPANY
|
||
|
|
|
|
|
March 1, 2017
|
|
By:
|
|
/s/ Joseph Wm. Foran
|
|
|
|
|
Joseph Wm. Foran
|
|
|
|
|
Chairman and Chief Executive Officer
|
Signature
|
|
Title
|
|
Date
|
|
|
|
||
/s/ Joseph Wm. Foran
|
|
Chairman and Chief Executive Officer
|
|
March 1, 2017
|
Joseph Wm. Foran
|
|
(Principal Executive Officer)
|
|
|
|
|
|
||
/s/ David E. Lancaster
|
|
Executive Vice President and
Chief Financial Officer
|
|
March 1, 2017
|
David E. Lancaster
|
|
(Principal Financial Officer)
|
|
|
|
|
|
||
/s/ Robert T. Macalik
|
|
Vice President and Chief Accounting
|
|
March 1, 2017
|
Robert T. Macalik
|
|
Officer (Principal Accounting Officer)
|
|
|
|
|
|
||
/s/ Reynald A. Baribault
|
|
Director
|
|
March 1, 2017
|
Reynald A. Baribault
|
|
|
|
|
|
|
|
||
/s/ R. Gaines Baty
|
|
Director
|
|
March 1, 2017
|
R. Gaines Baty
|
|
|
|
|
|
|
|
|
|
/s/ Craig T. Burkert
|
|
Director
|
|
March 1, 2017
|
Craig T. Burkert
|
|
|
|
|
|
|
|
|
|
/s/ William M. Byerley
|
|
Director
|
|
March 1, 2017
|
William M. Byerley
|
|
|
|
|
|
|
|
|
|
/s/ Joe A. Davis
|
|
Director
|
|
March 1, 2017
|
Joe A. Davis
|
|
|
|
|
|
|
|
|
|
/s/ Julia P. Forrester
|
|
Director
|
|
March 1, 2017
|
Julia P. Forrester
|
|
|
|
|
|
|
|
|
|
/s/ David M. Laney
|
|
Director
|
|
March 1, 2017
|
David M. Laney
|
|
|
|
|
|
|
|
||
/s/ Gregory E. Mitchell
|
|
Director
|
|
March 1, 2017
|
Gregory E. Mitchell
|
|
|
|
|
|
|
|
||
/s/ Steven W. Ohnimus
|
|
Director
|
|
March 1, 2017
|
Steven W. Ohnimus
|
|
|
|
|
|
|
|
|
|
/s/ Kenneth L. Stewart
|
|
Director
|
|
March 1, 2017
|
Kenneth L. Stewart
|
|
|
|
|
|
|
|
|
|
/s/ George M. Yates
|
|
Director
|
|
March 1, 2017
|
George M. Yates
|
|
|
|
|
|
|
Consolidated Financial Statements
|
|
|
|
|
|
|
|
December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash
|
|
$
|
212,884
|
|
|
$
|
16,732
|
|
Restricted cash
|
|
1,258
|
|
|
44,357
|
|
||
Accounts receivable
|
|
|
|
|
||||
Oil and natural gas revenues
|
|
34,154
|
|
|
16,616
|
|
||
Joint interest billings
|
|
19,347
|
|
|
16,999
|
|
||
Other
|
|
5,167
|
|
|
10,794
|
|
||
Derivative instruments
|
|
—
|
|
|
16,284
|
|
||
Lease and well equipment inventory
|
|
3,045
|
|
|
2,022
|
|
||
Prepaid expenses and other assets
|
|
3,327
|
|
|
3,203
|
|
||
Total current assets
|
|
279,182
|
|
|
127,007
|
|
||
Property and equipment, at cost
|
|
|
|
|
||||
Oil and natural gas properties, full-cost method
|
|
|
|
|
||||
Evaluated
|
|
2,408,305
|
|
|
2,122,174
|
|
||
Unproved and unevaluated
|
|
479,736
|
|
|
387,504
|
|
||
Other property and equipment
|
|
160,795
|
|
|
86,387
|
|
||
Less accumulated depletion, depreciation and amortization
|
|
(1,864,311
|
)
|
|
(1,583,659
|
)
|
||
Net property and equipment
|
|
1,184,525
|
|
|
1,012,406
|
|
||
Other assets
|
|
958
|
|
|
1,448
|
|
||
Total assets
|
|
$
|
1,464,665
|
|
|
$
|
1,140,861
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts payable
|
|
$
|
4,674
|
|
|
$
|
10,966
|
|
Accrued liabilities
|
|
101,460
|
|
|
92,369
|
|
||
Royalties payable
|
|
23,988
|
|
|
16,493
|
|
||
Amounts due to affiliates
|
|
8,651
|
|
|
5,670
|
|
||
Derivative instruments
|
|
24,203
|
|
|
—
|
|
||
Advances from joint interest owners
|
|
1,700
|
|
|
700
|
|
||
Deferred gain on plant sale
|
|
—
|
|
|
4,830
|
|
||
Amounts due to joint ventures
|
|
4,251
|
|
|
2,793
|
|
||
Income taxes payable
|
|
—
|
|
|
2,848
|
|
||
Other current liabilities
|
|
578
|
|
|
161
|
|
||
Total current liabilities
|
|
169,505
|
|
|
136,830
|
|
||
Long-term liabilities
|
|
|
|
|
||||
Senior unsecured notes payable
|
|
573,924
|
|
|
391,254
|
|
||
Asset retirement obligations
|
|
19,725
|
|
|
15,166
|
|
||
Derivative instruments
|
|
751
|
|
|
—
|
|
||
Amounts due to joint ventures
|
|
1,771
|
|
|
3,956
|
|
||
Deferred gain on plant sale
|
|
—
|
|
|
102,506
|
|
||
Other long-term liabilities
|
|
7,544
|
|
|
2,190
|
|
||
Total long-term liabilities
|
|
603,715
|
|
|
515,072
|
|
||
Commitments and contingencies (Note 13)
|
|
|
|
|
||||
Shareholders’ equity
|
|
|
|
|
||||
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively
|
|
995
|
|
|
856
|
|
||
Additional paid-in capital
|
|
1,325,481
|
|
|
1,026,077
|
|
||
Accumulated deficit
|
|
(636,351
|
)
|
|
(538,930
|
)
|
||
Total Matador Resources Company shareholders’ equity
|
|
690,125
|
|
|
488,003
|
|
||
Non-controlling interest in subsidiaries
|
|
1,320
|
|
|
956
|
|
||
Total shareholders’ equity
|
|
691,445
|
|
|
488,959
|
|
||
Total liabilities and shareholders’ equity
|
|
$
|
1,464,665
|
|
|
$
|
1,140,861
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues
|
|
|
|
|
|
|
||||||
Oil and natural gas revenues
|
|
$
|
291,156
|
|
|
$
|
278,340
|
|
|
$
|
367,712
|
|
Third-party midstream services revenues
|
|
5,218
|
|
|
1,864
|
|
|
1,213
|
|
|||
Realized gain on derivatives
|
|
9,286
|
|
|
77,094
|
|
|
5,022
|
|
|||
Unrealized (loss) gain on derivatives
|
|
(41,238
|
)
|
|
(39,265
|
)
|
|
58,302
|
|
|||
Total revenues
|
|
264,422
|
|
|
318,033
|
|
|
432,249
|
|
|||
Expenses
|
|
|
|
|
|
|
||||||
Production taxes, transportation and processing
|
|
43,046
|
|
|
35,650
|
|
|
33,172
|
|
|||
Lease operating
|
|
56,202
|
|
|
54,704
|
|
|
49,945
|
|
|||
Plant and other midstream services operating
|
|
5,389
|
|
|
3,489
|
|
|
1,408
|
|
|||
Depletion, depreciation and amortization
|
|
122,048
|
|
|
178,847
|
|
|
134,737
|
|
|||
Accretion of asset retirement obligations
|
|
1,182
|
|
|
734
|
|
|
504
|
|
|||
Full-cost ceiling impairment
|
|
158,633
|
|
|
801,166
|
|
|
—
|
|
|||
General and administrative
|
|
55,089
|
|
|
50,105
|
|
|
32,152
|
|
|||
Total expenses
|
|
441,589
|
|
|
1,124,695
|
|
|
251,918
|
|
|||
Operating (loss) income
|
|
(177,167
|
)
|
|
(806,662
|
)
|
|
180,331
|
|
|||
Other income (expense)
|
|
|
|
|
|
|
||||||
Net gain on asset sales and inventory impairment
|
|
107,277
|
|
|
908
|
|
|
—
|
|
|||
Interest expense
|
|
(28,199
|
)
|
|
(21,754
|
)
|
|
(5,334
|
)
|
|||
Other (expense) income
|
|
(4
|
)
|
|
616
|
|
|
132
|
|
|||
Total other income (expense)
|
|
79,074
|
|
|
(20,230
|
)
|
|
(5,202
|
)
|
|||
(Loss) income before income taxes
|
|
(98,093
|
)
|
|
(826,892
|
)
|
|
175,129
|
|
|||
Income tax provision (benefit)
|
|
|
|
|
|
|
||||||
Current
|
|
(1,036
|
)
|
|
2,959
|
|
|
133
|
|
|||
Deferred
|
|
—
|
|
|
(150,327
|
)
|
|
64,242
|
|
|||
Total income tax (benefit) provision
|
|
(1,036
|
)
|
|
(147,368
|
)
|
|
64,375
|
|
|||
Net (loss) income
|
|
(97,057
|
)
|
|
(679,524
|
)
|
|
110,754
|
|
|||
Net (income) loss attributable to non-controlling interest in subsidiaries
|
|
(364
|
)
|
|
(261
|
)
|
|
17
|
|
|||
Net (loss) income attributable to
Matador Resources Company shareholders |
|
$
|
(97,421
|
)
|
|
$
|
(679,785
|
)
|
|
$
|
110,771
|
|
Earnings (loss) per common share
|
|
|
|
|
|
|
||||||
Basic
|
|
$
|
(1.07
|
)
|
|
$
|
(8.34
|
)
|
|
$
|
1.58
|
|
Diluted
|
|
$
|
(1.07
|
)
|
|
$
|
(8.34
|
)
|
|
$
|
1.56
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
||||||
Basic
|
|
91,273
|
|
|
81,537
|
|
|
70,229
|
|
|||
Diluted
|
|
91,273
|
|
|
81,537
|
|
|
70,906
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total shareholders’ equity attributable to Matador Resources Company
|
|
|
|
|
|||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
|
|
|
|
Additional
paid-in
capital
|
|
Retained earnings (deficit
)
|
|
Treasury Stock
|
|
|
Non-controlling interest in subsidiaries
|
|
Total shareholders
’
equity
|
||||||||||||||||||||||||||||
|
|
Common Stock
|
|
Preferred Stock
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||||
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
Shares
|
|
Amount
|
|
|
|
||||||||||||||||||||||||
Balance at January 1, 2014
|
|
66,959
|
|
|
$
|
670
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
548,935
|
|
|
$
|
30,084
|
|
|
1,306
|
|
|
$
|
(10,765
|
)
|
|
$
|
568,924
|
|
|
$
|
—
|
|
|
$
|
568,924
|
|
Issuance of common stock
|
|
7,500
|
|
|
75
|
|
|
—
|
|
|
—
|
|
|
181,800
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
181,875
|
|
|
—
|
|
|
181,875
|
|
||||||||
Cost to issue equity
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(590
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(590
|
)
|
|
—
|
|
|
(590
|
)
|
||||||||
Issuance of common stock pursuant to directors’ and advisors’ compensation plan
|
|
30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
16
|
|
||||||||
Stock options expense related to equity-based awards
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,279
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,279
|
|
|
—
|
|
|
2,279
|
|
||||||||
Stock options exercised, net of options forfeited in net share settlements
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
—
|
|
|
43
|
|
||||||||
Liability-based stock option awards settled
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
84
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
84
|
|
|
—
|
|
|
84
|
|
||||||||
Restricted stock issued
|
|
212
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Restricted stock forfeited
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
—
|
|
|
60
|
|
|
—
|
|
|
(17
|
)
|
|
—
|
|
|
(17
|
)
|
||||||||
Restricted stock and restricted stock units expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,023
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,023
|
|
|
—
|
|
|
3,023
|
|
||||||||
Cancellation of treasury stock
|
|
(1,335
|
)
|
|
(13
|
)
|
|
—
|
|
|
—
|
|
|
(10,752
|
)
|
|
—
|
|
|
(1,335
|
)
|
|
10,765
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Capital contributed to less-than-wholly-owned subsidiaries
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150
|
|
|
150
|
|
||||||||
Current period net income (loss)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
110,771
|
|
|
—
|
|
|
—
|
|
|
110,771
|
|
|
(17
|
)
|
|
110,754
|
|
||||||||
Balance at December 31, 2014
|
|
73,374
|
|
|
734
|
|
|
—
|
|
|
—
|
|
|
724,819
|
|
|
140,855
|
|
|
31
|
|
|
—
|
|
|
866,408
|
|
|
133
|
|
|
866,541
|
|
||||||||
Issuance of common stock
|
|
10,329
|
|
|
104
|
|
|
—
|
|
|
—
|
|
|
260,148
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
260,252
|
|
|
—
|
|
|
260,252
|
|
||||||||
Issuance of preferred stock
|
|
—
|
|
|
—
|
|
|
150
|
|
|
1
|
|
|
32,489
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32,490
|
|
|
—
|
|
|
32,490
|
|
||||||||
Cost to issue equity
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,151
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,151
|
)
|
|
—
|
|
|
(1,151
|
)
|
||||||||
Conversion of preferred stock to common stock
|
|
1,500
|
|
|
15
|
|
|
(150
|
)
|
|
(1
|
)
|
|
(14
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Stock-based compensation expense related to equity-based awards
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,333
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,333
|
|
|
—
|
|
|
9,333
|
|
||||||||
Stock options exercised, net of options forfeited in net share settlements
|
|
25
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
||||||||
Liability-based stock option awards settled
|
|
25
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
446
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
446
|
|
|
—
|
|
|
446
|
|
||||||||
Restricted stock issued
|
|
429
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Restricted stock forfeited
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
138
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Vesting of restricted stock units
|
|
52
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Cancellation of treasury stock
|
|
(167
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
(167
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Capital contributed from less-than-wholly-owned subsidiaries
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
562
|
|
|
562
|
|
||||||||
Current period net (loss) income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(679,785
|
)
|
|
—
|
|
|
—
|
|
|
(679,785
|
)
|
|
261
|
|
|
(679,524
|
)
|
||||||||
Balance at December 31, 2015
|
|
85,567
|
|
|
856
|
|
|
—
|
|
|
—
|
|
|
1,026,077
|
|
|
(538,930
|
)
|
|
2
|
|
|
—
|
|
|
488,003
|
|
|
956
|
|
|
488,959
|
|
||||||||
Issuance of common stock pursuant to public offerings
|
|
13,500
|
|
|
135
|
|
|
—
|
|
|
—
|
|
|
288,375
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
288,510
|
|
|
—
|
|
|
288,510
|
|
||||||||
Issuance of common stock pursuant to employee stock compensation plan
|
|
471
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Issuance of common stock pursuant to directors’ and advisors’ compensation plan
|
|
51
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Cost to issue equity
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,190
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,190
|
)
|
|
—
|
|
|
(1,190
|
)
|
||||||||
Stock-based compensation expense related to equity-based awards
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,958
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,958
|
|
|
—
|
|
|
11,958
|
|
||||||||
Stock options exercised, net of options forfeited in net share settlements
|
|
36
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
||||||||
Liability-based stock option awards settled
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
255
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
255
|
|
|
—
|
|
|
255
|
|
||||||||
Restricted stock forfeited
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
120
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Cancellation of treasury stock
|
|
(116
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(116
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Current period net (loss) income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(97,421
|
)
|
|
—
|
|
|
—
|
|
|
(97,421
|
)
|
|
364
|
|
|
(97,057
|
)
|
||||||||
Balance at December 31, 2016
|
|
99,519
|
|
|
$
|
995
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
1,325,481
|
|
|
$
|
(636,351
|
)
|
|
6
|
|
|
$
|
—
|
|
|
$
|
690,125
|
|
|
$
|
1,320
|
|
|
$
|
691,445
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Operating activities
|
|
|
|
|
|
|
||||||
Net (loss) income
|
|
$
|
(97,057
|
)
|
|
$
|
(679,524
|
)
|
|
$
|
110,754
|
|
Adjustments to reconcile net (loss) income to net cash provided by operating activities
|
|
|
|
|
|
|
||||||
Unrealized loss (gain) on derivatives
|
|
41,238
|
|
|
39,265
|
|
|
(58,302
|
)
|
|||
Depletion, depreciation and amortization
|
|
122,048
|
|
|
178,847
|
|
|
134,737
|
|
|||
Accretion of asset retirement obligations
|
|
1,182
|
|
|
734
|
|
|
504
|
|
|||
Full-cost ceiling impairment
|
|
158,633
|
|
|
801,166
|
|
|
—
|
|
|||
Stock-based compensation expense
|
|
12,362
|
|
|
9,450
|
|
|
5,524
|
|
|||
Deferred income tax (benefit) provision
|
|
—
|
|
|
(150,327
|
)
|
|
64,242
|
|
|||
Amortization of debt issuance cost
|
|
1,148
|
|
|
852
|
|
|
—
|
|
|||
Net gain on asset sales and inventory impairment
|
|
(107,277
|
)
|
|
(908
|
)
|
|
—
|
|
|||
Changes in operating assets and liabilities
|
|
|
|
|
|
|
||||||
Accounts receivable
|
|
(14,259
|
)
|
|
3,633
|
|
|
(13,318
|
)
|
|||
Lease and well equipment inventory
|
|
(700
|
)
|
|
(180
|
)
|
|
(211
|
)
|
|||
Prepaid expenses
|
|
(124
|
)
|
|
(544
|
)
|
|
(783
|
)
|
|||
Other assets
|
|
490
|
|
|
(552
|
)
|
|
1,212
|
|
|||
Accounts payable, accrued liabilities and other current liabilities
|
|
6,611
|
|
|
1,375
|
|
|
607
|
|
|||
Royalties payable
|
|
7,495
|
|
|
1,654
|
|
|
6,663
|
|
|||
Advances from joint interest owners
|
|
1,000
|
|
|
700
|
|
|
—
|
|
|||
Income taxes payable
|
|
(2,848
|
)
|
|
2,405
|
|
|
39
|
|
|||
Other long-term liabilities
|
|
4,144
|
|
|
489
|
|
|
(187
|
)
|
|||
Net cash provided by operating activities
|
|
134,086
|
|
|
208,535
|
|
|
251,481
|
|
|||
Investing activities
|
|
|
|
|
|
|
||||||
Proceeds from sale of assets
|
|
5,173
|
|
|
139,836
|
|
|
79
|
|
|||
Oil and natural gas properties capital expenditures
|
|
(379,067
|
)
|
|
(432,715
|
)
|
|
(560,849
|
)
|
|||
Expenditures for other property and equipment
|
|
(74,845
|
)
|
|
(64,499
|
)
|
|
(9,152
|
)
|
|||
Business combination, net of cash acquired
|
|
—
|
|
|
(24,028
|
)
|
|
—
|
|
|||
Restricted cash
|
|
43,098
|
|
|
(43,098
|
)
|
|
—
|
|
|||
Restricted cash in less-than-wholly-owned subsidiaries
|
|
1
|
|
|
(650
|
)
|
|
(609
|
)
|
|||
Net cash used in investing activities
|
|
(405,640
|
)
|
|
(425,154
|
)
|
|
(570,531
|
)
|
|||
Financing activities
|
|
|
|
|
|
|
||||||
Repayments of borrowings
|
|
(120,000
|
)
|
|
(476,982
|
)
|
|
(180,000
|
)
|
|||
Borrowings under Credit Agreement
|
|
120,000
|
|
|
125,000
|
|
|
320,000
|
|
|||
Proceeds from issuance of common stock
|
|
288,510
|
|
|
188,720
|
|
|
181,875
|
|
|||
Proceeds from issuance of senior unsecured notes
|
|
184,625
|
|
|
400,000
|
|
|
—
|
|
|||
Cost to issue equity
|
|
(847
|
)
|
|
(1,158
|
)
|
|
(590
|
)
|
|||
Cost to issue senior unsecured notes
|
|
(2,734
|
)
|
|
(9,598
|
)
|
|
—
|
|
|||
Proceeds from stock options exercised
|
|
100
|
|
|
10
|
|
|
43
|
|
|||
Capital commitments from non-controlling interest owners of less-than-wholly-owned subsidiaries
|
|
—
|
|
|
562
|
|
|
150
|
|
|||
Taxes paid related to net share settlement of stock-based compensation
|
|
(1,948
|
)
|
|
(1,610
|
)
|
|
(308
|
)
|
|||
Net cash provided by financing activities
|
|
467,706
|
|
|
224,944
|
|
|
321,170
|
|
|||
Increase in cash
|
|
196,152
|
|
|
8,325
|
|
|
2,120
|
|
|||
Cash at beginning of year
|
|
16,732
|
|
|
8,407
|
|
|
6,287
|
|
|||
Cash at end of year
|
|
$
|
212,884
|
|
|
$
|
16,732
|
|
|
$
|
8,407
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net (loss) income attributable to Matador Resources Company shareholders — numerator
|
|
$
|
(97,421
|
)
|
|
$
|
(679,785
|
)
|
|
$
|
110,771
|
|
|
|
|
|
|
|
|
||||||
Weighted average common shares outstanding — denominator
|
|
|
|
|
|
|
||||||
Basic
|
|
91,273
|
|
|
81,537
|
|
|
70,229
|
|
|||
Dilutive effect of options, restricted stock units and preferred shares
|
|
—
|
|
|
—
|
|
|
677
|
|
|||
Diluted weighted average common shares outstanding
|
|
91,273
|
|
|
81,537
|
|
|
70,906
|
|
|||
Earnings (loss) per common share attributable to
Matador Resources Company shareholders |
|
|
|
|
|
|
||||||
Basic
|
|
$
|
(1.07
|
)
|
|
$
|
(8.34
|
)
|
|
$
|
1.58
|
|
Diluted
|
|
$
|
(1.07
|
)
|
|
$
|
(8.34
|
)
|
|
$
|
1.56
|
|
|
|
December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
Oil and natural gas properties
|
|
|
|
|
||||
Evaluated (subject to amortization)
|
|
$
|
2,408,305
|
|
|
$
|
2,122,174
|
|
Unproved and unevaluated (not subject to amortization)
|
|
479,736
|
|
|
387,504
|
|
||
Total oil and natural gas properties
|
|
2,888,041
|
|
|
2,509,678
|
|
||
Accumulated depletion
|
|
(1,850,882
|
)
|
|
(1,574,040
|
)
|
||
Net oil and natural gas properties
|
|
1,037,159
|
|
|
935,638
|
|
||
Other property and equipment
|
|
|
|
|
||||
Midstream equipment and facilities
|
|
145,662
|
|
|
78,564
|
|
||
Furniture, fixtures and other equipment
|
|
5,487
|
|
|
2,918
|
|
||
Software
|
|
3,206
|
|
|
2,193
|
|
||
Land
|
|
1,437
|
|
|
1,539
|
|
||
Leasehold improvements
|
|
5,003
|
|
|
1,173
|
|
||
Total other property and equipment
|
|
160,795
|
|
|
86,387
|
|
||
Accumulated depreciation
|
|
(13,429
|
)
|
|
(9,619
|
)
|
||
Net other property and equipment
|
|
147,366
|
|
|
76,768
|
|
||
Net property and equipment
|
|
$
|
1,184,525
|
|
|
$
|
1,012,406
|
|
Description
|
|
2016
|
|
2015
|
|
2014
|
|
2013 and prior
|
|
Total
|
||||||||||
Costs incurred for
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Property acquisition
|
|
$
|
126,857
|
|
|
$
|
236,507
|
|
|
$
|
55,258
|
|
|
$
|
23,654
|
|
|
$
|
442,276
|
|
Exploration wells
|
|
19,017
|
|
|
3,375
|
|
|
34
|
|
|
—
|
|
|
22,426
|
|
|||||
Development wells
|
|
13,086
|
|
|
1,218
|
|
|
730
|
|
|
—
|
|
|
15,034
|
|
|||||
Total
|
|
$
|
158,960
|
|
|
$
|
241,100
|
|
|
$
|
56,022
|
|
|
$
|
23,654
|
|
|
$
|
479,736
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
Beginning asset retirement obligations
|
|
$
|
15,420
|
|
|
$
|
11,951
|
|
Liabilities incurred during period
|
|
1,791
|
|
|
4,508
|
|
||
Liabilities settled during period
|
|
(375
|
)
|
|
(588
|
)
|
||
Revisions in estimated cash flows
|
|
2,622
|
|
|
(1,185
|
)
|
||
Accretion expense
|
|
1,182
|
|
|
734
|
|
||
Ending asset retirement obligations
|
|
20,640
|
|
|
15,420
|
|
||
Less: current asset retirement obligations
(1)
|
|
(915
|
)
|
|
(254
|
)
|
||
Long-term asset retirement obligations
|
|
$
|
19,725
|
|
|
$
|
15,166
|
|
(1)
|
Included in accrued liabilities in the Company’s consolidated balance sheets at
December 31, 2016 and 2015
.
|
•
|
incur indebtedness or grant liens on any of the Company’s assets;
|
•
|
enter into commodity hedging agreements;
|
•
|
declare or pay dividends, distributions or redemptions;
|
•
|
merge or consolidate;
|
•
|
make any loans or investments;
|
•
|
engage in transactions with affiliates;
|
•
|
engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and
|
•
|
take certain actions with respect to the Company’s senior unsecured notes.
|
•
|
failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods;
|
•
|
failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;
|
•
|
bankruptcy or insolvency events involving the Company or its subsidiaries; and
|
•
|
a change of control, as defined in the Credit Agreement.
|
Year
|
|
Redemption Price
|
2018
|
|
105.156%
|
2019
|
|
103.438%
|
2020
|
|
101.719%
|
2021 and thereafter
|
|
100.000%
|
•
|
incur or guarantee additional debt or issue certain types of preferred stock;
|
•
|
pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness;
|
•
|
transfer or sell assets;
|
•
|
make certain investments;
|
•
|
create certain liens;
|
•
|
enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as defined in the Indenture) to the Company;
|
•
|
consolidate, merge or transfer all or substantially all of its assets;
|
•
|
engage in transactions with affiliates; and
|
•
|
create unrestricted subsidiaries.
|
•
|
default for
30
days in the payment when due of interest on the Notes;
|
•
|
default in the payment when due of the principal of, or premium, if any, on the Notes;
|
•
|
failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply with the covenant relating to merger, consolidation or sale of assets;
|
•
|
failure by Matador for
180
days after notice to comply with its reporting obligations under the Indenture;
|
•
|
failure by Matador for
60
days after notice to comply with any of the other agreements in the Indenture;
|
•
|
payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted Subsidiaries in the aggregate principal amount of
$25.0 million
or more;
|
•
|
failure by Matador or any Restricted Subsidiary to pay certain final judgments aggregating in excess of
$25.0 million
within
60
days;
|
•
|
any subsidiary guarantee by a guarantor ceasing to be in full force and effect, being declared null and void in a judicial proceeding or being denied or disaffirmed by its maker; and
|
•
|
certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.
|
|
|
December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
Deferred tax assets
|
|
|
|
|
||||
Unrealized loss on derivatives
|
|
$
|
8,734
|
|
|
$
|
—
|
|
Net operating loss carryforwards
|
|
137,757
|
|
|
79,208
|
|
||
Alternative minimum tax carryforward
|
|
8,633
|
|
|
9,785
|
|
||
Percentage depletion carryover
|
|
2,595
|
|
|
2,442
|
|
||
Property and equipment
|
|
44,391
|
|
|
42,757
|
|
||
Deferred gain on sale leaseback transaction
|
|
—
|
|
|
32,831
|
|
||
Other
|
|
—
|
|
|
7,396
|
|
||
Total deferred tax assets
|
|
202,110
|
|
|
174,419
|
|
||
Valuation allowance on deferred tax assets
|
|
(190,255
|
)
|
|
(154,320
|
)
|
||
Total deferred tax assets, net of valuation allowance
|
|
11,855
|
|
|
20,099
|
|
||
Deferred tax liabilities
|
|
|
|
|
||||
Unrealized gain on derivatives
|
|
(3,800
|
)
|
|
(5,699
|
)
|
||
Other
|
|
(8,055
|
)
|
|
(14,400
|
)
|
||
Total deferred tax liabilities
|
|
(11,855
|
)
|
|
(20,099
|
)
|
||
Net deferred tax liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Current income tax provision
|
|
|
|
|
|
|
||||||
State income tax
|
|
$
|
108
|
|
|
$
|
371
|
|
|
$
|
—
|
|
Federal alternative minimum tax
|
|
(1,144
|
)
|
|
2,588
|
|
|
133
|
|
|||
Net current income tax (benefit) provision
|
|
$
|
(1,036
|
)
|
|
$
|
2,959
|
|
|
$
|
133
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Federal tax (benefit) expense at statutory rate
(1)
|
|
$
|
(34,333
|
)
|
|
$
|
(289,412
|
)
|
|
$
|
61,301
|
|
State income tax
|
|
539
|
|
|
(13,215
|
)
|
|
2,707
|
|
|||
Permanent differences
(2)
|
|
(499
|
)
|
|
698
|
|
|
397
|
|
|||
Federal alternative minimum tax
|
|
1,144
|
|
|
(2,588
|
)
|
|
(133
|
)
|
|||
Change in federal valuation allowance
|
|
33,688
|
|
|
145,777
|
|
|
—
|
|
|||
Change in state valuation allowance
|
|
(539
|
)
|
|
8,413
|
|
|
(30
|
)
|
|||
Net deferred income tax (benefit) provision
|
|
—
|
|
|
(150,327
|
)
|
|
64,242
|
|
|||
Net current income tax (benefit) provision
|
|
(1,036
|
)
|
|
2,959
|
|
|
133
|
|
|||
Total income tax (benefit) provision
|
|
$
|
(1,036
|
)
|
|
$
|
(147,368
|
)
|
|
$
|
64,375
|
|
(1)
|
The statutory federal tax rate was
35%
for the years ended
December 31, 2016, 2015 and 2014
.
|
(2)
|
Amount is primarily attributable to stock-based compensation.
|
|
|
2016
|
|
2015
|
|
2014
|
Stock option pricing model
|
|
Black Scholes Merton
|
|
Black Scholes Merton
|
|
Black Scholes Merton
|
Expected option life
|
|
3.14 years
|
|
0.39 years
|
|
1.51 years
|
Risk-free interest rate
|
|
1.70%
|
|
0.64%
|
|
0.74%
|
Volatility
|
|
47.07%
|
|
91.98%
|
|
55.14%
|
Dividend yield
|
|
—%
|
|
—%
|
|
—%
|
Estimated forfeiture rate
|
|
—%
|
|
—%
|
|
—%
|
|
|
2016
|
|
2015
|
|
2014
|
Stock option pricing model
|
|
Black Scholes Merton
|
|
Black Scholes Merton
|
|
Black Scholes Merton
|
Expected option life
|
|
3.96 years
|
|
4.00 years
|
|
3.99 years
|
Risk-free interest rate
|
|
1.08%
|
|
1.15%
|
|
1.21%
|
Volatility
|
|
45.68%
|
|
56.89%
|
|
51.47%
|
Dividend yield
|
|
—%
|
|
—%
|
|
—%
|
Estimated forfeiture rate
|
|
1.16%
|
|
3.21%
|
|
4.28%
|
Weighted average fair value of stock option awards granted during the year
|
|
$5.65
|
|
$9.90
|
|
$9.45
|
|
|
Number of
options
(in thousands)
|
|
Weighted
average
exercise price
|
|||
Options outstanding at December 31, 2015
|
|
2,363
|
|
|
$
|
15.40
|
|
Options granted
|
|
668
|
|
|
$
|
15.51
|
|
Options exercised
|
|
(114
|
)
|
|
$
|
10.12
|
|
Options forfeited
|
|
(28
|
)
|
|
$
|
19.73
|
|
Options expired
|
|
(2
|
)
|
|
$
|
22.66
|
|
Options outstanding at December 31, 2016
|
|
2,887
|
|
|
$
|
15.59
|
|
|
|
Options outstanding at
December 31, 2016
|
|
Options exercisable at
December 31, 2016
|
||||||||||||
Range of exercise prices
|
|
Shares
outstanding
(in thousands)
|
|
Weighted
average
remaining
contractual
life
|
|
Weighted
average
exercise
price
|
|
Shares
exercisable
(in thousands)
|
|
Weighted
average
exercise
price
|
||||||
$8.18 - $9.55
|
|
816
|
|
|
1.30
|
|
$
|
8.30
|
|
|
484
|
|
|
$
|
8.35
|
|
$10.49 - $17.80
|
|
925
|
|
|
2.87
|
|
$
|
13.55
|
|
|
302
|
|
|
$
|
10.58
|
|
$18.77 - $22.70
|
|
862
|
|
|
3.05
|
|
$
|
21.84
|
|
|
65
|
|
|
$
|
21.21
|
|
$23.40 - $27.33
|
|
284
|
|
|
2.26
|
|
$
|
24.22
|
|
|
112
|
|
|
$
|
23.49
|
|
|
|
Restricted Stock
|
|
Restricted Stock Units
|
||||||||||
Non-vested restricted stock and
restricted stock units
|
|
Shares
|
|
Weighted
average
fair
value
|
|
Shares
|
|
Weighted
average
fair
value
|
||||||
Non-vested at December 31, 2015
|
|
854
|
|
|
$
|
17.64
|
|
|
68
|
|
|
$
|
21.89
|
|
Granted
|
|
472
|
|
|
$
|
18.55
|
|
|
66
|
|
|
$
|
19.44
|
|
Vested
|
|
(225
|
)
|
|
$
|
16.05
|
|
|
(52
|
)
|
|
$
|
19.67
|
|
Forfeited
|
|
(62
|
)
|
|
$
|
20.49
|
|
|
—
|
|
|
—
|
|
|
Non-vested at December 31, 2016
|
|
1,039
|
|
|
$
|
18.23
|
|
|
82
|
|
|
$
|
21.32
|
|
|
|
|
|
Notional Quantity (Bbl or MMBtu)
|
|
Weighted Average Price Floor ($/Bbl or
$/MMBtu) |
|
Weighted Average Price Ceiling ($/Bbl or
$/MMBtu) |
|
Fair Value of Liabilities (thousands)
|
|||||||
|
|
|
|
|
|
|
|||||||||||
Commodity
|
|
Calculation Period
|
|
|
|
|
|||||||||||
Oil
|
|
01/01/2017 - 12/31/2017
|
|
2,760,000
|
|
|
$
|
41.39
|
|
|
$
|
51.88
|
|
|
$
|
(18,316
|
)
|
Oil
|
|
01/01/2018 - 12/31/2018
|
|
720,000
|
|
|
$
|
43.75
|
|
|
$
|
63.90
|
|
|
(751
|
)
|
|
Natural Gas
|
|
01/01/2017 - 12/31/2017
|
|
16,860,000
|
|
|
$
|
2.40
|
|
|
$
|
3.59
|
|
|
(5,887
|
)
|
|
Total open derivative financial instruments
|
|
|
|
|
|
|
|
$
|
(24,954
|
)
|
Derivative Instruments
|
Gross amounts recognized
|
|
Gross amounts netted in the consolidated balance sheets
|
|
Net amounts presented in the consolidated balance sheets
|
||||||
December 31, 2016
|
|
|
|
|
|
||||||
Current liabilities
|
$
|
(24,203
|
)
|
|
$
|
—
|
|
|
$
|
(24,203
|
)
|
Other liabilities
|
(751
|
)
|
|
—
|
|
|
(751
|
)
|
|||
Total
|
$
|
(24,954
|
)
|
|
$
|
—
|
|
|
$
|
(24,954
|
)
|
December 31, 2015
|
|
|
|
|
|
||||||
Current assets
|
$
|
16,767
|
|
|
$
|
(483
|
)
|
|
$
|
16,284
|
|
Current liabilities
|
(483
|
)
|
|
483
|
|
|
—
|
|
|||
Total
|
$
|
16,284
|
|
|
$
|
—
|
|
|
$
|
16,284
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
Type of Instrument
|
Location in Statement of Operations
|
2016
|
|
2015
|
|
2014
|
||||||||
Derivative Instrument
|
|
|
|
|
|
|
|
|
||||||
Oil
|
|
Revenues: Realized gain on derivatives
|
|
$
|
5,851
|
|
|
$
|
62,259
|
|
|
$
|
5,221
|
|
Natural Gas
|
|
Revenues: Realized gain (loss) on derivatives
|
|
3,435
|
|
|
12,653
|
|
|
(718
|
)
|
|||
Natural Gas Liquids (NGL)
|
|
Revenues: Realized gain on derivatives
|
|
—
|
|
|
2,182
|
|
|
519
|
|
|||
Realized gain on derivatives
|
|
|
|
9,286
|
|
|
77,094
|
|
|
5,022
|
|
|||
Oil
|
|
Revenues: Unrealized (loss) gain on derivatives
|
|
(18,969
|
)
|
|
(31,897
|
)
|
|
47,178
|
|
|||
Natural Gas
|
|
Revenues: Unrealized (loss) gain on derivatives
|
|
(22,269
|
)
|
|
(5,440
|
)
|
|
9,087
|
|
|||
Natural Gas Liquids (NGL)
|
|
Revenues: Unrealized (loss) gain on derivatives
|
|
—
|
|
|
(1,928
|
)
|
|
2,037
|
|
|||
Unrealized (loss) gain on derivatives
|
|
|
|
(41,238
|
)
|
|
(39,265
|
)
|
|
58,302
|
|
|||
Total
|
|
|
|
$
|
(31,952
|
)
|
|
$
|
37,829
|
|
|
$
|
63,324
|
|
Level 1
|
Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.
|
Level 2
|
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
|
Level 3
|
Unobservable inputs that are not corroborated by market data which reflect a company’s own market assumptions.
|
|
|
Fair Value Measurements at
December 31, 2016 using |
||||||||||||||
Description
|
|
|||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|||||||||
Assets (Liabilities)
|
|
|
|
|
|
|
|
|
||||||||
Oil and natural gas derivatives
|
|
$
|
—
|
|
|
$
|
(24,954
|
)
|
|
$
|
—
|
|
|
$
|
(24,954
|
)
|
Total
|
|
$
|
—
|
|
|
$
|
(24,954
|
)
|
|
$
|
—
|
|
|
$
|
(24,954
|
)
|
|
|
Fair Value Measurements at
December 31, 2015 using |
||||||||||||||
Description
|
|
|||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|||||||||
Assets (Liabilities)
|
|
|
|
|
|
|
|
|
||||||||
Oil and natural gas derivatives
|
|
$
|
—
|
|
|
$
|
16,284
|
|
|
$
|
—
|
|
|
$
|
16,284
|
|
Total
|
|
$
|
—
|
|
|
$
|
16,284
|
|
|
$
|
—
|
|
|
$
|
16,284
|
|
|
|
December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
Accrued evaluated and unproved and unevaluated property costs
|
|
$
|
54,273
|
|
|
$
|
54,586
|
|
Accrued support equipment and facilities costs
|
|
15,139
|
|
|
17,393
|
|
||
Accrued lease operating expenses
|
|
16,009
|
|
|
7,743
|
|
||
Accrued interest on debt
|
|
6,541
|
|
|
5,806
|
|
||
Accrued asset retirement obligations
|
|
915
|
|
|
254
|
|
||
Accrued partners’ share of joint interest charges
|
|
5,572
|
|
|
4,565
|
|
||
Other
|
|
3,011
|
|
|
2,022
|
|
||
Total accrued liabilities
|
|
$
|
101,460
|
|
|
$
|
92,369
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Cash paid for income taxes
|
|
$
|
2,895
|
|
|
$
|
506
|
|
|
$
|
94
|
|
Cash paid for interest expense, net of amounts capitalized
|
|
27,464
|
|
|
16,154
|
|
|
5,269
|
|
|||
Increase in asset retirement obligations related to mineral properties
|
|
3,817
|
|
|
2,510
|
|
|
3,843
|
|
|||
Increase in asset retirement obligations related to support equipment and facilities
|
|
222
|
|
|
383
|
|
|
120
|
|
|||
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures
|
|
1,775
|
|
|
(30,683
|
)
|
|
32,972
|
|
|||
(Decrease) increase in liabilities for support equipment and facilities
|
|
(588
|
)
|
|
12,076
|
|
|
4,290
|
|
|||
Issuance of restricted stock units for Board and advisor services
|
|
992
|
|
|
584
|
|
|
444
|
|
|||
Stock-based compensation expense recognized as liability
|
|
569
|
|
|
79
|
|
|
223
|
|
|||
Increase in liabilities for accrued cost to issue equity
|
|
343
|
|
|
—
|
|
|
—
|
|
|||
Transfer of inventory to oil and natural gas properties
|
|
395
|
|
|
615
|
|
|
216
|
|
|
Exploration and Production
|
|
|
|
|
|
|
|
Consolidated Company
|
||||||||||
|
|
Midstream
|
|
Corporate
|
|
Eliminations
|
|
||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas revenues
|
$
|
289,512
|
|
|
$
|
1,644
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
291,156
|
|
Midstream services revenues
|
—
|
|
|
18,982
|
|
|
—
|
|
|
(13,764
|
)
|
|
5,218
|
|
|||||
Realized gain on derivatives
|
9,286
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,286
|
|
|||||
Unrealized gain on derivatives
|
(41,238
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(41,238
|
)
|
|||||
Expenses
(1)
|
391,098
|
|
|
8,254
|
|
|
56,001
|
|
|
(13,764
|
)
|
|
441,589
|
|
|||||
Operating (loss) income
(2)
|
$
|
(133,538
|
)
|
|
$
|
12,372
|
|
|
$
|
(56,001
|
)
|
|
$
|
—
|
|
|
$
|
(177,167
|
)
|
Total Assets
|
$
|
1,098,525
|
|
|
$
|
140,459
|
|
|
$
|
225,681
|
|
|
$
|
—
|
|
|
$
|
1,464,665
|
|
Capital Expenditures
|
$
|
379,881
|
|
|
$
|
67,566
|
|
|
$
|
6,913
|
|
|
$
|
—
|
|
|
$
|
454,360
|
|
|
Exploration and Production
|
|
|
|
|
|
|
|
Consolidated Company
|
||||||||||
|
|
Midstream
|
|
Corporate
|
|
Eliminations
|
|
||||||||||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas revenues
|
$
|
277,844
|
|
|
$
|
496
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
278,340
|
|
Midstream services revenues
|
—
|
|
|
11,485
|
|
|
—
|
|
|
(9,621
|
)
|
|
1,864
|
|
|||||
Realized gain on derivatives
|
77,094
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
77,094
|
|
|||||
Unrealized loss on derivatives
|
(39,265
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39,265
|
)
|
|||||
Expenses
(1)
|
1,078,534
|
|
|
5,178
|
|
|
50,604
|
|
|
(9,621
|
)
|
|
1,124,695
|
|
|||||
Operating (loss) income
(2)
|
$
|
(762,861
|
)
|
|
$
|
6,803
|
|
|
$
|
(50,604
|
)
|
|
$
|
—
|
|
|
$
|
(806,662
|
)
|
Total Assets
|
$
|
1,000,075
|
|
|
$
|
75,980
|
|
|
$
|
64,806
|
|
|
$
|
—
|
|
|
$
|
1,140,861
|
|
Capital Expenditures
(3)
|
$
|
622,642
|
|
|
$
|
75,009
|
|
|
$
|
786
|
|
|
$
|
—
|
|
|
$
|
698,437
|
|
|
Exploration and Production
|
|
|
|
|
|
|
|
Consolidated Company
|
||||||||||
|
|
Midstream
|
|
Corporate
|
|
Eliminations
|
|
||||||||||||
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas revenues
|
$
|
366,191
|
|
|
$
|
1,521
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
367,712
|
|
Midstream services revenues
|
—
|
|
|
4,929
|
|
|
—
|
|
|
(3,716
|
)
|
|
1,213
|
|
|||||
Realized gain on derivatives
|
5,022
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,022
|
|
|||||
Unrealized loss on derivatives
|
58,302
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
58,302
|
|
|||||
Expenses
(1)
|
220,374
|
|
|
2,703
|
|
|
32,557
|
|
|
(3,716
|
)
|
|
251,918
|
|
|||||
Operating (loss) income
(2)
|
$
|
209,141
|
|
|
$
|
3,747
|
|
|
$
|
(32,557
|
)
|
|
$
|
—
|
|
|
$
|
180,331
|
|
Total Assets
|
$
|
1,388,261
|
|
|
$
|
35,100
|
|
|
$
|
11,129
|
|
|
$
|
—
|
|
|
$
|
1,434,490
|
|
Capital Expenditures
|
$
|
597,351
|
|
|
$
|
12,504
|
|
|
$
|
517
|
|
|
$
|
—
|
|
|
$
|
610,372
|
|
|
|
December 31, 2016
|
||||||||||
|
|
As Reported
|
|
Adjustment
|
|
Pro Forma
|
||||||
ASSETS
|
|
|
|
|
|
|
||||||
Current assets
|
|
|
|
|
|
|
||||||
Cash
|
|
$
|
212,884
|
|
|
$
|
164,340
|
|
(1)
|
$
|
377,224
|
|
Restricted cash
|
|
1,258
|
|
|
9,407
|
|
(2)
|
10,665
|
|
|||
Accounts receivable
|
|
|
|
|
|
—
|
|
|||||
Oil and natural gas revenues
|
|
34,154
|
|
|
—
|
|
|
34,154
|
|
|||
Joint interest billings
|
|
19,347
|
|
|
—
|
|
|
19,347
|
|
|||
Other
|
|
5,167
|
|
|
—
|
|
|
5,167
|
|
|||
Lease and well equipment inventory
|
|
3,045
|
|
|
—
|
|
|
3,045
|
|
|||
Prepaid expenses and other assets
|
|
3,327
|
|
|
—
|
|
|
3,327
|
|
|||
Total current assets
|
|
279,182
|
|
|
173,747
|
|
|
452,929
|
|
|||
Property and equipment, at cost
|
|
|
|
|
|
|
||||||
Oil and natural gas properties, full-cost method
|
|
|
|
|
|
|
||||||
Evaluated
|
|
2,408,305
|
|
|
—
|
|
|
2,408,305
|
|
|||
Unproved and unevaluated
|
|
479,736
|
|
|
—
|
|
|
479,736
|
|
|||
Other property and equipment
|
|
160,795
|
|
|
—
|
|
|
160,795
|
|
|||
Less accumulated depletion, depreciation and amortization
|
|
(1,864,311
|
)
|
|
—
|
|
|
(1,864,311
|
)
|
|||
Net property and equipment
|
|
1,184,525
|
|
|
—
|
|
|
1,184,525
|
|
|||
Other assets
|
|
958
|
|
|
|
|
958
|
|
||||
Total assets
|
|
$
|
1,464,665
|
|
|
$
|
173,747
|
|
|
$
|
1,638,412
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
||||||
Current liabilities
|
|
|
|
|
|
|
||||||
Accounts payable
|
|
$
|
4,674
|
|
|
$
|
—
|
|
|
$
|
4,674
|
|
Accrued liabilities
|
|
101,460
|
|
|
—
|
|
|
101,460
|
|
|||
Royalties payable
|
|
23,988
|
|
|
—
|
|
|
23,988
|
|
|||
Amounts due to affiliates
|
|
8,651
|
|
|
—
|
|
|
8,651
|
|
|||
Derivative instruments
|
|
24,203
|
|
|
—
|
|
|
24,203
|
|
|||
Advances from joint interest owners
|
|
1,700
|
|
|
—
|
|
|
1,700
|
|
|||
Amounts due to joint ventures
|
|
4,251
|
|
|
—
|
|
|
4,251
|
|
|||
Other current liabilities
|
|
578
|
|
|
—
|
|
|
578
|
|
|||
Total current liabilities
|
|
169,505
|
|
|
—
|
|
|
169,505
|
|
|||
Long-term liabilities
|
|
|
|
|
|
|
||||||
Senior unsecured notes payable
|
|
573,924
|
|
|
—
|
|
|
573,924
|
|
|||
Asset retirement obligations
|
|
19,725
|
|
|
—
|
|
|
19,725
|
|
|||
Derivative instruments
|
|
751
|
|
|
—
|
|
|
751
|
|
|||
Amounts due to joint ventures
|
|
1,771
|
|
|
—
|
|
|
1,771
|
|
|||
Other long-term liabilities
|
|
7,544
|
|
|
—
|
|
|
7,544
|
|
|||
Total long-term liabilities
|
|
603,715
|
|
|
—
|
|
|
603,715
|
|
|||
Commitments and contingencies (Note 13)
|
|
|
|
|
|
|
||||||
Shareholders’ equity
|
|
|
|
|
|
|
||||||
Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and 85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively
|
|
995
|
|
|
—
|
|
|
995
|
|
|||
Additional paid-in capital
|
|
1,325,481
|
|
|
124,871
|
|
(3)
|
1,450,352
|
|
|||
Accumulated deficit
|
|
(636,351
|
)
|
|
—
|
|
|
(636,351
|
)
|
|||
Total Matador Resources Company shareholders’ equity
|
|
690,125
|
|
|
124,871
|
|
|
814,996
|
|
|||
Non-controlling interest in subsidiaries
|
|
1,320
|
|
|
48,876
|
|
(4)
|
50,196
|
|
|||
Total shareholders’ equity
|
|
691,445
|
|
|
173,747
|
|
|
865,192
|
|
|||
Total liabilities and shareholders’ equity
|
|
$
|
1,464,665
|
|
|
$
|
173,747
|
|
|
$
|
1,638,412
|
|
(1)
|
Represents
$176.4 million
of cash contributed by Five Point in connection with the formation of San Mateo less (i) approximately
$2.6 million
paid by the Company to acquire the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and (ii)
$10.0
|
(2)
|
Represents
$10.0 million
in cash contributed to San Mateo less
$0.6 million
released from restriction upon the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own.
|
(3)
|
Reflects the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and the amount received in connection with the formation of San Mateo.
|
(4)
|
Represents the adjustment required to reflect the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and Five Point’s
49%
non-controlling interest in San Mateo.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Property acquisition costs
|
|
|
|
|
|
|
||||||
Proved
|
|
$
|
—
|
|
|
$
|
16,524
|
|
|
$
|
2,728
|
|
Unproved and unevaluated
|
|
108,206
|
|
|
253,923
|
|
|
78,484
|
|
|||
Exploration costs
|
|
113,562
|
|
|
122,495
|
|
|
156,178
|
|
|||
Development costs
|
|
158,113
|
|
|
229,700
|
|
|
359,961
|
|
|||
Total costs incurred
(1)
|
|
$
|
379,881
|
|
|
$
|
622,642
|
|
|
$
|
597,351
|
|
(1)
|
Excludes midstream-related development and corporate costs of approximately $74.5 million, $75.8 million and $13.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.
|
|
|
Net Proved Reserves
|
|||||||
|
|
Oil
|
|
Natural Gas
|
|
Oil
Equivalent
|
|||
|
|
(MBbl)
|
|
(MMcf)
|
|
(MBOE)
|
|||
Total at December 31, 2013
|
|
16,362
|
|
|
212,195
|
|
|
51,729
|
|
Revisions of prior estimates
|
|
(1,196
|
)
|
|
164
|
|
|
(1,169
|
)
|
Purchases of minerals in-place
|
|
10
|
|
|
433
|
|
|
82
|
|
Extensions and discoveries
|
|
12,328
|
|
|
69,566
|
|
|
23,921
|
|
Production
|
|
(3,320
|
)
|
|
(15,303
|
)
|
|
(5,870
|
)
|
Total at December 31, 2014
|
|
24,184
|
|
|
267,055
|
|
|
68,693
|
|
Revisions of prior estimates
|
|
(2,609
|
)
|
|
(75,433
|
)
|
|
(15,181
|
)
|
Purchases of minerals in-place
|
|
1,102
|
|
|
2,927
|
|
|
1,589
|
|
Extensions and discoveries
|
|
27,459
|
|
|
70,054
|
|
|
39,135
|
|
Production
|
|
(4,492
|
)
|
|
(27,702
|
)
|
|
(9,109
|
)
|
Total at December 31, 2015
|
|
45,644
|
|
|
236,901
|
|
|
85,127
|
|
Revisions of prior estimates
|
|
(6,440
|
)
|
|
(28,481
|
)
|
|
(11,187
|
)
|
Extensions and discoveries
|
|
22,869
|
|
|
114,730
|
|
|
41,992
|
|
Production
|
|
(5,096
|
)
|
|
(30,501
|
)
|
|
(10,180
|
)
|
Total at December 31, 2016
|
|
56,977
|
|
|
292,649
|
|
|
105,752
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|||
December 31, 2013
|
|
8,258
|
|
|
53,458
|
|
|
17,168
|
|
December 31, 2014
|
|
14,053
|
|
|
102,795
|
|
|
31,185
|
|
December 31, 2015
|
|
17,129
|
|
|
101,447
|
|
|
34,037
|
|
December 31, 2016
|
|
22,604
|
|
|
126,759
|
|
|
43,731
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|||
December 31, 2013
|
|
8,104
|
|
|
158,737
|
|
|
34,561
|
|
December 31, 2014
|
|
10,131
|
|
|
164,260
|
|
|
37,508
|
|
December 31, 2015
|
|
28,515
|
|
|
135,454
|
|
|
51,090
|
|
December 31, 2016
|
|
34,373
|
|
|
165,890
|
|
|
62,021
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Future cash inflows
|
|
$
|
2,684,877
|
|
|
$
|
2,461,131
|
|
|
$
|
3,197,317
|
|
Future production costs
|
|
(927,725
|
)
|
|
(843,117
|
)
|
|
(803,662
|
)
|
|||
Future development costs
|
|
(630,280
|
)
|
|
(615,692
|
)
|
|
(553,799
|
)
|
|||
Future income tax expense
|
|
(24,742
|
)
|
|
(43,956
|
)
|
|
(321,088
|
)
|
|||
Future net cash flows
|
|
1,102,130
|
|
|
958,366
|
|
|
1,518,768
|
|
|||
10% annual discount for estimated timing of cash flows
|
|
(527,087
|
)
|
|
(429,185
|
)
|
|
(605,449
|
)
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
575,043
|
|
|
$
|
529,181
|
|
|
$
|
913,319
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Balance, beginning of period
|
|
$
|
529,181
|
|
|
$
|
913,319
|
|
|
$
|
578,668
|
|
Net change in sales and transfer prices and in production (lifting) costs related to future production
|
|
(92,477
|
)
|
|
(509,901
|
)
|
|
87,067
|
|
|||
Changes in estimated future development costs
|
|
(74,142
|
)
|
|
(145,861
|
)
|
|
(150,447
|
)
|
|||
Sales and transfers of oil and natural gas produced during the period
|
|
(191,908
|
)
|
|
(184,612
|
)
|
|
(283,187
|
)
|
|||
Purchases of reserves in place
|
|
—
|
|
|
16,321
|
|
|
1,838
|
|
|||
Net change due to extensions and discoveries
|
|
360,033
|
|
|
401,895
|
|
|
537,472
|
|
|||
Net change due to revisions in estimates of reserves quantities
|
|
(95,917
|
)
|
|
(285,823
|
)
|
|
(26,263
|
)
|
|||
Previously estimated development costs incurred during the period
|
|
84,519
|
|
|
121,543
|
|
|
187,459
|
|
|||
Accretion of discount
|
|
51,779
|
|
|
82,574
|
|
|
65,518
|
|
|||
Other
|
|
(1,962
|
)
|
|
2,029
|
|
|
5,492
|
|
|||
Net change in income taxes
|
|
5,937
|
|
|
117,697
|
|
|
(90,298
|
)
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
575,043
|
|
|
$
|
529,181
|
|
|
$
|
913,319
|
|
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
||||||||
2016
|
|
|
|
|
|
|
|
|
||||||||
Oil and natural gas revenues
|
|
$
|
94,815
|
|
|
$
|
83,079
|
|
|
$
|
69,336
|
|
|
$
|
43,926
|
|
Third-party midstream services revenues
|
|
2,261
|
|
|
1,566
|
|
|
918
|
|
|
473
|
|
||||
Realized (loss) gain on derivatives
|
|
(1,127
|
)
|
|
885
|
|
|
2,465
|
|
|
7,063
|
|
||||
Unrealized (loss) gain on derivatives
|
|
(10,977
|
)
|
|
3,203
|
|
|
(26,625
|
)
|
|
(6,839
|
)
|
||||
Expenses
(1)
|
|
76,753
|
|
|
71,879
|
|
|
146,705
|
|
|
146,252
|
|
||||
Other income (expense)
(2)
|
|
96,196
|
|
|
(5,948
|
)
|
|
(5,136
|
)
|
|
(6,038
|
)
|
||||
Income (loss) before income taxes
|
|
104,415
|
|
|
10,906
|
|
|
(105,747
|
)
|
|
(107,667
|
)
|
||||
Income tax provision (benefit)
|
|
105
|
|
|
(1,141
|
)
|
|
—
|
|
|
—
|
|
||||
Net income (loss)
|
|
104,310
|
|
|
12,047
|
|
|
(105,747
|
)
|
|
(107,667
|
)
|
||||
Net (income) loss attributable to non-controlling interest in subsidiaries
|
|
(155
|
)
|
|
(116
|
)
|
|
(106
|
)
|
|
13
|
|
||||
Net income (loss) attributable to
Matador Resources Company shareholders |
|
$
|
104,155
|
|
|
$
|
11,931
|
|
|
$
|
(105,853
|
)
|
|
$
|
(107,654
|
)
|
Earnings (loss) per common share
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
1.10
|
|
|
$
|
0.13
|
|
|
$
|
(1.15
|
)
|
|
$
|
(1.26
|
)
|
Diluted
|
|
$
|
1.09
|
|
|
$
|
0.13
|
|
|
$
|
(1.15
|
)
|
|
$
|
(1.26
|
)
|
(1)
|
Expenses for June 30 and March 31, 2016 included full-cost ceiling impairment charges of $78.2 million, and $80.5 million, respectively.
|
(2)
|
Other income (expense) for December 31, 2016 included gain on the sale of the Loving County Processing System of $104.1 million. See Note 5.
|
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
||||||||
2015
|
|
|
|
|
|
|
|
|
||||||||
Oil and natural gas revenues
|
|
$
|
56,212
|
|
|
$
|
71,815
|
|
|
$
|
87,848
|
|
|
$
|
62,465
|
|
Third-party midstream services revenues
|
|
480
|
|
|
569
|
|
|
464
|
|
|
351
|
|
||||
Realized gain on derivatives
|
|
24,948
|
|
|
19,862
|
|
|
13,780
|
|
|
18,504
|
|
||||
Unrealized (loss) gain on derivatives
|
|
(13,909
|
)
|
|
6,733
|
|
|
(23,532
|
)
|
|
(8,557
|
)
|
||||
Expenses
(1)
|
|
290,751
|
|
|
367,633
|
|
|
319,140
|
|
|
147,171
|
|
||||
Other expense
|
|
5,599
|
|
|
6,665
|
|
|
5,786
|
|
|
2,180
|
|
||||
Loss before income taxes
|
|
(228,619
|
)
|
|
(275,319
|
)
|
|
(246,366
|
)
|
|
(76,588
|
)
|
||||
Income tax provision (benefit)
|
|
1,677
|
|
|
(33,305
|
)
|
|
(89,350
|
)
|
|
(26,390
|
)
|
||||
Net loss
|
|
(230,296
|
)
|
|
(242,014
|
)
|
|
(157,016
|
)
|
|
(50,198
|
)
|
||||
Net income attributable to non-controlling interest in subsidiaries
|
|
(105
|
)
|
|
(45
|
)
|
|
(75
|
)
|
|
(36
|
)
|
||||
Net loss attributable to
Matador Resources Company shareholders |
|
$
|
(230,401
|
)
|
|
$
|
(242,059
|
)
|
|
$
|
(157,091
|
)
|
|
$
|
(50,234
|
)
|
Loss per common share attributable to Matador Resources Company shareholders
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
(2.72
|
)
|
|
$
|
(2.86
|
)
|
|
$
|
(1.89
|
)
|
|
$
|
(0.68
|
)
|
Diluted
|
|
$
|
(2.72
|
)
|
|
$
|
(2.86
|
)
|
|
$
|
(1.89
|
)
|
|
$
|
(0.68
|
)
|
(1)
|
Expenses for December 31, September 30, June 30 and March 31, 2015 included full-cost ceiling impairment charges of $219.4 million, $285.7 million, $229.0 million and $67.1 million, respectively.
|
|
|
|
Name
|
|
Jurisdiction
|
|
|
|
Black River Water Management Company, LLC
|
|
Texas
|
|
|
|
Delaware Water Management Company, LLC
|
|
Texas
|
|
|
|
DLK Black River Midstream, LLC
|
|
Texas
|
|
|
|
Fulcrum Delaware Water Resources, LLC
|
|
Texas
|
|
|
|
Longwood Gathering and Disposal Systems GP, Inc.
|
|
Texas
|
|
|
|
Longwood Gathering and Disposal Systems, LP
|
|
Texas
|
|
|
|
Longwood Midstream Delaware, LLC
|
|
Texas
|
|
|
|
Longwood Midstream Southeast, LLC
|
|
Texas
|
|
|
|
Longwood Midstream South Texas, LLC
|
|
Texas
|
|
|
|
Matador Production Company
|
|
Texas
|
|
|
|
MRC Delaware Resources, LLC
|
|
Texas
|
|
|
|
MRC Energy Company
|
|
Texas
|
|
|
|
MRC Energy Southeast Company, LLC
|
|
Texas
|
|
|
|
MRC Energy South Texas Company, LLC
|
|
Texas
|
|
|
|
MRC Permian Company
|
|
Texas
|
|
|
|
MRC Permian LKE Company, LLC
|
|
Texas
|
|
|
|
MRC Rockies Company
|
|
Texas
|
|
|
|
Southeast Water Management Company, LLC
|
|
Texas
|
|
|
Exhibit 23.2
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||
|
|
|
By:
|
|
/s/ C.H. (Scott) Rees III
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
Chairman and Chief Executive Officer
|
March 1, 2017
|
|
/s/ Joseph Wm. Foran
|
|
|
Joseph Wm. Foran
|
|
|
Chairman and Chief Executive Officer
(Principal Executive Officer)
|
|
|
|
March 1, 2017
|
|
/s/ David E. Lancaster
|
|
|
David E. Lancaster
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
|
March 1, 2017
|
|
/s/ Joseph Wm. Foran
|
|
|
Joseph Wm. Foran
|
|
|
Chairman and Chief Executive Officer
(Principal Executive Officer)
|
March 1, 2017
|
|
/s/ David E. Lancaster
|
|
|
David E. Lancaster
|
|
|
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
||||
|
|
Oil
|
|
Gas
|
|
|
|
Present Worth
|
Category
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
22,603
|
|
126,557
|
|
645,712
|
|
431,677
|
Proved Developed Non-Producing
|
|
1
|
|
201
|
|
89
|
|
45
|
Proved Undeveloped
|
|
34,372
|
|
165,891
|
|
481,070
|
|
149,762
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
56,977
|
|
292,650
|
|
1,126,872
|
|
581,484
|