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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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Smaller reporting company
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¨
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Emerging growth 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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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 estimated future reserves and the present value thereof;
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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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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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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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•
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government regulation and taxation of the oil and natural gas industry;
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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 operation and 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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the ability of our midstream joint venture to attract third-party volumes;
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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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competition in the oil and natural gas industry, including in both the exploration and production and midstream segments;
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•
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the effectiveness of our risk management and hedging activities;
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•
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our technology;
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•
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environmental liabilities;
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•
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counterparty credit risk;
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•
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developments in oil-producing and natural gas-producing countries;
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our future operating results; and
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our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical.
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•
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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 play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas;
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•
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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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•
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continue to improve operational and cost efficiencies;
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•
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identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo;
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•
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maintain our financial discipline; and
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•
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pursue opportunistic acquisitions, divestitures and joint ventures.
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•
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in our Rustler Breaks asset area, the results from the David Edelstein State Com 12&11-24S-27E RB #203H well, our first operated two-mile horizontal well, the performance of our Wolfcamp A-XY completions moving to the northwest region of the asset area, positive tests of the Second Bone Spring formation and the continued delineation and development of previously tested horizons;
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•
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in our Wolf asset area, the results from several wells with longer laterals (greater than one mile) drilled and completed in the Wolfcamp A-XY interval in the southern portion of the asset area;
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•
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in our Jackson Trust asset area, the continued development of the Wolfcamp A-Lower interval;
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•
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in our Arrowhead and Ranger asset areas, the results from our Second and Third Bone Spring completions, particularly in the SST and Stebbins acreage blocks in the Arrowhead asset area, and results from the recently completed Verna Rae Federal #204H well in the Ranger asset area, whose 24-hour initial potential (“IP”) test results and subsequent well performance demonstrate the potential prospectivity of the Wolfcamp formation moving north in the Delaware Basin;
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•
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in our Antelope Ridge asset area, the testing of six distinct intervals during 2018, including the Brushy Canyon, First, Second and Third Bone Spring, Wolfcamp A-XY and Wolfcamp A-Lower; and
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•
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the significant progress made in our midstream operations, including (i) the completion and successful startup of the expansion of San Mateo’s Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”) to a designed inlet capacity of 260 MMcf of natural gas per day, (ii) the completion of a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP, (iii) the ongoing buildout of oil, natural gas and water pipeline systems in both the Rustler Breaks and Wolf asset areas, (iv) the entrance into a strategic relationship with Plains to gather and transport crude oil in the Rustler Breaks asset area, (v) placing into service crude oil gathering and transportation systems in the Wolf and Rustler Breaks asset areas, (vi) entering into long-term agreements with significant producers in Eddy County, New Mexico relating to the gathering and disposal of one such producer’s salt water and the gathering and processing of another such producer’s natural gas production and (vii) the drilling and completion of additional commercial salt water disposal wells and the construction of associated commercial facilities in the Rustler Breaks asset area, significantly increasing San Mateo’s salt water disposal capacity.
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the completion of a public offering of
7,000,000
shares of our common stock, whereby we received net proceeds of approximately $226.4 million;
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a series of transactions whereby we (i) issued $1.05 billion aggregate principal amount of senior notes and received net proceeds of $1.04 billion, (ii) redeemed $575.0 million aggregate principal amount of senior notes, (iii) improved the coupon rate on our senior notes outstanding to 5.875% from 6.875% and (iv) extended the maturity date of our senior notes from 2023 to 2026;
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the amendment of our third amended and restated credit agreement (the “Credit Agreement”) to, among other items, (i) increase the maximum facility amount to $1.5 billion, (ii) increase the borrowing base to $850.0 million, (iii) increase the elected borrowing commitment to $500.0 million, (iv) extend the maturity to October 31, 2023, (v) reduce borrowing rates by 0.25% per annum and (vi) set the maximum leverage ratio at 4.00 to 1.00; and
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San Mateo’s entrance into a $250.0 million credit facility led by The Bank of Nova Scotia, as administrative agent (the “San Mateo Credit Facility”), and the cash distribution of $195.0 million, which was distributed 51% to us and 49% to our partner.
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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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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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222,200
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132,000
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630
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290.7
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5,442
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2,472.2
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191,490
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42.3
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45,237
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South Texas:
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Eagle Ford
(5)
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32,000
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28,900
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148
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122.5
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238
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206.9
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12,189
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61.5
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3,158
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Northwest Louisiana/East Texas:
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Haynesville
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19,600
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12,000
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227
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20.4
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395
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100.2
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10,919
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46.5
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3,417
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Cotton Valley
(6)
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21,100
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18,600
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79
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53.3
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71
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49.2
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715
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100.0
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316
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Area Total
(7)
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25,500
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22,800
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306
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73.7
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|
466
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|
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149.4
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11,634
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|
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49.8
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|
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3,733
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Total
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279,700
|
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183,700
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1,084
|
|
|
486.9
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|
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6,146
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|
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2,828.5
|
|
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215,313
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|
|
43.8
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|
|
52,128
|
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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, 2018
. 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. Each location represents a one-mile lateral. At
December 31, 2018
, these engineered drilling locations included only 301 gross (147.6 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Strawn formations, in the Delaware Basin, 17 gross (17.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 14 gross (4.9 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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Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. 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, Brushy Canyon, Strawn and Avalon plays on our acreage in the Delaware Basin at
December 31, 2018
.
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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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Year Ended December 31,
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||||||||||
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2018
|
|
2017
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|
2016
|
||||||
Unaudited Production Data:
|
|
|
|
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|
|
||||||
Net Production Volumes:
|
|
|
|
|
|
|
||||||
Oil (MBbl)
|
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11,141
|
|
|
7,851
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|
|
5,096
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|
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Natural gas (Bcf)
|
|
47.3
|
|
|
38.2
|
|
|
30.5
|
|
|||
Total oil equivalent (MBOE)
(1)
|
|
19,026
|
|
|
14,212
|
|
|
10,180
|
|
|||
Average daily production (BOE/d)
(1)
|
|
52,128
|
|
|
38,936
|
|
|
27,813
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|
|||
Average Sales Prices:
|
|
|
|
|
|
|
||||||
Oil, without realized derivatives (per Bbl)
|
|
$
|
57.04
|
|
|
$
|
49.28
|
|
|
$
|
41.19
|
|
Oil, with realized derivatives (per Bbl)
|
|
$
|
57.38
|
|
|
$
|
48.81
|
|
|
$
|
42.34
|
|
Natural gas, without realized derivatives (per Mcf)
|
|
$
|
3.49
|
|
|
$
|
3.72
|
|
|
$
|
2.66
|
|
Natural gas, with realized derivatives (per Mcf)
|
|
$
|
3.46
|
|
|
$
|
3.70
|
|
|
$
|
2.78
|
|
Operating Expenses (per BOE):
|
|
|
|
|
|
|
||||||
Production taxes, transportation and processing
|
|
$
|
4.00
|
|
|
$
|
4.10
|
|
|
$
|
4.23
|
|
Lease operating
|
|
$
|
4.89
|
|
|
$
|
4.74
|
|
|
$
|
5.52
|
|
Plant and other midstream services operating
|
|
$
|
1.29
|
|
|
$
|
0.92
|
|
|
$
|
0.53
|
|
Depletion, depreciation and amortization
|
|
$
|
13.94
|
|
|
$
|
12.49
|
|
|
$
|
11.99
|
|
General and administrative
|
|
$
|
3.64
|
|
|
$
|
4.65
|
|
|
$
|
5.41
|
|
(1)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
|
|
Southeast
New Mexico/West Texas |
|
South Texas
|
|
Northwest Louisiana/East Texas
|
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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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|
|
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|
|
|
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|
||||||||||
Oil (MBbl)
|
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10,230
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|
|
907
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|
|
—
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|
4
|
|
|
11,141
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|
|||||
Natural gas (Bcf)
|
|
37.7
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|
|
1.5
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|
|
7.5
|
|
|
0.6
|
|
|
47.3
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|
|||||
Total oil equivalent (MBOE)
(3)
|
|
16,512
|
|
|
1,152
|
|
|
1,247
|
|
|
115
|
|
|
19,026
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|
|||||
Percentage of total annual net production
|
|
86.8
|
%
|
|
6.0
|
%
|
|
6.6
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%
|
|
0.6
|
%
|
|
100.0
|
%
|
|||||
Average Net Daily Production Volumes
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (Bbl/d)
|
|
28,026
|
|
|
2,485
|
|
|
—
|
|
|
12
|
|
|
30,523
|
|
|||||
Natural gas (MMcf/d)
|
|
103.3
|
|
|
4.0
|
|
|
20.5
|
|
|
1.8
|
|
|
129.6
|
|
|||||
Total oil equivalent (BOE/d)
|
|
45,237
|
|
|
3,158
|
|
|
3,417
|
|
|
316
|
|
|
52,128
|
|
|||||
Average Sales Prices
(4)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
|
$
|
56.12
|
|
|
$
|
67.40
|
|
|
$
|
—
|
|
|
$
|
64.72
|
|
|
$
|
57.04
|
|
Natural gas (per Mcf)
|
|
$
|
3.55
|
|
|
$
|
5.46
|
|
|
$
|
2.85
|
|
|
$
|
2.80
|
|
|
$
|
3.49
|
|
Total oil equivalent (per BOE)
|
|
$
|
42.88
|
|
|
$
|
60.02
|
|
|
$
|
17.09
|
|
|
$
|
18.59
|
|
|
$
|
42.08
|
|
Production Costs
(5)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating, transportation and processing (per BOE)
|
|
$
|
4.79
|
|
|
$
|
17.25
|
|
|
$
|
5.41
|
|
|
$
|
19.11
|
|
|
$
|
5.68
|
|
(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)
|
Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. 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)
|
|
6,579
|
|
|
1,268
|
|
|
—
|
|
|
4
|
|
|
7,851
|
|
|||||
Natural gas (Bcf)
|
|
25.1
|
|
|
2.0
|
|
|
10.3
|
|
|
0.8
|
|
|
38.2
|
|
|||||
Total oil equivalent (MBOE)
(3)
|
|
10,754
|
|
|
1,611
|
|
|
1,714
|
|
|
133
|
|
|
14,212
|
|
|||||
Percentage of total annual net production
|
|
75.7
|
%
|
|
11.3
|
%
|
|
12.1
|
%
|
|
0.9
|
%
|
|
100.0
|
%
|
|||||
Average Net Daily Production Volumes
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (Bbl/d)
|
|
18,023
|
|
|
3,475
|
|
|
—
|
|
|
12
|
|
|
21,510
|
|
|||||
Natural gas (MMcf/d)
|
|
68.6
|
|
|
5.6
|
|
|
28.3
|
|
|
2.1
|
|
|
104.6
|
|
|||||
Total oil equivalent (BOE/d)
|
|
29,463
|
|
|
4,413
|
|
|
4,697
|
|
|
363
|
|
|
38,936
|
|
|||||
Average Sales Prices
(4)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
|
$
|
49.08
|
|
|
$
|
50.29
|
|
|
$
|
—
|
|
|
$
|
45.52
|
|
|
$
|
49.28
|
|
Natural gas (per Mcf)
|
|
$
|
4.03
|
|
|
$
|
4.69
|
|
|
$
|
2.83
|
|
|
$
|
2.79
|
|
|
$
|
3.72
|
|
Total oil equivalent (per BOE)
|
|
$
|
39.41
|
|
|
$
|
45.58
|
|
|
$
|
16.96
|
|
|
$
|
17.69
|
|
|
$
|
37.20
|
|
Production Costs
(5)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating, transportation and processing (per BOE)
|
|
$
|
5.80
|
|
|
$
|
10.92
|
|
|
$
|
4.21
|
|
|
$
|
16.77
|
|
|
$
|
6.29
|
|
(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)
|
Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. 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)
|
|
3,805
|
|
|
1,286
|
|
|
—
|
|
|
5
|
|
|
5,096
|
|
|||||
Natural gas (Bcf)
|
|
12.2
|
|
|
3.1
|
|
|
14.3
|
|
|
0.9
|
|
|
30.5
|
|
|||||
Total oil equivalent (MBOE)
(3)
|
|
5,834
|
|
|
1,813
|
|
|
2,385
|
|
|
148
|
|
|
10,180
|
|
|||||
Percentage of total annual net production
|
|
57.3
|
%
|
|
17.8
|
%
|
|
23.4
|
%
|
|
1.5
|
%
|
|
100.0
|
%
|
|||||
Average Net Daily Production Volumes
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (Bbl/d)
|
|
10,395
|
|
|
3,517
|
|
|
—
|
|
|
12
|
|
|
13,924
|
|
|||||
Natural gas (MMcf/d)
|
|
33.3
|
|
|
8.6
|
|
|
39.1
|
|
|
2.3
|
|
|
83.3
|
|
|||||
Total oil equivalent (BOE/d)
|
|
15,941
|
|
|
4,952
|
|
|
6,517
|
|
|
403
|
|
|
27,813
|
|
|||||
Average Sales Prices
(4)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
|
$
|
41.76
|
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
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)
|
Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. 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.
|
|
|
Oil Wells
|
|
Natural Gas Wells
|
|
Total Wells
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Southeast New Mexico/West Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Delaware Basin
(1)
|
|
519
|
|
|
241.0
|
|
|
111
|
|
|
49.7
|
|
|
630
|
|
|
290.7
|
|
South Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Eagle Ford
(2)
|
|
144
|
|
|
118.5
|
|
|
4
|
|
|
4.0
|
|
|
148
|
|
|
122.5
|
|
Northwest Louisiana/East Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Haynesville
|
|
—
|
|
|
—
|
|
|
227
|
|
|
20.4
|
|
|
227
|
|
|
20.4
|
|
Cotton Valley
(3)
|
|
2
|
|
|
2.0
|
|
|
77
|
|
|
51.3
|
|
|
79
|
|
|
53.3
|
|
Area Total
|
|
2
|
|
|
2.0
|
|
|
304
|
|
|
71.7
|
|
|
306
|
|
|
73.7
|
|
Total
|
|
665
|
|
|
361.5
|
|
|
419
|
|
|
125.4
|
|
|
1,084
|
|
|
486.9
|
|
(1)
|
Includes 224 gross (58.6 net) vertical wells that were acquired in multiple transactions.
|
(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)
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Estimated Proved Reserves Data:
(2)
|
|
|
|
|
|
|
||||||
Estimated proved reserves:
|
|
|
|
|
|
|
||||||
Oil (MBbl)
|
|
123,401
|
|
|
86,743
|
|
|
56,977
|
|
|||
Natural Gas (Bcf)
|
|
551.5
|
|
|
396.2
|
|
|
292.6
|
|
|||
Total (MBOE)
(3)
|
|
215,313
|
|
|
152,771
|
|
|
105,752
|
|
|||
Estimated proved developed reserves:
|
|
|
|
|
|
|
||||||
Oil (MBbl)
|
|
53,223
|
|
|
36,966
|
|
|
22,604
|
|
|||
Natural Gas (Bcf)
|
|
246.2
|
|
|
190.1
|
|
|
126.8
|
|
|||
Total (MBOE)
(3)
|
|
94,261
|
|
|
68,651
|
|
|
43,731
|
|
|||
Percent developed
|
|
43.8
|
%
|
|
44.9
|
%
|
|
41.4
|
%
|
|||
Estimated proved undeveloped reserves:
|
|
|
|
|
|
|
||||||
Oil (MBbl)
|
|
70,178
|
|
|
49,777
|
|
|
34,373
|
|
|||
Natural Gas (Bcf)
|
|
305.2
|
|
|
206.1
|
|
|
165.9
|
|
|||
Total (MBOE)
(3)
|
|
121,052
|
|
|
84,120
|
|
|
62,021
|
|
|||
Standardized Measure
(4)
(in millions)
|
|
$
|
2,250.6
|
|
|
$
|
1,258.6
|
|
|
$
|
575.0
|
|
PV-10
(5)
(in millions)
|
|
$
|
2,579.3
|
|
|
$
|
1,333.4
|
|
|
$
|
581.5
|
|
(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, 2018
were
$62.04
per Bbl for oil and
$3.10
per MMBtu for natural gas, for the 12 months ended
December 31, 2017
were
$47.79
per Bbl for oil and
$2.98
per MMBtu for natural gas, and for the 12 months ended
December 31, 2016
were
$39.25
per Bbl for oil and
$2.48
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 NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold.
|
(3)
|
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
|
(4)
|
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.
|
(5)
|
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, 2018, 2017 and 2016
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, 2018, 2017 and 2016
were, in millions,
$328.7
,
$74.8
and
$6.5
, respectively.
|
|
|
Proved Developed Reserves
|
|
|
|
||
|
|
(MBOE)
(1)
|
|
As of December 31, 2017
|
|
68,651
|
|
Extensions and discoveries
|
|
14,666
|
|
Purchases of minerals-in-place
|
|
596
|
|
Revisions of prior estimates
|
|
3,091
|
|
Production
|
|
(19,026
|
)
|
Conversion of proved undeveloped to proved developed
|
|
26,283
|
|
As of December 31, 2018
|
|
94,261
|
|
(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, 2017
|
|
84,120
|
|
Extensions and discoveries
|
|
54,980
|
|
Purchases of minerals-in-place
|
|
—
|
|
Revisions of prior estimates
|
|
8,235
|
|
Conversion of proved undeveloped to proved developed
|
|
(26,283
|
)
|
As of December 31, 2018
|
|
121,052
|
|
(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)
|
|
||||||
2015
|
|
2,854
|
|
|
23.4
|
|
|
6,747
|
|
|
104,989
|
|
|
2016
|
|
4,705
|
|
|
13.1
|
|
|
6,883
|
|
|
94,579
|
|
|
2017
|
|
9,300
|
|
|
45.0
|
|
|
16,808
|
|
|
211,860
|
|
|
2018
|
|
16,009
|
|
|
61.7
|
|
|
26,283
|
|
|
$
|
356,830
|
|
Total
|
|
32,868
|
|
|
143.2
|
|
|
56,721
|
|
|
$
|
768,258
|
|
(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
|
|
114,823
|
|
|
460.0
|
|
|
191,490
|
|
|
$
|
2,056.7
|
|
|
$
|
2,357.1
|
|
South Texas:
|
|
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
(5)
|
|
8,537
|
|
|
21.9
|
|
|
12,189
|
|
|
160.9
|
|
|
184.4
|
|
||
Northwest Louisiana/East Texas:
|
|
|
|
|
|
|
|
|
|
|
|||||||
Haynesville
|
|
—
|
|
|
65.5
|
|
|
10,919
|
|
|
31.0
|
|
|
35.5
|
|
||
Cotton Valley
(6)
|
|
41
|
|
|
4.1
|
|
|
715
|
|
|
2.0
|
|
|
2.3
|
|
||
Area Total
|
|
41
|
|
|
69.6
|
|
|
11,634
|
|
|
33.0
|
|
|
37.8
|
|
||
Total
|
|
123,401
|
|
|
551.5
|
|
|
215,313
|
|
|
$
|
2,250.6
|
|
|
$
|
2,579.3
|
|
(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, 2018
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, 2018
were approximately $
328.7 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
|
|
123,000
|
|
|
71,900
|
|
|
99,200
|
|
|
60,100
|
|
|
222,200
|
|
|
132,000
|
|
South Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Eagle Ford
|
|
29,900
|
|
|
26,800
|
|
|
2,100
|
|
|
2,100
|
|
|
32,000
|
|
|
28,900
|
|
Northwest Louisiana/East Texas
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Haynesville
|
|
19,000
|
|
|
11,500
|
|
|
600
|
|
|
500
|
|
|
19,600
|
|
|
12,000
|
|
Cotton Valley
|
|
20,400
|
|
|
18,500
|
|
|
700
|
|
|
100
|
|
|
21,100
|
|
|
18,600
|
|
Area Total
(2)
|
|
24,300
|
|
|
22,200
|
|
|
1,200
|
|
|
600
|
|
|
25,500
|
|
|
22,800
|
|
Total
|
|
177,200
|
|
|
120,900
|
|
|
102,500
|
|
|
62,800
|
|
|
279,700
|
|
|
183,700
|
|
(1)
|
Developed acres include 2,800 gross and net mineral acres in Northwest Louisiana.
|
(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.
|
|
|
Acres
|
|
Acres
|
|
Acres
|
|
Acres
|
|
Acres
|
||||||||||||||||||||
|
|
Expiring 2019
|
|
Expiring 2020
|
|
Expiring 2021
|
|
Expiring 2022
|
|
Expiring 2023
|
||||||||||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||||
Southeast New Mexico/West Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Delaware Basin
(1)
|
|
13,900
|
|
|
9,400
|
|
|
16,400
|
|
|
8,900
|
|
|
25,100
|
|
|
14,900
|
|
|
7,600
|
|
|
8,200
|
|
|
4,000
|
|
|
5,400
|
|
South Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Eagle Ford
|
|
100
|
|
|
100
|
|
|
1,600
|
|
|
1,500
|
|
|
400
|
|
|
400
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Northwest Louisiana/East Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Haynesville
|
|
300
|
|
|
300
|
|
|
200
|
|
|
200
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Cotton Valley
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Area Total
(2)
|
|
300
|
|
|
300
|
|
|
200
|
|
|
200
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
14,300
|
|
|
9,800
|
|
|
18,200
|
|
|
10,600
|
|
|
25,500
|
|
|
15,300
|
|
|
7,600
|
|
|
8,200
|
|
|
4,000
|
|
|
5,400
|
|
(1)
|
Approximately 49% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage through our 2019 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,
|
||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|||||||
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
118
|
|
|
54.7
|
|
|
72
|
|
|
43.7
|
|
|
44
|
|
|
23.5
|
|
Dry
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploration Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
35
|
|
|
20.8
|
|
|
33
|
|
|
22.3
|
|
|
28
|
|
|
15.6
|
|
Dry
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
153
|
|
|
75.5
|
|
|
105
|
|
|
66.0
|
|
|
72
|
|
|
39.1
|
|
Dry
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
•
|
the domestic and foreign supply of, and demand for, oil and natural gas;
|
•
|
the actions of 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;
|
•
|
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 oil, natural gas and NGLs;
|
•
|
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;
|
•
|
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 attract third-party customers for our midstream services;
|
•
|
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;
|
•
|
the existence or magnitude of faults or unanticipated geological features;
|
•
|
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;
|
•
|
drilling out the plugs between stages following hydraulic fracturing operations; and
|
•
|
being able to run tools and other equipment consistently through the horizontal wellbore.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
the 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, dispositions or joint ventures by us;
|
•
|
public reaction to our operations or plans, press releases, announcements and filings with the SEC;
|
•
|
sales of our common stock by the Company, directors, officers or other 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 NGLs;
|
•
|
the realization of any of the risk factors presented in this Annual Report;
|
•
|
the recruitment or departure of key personnel;
|
•
|
commencement of, involvement in or unfavorable resolution of litigation;
|
•
|
the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs 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.
|
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)
|
|
2,962,249
|
|
|
$
|
23.48
|
|
|
991,281
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
2,962,249
|
|
|
$
|
23.48
|
|
|
991,281
|
|
(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 Matador Resources Company 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, 2018 to October 31, 2018
|
|
11,777
|
|
|
$
|
33.39
|
|
|
—
|
|
|
—
|
|
November 1, 2018 to November 30, 2018
|
|
216
|
|
|
25.79
|
|
|
—
|
|
|
—
|
|
|
December 1, 2018 to December 31, 2018
|
|
106
|
|
|
15.49
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
12,099
|
|
|
$
|
33.10
|
|
|
—
|
|
|
—
|
|
(1)
|
The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas revenues
|
|
$
|
800,700
|
|
|
$
|
528,684
|
|
|
$
|
291,156
|
|
|
$
|
278,340
|
|
|
$
|
367,712
|
|
Third-party midstream services revenues
|
|
21,920
|
|
|
10,198
|
|
|
5,218
|
|
|
1,864
|
|
|
1,213
|
|
|||||
Sales of purchased natural gas
|
|
7,071
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Lease bonus - mineral acreage
|
|
2,489
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Realized gain (loss) on derivatives
|
|
2,334
|
|
|
(4,321
|
)
|
|
9,286
|
|
|
77,094
|
|
|
5,022
|
|
|||||
Unrealized gain (loss) on derivatives
|
|
65,085
|
|
|
9,715
|
|
|
(41,238
|
)
|
|
(39,265
|
)
|
|
58,302
|
|
|||||
Total revenues
|
|
899,599
|
|
|
544,276
|
|
|
264,422
|
|
|
318,033
|
|
|
432,249
|
|
|||||
Expenses
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production taxes, transportation and processing
|
|
76,138
|
|
|
58,275
|
|
|
43,046
|
|
|
35,650
|
|
|
33,172
|
|
|||||
Lease operating
|
|
92,966
|
|
|
67,313
|
|
|
56,202
|
|
|
54,704
|
|
|
49,945
|
|
|||||
Plant and other midstream services operating
|
|
24,609
|
|
|
13,039
|
|
|
5,389
|
|
|
3,489
|
|
|
1,408
|
|
|||||
Purchased natural gas
|
|
6,635
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Depletion, depreciation and amortization
|
|
265,142
|
|
|
177,502
|
|
|
122,048
|
|
|
178,847
|
|
|
134,737
|
|
|||||
Accretion of asset retirement obligations
|
|
1,530
|
|
|
1,290
|
|
|
1,182
|
|
|
734
|
|
|
504
|
|
|||||
Full-cost ceiling impairment
|
|
—
|
|
|
—
|
|
|
158,633
|
|
|
801,166
|
|
|
—
|
|
|||||
General and administrative
|
|
69,308
|
|
|
66,016
|
|
|
55,089
|
|
|
50,105
|
|
|
32,152
|
|
|||||
Total expenses
|
|
536,328
|
|
|
383,435
|
|
|
441,589
|
|
|
1,124,695
|
|
|
251,918
|
|
|||||
Operating income (loss)
|
|
363,271
|
|
|
160,841
|
|
|
(177,167
|
)
|
|
(806,662
|
)
|
|
180,331
|
|
|||||
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net (loss) gain on asset sales and inventory impairment
|
|
(196
|
)
|
|
23
|
|
|
107,277
|
|
|
908
|
|
|
—
|
|
|||||
Interest expense
|
|
(41,327
|
)
|
|
(34,565
|
)
|
|
(28,199
|
)
|
|
(21,754
|
)
|
|
(5,334
|
)
|
|||||
Prepayment premium on extinguishment of debt
|
|
(31,226
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other income (expense)
|
|
1,551
|
|
|
3,551
|
|
|
(4
|
)
|
|
616
|
|
|
132
|
|
|||||
Total other (expense) income
|
|
(71,198
|
)
|
|
(30,991
|
)
|
|
79,074
|
|
|
(20,230
|
)
|
|
(5,202
|
)
|
|||||
Net income (loss)
|
|
299,764
|
|
|
138,007
|
|
|
(97,057
|
)
|
|
(679,524
|
)
|
|
110,754
|
|
|||||
Net (income) loss attributable to non-controlling interest in subsidiaries
|
|
(25,557
|
)
|
|
(12,140
|
)
|
|
(364
|
)
|
|
(261
|
)
|
|
17
|
|
|||||
Net income (loss) attributable to Matador Resources Company shareholders
|
|
$
|
274,207
|
|
|
$
|
125,867
|
|
|
$
|
(97,421
|
)
|
|
$
|
(679,785
|
)
|
|
$
|
110,771
|
|
Earnings (loss) per common share
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
2.41
|
|
|
$
|
1.23
|
|
|
$
|
(1.07
|
)
|
|
$
|
(8.34
|
)
|
|
$
|
1.58
|
|
Diluted
|
|
$
|
2.41
|
|
|
$
|
1.23
|
|
|
$
|
(1.07
|
)
|
|
$
|
(8.34
|
)
|
|
$
|
1.56
|
|
|
|
At December 31,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
|
$
|
64,545
|
|
|
$
|
96,505
|
|
|
$
|
212,884
|
|
|
$
|
16,732
|
|
|
$
|
8,407
|
|
Restricted cash
|
|
$
|
19,439
|
|
|
$
|
5,977
|
|
|
$
|
1,258
|
|
|
$
|
44,357
|
|
|
$
|
609
|
|
Net property and equipment
|
|
$
|
3,122,864
|
|
|
$
|
1,881,456
|
|
|
$
|
1,184,525
|
|
|
$
|
1,012,406
|
|
|
$
|
1,322,072
|
|
Total assets
|
|
$
|
3,455,518
|
|
|
$
|
2,145,690
|
|
|
$
|
1,464,665
|
|
|
$
|
1,140,861
|
|
|
$
|
1,434,490
|
|
Current liabilities
|
|
$
|
330,022
|
|
|
$
|
282,606
|
|
|
$
|
169,505
|
|
|
$
|
136,830
|
|
|
$
|
142,036
|
|
Long-term liabilities
|
|
$
|
1,345,839
|
|
|
$
|
605,538
|
|
|
$
|
603,715
|
|
|
$
|
515,072
|
|
|
$
|
425,913
|
|
Total Matador Resources Company shareholders’ equity
|
|
$
|
1,688,880
|
|
|
$
|
1,156,556
|
|
|
$
|
690,125
|
|
|
$
|
488,003
|
|
|
$
|
866,408
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other financial data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
608,523
|
|
|
$
|
299,125
|
|
|
$
|
134,086
|
|
|
$
|
208,535
|
|
|
$
|
251,481
|
|
Net cash used in investing activities
|
|
$
|
(1,515,253
|
)
|
|
$
|
(819,284
|
)
|
|
$
|
(448,739
|
)
|
|
$
|
(381,406
|
)
|
|
$
|
(569,922
|
)
|
Oil and natural gas properties capital expenditures
|
|
$
|
(1,357,802
|
)
|
|
$
|
(699,445
|
)
|
|
$
|
(379,067
|
)
|
|
$
|
(432,715
|
)
|
|
$
|
(560,849
|
)
|
Expenditures for midstream and other property and equipment
|
|
$
|
(165,784
|
)
|
|
$
|
(120,816
|
)
|
|
$
|
(74,845
|
)
|
|
$
|
(64,499
|
)
|
|
$
|
(9,152
|
)
|
Net cash provided by financing activities
|
|
$
|
888,232
|
|
|
$
|
408,499
|
|
|
$
|
467,706
|
|
|
$
|
224,944
|
|
|
$
|
321,170
|
|
Adjusted EBITDA attributable to Matador Resources Company shareholders
(1)
|
|
$
|
553,223
|
|
|
$
|
336,063
|
|
|
$
|
157,892
|
|
|
$
|
223,138
|
|
|
$
|
262,943
|
|
(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,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income (loss) attributable to Matador Resources Company shareholders
|
|
$
|
274,207
|
|
|
$
|
125,867
|
|
|
$
|
(97,421
|
)
|
|
$
|
(679,785
|
)
|
|
$
|
110,771
|
|
Net income (loss) attributable to non-controlling interest in subsidiaries
|
|
25,557
|
|
|
12,140
|
|
|
364
|
|
|
261
|
|
|
(17
|
)
|
|||||
Net income (loss)
|
|
299,764
|
|
|
138,007
|
|
|
(97,057
|
)
|
|
(679,524
|
)
|
|
110,754
|
|
|||||
Interest expense
|
|
41,327
|
|
|
34,565
|
|
|
28,199
|
|
|
21,754
|
|
|
5,334
|
|
|||||
Total income tax (benefit) provision
|
|
(7,691
|
)
|
|
(8,157
|
)
|
|
(1,036
|
)
|
|
(147,368
|
)
|
|
64,375
|
|
|||||
Depletion, depreciation and amortization
|
|
265,142
|
|
|
177,502
|
|
|
122,048
|
|
|
178,847
|
|
|
134,737
|
|
|||||
Accretion of asset retirement obligations
|
|
1,530
|
|
|
1,290
|
|
|
1,182
|
|
|
734
|
|
|
504
|
|
|||||
Full-cost ceiling impairment
|
|
—
|
|
|
—
|
|
|
158,633
|
|
|
801,166
|
|
|
—
|
|
|||||
Unrealized (gain) loss on derivatives
|
|
(65,085
|
)
|
|
(9,715
|
)
|
|
41,238
|
|
|
39,265
|
|
|
(58,302
|
)
|
|||||
Stock-based compensation expense
|
|
17,200
|
|
|
16,654
|
|
|
12,362
|
|
|
9,450
|
|
|
5,524
|
|
|||||
Net loss (gain) on asset sales and inventory impairment
|
|
196
|
|
|
(23
|
)
|
|
(107,277
|
)
|
|
(908
|
)
|
|
—
|
|
|||||
Prepayment premium on extinguishment of debt
|
|
31,226
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Consolidated Adjusted EBITDA
|
|
583,609
|
|
|
350,123
|
|
|
158,292
|
|
|
223,416
|
|
|
262,926
|
|
|||||
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
|
|
(30,386
|
)
|
|
(14,060
|
)
|
|
(400
|
)
|
|
(278
|
)
|
|
17
|
|
|||||
Adjusted EBITDA attributable to Matador Resources Company shareholders
|
|
$
|
553,223
|
|
|
$
|
336,063
|
|
|
$
|
157,892
|
|
|
$
|
223,138
|
|
|
$
|
262,943
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by
Operating Activities: |
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
608,523
|
|
|
$
|
299,125
|
|
|
$
|
134,086
|
|
|
$
|
208,535
|
|
|
$
|
251,481
|
|
Net change in operating assets and liabilities
|
|
(64,429
|
)
|
|
25,058
|
|
|
(1,809
|
)
|
|
(8,980
|
)
|
|
5,978
|
|
|||||
Interest expense, net of non-cash portion
|
|
39,970
|
|
|
34,097
|
|
|
27,051
|
|
|
20,902
|
|
|
5,334
|
|
|||||
Current income tax (benefit) provision
|
|
(455
|
)
|
|
(8,157
|
)
|
|
(1,036
|
)
|
|
2,959
|
|
|
133
|
|
|||||
Adjusted EBITDA attributable to non-controlling interest in subsidiaries
|
|
(30,386
|
)
|
|
(14,060
|
)
|
|
(400
|
)
|
|
(278
|
)
|
|
17
|
|
|||||
Adjusted EBITDA attributable to Matador Resources Company shareholders
|
|
$
|
553,223
|
|
|
$
|
336,063
|
|
|
$
|
157,892
|
|
|
$
|
223,138
|
|
|
$
|
262,943
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Operating Data:
|
|
|
|
|
|
|
||||||
Revenues (in thousands):
(1)
|
|
|
|
|
|
|
||||||
Oil
|
|
$
|
635,554
|
|
|
$
|
386,865
|
|
|
$
|
209,908
|
|
Natural gas
|
|
165,146
|
|
|
141,819
|
|
|
81,248
|
|
|||
Total oil and natural gas revenues
|
|
800,700
|
|
|
528,684
|
|
|
291,156
|
|
|||
Third-party midstream services revenues
|
|
21,920
|
|
|
10,198
|
|
|
5,218
|
|
|||
Sales of purchased natural gas
|
|
7,071
|
|
|
—
|
|
|
—
|
|
|||
Lease bonus - mineral acreage
|
|
2,489
|
|
|
—
|
|
|
—
|
|
|||
Realized gain (loss) on derivatives
|
|
2,334
|
|
|
(4,321
|
)
|
|
9,286
|
|
|||
Unrealized gain (loss) on derivatives
|
|
65,085
|
|
|
9,715
|
|
|
(41,238
|
)
|
|||
Total revenues
|
|
$
|
899,599
|
|
|
$
|
544,276
|
|
|
$
|
264,422
|
|
Net Production Volumes:
(1)
|
|
|
|
|
|
|
||||||
Oil (MBbl)
|
|
11,141
|
|
|
7,851
|
|
|
5,096
|
|
|||
Natural gas (Bcf)
|
|
47.3
|
|
|
38.2
|
|
|
30.5
|
|
|||
Total oil equivalent (MBOE)
(2)
|
|
19,026
|
|
|
14,212
|
|
|
10,180
|
|
|||
Average daily production (BOE/d)
(2)
|
|
52,128
|
|
|
38,936
|
|
|
27,813
|
|
|||
Average Sales Prices:
|
|
|
|
|
|
|
||||||
Oil, without realized derivatives (per Bbl)
|
|
$
|
57.04
|
|
|
$
|
49.28
|
|
|
$
|
41.19
|
|
Oil, with realized derivatives (per Bbl)
|
|
$
|
57.38
|
|
|
$
|
48.81
|
|
|
$
|
42.34
|
|
Natural gas, without realized derivatives (per Mcf)
|
|
$
|
3.49
|
|
|
$
|
3.72
|
|
|
$
|
2.66
|
|
Natural gas, with realized derivatives (per Mcf)
|
|
$
|
3.46
|
|
|
$
|
3.70
|
|
|
$
|
2.78
|
|
(1)
|
We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs 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,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
(In thousands, except expenses per BOE)
|
|
|
|
|
|
|
||||||
Expenses:
|
|
|
|
|
|
|
||||||
Production taxes, transportation and processing
|
|
$
|
76,138
|
|
|
$
|
58,275
|
|
|
$
|
43,046
|
|
Lease operating
|
|
92,966
|
|
|
67,313
|
|
|
56,202
|
|
|||
Plant and other midstream services operating
|
|
24,609
|
|
|
13,039
|
|
|
5,389
|
|
|||
Purchased natural gas
|
|
6,635
|
|
|
—
|
|
|
—
|
|
|||
Depletion, depreciation and amortization
|
|
265,142
|
|
|
177,502
|
|
|
122,048
|
|
|||
Accretion of asset retirement obligations
|
|
1,530
|
|
|
1,290
|
|
|
1,182
|
|
|||
Full-cost ceiling impairment
|
|
—
|
|
|
—
|
|
|
158,633
|
|
|||
General and administrative
|
|
69,308
|
|
|
66,016
|
|
|
55,089
|
|
|||
Total expenses
|
|
536,328
|
|
|
383,435
|
|
|
441,589
|
|
|||
Operating income (loss)
|
|
363,271
|
|
|
160,841
|
|
|
(177,167
|
)
|
|||
Other income (expense):
|
|
|
|
|
|
|
||||||
Net (loss) gain on asset sales and inventory impairment
|
|
(196
|
)
|
|
23
|
|
|
107,277
|
|
|||
Interest expense
|
|
(41,327
|
)
|
|
(34,565
|
)
|
|
(28,199
|
)
|
|||
Prepayment premium on extinguishment of debt
|
|
(31,226
|
)
|
|
—
|
|
|
—
|
|
|||
Other income (expense)
|
|
1,551
|
|
|
3,551
|
|
|
(4
|
)
|
|||
Total other (expense) income
|
|
(71,198
|
)
|
|
(30,991
|
)
|
|
79,074
|
|
|||
Income (loss) before income taxes
|
|
292,073
|
|
|
129,850
|
|
|
(98,093
|
)
|
|||
Total income tax benefit
|
|
(7,691
|
)
|
|
(8,157
|
)
|
|
(1,036
|
)
|
|||
Net income attributable to non-controlling interest in subsidiaries
|
|
(25,557
|
)
|
|
(12,140
|
)
|
|
(364
|
)
|
|||
Net income (loss) attributable to Matador Resources Company shareholders
|
|
$
|
274,207
|
|
|
$
|
125,867
|
|
|
$
|
(97,421
|
)
|
Expenses per BOE:
|
|
|
|
|
|
|
||||||
Production taxes, transportation and processing
|
|
$
|
4.00
|
|
|
$
|
4.10
|
|
|
$
|
4.23
|
|
Lease operating
|
|
$
|
4.89
|
|
|
$
|
4.74
|
|
|
$
|
5.52
|
|
Plant and other midstream services operating
|
|
$
|
1.29
|
|
|
$
|
0.92
|
|
|
$
|
0.53
|
|
Depletion, depreciation and amortization
|
|
$
|
13.94
|
|
|
$
|
12.49
|
|
|
$
|
11.99
|
|
General and administrative
|
|
$
|
3.64
|
|
|
$
|
4.65
|
|
|
$
|
5.41
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
(In thousands)
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
608,523
|
|
|
$
|
299,125
|
|
|
$
|
134,086
|
|
Net cash used in investing activities
|
|
(1,515,253
|
)
|
|
(819,284
|
)
|
|
(448,739
|
)
|
|||
Net cash provided by financing activities
|
|
888,232
|
|
|
408,499
|
|
|
467,706
|
|
|||
Net change in cash
|
|
$
|
(18,498
|
)
|
|
$
|
(111,660
|
)
|
|
$
|
153,053
|
|
|
|
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)
|
|
$
|
262,991
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
262,991
|
|
|
$
|
—
|
|
Senior unsecured notes
(2)
|
|
1,050,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,050,000
|
|
|||||
Office leases
|
|
28,953
|
|
|
3,091
|
|
|
7,791
|
|
|
8,150
|
|
|
9,921
|
|
|||||
Non-operated drilling commitments
(3)
|
|
24,320
|
|
|
24,320
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Drilling rig contracts
(4)
|
|
28,381
|
|
|
28,381
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Asset retirement obligations
|
|
31,086
|
|
|
1,350
|
|
|
914
|
|
|
2,094
|
|
|
26,728
|
|
|||||
Natural gas transportation, gathering and processing agreements with non-affiliates
(5)
|
|
420,149
|
|
|
18,936
|
|
|
85,944
|
|
|
85,944
|
|
|
229,325
|
|
|||||
Gathering, processing and disposal agreements with San Mateo
(6)
|
|
221,101
|
|
|
800
|
|
|
69,994
|
|
|
75,102
|
|
|
75,205
|
|
|||||
Natural gas construction contracts
(7)
|
|
3,635
|
|
|
3,635
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total contractual cash obligations
|
|
$
|
2,070,616
|
|
|
$
|
80,513
|
|
|
$
|
164,643
|
|
|
$
|
434,281
|
|
|
$
|
1,391,179
|
|
(1)
|
At
December 31, 2018
, we had
$40.0 million
of borrowings outstanding under the Credit Agreement and approximately
$3.0 million
in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2023. We also had
$220.0 million
of borrowings outstanding under the San Mateo Credit Facility. The San Mateo Credit Facility matures in December 2023. The amounts included in the table above represent principal maturities only. Assuming the amounts outstanding and interest rates of 3.68% and 4.01%, respectively, at
December 31, 2018
, the interest expense is expected to be approximately $1.5 million and $8.8 million each year until maturity.
|
(2)
|
The amounts included in the table above represent principal maturities only. Interest expense on the
$1.05 billion
of Notes that were outstanding as of
December 31, 2018
is expected to be approximately
$61.7 million
each year until maturity.
|
(3)
|
At
December 31, 2018
, 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, 2018
. If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately
$24.3 million
at
December 31, 2018
, 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)
|
In late 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. In late 2017, we entered into an 18-year fixed-fee natural gas transportation agreement where we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline in Eddy County, New Mexico. In late 2017, we also entered into a fixed-fee NGL transportation and fractionation agreement whereby we committed to deliver our NGL production at the tailgate of the Black River Processing Plant. We have committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed in 2020. We have no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then we do not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then we will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If we do not meet our NGL volume commitment in any quarter during the seven-year commitment period, we will be required to pay a deficiency fee per gallon of NGL deficiency. The amounts in the table assume that the seven-year period containing minimum NGL volume commitments begins in 2020. In the second quarter of 2018, we entered into a 16-year, fixed-fee natural gas transportation agreement that begins on October 1, 2019, whereby we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Additionally, in the second quarter of 2018, we entered into a short-term natural gas transportation agreement whereby we committed to deliver a portion of the residue gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Lastly, in the second quarter of 2018, we entered into a 10-year, fixed-fee natural gas sales agreement whereby we committed to deliver residue gas through the counterparty’s pipeline to the Texas Gulf Coast beginning on the in-service date for such pipeline, which is expected to be operational in late 2019. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.
|
(6)
|
In February 2017, we dedicated our current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, effective February 1, 2017, we dedicated our current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, fixed-fee natural gas processing agreement. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.
|
(7)
|
During the first quarter of 2018, a subsidiary of San Mateo entered into agreements for additional field compression and an amine gas treatment unit to maximize the operation of the Black River Processing Plant. See Note 13 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.
|
Exhibit
Number
|
|
Description
|
|
|
|
2.1
|
|
|
|
|
|
3.1
|
|
|
|
|
|
3.2
|
|
|
|
|
|
3.3
|
|
|
|
|
|
3.4
|
|
|
|
|
|
4.1
|
|
|
|
|
|
4.2
|
|
|
|
|
|
4.3
|
|
|
|
|
|
4.4
|
|
|
|
|
|
4.5
|
|
|
|
|
|
10.1†
|
|
|
|
|
|
10.2†
|
|
|
|
|
|
10.3†
|
|
|
|
|
|
10.4†
|
|
|
|
|
|
10.5†
|
|
|
|
|
|
10.6†
|
|
|
|
|
|
10.7†
|
|
|
|
|
|
10.8†
|
|
|
|
|
|
10.9†
|
|
|
|
|
|
10.10†
|
|
|
|
|
|
10.11†
|
|
|
|
|
|
10.12†
|
|
|
|
|
|
10.13†
|
|
|
|
|
|
10.14†
|
|
|
|
|
|
10.15†
|
|
|
|
|
|
10.16†
|
|
|
|
|
|
10.17†
|
|
|
|
|
|
10.18†
|
|
|
|
|
|
10.19†
|
|
|
|
|
|
10.20†
|
|
|
|
|
|
10.21†
|
|
|
|
|
|
10.22†
|
|
|
|
|
|
10.23†
|
|
|
|
|
|
10.24†
|
|
|
|
|
|
10.25†
|
|
|
|
|
|
10.26
|
|
|
|
|
|
10.27
|
|
|
|
|
|
10.28
|
|
|
|
|
|
10.29
|
|
|
|
|
|
10.30
|
|
|
|
|
|
10.31
|
|
|
|
|
|
10.32
|
|
|
|
|
|
10.33
|
|
|
|
|
|
10.34
|
|
|
|
|
|
10.35
|
|
|
|
|
|
10.36
|
|
|
|
|
|
10.37
|
|
|
|
|
|
10.38
|
|
|
|
|
|
10.39†
|
|
|
|
|
|
10.40†
|
|
|
|
|
|
10.41†
|
|
|
|
|
|
10.42†
|
|
|
|
|
|
10.43†
|
|
|
|
|
|
10.44†
|
|
|
|
|
|
10.45†
|
|
|
|
|
|
10.46†
|
|
|
|
|
|
10.47†
|
|
|
|
|
|
10.48†
|
|
|
|
|
|
10.49†
|
|
|
|
|
|
10.50†
|
|
|
|
|
|
10.51†
|
|
|
|
|
|
10.52†
|
|
|
|
|
|
10.53†
|
|
|
|
|
|
10.54†
|
|
|
|
|
|
10.55†
|
|
|
|
|
|
10.56†
|
|
|
|
|
|
10.57†
|
|
|
|
|
|
10.58†
|
|
|
|
|
|
|
|
MATADOR RESOURCES COMPANY
|
||
|
|
|
|
|
March 1, 2019
|
|
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, 2019
|
Joseph Wm. Foran
|
|
(Principal Executive Officer)
|
|
|
|
|
|
||
/s/ David E. Lancaster
|
|
Executive Vice President and Chief Financial Officer
|
|
March 1, 2019
|
David E. Lancaster
|
|
(Principal Financial Officer)
|
|
|
|
|
|
||
/s/ Robert T. Macalik
|
|
Senior Vice President and Chief Accounting Officer
|
|
March 1, 2019
|
Robert T. Macalik
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
||
/s/ Reynald A. Baribault
|
|
Director
|
|
March 1, 2019
|
Reynald A. Baribault
|
|
|
|
|
|
|
|
||
/s/ R. Gaines Baty
|
|
Director
|
|
March 1, 2019
|
R. Gaines Baty
|
|
|
|
|
|
|
|
|
|
/s/ Craig T. Burkert
|
|
Director
|
|
March 1, 2019
|
Craig T. Burkert
|
|
|
|
|
|
|
|
|
|
/s/ William M. Byerley
|
|
Director
|
|
March 1, 2019
|
William M. Byerley
|
|
|
|
|
|
|
|
|
|
/s/ Matthew P. Clifton
|
|
Director
|
|
March 1, 2019
|
Matthew P. Clifton
|
|
|
|
|
|
|
|
|
|
/s/ Julia P. Forrester Rogers
|
|
Director
|
|
March 1, 2019
|
Julia P. Forrester Rogers
|
|
|
|
|
|
|
|
|
|
/s/ Timothy E. Parker
|
|
Director
|
|
March 1, 2019
|
Timothy E. Parker
|
|
|
|
|
|
|
|
|
|
/s/ David M. Posner
|
|
Director
|
|
March 1, 2019
|
David M. Posner
|
|
|
|
|
|
|
|
|
|
/s/ Kenneth L. Stewart
|
|
Director
|
|
March 1, 2019
|
Kenneth L. Stewart
|
|
|
|
|
|
|
Consolidated Financial Statements
|
|
|
|
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash
|
|
$
|
64,545
|
|
|
$
|
96,505
|
|
Restricted cash
|
|
19,439
|
|
|
5,977
|
|
||
Accounts receivable
|
|
|
|
|
||||
Oil and natural gas revenues
|
|
68,161
|
|
|
65,962
|
|
||
Joint interest billings
|
|
61,831
|
|
|
67,225
|
|
||
Other
|
|
16,159
|
|
|
8,031
|
|
||
Derivative instruments
|
|
49,929
|
|
|
1,190
|
|
||
Lease and well equipment inventory
|
|
17,564
|
|
|
5,993
|
|
||
Prepaid expenses and other assets
|
|
8,057
|
|
|
6,287
|
|
||
Total current assets
|
|
305,685
|
|
|
257,170
|
|
||
Property and equipment, at cost
|
|
|
|
|
||||
Oil and natural gas properties, full-cost method
|
|
|
|
|
||||
Evaluated
|
|
3,780,236
|
|
|
3,004,770
|
|
||
Unproved and unevaluated
|
|
1,199,511
|
|
|
637,396
|
|
||
Midstream and other property and equipment
|
|
450,066
|
|
|
281,096
|
|
||
Less accumulated depletion, depreciation and amortization
|
|
(2,306,949
|
)
|
|
(2,041,806
|
)
|
||
Net property and equipment
|
|
3,122,864
|
|
|
1,881,456
|
|
||
Other assets
|
|
|
|
|
||||
Deferred income taxes
|
|
20,457
|
|
|
—
|
|
||
Other assets
|
|
6,512
|
|
|
7,064
|
|
||
Total other assets
|
|
26,969
|
|
|
7,064
|
|
||
Total assets
|
|
$
|
3,455,518
|
|
|
$
|
2,145,690
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts payable
|
|
$
|
66,970
|
|
|
$
|
11,757
|
|
Accrued liabilities
|
|
170,855
|
|
|
174,348
|
|
||
Royalties payable
|
|
64,776
|
|
|
61,358
|
|
||
Amounts due to affiliates
|
|
13,052
|
|
|
10,302
|
|
||
Derivative instruments
|
|
—
|
|
|
16,429
|
|
||
Advances from joint interest owners
|
|
10,968
|
|
|
2,789
|
|
||
Amounts due to joint ventures
|
|
2,373
|
|
|
4,873
|
|
||
Other current liabilities
|
|
1,028
|
|
|
750
|
|
||
Total current liabilities
|
|
330,022
|
|
|
282,606
|
|
||
Long-term liabilities
|
|
|
|
|
||||
Borrowings under Credit Agreement
|
|
40,000
|
|
|
—
|
|
||
Borrowings under San Mateo Credit Facility
|
|
220,000
|
|
|
—
|
|
||
Senior unsecured notes payable
|
|
1,037,837
|
|
|
574,073
|
|
||
Asset retirement obligations
|
|
29,736
|
|
|
25,080
|
|
||
Derivative instruments
|
|
83
|
|
|
—
|
|
||
Deferred income taxes
|
|
13,221
|
|
|
—
|
|
||
Other long-term liabilities
|
|
4,962
|
|
|
6,385
|
|
||
Total long-term liabilities
|
|
1,345,839
|
|
|
605,538
|
|
||
Commitments and contingencies (Note 13)
|
|
|
|
|
||||
Shareholders’ equity
|
|
|
|
|
||||
Common stock — $0.01 par value, 160,000,000 shares authorized; 116,374,503 and 108,513,597 shares issued; and 116,353,590 and 108,510,160 shares outstanding, respectively
|
|
1,164
|
|
|
1,085
|
|
||
Additional paid-in capital
|
|
1,924,408
|
|
|
1,666,024
|
|
||
Accumulated deficit
|
|
(236,277
|
)
|
|
(510,484
|
)
|
||
Treasury stock, at cost, 20,913 and 3,437 shares, respectively
|
|
(415
|
)
|
|
(69
|
)
|
||
Total Matador Resources Company shareholders’ equity
|
|
1,688,880
|
|
|
1,156,556
|
|
||
Non-controlling interest in subsidiaries
|
|
90,777
|
|
|
100,990
|
|
||
Total shareholders’ equity
|
|
1,779,657
|
|
|
1,257,546
|
|
||
Total liabilities and shareholders’ equity
|
|
$
|
3,455,518
|
|
|
$
|
2,145,690
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Revenues
|
|
|
|
|
|
|
||||||
Oil and natural gas revenues
|
|
$
|
800,700
|
|
|
$
|
528,684
|
|
|
$
|
291,156
|
|
Third-party midstream services revenues
|
|
21,920
|
|
|
10,198
|
|
|
5,218
|
|
|||
Sales of purchased natural gas
|
|
7,071
|
|
|
—
|
|
|
—
|
|
|||
Lease bonus - mineral acreage
|
|
2,489
|
|
|
—
|
|
|
—
|
|
|||
Realized gain (loss) on derivatives
|
|
2,334
|
|
|
(4,321
|
)
|
|
9,286
|
|
|||
Unrealized gain (loss) on derivatives
|
|
65,085
|
|
|
9,715
|
|
|
(41,238
|
)
|
|||
Total revenues
|
|
899,599
|
|
|
544,276
|
|
|
264,422
|
|
|||
Expenses
|
|
|
|
|
|
|
||||||
Production taxes, transportation and processing
|
|
76,138
|
|
|
58,275
|
|
|
43,046
|
|
|||
Lease operating
|
|
92,966
|
|
|
67,313
|
|
|
56,202
|
|
|||
Plant and other midstream services operating
|
|
24,609
|
|
|
13,039
|
|
|
5,389
|
|
|||
Purchased natural gas
|
|
6,635
|
|
|
—
|
|
|
—
|
|
|||
Depletion, depreciation and amortization
|
|
265,142
|
|
|
177,502
|
|
|
122,048
|
|
|||
Accretion of asset retirement obligations
|
|
1,530
|
|
|
1,290
|
|
|
1,182
|
|
|||
Full-cost ceiling impairment
|
|
—
|
|
|
—
|
|
|
158,633
|
|
|||
General and administrative
|
|
69,308
|
|
|
66,016
|
|
|
55,089
|
|
|||
Total expenses
|
|
536,328
|
|
|
383,435
|
|
|
441,589
|
|
|||
Operating income (loss)
|
|
363,271
|
|
|
160,841
|
|
|
(177,167
|
)
|
|||
Other income (expense)
|
|
|
|
|
|
|
||||||
Net (loss) gain on asset sales and inventory impairment
|
|
(196
|
)
|
|
23
|
|
|
107,277
|
|
|||
Interest expense
|
|
(41,327
|
)
|
|
(34,565
|
)
|
|
(28,199
|
)
|
|||
Prepayment premium on extinguishment of debt
|
|
(31,226
|
)
|
|
—
|
|
|
—
|
|
|||
Other income (expense)
|
|
1,551
|
|
|
3,551
|
|
|
(4
|
)
|
|||
Total other (expense) income
|
|
(71,198
|
)
|
|
(30,991
|
)
|
|
79,074
|
|
|||
Income (loss) before income taxes
|
|
292,073
|
|
|
129,850
|
|
|
(98,093
|
)
|
|||
Income tax (benefit) provision
|
|
|
|
|
|
|
||||||
Current
|
|
(455
|
)
|
|
(8,157
|
)
|
|
(1,036
|
)
|
|||
Deferred
|
|
(7,236
|
)
|
|
—
|
|
|
—
|
|
|||
Total income tax benefit
|
|
(7,691
|
)
|
|
(8,157
|
)
|
|
(1,036
|
)
|
|||
Net income (loss)
|
|
299,764
|
|
|
138,007
|
|
|
(97,057
|
)
|
|||
Net income attributable to non-controlling interest in subsidiaries
|
|
(25,557
|
)
|
|
(12,140
|
)
|
|
(364
|
)
|
|||
Net income (loss) attributable to Matador Resources Company shareholders
|
|
$
|
274,207
|
|
|
$
|
125,867
|
|
|
$
|
(97,421
|
)
|
Earnings (loss) per common share
|
|
|
|
|
|
|
||||||
Basic
|
|
$
|
2.41
|
|
|
$
|
1.23
|
|
|
$
|
(1.07
|
)
|
Diluted
|
|
$
|
2.41
|
|
|
$
|
1.23
|
|
|
$
|
(1.07
|
)
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
||||||
Basic
|
|
113,580
|
|
|
102,029
|
|
|
91,273
|
|
|||
Diluted
|
|
113,691
|
|
|
102,543
|
|
|
91,273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total shareholders’ equity attributable to Matador Resources Company
|
|
|
|
|
||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
|
|
Additional
paid-in
capital
|
|
Accumulated deficit
|
|
Treasury Stock
|
|
|
Non-controlling interest in subsidiaries
|
|
Total shareholders
’
equity
|
||||||||||||||||||||||
|
|
Common Stock
|
|
|
|
|
|
|
||||||||||||||||||||||||||
|
|
Shares
|
|
Amount
|
|
|
|
Shares
|
|
Amount
|
|
|
|
|||||||||||||||||||||
Balance at January 1, 2016
|
|
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
|
|
|||||||
Issuance of common stock pursuant to public offering
|
|
8,000
|
|
|
80
|
|
|
208,640
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
208,720
|
|
|
—
|
|
|
208,720
|
|
|||||||
Issuance of common stock pursuant to employee stock compensation plan
|
|
530
|
|
|
5
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Issuance of common stock pursuant to directors’ and advisors’ compensation plan
|
|
77
|
|
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Cost to issue equity
|
|
—
|
|
|
—
|
|
|
(280
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(280
|
)
|
|
—
|
|
|
(280
|
)
|
|||||||
Stock-based compensation expense related to equity-based awards including amounts capitalized
|
|
—
|
|
|
—
|
|
|
19,594
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,594
|
|
|
—
|
|
|
19,594
|
|
|||||||
Stock options exercised, net of options forfeited in net share settlements
|
|
514
|
|
|
5
|
|
|
(1,189
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,184
|
)
|
|
—
|
|
|
(1,184
|
)
|
|||||||
Restricted stock forfeited
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
123
|
|
|
(1,658
|
)
|
|
(1,658
|
)
|
|
—
|
|
|
(1,658
|
)
|
|||||||
Purchase of non-controlling interest of less-than-wholly-owned subsidiary
|
|
—
|
|
|
—
|
|
|
(1,250
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,250
|
)
|
|
(1,403
|
)
|
|
(2,653
|
)
|
|||||||
Contributions related to formation of Joint Venture (see Note 5)
|
|
—
|
|
|
—
|
|
|
116,622
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
116,622
|
|
|
54,878
|
|
|
171,500
|
|
|||||||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
44,100
|
|
|
44,100
|
|
|||||||
Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,045
|
)
|
|
(10,045
|
)
|
|||||||
Cancellation of treasury stock
|
|
(126
|
)
|
|
(1
|
)
|
|
(1,588
|
)
|
|
—
|
|
|
(126
|
)
|
|
1,589
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Current period net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
125,867
|
|
|
—
|
|
|
—
|
|
|
125,867
|
|
|
12,140
|
|
|
138,007
|
|
|||||||
Balance at December 31, 2017
|
|
108,514
|
|
|
1,085
|
|
|
1,666,024
|
|
|
(510,484
|
)
|
|
3
|
|
|
(69
|
)
|
|
1,156,556
|
|
|
100,990
|
|
|
1,257,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total shareholders’ equity attributable to Matador Resources Company
|
|
|
|
|
||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
|
|
Additional
paid-in
capital
|
|
Accumulated deficit
|
|
Treasury Stock
|
|
|
Non-controlling interest in subsidiaries
|
|
Total shareholders
’
equity
|
||||||||||||||||||||||
|
|
Common Stock
|
|
|
|
|
|
|
||||||||||||||||||||||||||
|
|
Shares
|
|
Amount
|
|
|
|
Shares
|
|
Amount
|
|
|
|
|||||||||||||||||||||
Issuance of common stock pursuant to employee stock compensation plan
|
|
759
|
|
|
8
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Issuance of common stock pursuant to public offering
|
|
7,000
|
|
|
70
|
|
|
226,542
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
226,612
|
|
|
—
|
|
|
226,612
|
|
|||||||
Cost to issue equity
|
|
—
|
|
|
—
|
|
|
(204
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(204
|
)
|
|
—
|
|
|
(204
|
)
|
|||||||
Issuance of common stock pursuant to directors’ and advisors’ compensation plan
|
|
81
|
|
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Stock-based compensation expense related to equity-based awards including amounts capitalized
|
|
—
|
|
|
—
|
|
|
22,660
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,660
|
|
|
—
|
|
|
22,660
|
|
|||||||
Stock options exercised, net of options forfeited in net share settlements
|
|
179
|
|
|
2
|
|
|
(1,269
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,267
|
)
|
|
—
|
|
|
(1,267
|
)
|
|||||||
Restricted stock forfeited
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
176
|
|
|
(4,384
|
)
|
|
(4,384
|
)
|
|
—
|
|
|
(4,384
|
)
|
|||||||
Contributions related to formation of Joint Venture (see Note 5)
|
|
—
|
|
|
—
|
|
|
14,700
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,700
|
|
|
—
|
|
|
14,700
|
|
|||||||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
85,750
|
|
|
85,750
|
|
|||||||
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(121,520
|
)
|
|
(121,520
|
)
|
|||||||
Cancellation of treasury stock
|
|
(158
|
)
|
|
(2
|
)
|
|
(4,036
|
)
|
|
—
|
|
|
(158
|
)
|
|
4,038
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Current period net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
274,207
|
|
|
—
|
|
|
—
|
|
|
274,207
|
|
|
25,557
|
|
|
299,764
|
|
|||||||
Balance at December 31, 2018
|
|
116,375
|
|
|
$
|
1,164
|
|
|
$
|
1,924,408
|
|
|
$
|
(236,277
|
)
|
|
21
|
|
|
$
|
(415
|
)
|
|
$
|
1,688,880
|
|
|
$
|
90,777
|
|
|
$
|
1,779,657
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Operating activities
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
299,764
|
|
|
$
|
138,007
|
|
|
$
|
(97,057
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities
|
|
|
|
|
|
|
||||||
Unrealized (gain) loss on derivatives
|
|
(65,085
|
)
|
|
(9,715
|
)
|
|
41,238
|
|
|||
Depletion, depreciation and amortization
|
|
265,142
|
|
|
177,502
|
|
|
122,048
|
|
|||
Accretion of asset retirement obligations
|
|
1,530
|
|
|
1,290
|
|
|
1,182
|
|
|||
Full-cost ceiling impairment
|
|
—
|
|
|
—
|
|
|
158,633
|
|
|||
Stock-based compensation expense
|
|
17,200
|
|
|
16,654
|
|
|
12,362
|
|
|||
Prepayment premium on extinguishment of debt
|
|
31,226
|
|
|
—
|
|
|
—
|
|
|||
Deferred income tax benefit
|
|
(7,236
|
)
|
|
—
|
|
|
—
|
|
|||
Amortization of debt issuance cost
|
|
1,357
|
|
|
468
|
|
|
1,148
|
|
|||
Net loss (gain) on asset sales and inventory impairment
|
|
196
|
|
|
(23
|
)
|
|
(107,277
|
)
|
|||
Changes in operating assets and liabilities
|
|
|
|
|
|
|
||||||
Accounts receivable
|
|
(4,934
|
)
|
|
(82,549
|
)
|
|
(14,259
|
)
|
|||
Lease and well equipment inventory
|
|
(12,176
|
)
|
|
(3,623
|
)
|
|
(700
|
)
|
|||
Prepaid expenses and other assets
|
|
(1,770
|
)
|
|
(2,960
|
)
|
|
(124
|
)
|
|||
Other assets
|
|
3,418
|
|
|
(6,425
|
)
|
|
490
|
|
|||
Accounts payable, accrued liabilities and other current liabilities
|
|
68,647
|
|
|
33,559
|
|
|
6,611
|
|
|||
Royalties payable
|
|
3,418
|
|
|
37,370
|
|
|
7,495
|
|
|||
Advances from joint interest owners
|
|
8,179
|
|
|
1,089
|
|
|
1,000
|
|
|||
Income taxes payable
|
|
—
|
|
|
—
|
|
|
(2,848
|
)
|
|||
Other long-term liabilities
|
|
(353
|
)
|
|
(1,519
|
)
|
|
4,144
|
|
|||
Net cash provided by operating activities
|
|
608,523
|
|
|
299,125
|
|
|
134,086
|
|
|||
Investing activities
|
|
|
|
|
|
|
||||||
Oil and natural gas properties capital expenditures
|
|
(1,357,802
|
)
|
|
(699,445
|
)
|
|
(379,067
|
)
|
|||
Expenditures for midstream and other property and equipment
|
|
(165,784
|
)
|
|
(120,816
|
)
|
|
(74,845
|
)
|
|||
Proceeds from sale of assets
|
|
8,333
|
|
|
977
|
|
|
5,173
|
|
|||
Net cash used in investing activities
|
|
(1,515,253
|
)
|
|
(819,284
|
)
|
|
(448,739
|
)
|
|||
Financing activities
|
|
|
|
|
|
|
||||||
Repayments of borrowings
|
|
(370,000
|
)
|
|
—
|
|
|
(120,000
|
)
|
|||
Borrowings under Credit Agreement
|
|
410,000
|
|
|
—
|
|
|
120,000
|
|
|||
Borrowings under San Mateo Credit Facility
|
|
220,000
|
|
|
—
|
|
|
—
|
|
|||
Cost to enter into or amend credit facilities
|
|
(3,077
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from issuance of senior unsecured notes
|
|
1,051,500
|
|
|
—
|
|
|
184,625
|
|
|||
Cost to issue senior unsecured notes
|
|
(14,098
|
)
|
|
—
|
|
|
(2,734
|
)
|
|||
Purchase of senior unsecured notes
|
|
(605,780
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from issuance of common stock
|
|
226,612
|
|
|
208,720
|
|
|
288,510
|
|
|||
Cost to issue equity
|
|
(204
|
)
|
|
(280
|
)
|
|
(847
|
)
|
|||
Proceeds from stock options exercised
|
|
815
|
|
|
2,920
|
|
|
100
|
|
|||
Contributions related to formation of Joint Venture
|
|
14,700
|
|
|
171,500
|
|
|
—
|
|
|||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries
|
|
85,750
|
|
|
44,100
|
|
|
—
|
|
|||
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries
|
|
(121,520
|
)
|
|
(10,045
|
)
|
|
—
|
|
|||
Taxes paid related to net share settlement of stock-based compensation
|
|
(6,466
|
)
|
|
(5,763
|
)
|
|
(1,948
|
)
|
|||
Purchase of non-controlling interest of less-than-wholly-owned subsidiary
|
|
—
|
|
|
(2,653
|
)
|
|
—
|
|
|||
Net cash provided by financing activities
|
|
888,232
|
|
|
408,499
|
|
|
467,706
|
|
|||
(Decrease) increase in cash and restricted cash
|
|
(18,498
|
)
|
|
(111,660
|
)
|
|
153,053
|
|
|||
Cash and restricted cash at beginning of year
|
|
102,482
|
|
|
214,142
|
|
|
61,089
|
|
|||
Cash and restricted cash at end of year
|
|
$
|
83,984
|
|
|
$
|
102,482
|
|
|
$
|
214,142
|
|
|
Year Ended
December 31, 2018 |
||
Revenues from contracts with customers
|
$
|
829,691
|
|
Lease bonus - mineral acreage
|
2,489
|
|
|
Realized gain on derivatives
|
2,334
|
|
|
Unrealized gain on derivatives
|
65,085
|
|
|
Total revenues
|
$
|
899,599
|
|
|
Year Ended
December 31, 2018 |
||
Oil revenues
|
$
|
635,554
|
|
Natural gas revenues
|
165,146
|
|
|
Third-party midstream services revenues
|
21,920
|
|
|
Sales of purchased natural gas
|
7,071
|
|
|
Total revenues from contracts with customers
|
$
|
829,691
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Net income (loss) attributable to Matador Resources Company shareholders — numerator
|
|
$
|
274,207
|
|
|
$
|
125,867
|
|
|
$
|
(97,421
|
)
|
|
|
|
|
|
|
|
||||||
Weighted average common shares outstanding — denominator
|
|
|
|
|
|
|
||||||
Basic
|
|
113,580
|
|
|
102,029
|
|
|
91,273
|
|
|||
Dilutive effect of options and restricted stock units
|
|
111
|
|
|
514
|
|
|
—
|
|
|||
Diluted weighted average common shares outstanding
|
|
113,691
|
|
|
102,543
|
|
|
91,273
|
|
|||
Earnings (loss) per common share attributable to
Matador Resources Company shareholders |
|
|
|
|
|
|
||||||
Basic
|
|
$
|
2.41
|
|
|
$
|
1.23
|
|
|
$
|
(1.07
|
)
|
Diluted
|
|
$
|
2.41
|
|
|
$
|
1.23
|
|
|
$
|
(1.07
|
)
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Oil and natural gas properties
|
|
|
|
|
||||
Evaluated (subject to amortization)
|
|
$
|
3,780,236
|
|
|
$
|
3,004,770
|
|
Unproved and unevaluated (not subject to amortization)
|
|
1,199,511
|
|
|
637,396
|
|
||
Total oil and natural gas properties
|
|
4,979,747
|
|
|
3,642,166
|
|
||
Accumulated depletion
|
|
(2,273,010
|
)
|
|
(2,021,169
|
)
|
||
Net oil and natural gas properties
|
|
2,706,737
|
|
|
1,620,997
|
|
||
Midstream and other property and equipment
|
|
|
|
|
||||
Midstream equipment and facilities
|
|
424,480
|
|
|
258,725
|
|
||
Furniture, fixtures and other equipment
|
|
7,184
|
|
|
6,109
|
|
||
Software
|
|
8,039
|
|
|
7,942
|
|
||
Land
|
|
4,192
|
|
|
2,892
|
|
||
Leasehold improvements
|
|
6,171
|
|
|
5,428
|
|
||
Total midstream and other property and equipment
|
|
450,066
|
|
|
281,096
|
|
||
Accumulated depreciation
|
|
(33,939
|
)
|
|
(20,637
|
)
|
||
Net midstream and other property and equipment
|
|
416,127
|
|
|
260,459
|
|
||
Net property and equipment
|
|
$
|
3,122,864
|
|
|
$
|
1,881,456
|
|
Description
|
|
2018
|
|
2017
|
|
2016
|
|
2015 and prior
|
|
Total
|
||||||||||
Costs incurred for
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Property acquisition
|
|
$
|
602,117
|
|
|
$
|
212,846
|
|
|
$
|
116,389
|
|
|
$
|
223,656
|
|
|
$
|
1,155,008
|
|
Exploration wells
|
|
12,361
|
|
|
1,235
|
|
|
712
|
|
|
204
|
|
|
14,512
|
|
|||||
Development wells
|
|
29,399
|
|
|
391
|
|
|
159
|
|
|
42
|
|
|
29,991
|
|
|||||
Total
|
|
$
|
643,877
|
|
|
$
|
214,472
|
|
|
$
|
117,260
|
|
|
$
|
223,902
|
|
|
$
|
1,199,511
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Beginning asset retirement obligations
|
|
$
|
26,256
|
|
|
$
|
20,640
|
|
Liabilities incurred during period
|
|
3,566
|
|
|
2,920
|
|
||
Liabilities settled during period
|
|
(708
|
)
|
|
(430
|
)
|
||
Revisions in estimated cash flows
|
|
442
|
|
|
1,836
|
|
||
Accretion expense
|
|
1,530
|
|
|
1,290
|
|
||
Ending asset retirement obligations
|
|
31,086
|
|
|
26,256
|
|
||
Less: current asset retirement obligations
(1)
|
|
(1,350
|
)
|
|
(1,176
|
)
|
||
Long-term asset retirement obligations
|
|
$
|
29,736
|
|
|
$
|
25,080
|
|
(1)
|
Included in accrued liabilities in the Company’s consolidated balance sheets at
December 31, 2018 and 2017
.
|
•
|
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.
|
•
|
incur indebtedness or grant liens on any of San Mateo’s assets;
|
•
|
enter into 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 San Mateo’s assets; and
|
•
|
issue equity interests in San Mateo or its subsidiaries.
|
•
|
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 San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods;
|
•
|
bankruptcy or insolvency events involving San Mateo or its subsidiaries; and
|
•
|
a change of control, as defined in the San Mateo Credit Facility.
|
Year
|
|
Redemption Price
|
2021
|
|
104.406%
|
2022
|
|
102.938%
|
2023
|
|
101.469%
|
2024 and thereafter
|
|
100.000%
|
•
|
incur additional indebtedness;
|
•
|
sell assets;
|
•
|
pay dividends or make certain investments;
|
•
|
create liens that secure indebtedness;
|
•
|
enter into transactions with affiliates; and
|
•
|
merge or consolidate with another company.
|
•
|
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 the Company to comply with its obligations to offer to purchase or purchase notes pursuant to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating to mergers;
|
•
|
failure by the Company for
180
days after notice to comply with its reporting obligations under the Indenture;
|
•
|
failure by the Company 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 the Company and its Restricted Subsidiaries in the aggregate principal amount of
$50.0 million
or more;
|
•
|
failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of
$50.0 million
within
60
days;
|
•
|
any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and
|
•
|
certain events of bankruptcy or insolvency with respect to the Company 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,
|
||||||
|
|
2018
|
|
2017
|
||||
Deferred tax assets
|
|
|
|
|
||||
Unrealized loss on derivatives
|
|
$
|
—
|
|
|
$
|
3,200
|
|
Net operating loss carryforwards
|
|
116,374
|
|
|
118,134
|
|
||
Percentage depletion carryover
|
|
1,624
|
|
|
1,582
|
|
||
Basis increase related to the San Mateo transaction
|
|
—
|
|
|
18,382
|
|
||
Other
|
|
9,115
|
|
|
—
|
|
||
Total deferred tax assets
|
|
127,113
|
|
|
141,298
|
|
||
Valuation allowance on deferred tax assets
|
|
(6,519
|
)
|
|
(89,482
|
)
|
||
Total deferred tax assets, net of valuation allowance
|
|
120,594
|
|
|
51,816
|
|
||
Deferred tax liabilities
|
|
|
|
|
||||
Unrealized gain on derivatives
|
|
(10,468
|
)
|
|
—
|
|
||
Property and equipment
|
|
(100,634
|
)
|
|
(40,568
|
)
|
||
Other
|
|
(2,256
|
)
|
|
(11,248
|
)
|
||
Total deferred tax liabilities
|
|
(113,358
|
)
|
|
(51,816
|
)
|
||
Net deferred tax assets
|
|
$
|
7,236
|
|
|
$
|
—
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Current income tax (benefit) provision
|
|
|
|
|
|
|
||||||
Federal income tax
|
|
$
|
(455
|
)
|
|
$
|
(8,178
|
)
|
|
$
|
(1,144
|
)
|
State income tax
|
|
—
|
|
|
21
|
|
|
108
|
|
|||
Net current income tax benefit
|
|
$
|
(455
|
)
|
|
$
|
(8,157
|
)
|
|
$
|
(1,036
|
)
|
Deferred income tax (benefit) provision
|
|
|
|
|
|
|
||||||
Federal income tax
|
|
$
|
(20,457
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
State income tax
|
|
13,221
|
|
|
—
|
|
|
—
|
|
|||
Net deferred income tax benefit
|
|
$
|
(7,236
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Federal tax expense (benefit) at statutory rate
(1)
|
|
$
|
61,543
|
|
|
$
|
45,447
|
|
|
$
|
(34,333
|
)
|
State income tax
|
|
16,181
|
|
|
368
|
|
|
539
|
|
|||
Permanent differences
|
|
(2,488
|
)
|
|
(4,740
|
)
|
|
(499
|
)
|
|||
Federal alternative minimum tax
|
|
—
|
|
|
—
|
|
|
1,144
|
|
|||
AMT credit refundable
|
|
455
|
|
|
8,178
|
|
|
—
|
|
|||
Tax Cuts and Jobs Act rate change
|
|
—
|
|
|
51,525
|
|
|
—
|
|
|||
Change in federal valuation allowance
|
|
(80,003
|
)
|
|
(101,917
|
)
|
|
33,688
|
|
|||
Change in state valuation allowance
|
|
(2,924
|
)
|
|
1,139
|
|
|
(539
|
)
|
|||
Net deferred income tax benefit
|
|
(7,236
|
)
|
|
—
|
|
|
—
|
|
|||
Net current income tax benefit
|
|
(455
|
)
|
|
(8,157
|
)
|
|
(1,036
|
)
|
|||
Total income tax benefit
|
|
$
|
(7,691
|
)
|
|
$
|
(8,157
|
)
|
|
$
|
(1,036
|
)
|
(1)
|
The statutory federal tax rate was
21%
for the year ended
December 31, 2018
and
35%
for the years ended December 31, 2017 and 2016.
|
|
|
2018
|
|
2017
|
|
2016
|
Stock option pricing model
|
|
Black Scholes Merton
|
|
Black Scholes Merton
|
|
Black Scholes Merton
|
Expected option life
|
|
1.14 years
|
|
2.14 years
|
|
3.14 years
|
Risk-free interest rate
|
|
2.48%
|
|
1.98%
|
|
1.70%
|
Volatility
|
|
37.94%
|
|
43.60%
|
|
47.07%
|
Dividend yield
|
|
—%
|
|
—%
|
|
—%
|
Estimated forfeiture rate
|
|
—%
|
|
—%
|
|
—%
|
|
|
2018
|
|
2017
|
|
2016
|
Stock option pricing model
|
|
Black Scholes Merton
|
|
Black Scholes Merton
|
|
Black Scholes Merton
|
Expected option life
|
|
4.00 years
|
|
4.00 years
|
|
3.96 years
|
Risk-free interest rate
|
|
2.51%
|
|
1.77%
|
|
1.08%
|
Volatility
|
|
45.17%
|
|
47.00%
|
|
45.68%
|
Dividend yield
|
|
—%
|
|
—%
|
|
—%
|
Estimated forfeiture rate
|
|
2.24%
|
|
3.66%
|
|
1.16%
|
Weighted average fair value of stock option awards granted during the year
|
|
$12.64
|
|
$10.49
|
|
$5.65
|
|
|
Number of
options
(in thousands)
|
|
Weighted
average
exercise price
|
|||
Options outstanding at December 31, 2017
|
|
3,064
|
|
|
$
|
21.14
|
|
Options granted
|
|
563
|
|
|
$
|
29.68
|
|
Options exercised
|
|
(383
|
)
|
|
$
|
13.84
|
|
Options forfeited
|
|
(18
|
)
|
|
$
|
26.33
|
|
Options expired
|
|
(1
|
)
|
|
$
|
26.86
|
|
Options outstanding at December 31, 2018
|
|
3,225
|
|
|
$
|
23.48
|
|
|
|
Options outstanding at
December 31, 2018
|
|
Options exercisable at
December 31, 2018
|
||||||||||||
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
|
||||||
$9.00
|
|
68
|
|
|
1.14
|
|
$
|
9.00
|
|
|
68
|
|
|
$
|
9.00
|
|
$13.22 - $15.00
|
|
615
|
|
|
2.13
|
|
$
|
14.98
|
|
|
3
|
|
|
$
|
13.22
|
|
$19.71 - $22.70
|
|
727
|
|
|
1.10
|
|
$
|
21.92
|
|
|
706
|
|
|
$
|
21.93
|
|
$23.40 - $29.68
|
|
1,815
|
|
|
3.91
|
|
$
|
26.79
|
|
|
556
|
|
|
$
|
24.65
|
|
|
|
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, 2017
|
|
1,104
|
|
|
$
|
22.59
|
|
|
65
|
|
|
$
|
23.36
|
|
Granted
|
|
759
|
|
|
$
|
29.45
|
|
|
64
|
|
|
$
|
27.69
|
|
Vested
|
|
(475
|
)
|
|
$
|
23.87
|
|
|
(71
|
)
|
|
$
|
23.90
|
|
Forfeited
|
|
(32
|
)
|
|
$
|
27.20
|
|
|
—
|
|
|
—
|
|
|
Non-vested at December 31, 2018
|
|
1,356
|
|
|
$
|
25.87
|
|
|
58
|
|
|
$
|
27.48
|
|
Commodity
|
|
Calculation Period
|
|
Notional Quantity (Bbl)
|
|
Weighted Average Price Floor ($/Bbl)
|
|
Weighted Average Price, Short Call ($/Bbl)
|
|
Weighted Average Price, Long Call ($/Bbl)
|
|
Fair Value of Asset (Liability) (thousands)
|
|||||||||||
Oil
|
|
01/01/2019 - 12/31/2019
|
|
1,320,000
|
|
|
$
|
60.00
|
|
|
$
|
75.00
|
|
|
$
|
78.85
|
|
|
$
|
18,114
|
|
||
Natural Gas
|
|
01/01/2019 - 12/31/2019
|
2.50
|
|
4,800,000
|
|
|
$
|
2.50
|
|
|
$
|
3.00
|
|
|
3.24
|
|
120
|
|
120
|
|
||
Total open three-way costless collar contracts
|
|
|
|
|
|
|
|
$
|
18,234
|
|
Commodity
|
|
Calculation Period
|
|
Notional Quantity (Bbl or Gal)
|
|
Fixed Price
($/Bbl or $/Gal)
|
|
Fair Value of Asset (Liability)
(thousands) |
|||||
Oil Basis Swaps
|
|
01/01/2020 - 12/31/2020
|
|
1,200,000
|
|
|
$
|
(0.15
|
)
|
|
$
|
(83
|
)
|
Total open swap contracts
|
|
|
|
|
|
|
|
$
|
(83
|
)
|
Derivative Instruments
|
|
Gross amounts recognized
|
|
Gross amounts netted in the consolidated balance sheets
|
|
Net amounts presented in the consolidated balance sheets
|
||||||
December 31, 2018
|
|
|
|
|
|
|
||||||
Current assets
|
|
$
|
53,136
|
|
|
$
|
(3,207
|
)
|
|
$
|
49,929
|
|
Long-term liabilities
|
|
(83
|
)
|
|
—
|
|
|
(83
|
)
|
|||
Total
|
|
$
|
53,053
|
|
|
$
|
(3,207
|
)
|
|
$
|
49,846
|
|
December 31, 2017
|
|
|
|
|
|
|
||||||
Current assets
|
|
$
|
131,092
|
|
|
$
|
(129,902
|
)
|
|
$
|
1,190
|
|
Current liabilities
|
|
(146,331
|
)
|
|
129,902
|
|
|
(16,429
|
)
|
|||
Total
|
|
$
|
(15,239
|
)
|
|
$
|
—
|
|
|
$
|
(15,239
|
)
|
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, 2018 using |
||||||||||||||
Description
|
|
|||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|||||||||
Assets (Liabilities)
|
|
|
|
|
|
|
|
|
||||||||
Oil derivatives and basis swaps
|
|
$
|
—
|
|
|
$
|
49,562
|
|
|
$
|
—
|
|
|
$
|
49,562
|
|
Natural gas derivatives
|
|
—
|
|
|
284
|
|
|
—
|
|
|
284
|
|
||||
Total
|
|
$
|
—
|
|
|
$
|
49,846
|
|
|
$
|
—
|
|
|
$
|
49,846
|
|
|
|
Fair Value Measurements at
December 31, 2017 using |
||||||||||||||
Description
|
|
|||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|||||||||
Assets (Liabilities)
|
|
|
|
|
|
|
|
|
||||||||
Oil derivatives and basis swaps
|
|
$
|
—
|
|
|
$
|
(16,429
|
)
|
|
$
|
—
|
|
|
$
|
(16,429
|
)
|
Natural gas derivatives
|
|
—
|
|
|
1,190
|
|
|
—
|
|
|
1,190
|
|
||||
Total
|
|
$
|
—
|
|
|
$
|
(15,239
|
)
|
|
$
|
—
|
|
|
$
|
(15,239
|
)
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Accrued evaluated and unproved and unevaluated property costs
|
|
$
|
86,318
|
|
|
$
|
105,347
|
|
Accrued midstream properties costs
|
|
16,808
|
|
|
14,823
|
|
||
Accrued lease operating expenses
|
|
12,705
|
|
|
12,611
|
|
||
Accrued interest on debt
|
|
22,448
|
|
|
8,345
|
|
||
Accrued asset retirement obligations
|
|
1,350
|
|
|
1,176
|
|
||
Accrued partners’ share of joint interest charges
|
|
17,037
|
|
|
27,628
|
|
||
Other
|
|
14,189
|
|
|
4,418
|
|
||
Total accrued liabilities
|
|
$
|
170,855
|
|
|
$
|
174,348
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Cash paid for income taxes
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,895
|
|
Cash paid for interest expense, net of amounts capitalized
|
|
$
|
29,474
|
|
|
$
|
32,760
|
|
|
$
|
27,464
|
|
Increase in asset retirement obligations related to mineral properties
|
|
$
|
2,614
|
|
|
$
|
4,385
|
|
|
$
|
3,817
|
|
Increase (decrease) in asset retirement obligations related to midstream properties
|
|
$
|
686
|
|
|
$
|
(60
|
)
|
|
$
|
222
|
|
(Decrease) increase in liabilities for oil and natural gas properties capital expenditures
|
|
$
|
(16,802
|
)
|
|
$
|
48,929
|
|
|
$
|
1,775
|
|
Increase (decrease) in liabilities for midstream properties capital expenditures
|
|
$
|
2,499
|
|
|
$
|
(955
|
)
|
|
$
|
(588
|
)
|
Issuance of restricted stock units for director and advisor services
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
992
|
|
Stock-based compensation (benefit) expense recognized as liability
|
|
$
|
(1,069
|
)
|
|
$
|
362
|
|
|
$
|
569
|
|
(Decrease) increase in liabilities for accrued cost to issue equity
|
|
$
|
—
|
|
|
$
|
(343
|
)
|
|
$
|
343
|
|
Increase in liabilities for accrued cost to issue debt
|
|
$
|
232
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Transfer of inventory from (to) oil and natural gas properties
|
|
$
|
409
|
|
|
$
|
(374
|
)
|
|
$
|
395
|
|
Transfer of inventory to midstream and other property and equipment
|
|
$
|
—
|
|
|
$
|
(317
|
)
|
|
$
|
—
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Cash
|
|
$
|
64,545
|
|
|
$
|
96,505
|
|
|
$
|
212,884
|
|
Restricted cash
|
|
19,439
|
|
|
5,977
|
|
|
1,258
|
|
|||
Total cash and restricted cash
|
|
$
|
83,984
|
|
|
$
|
102,482
|
|
|
$
|
214,142
|
|
|
Exploration and Production
|
|
|
|
|
|
Consolidations and Eliminations
|
|
Consolidated Company
|
||||||||||
|
|
Midstream
|
|
Corporate
|
|
|
|||||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas revenues
|
$
|
794,261
|
|
|
$
|
6,439
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
800,700
|
|
Midstream services revenues
|
—
|
|
|
86,737
|
|
|
—
|
|
|
(64,817
|
)
|
|
21,920
|
|
|||||
Sales of purchased natural gas
|
902
|
|
|
6,169
|
|
|
—
|
|
|
—
|
|
|
7,071
|
|
|||||
Lease bonus - mineral acreage
|
2,489
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,489
|
|
|||||
Realized gain on derivatives
|
2,334
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,334
|
|
|||||
Unrealized gain on derivatives
|
65,085
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
65,085
|
|
|||||
Expenses
(1)
|
487,539
|
|
|
44,098
|
|
|
69,508
|
|
|
(64,817
|
)
|
|
536,328
|
|
|||||
Operating income (loss)
(2)
|
$
|
377,532
|
|
|
$
|
55,247
|
|
|
$
|
(69,508
|
)
|
|
$
|
—
|
|
|
$
|
363,271
|
|
Total assets
|
$
|
2,910,326
|
|
|
$
|
439,953
|
|
|
$
|
105,239
|
|
|
$
|
—
|
|
|
$
|
3,455,518
|
|
Capital expenditures
(3)
|
$
|
1,335,690
|
|
|
$
|
166,407
|
|
|
$
|
2,562
|
|
|
$
|
—
|
|
|
$
|
1,504,659
|
|
(1)
|
Includes depletion, depreciation and amortization expenses of
$252.3 million
and
$10.5 million
for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of
$2.4 million
.
|
(2)
|
Includes
$25.6 million
in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.
|
(3)
|
Includes
$656.9 million
attributable to land and seismic acquisition expenditures related to the exploration and production segment and
$80.2 million
in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.
|
|
Exploration and Production
|
|
|
|
|
|
Consolidations and Eliminations
|
|
Consolidated Company
|
||||||||||
|
|
Midstream
|
|
Corporate
|
|
|
|||||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas revenues
|
$
|
525,862
|
|
|
$
|
2,822
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
528,684
|
|
Midstream services revenues
|
—
|
|
|
47,037
|
|
|
—
|
|
|
(36,839
|
)
|
|
10,198
|
|
|||||
Realized loss on derivatives
|
(4,321
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,321
|
)
|
|||||
Unrealized gain on derivatives
|
9,715
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,715
|
|
|||||
Expenses
(1)
|
333,923
|
|
|
23,420
|
|
|
62,931
|
|
|
(36,839
|
)
|
|
383,435
|
|
|||||
Operating income (loss)
(2)
|
$
|
197,333
|
|
|
$
|
26,439
|
|
|
$
|
(62,931
|
)
|
|
$
|
—
|
|
|
$
|
160,841
|
|
Total assets
|
$
|
1,768,393
|
|
|
$
|
257,871
|
|
|
$
|
119,426
|
|
|
$
|
—
|
|
|
$
|
2,145,690
|
|
Capital expenditures
(3)
|
$
|
753,157
|
|
|
$
|
114,113
|
|
|
$
|
5,688
|
|
|
$
|
—
|
|
|
$
|
872,958
|
|
(1)
|
Includes depletion, depreciation and amortization expenses of
$170.5 million
and
$5.2 million
for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of
$1.7 million
.
|
(2)
|
Includes
$12.1 million
in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.
|
(3)
|
Includes
$54.9 million
in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.
|
|
Exploration and Production
|
|
|
|
|
|
Consolidations and Eliminations
|
|
Consolidated Company
|
||||||||||
|
|
Midstream
|
|
Corporate
|
|
|
|||||||||||||
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 loss 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
|
|
(1)
|
Includes depletion, depreciation and amortization expenses of
$118.4 million
and
$2.7 million
for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of
$0.9 million
and full-cost ceiling impairment expense of
$158.6 million
for the exploration and production segment.
|
(2)
|
Includes
$0.4 million
in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.
|
Condensed Consolidating Balance Sheet
December 31, 2018 |
||||||||||||||||||||
|
|
Matador
|
|
Non-Guarantor Subsidiaries
|
|
Guarantor Subsidiaries
|
|
Eliminating Entries
|
|
Consolidated
|
||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Intercompany receivable
|
|
$
|
1,244,405
|
|
|
$
|
29,816
|
|
|
$
|
—
|
|
|
$
|
(1,274,221
|
)
|
|
$
|
—
|
|
Current assets
|
|
4,109
|
|
|
34,027
|
|
|
267,549
|
|
|
—
|
|
|
305,685
|
|
|||||
Net property and equipment
|
|
—
|
|
|
379,052
|
|
|
2,743,812
|
|
|
—
|
|
|
3,122,864
|
|
|||||
Investment in subsidiaries
|
|
1,490,401
|
|
|
—
|
|
|
95,346
|
|
|
(1,585,747
|
)
|
|
—
|
|
|||||
Long-term assets
|
|
23,897
|
|
|
1,479
|
|
|
11,095
|
|
|
(9,502
|
)
|
|
26,969
|
|
|||||
Total assets
|
|
$
|
2,762,812
|
|
|
$
|
444,374
|
|
|
$
|
3,117,802
|
|
|
$
|
(2,869,470
|
)
|
|
$
|
3,455,518
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Intercompany payable
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,274,221
|
|
|
$
|
(1,274,221
|
)
|
|
$
|
—
|
|
Current liabilities
|
|
22,874
|
|
|
27,988
|
|
|
279,884
|
|
|
(724
|
)
|
|
330,022
|
|
|||||
Senior unsecured notes payable
|
|
1,037,837
|
|
|
—
|
|
|
—
|
|
|
|
|
1,037,837
|
|
||||||
Other long-term liabilities
|
|
13,221
|
|
|
230,263
|
|
|
73,296
|
|
|
(8,778
|
)
|
|
308,002
|
|
|||||
Total equity attributable to Matador Resources Company
|
|
1,688,880
|
|
|
95,346
|
|
|
1,490,401
|
|
|
(1,585,747
|
)
|
|
1,688,880
|
|
|||||
Non-controlling interest in subsidiaries
|
|
—
|
|
|
90,777
|
|
|
—
|
|
|
—
|
|
|
90,777
|
|
|||||
Total liabilities and equity
|
|
$
|
2,762,812
|
|
|
$
|
444,374
|
|
|
$
|
3,117,802
|
|
|
$
|
(2,869,470
|
)
|
|
$
|
3,455,518
|
|
Condensed Consolidating Balance Sheet
December 31, 2017 |
||||||||||||||||||||
|
|
Matador
|
|
Non-Guarantor Subsidiaries
|
|
Guarantor Subsidiaries
|
|
Eliminating Entries
|
|
Consolidated
|
||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Intercompany receivable
|
|
$
|
585,109
|
|
|
$
|
2,912
|
|
|
$
|
—
|
|
|
$
|
(588,021
|
)
|
|
$
|
—
|
|
Third-party current assets
|
|
2,240
|
|
|
9,334
|
|
|
245,596
|
|
|
—
|
|
|
257,170
|
|
|||||
Net property and equipment
|
|
—
|
|
|
223,178
|
|
|
1,658,278
|
|
|
—
|
|
|
1,881,456
|
|
|||||
Investment in subsidiaries
|
|
1,147,295
|
|
|
—
|
|
|
111,077
|
|
|
(1,258,372
|
)
|
|
—
|
|
|||||
Third-party long-term assets
|
|
6,425
|
|
|
—
|
|
|
3,642
|
|
|
(3,003
|
)
|
|
7,064
|
|
|||||
Total assets
|
|
$
|
1,741,069
|
|
|
$
|
235,424
|
|
|
$
|
2,018,593
|
|
|
$
|
(1,849,396
|
)
|
|
$
|
2,145,690
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Intercompany payable
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
588,021
|
|
|
$
|
(588,021
|
)
|
|
$
|
—
|
|
Third-party current liabilities
|
|
8,847
|
|
|
19,891
|
|
|
254,142
|
|
|
(274
|
)
|
|
282,606
|
|
|||||
Senior unsecured notes payable
|
|
574,073
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
574,073
|
|
|||||
Other third-party long-term liabilities
|
|
1,593
|
|
|
3,466
|
|
|
29,135
|
|
|
(2,729
|
)
|
|
31,465
|
|
|||||
Total equity attributable to Matador Resources Company
|
|
1,156,556
|
|
|
111,077
|
|
|
1,147,295
|
|
|
(1,258,372
|
)
|
|
1,156,556
|
|
|||||
Non-controlling interest in subsidiaries
|
|
—
|
|
|
100,990
|
|
|
—
|
|
|
—
|
|
|
100,990
|
|
|||||
Total liabilities and equity
|
|
$
|
1,741,069
|
|
|
$
|
235,424
|
|
|
$
|
2,018,593
|
|
|
$
|
(1,849,396
|
)
|
|
$
|
2,145,690
|
|
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2018 |
||||||||||||||||||||
|
|
Matador
|
|
Non-Guarantor Subsidiaries
|
|
Guarantor Subsidiaries
|
|
Eliminating Entries
|
|
Consolidated
|
||||||||||
Total revenues
|
|
$
|
—
|
|
|
$
|
98,665
|
|
|
$
|
865,725
|
|
|
$
|
(64,791
|
)
|
|
$
|
899,599
|
|
Total expenses
|
|
4,935
|
|
|
46,236
|
|
|
549,948
|
|
|
(64,791
|
)
|
|
536,328
|
|
|||||
Operating (loss) income
|
|
(4,935
|
)
|
|
52,429
|
|
|
315,777
|
|
|
—
|
|
|
363,271
|
|
|||||
Net loss on asset sales and inventory impairment
|
|
—
|
|
|
—
|
|
|
(196
|
)
|
|
—
|
|
|
(196
|
)
|
|||||
Interest expense
|
|
(40,994
|
)
|
|
(333
|
)
|
|
—
|
|
|
—
|
|
|
(41,327
|
)
|
|||||
Prepayment penalty on extinguishment of debt
|
|
(31,226
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(31,226
|
)
|
|||||
Other income
|
|
565
|
|
|
62
|
|
|
924
|
|
|
—
|
|
|
1,551
|
|
|||||
Earnings in subsidiaries
|
|
343,106
|
|
|
—
|
|
|
26,601
|
|
|
(369,707
|
)
|
|
—
|
|
|||||
Income before income taxes
|
|
266,516
|
|
|
52,158
|
|
|
343,106
|
|
|
(369,707
|
)
|
|
292,073
|
|
|||||
Total income tax benefit
|
|
(7,691
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,691
|
)
|
|||||
Net income attributable to non-controlling interest in subsidiaries
|
|
—
|
|
|
(25,557
|
)
|
|
—
|
|
|
—
|
|
|
(25,557
|
)
|
|||||
Net income attributable to Matador Resources Company shareholders
|
|
$
|
274,207
|
|
|
$
|
26,601
|
|
|
$
|
343,106
|
|
|
$
|
(369,707
|
)
|
|
$
|
274,207
|
|
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2017 |
||||||||||||||||||||
|
|
Matador
|
|
Non-Guarantor Subsidiaries
|
|
Guarantor Subsidiaries
|
|
Eliminating Entries
|
|
Consolidated
|
||||||||||
Total revenues
|
|
$
|
—
|
|
|
$
|
47,883
|
|
|
$
|
531,508
|
|
|
$
|
(35,115
|
)
|
|
$
|
544,276
|
|
Total expenses
|
|
5,610
|
|
|
21,260
|
|
|
391,680
|
|
|
(35,115
|
)
|
|
383,435
|
|
|||||
Operating (loss) income
|
|
(5,610
|
)
|
|
26,623
|
|
|
139,828
|
|
|
—
|
|
|
160,841
|
|
|||||
Net gain on asset sales and inventory impairment
|
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
|
23
|
|
|||||
Interest expense
|
|
(34,565
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(34,565
|
)
|
|||||
Other income
|
|
27
|
|
|
37
|
|
|
3,487
|
|
|
—
|
|
|
3,551
|
|
|||||
Earnings in subsidiaries
|
|
157,589
|
|
|
—
|
|
|
14,251
|
|
|
(171,840
|
)
|
|
—
|
|
|||||
Income before income taxes
|
|
117,441
|
|
|
26,660
|
|
|
157,589
|
|
|
(171,840
|
)
|
|
129,850
|
|
|||||
Total income tax (benefit) provision
|
|
(8,426
|
)
|
|
269
|
|
|
—
|
|
|
—
|
|
|
(8,157
|
)
|
|||||
Net income attributable to non-controlling interest in subsidiaries
|
|
—
|
|
|
(12,140
|
)
|
|
—
|
|
|
—
|
|
|
(12,140
|
)
|
|||||
Net income attributable to Matador Resources Company shareholders
|
|
$
|
125,867
|
|
|
$
|
14,251
|
|
|
$
|
157,589
|
|
|
$
|
(171,840
|
)
|
|
$
|
125,867
|
|
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2016 |
||||||||||||||||||||
|
|
Matador
|
|
Non-Guarantor Subsidiaries
|
|
Guarantor Subsidiaries
|
|
Eliminating Entries
|
|
Consolidated
|
||||||||||
Total revenues
|
|
$
|
—
|
|
|
$
|
17,302
|
|
|
$
|
257,828
|
|
|
$
|
(10,708
|
)
|
|
$
|
264,422
|
|
Total expenses
|
|
5,319
|
|
|
7,031
|
|
|
439,947
|
|
|
(10,708
|
)
|
|
441,589
|
|
|||||
Operating (loss) income
|
|
(5,319
|
)
|
|
10,271
|
|
|
(182,119
|
)
|
|
—
|
|
|
(177,167
|
)
|
|||||
Net gain on asset sales and inventory impairment
|
|
—
|
|
|
—
|
|
|
107,277
|
|
|
—
|
|
|
107,277
|
|
|||||
Interest expense
|
|
(28,199
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(28,199
|
)
|
|||||
Other expense
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
|||||
(Loss) earnings in subsidiaries
|
|
(64,349
|
)
|
|
—
|
|
|
9,810
|
|
|
54,539
|
|
|
—
|
|
|||||
(Loss) income before income taxes
|
|
(97,867
|
)
|
|
10,271
|
|
|
(65,036
|
)
|
|
54,539
|
|
|
(98,093
|
)
|
|||||
Total income tax (benefit) provision
|
|
(446
|
)
|
|
97
|
|
|
(687
|
)
|
|
—
|
|
|
(1,036
|
)
|
|||||
Net income attributable to non-controlling interest in subsidiaries
|
|
—
|
|
|
(364
|
)
|
|
—
|
|
|
—
|
|
|
(364
|
)
|
|||||
Net (loss) income attributable to Matador Resources Company shareholders
|
|
$
|
(97,421
|
)
|
|
$
|
9,810
|
|
|
$
|
(64,349
|
)
|
|
$
|
54,539
|
|
|
$
|
(97,421
|
)
|
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2018 |
||||||||||||||||||||
|
|
Matador
|
|
Non-Guarantor Subsidiaries
|
|
Guarantor Subsidiaries
|
|
Eliminating Entries
|
|
Consolidated
|
||||||||||
Net cash (used in) provided by operating activities
|
|
$
|
(657,860
|
)
|
|
$
|
35,119
|
|
|
$
|
1,231,264
|
|
|
$
|
—
|
|
|
$
|
608,523
|
|
Net cash used in investing activities
|
|
—
|
|
|
(162,147
|
)
|
|
(1,310,776
|
)
|
|
(42,330
|
)
|
|
(1,515,253
|
)
|
|||||
Net cash provided by financing activities
|
|
658,030
|
|
|
140,205
|
|
|
47,667
|
|
|
42,330
|
|
|
888,232
|
|
|||||
Increase (decrease) in cash and restricted cash
|
|
170
|
|
|
13,177
|
|
|
(31,845
|
)
|
|
—
|
|
|
(18,498
|
)
|
|||||
Cash and restricted cash at beginning of year
|
|
286
|
|
|
5,663
|
|
|
96,533
|
|
|
—
|
|
|
102,482
|
|
|||||
Cash and restricted cash at end of year
|
|
$
|
456
|
|
|
$
|
18,840
|
|
|
$
|
64,688
|
|
|
$
|
—
|
|
|
$
|
83,984
|
|
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2017 |
||||||||||||||||||||
|
|
Matador
|
|
Non-Guarantor Subsidiaries
|
|
Guarantor Subsidiaries
|
|
Eliminating Entries
|
|
Consolidated
|
||||||||||
Net cash (used in) provided by operating activities
|
|
$
|
(307,982
|
)
|
|
$
|
21,308
|
|
|
$
|
585,799
|
|
|
$
|
—
|
|
|
$
|
299,125
|
|
Net cash provided by (used in) investing activities
|
|
33
|
|
|
(114,852
|
)
|
|
(597,870
|
)
|
|
(106,595
|
)
|
|
(819,284
|
)
|
|||||
Net cash provided by (used in) financing activities
|
|
208,440
|
|
|
96,307
|
|
|
(2,843
|
)
|
|
106,595
|
|
|
408,499
|
|
|||||
Decrease in cash and restricted cash
|
|
(99,509
|
)
|
|
2,763
|
|
|
(14,914
|
)
|
|
—
|
|
|
(111,660
|
)
|
|||||
Cash and restricted cash at beginning of year
|
|
99,795
|
|
|
2,900
|
|
|
111,447
|
|
|
—
|
|
|
214,142
|
|
|||||
Cash and restricted cash at end of year
|
|
$
|
286
|
|
|
$
|
5,663
|
|
|
$
|
96,533
|
|
|
$
|
—
|
|
|
$
|
102,482
|
|
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2016 |
||||||||||||||||||||
|
|
Matador
|
|
Non-Guarantor Subsidiaries
|
|
Guarantor Subsidiaries
|
|
Eliminating Entries
|
|
Consolidated
|
||||||||||
Net cash (used in) provided by operating activities
|
|
$
|
(45,215
|
)
|
|
$
|
6,694
|
|
|
$
|
172,607
|
|
|
$
|
—
|
|
|
$
|
134,086
|
|
Net cash used in investing activities
|
|
(324,724
|
)
|
|
(64,999
|
)
|
|
(443,817
|
)
|
|
384,801
|
|
|
(448,739
|
)
|
|||||
Net cash provided by financing activities
|
|
469,654
|
|
|
60,110
|
|
|
322,743
|
|
|
(384,801
|
)
|
|
467,706
|
|
|||||
Increase in cash and restricted cash
|
|
99,715
|
|
|
1,805
|
|
|
51,533
|
|
|
—
|
|
|
153,053
|
|
|||||
Cash and restricted cash at beginning of year
|
|
80
|
|
|
1,095
|
|
|
59,914
|
|
|
—
|
|
|
61,089
|
|
|||||
Cash and restricted cash at end of year
|
|
$
|
99,795
|
|
|
$
|
2,900
|
|
|
$
|
111,447
|
|
|
$
|
—
|
|
|
$
|
214,142
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Property acquisition costs
|
|
|
|
|
|
|
||||||
Proved
|
|
$
|
4,788
|
|
|
$
|
45,270
|
|
|
$
|
—
|
|
Unproved and unevaluated
|
|
633,502
|
|
|
214,662
|
|
|
108,206
|
|
|||
Exploration costs
|
|
229,974
|
|
|
167,213
|
|
|
113,562
|
|
|||
Development costs
|
|
467,426
|
|
|
326,012
|
|
|
158,113
|
|
|||
Total costs incurred
(1)
|
|
$
|
1,335,690
|
|
|
$
|
753,157
|
|
|
$
|
379,881
|
|
(1)
|
Excludes midstream-related development and corporate costs of approximately $169.0 million, $119.8 million and $74.5 million for the years ended
December 31, 2018, 2017 and 2016
, respectively.
|
|
|
Net Proved Reserves
|
|||||||
|
|
Oil
|
|
Natural Gas
|
|
Oil
Equivalent
|
|||
|
|
(MBbl)
|
|
(MMcf)
|
|
(MBOE)
|
|||
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
|
|
Revisions of prior estimates
|
|
3,847
|
|
|
34,395
|
|
|
9,580
|
|
Purchases of minerals-in-place
|
|
5,257
|
|
|
7,348
|
|
|
6,482
|
|
Extensions and discoveries
|
|
28,513
|
|
|
99,935
|
|
|
45,169
|
|
Production
|
|
(7,851
|
)
|
|
(38,163
|
)
|
|
(14,212
|
)
|
Total at December 31, 2017
|
|
86,743
|
|
|
396,164
|
|
|
152,771
|
|
Revisions of prior estimates
|
|
5,908
|
|
|
32,497
|
|
|
11,326
|
|
Purchases of minerals-in-place
|
|
446
|
|
|
900
|
|
|
596
|
|
Extensions and discoveries
|
|
41,445
|
|
|
169,224
|
|
|
69,646
|
|
Production
|
|
(11,141
|
)
|
|
(47,311
|
)
|
|
(19,026
|
)
|
Total at December 31, 2018
|
|
123,401
|
|
|
551,474
|
|
|
215,313
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|||
December 31, 2015
|
|
17,129
|
|
|
101,447
|
|
|
34,037
|
|
December 31, 2016
|
|
22,604
|
|
|
126,759
|
|
|
43,731
|
|
December 31, 2017
|
|
36,966
|
|
|
190,109
|
|
|
68,651
|
|
December 31, 2018
|
|
53,223
|
|
|
246,229
|
|
|
94,261
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|||
December 31, 2015
|
|
28,515
|
|
|
135,454
|
|
|
51,090
|
|
December 31, 2016
|
|
34,373
|
|
|
165,890
|
|
|
62,021
|
|
December 31, 2017
|
|
49,777
|
|
|
206,055
|
|
|
84,120
|
|
December 31, 2018
|
|
70,178
|
|
|
305,245
|
|
|
121,052
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Future cash inflows
|
|
$
|
8,822,004
|
|
|
$
|
5,249,116
|
|
|
$
|
2,684,877
|
|
Future production costs
|
|
(2,713,043
|
)
|
|
(1,759,495
|
)
|
|
(927,725
|
)
|
|||
Future development costs
|
|
(1,384,916
|
)
|
|
(1,029,105
|
)
|
|
(630,280
|
)
|
|||
Future income tax expense
|
|
(710,222
|
)
|
|
(228,622
|
)
|
|
(24,742
|
)
|
|||
Future net cash flows
|
|
4,013,823
|
|
|
2,231,894
|
|
|
1,102,130
|
|
|||
10% annual discount for estimated timing of cash flows
|
|
(1,763,210
|
)
|
|
(973,248
|
)
|
|
(527,087
|
)
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
2,250,613
|
|
|
$
|
1,258,646
|
|
|
$
|
575,043
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Balance, beginning of period
|
|
$
|
1,258,646
|
|
|
$
|
575,043
|
|
|
$
|
529,181
|
|
Net change in sales and transfer prices and in production (lifting) costs related to future production
|
|
574,381
|
|
|
374,370
|
|
|
(92,477
|
)
|
|||
Changes in estimated future development costs
|
|
(347,038
|
)
|
|
(298,504
|
)
|
|
(74,142
|
)
|
|||
Sales and transfers of oil and natural gas produced during the period
|
|
(631,596
|
)
|
|
(403,095
|
)
|
|
(191,908
|
)
|
|||
Purchases of reserves in place
|
|
9,227
|
|
|
97,225
|
|
|
—
|
|
|||
Net change due to extensions and discoveries
|
|
1,078,935
|
|
|
677,681
|
|
|
360,033
|
|
|||
Net change due to revisions in estimates of reserves quantities
|
|
175,440
|
|
|
143,749
|
|
|
(95,917
|
)
|
|||
Previously estimated development costs incurred during the period
|
|
279,799
|
|
|
151,974
|
|
|
84,519
|
|
|||
Accretion of discount
|
|
103,085
|
|
|
54,623
|
|
|
51,779
|
|
|||
Other
|
|
3,600
|
|
|
(3,929
|
)
|
|
(1,962
|
)
|
|||
Net change in income taxes
|
|
(253,866
|
)
|
|
(110,491
|
)
|
|
5,937
|
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
2,250,613
|
|
|
$
|
1,258,646
|
|
|
$
|
575,043
|
|
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
||||||||
2018
|
|
|
|
|
|
|
|
|
||||||||
Oil and natural gas revenues
|
|
$
|
193,445
|
|
|
$
|
216,282
|
|
|
$
|
209,019
|
|
|
$
|
181,954
|
|
Third-party midstream services revenues
|
|
8,636
|
|
|
6,809
|
|
|
3,407
|
|
|
3,068
|
|
||||
Sales of purchased gas
|
|
7,071
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Lease bonus - mineral acreage
|
|
2,489
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Realized gain (loss) on derivatives
|
|
3,656
|
|
|
5,424
|
|
|
(2,488
|
)
|
|
(4,258
|
)
|
||||
Unrealized gain (loss) on derivatives
|
|
74,577
|
|
|
(21,337
|
)
|
|
1,429
|
|
|
10,416
|
|
||||
Expenses
|
|
141,811
|
|
|
139,325
|
|
|
137,374
|
|
|
117,818
|
|
||||
Other expense
|
|
(11,666
|
)
|
|
(42,738
|
)
|
|
(8,356
|
)
|
|
(8,438
|
)
|
||||
Income before income taxes
|
|
136,397
|
|
|
25,115
|
|
|
65,637
|
|
|
64,924
|
|
||||
Income tax benefit
|
|
(7,691
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Net income
|
|
144,088
|
|
|
25,115
|
|
|
65,637
|
|
|
64,924
|
|
||||
Net income attributable to non-controlling interest in subsidiaries
|
|
(7,375
|
)
|
|
(7,321
|
)
|
|
(5,831
|
)
|
|
(5,030
|
)
|
||||
Net income attributable to
Matador Resources Company shareholders |
|
$
|
136,713
|
|
|
$
|
17,794
|
|
|
$
|
59,806
|
|
|
$
|
59,894
|
|
Earnings per common share
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
1.18
|
|
|
$
|
0.15
|
|
|
$
|
0.53
|
|
|
$
|
0.55
|
|
Diluted
|
|
$
|
1.17
|
|
|
$
|
0.15
|
|
|
$
|
0.53
|
|
|
$
|
0.55
|
|
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
||||||||
2017
|
|
|
|
|
|
|
|
|
||||||||
Oil and natural gas revenues
|
|
$
|
165,125
|
|
|
$
|
134,948
|
|
|
$
|
113,764
|
|
|
$
|
114,847
|
|
Third-party midstream services revenues
|
|
3,326
|
|
|
3,218
|
|
|
2,099
|
|
|
1,555
|
|
||||
Realized (loss) gain on derivatives
|
|
(3,145
|
)
|
|
485
|
|
|
558
|
|
|
(2,219
|
)
|
||||
Unrealized (loss) gain on derivatives
|
|
(11,734
|
)
|
|
(12,372
|
)
|
|
13,190
|
|
|
20,631
|
|
||||
Expenses
|
|
112,547
|
|
|
99,730
|
|
|
90,622
|
|
|
80,536
|
|
||||
Other expense
|
|
(6,741
|
)
|
|
(8,570
|
)
|
|
(7,302
|
)
|
|
(8,378
|
)
|
||||
Income before income taxes
|
|
34,284
|
|
|
17,979
|
|
|
31,687
|
|
|
45,900
|
|
||||
Income tax benefit
|
|
(8,157
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Net income
|
|
42,441
|
|
|
17,979
|
|
|
31,687
|
|
|
45,900
|
|
||||
Net income attributable to non-controlling interest in subsidiaries
|
|
(4,106
|
)
|
|
(2,940
|
)
|
|
(3,178
|
)
|
|
(1,916
|
)
|
||||
Net income attributable to
Matador Resources Company shareholders |
|
$
|
38,335
|
|
|
$
|
15,039
|
|
|
$
|
28,509
|
|
|
$
|
43,984
|
|
Earnings per common share
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
0.36
|
|
|
$
|
0.15
|
|
|
$
|
0.28
|
|
|
$
|
0.44
|
|
Diluted
|
|
$
|
0.35
|
|
|
$
|
0.15
|
|
|
$
|
0.28
|
|
|
$
|
0.44
|
|
Title:
|
Executive Vice President
|
Title:
|
Executive Vice President
|
Title:
|
Executive Vice President
|
Title:
|
Executive Vice President
|
i.
|
PERFORMANCE PERIOD
|
ii.
|
PERFORMANCE GOAL
|
Company’s Percentile Ranking
|
Percentage of Target Units that will become Vested Units
|
0
|
0%
|
10th
|
20%
|
20th
|
40%
|
30th
|
60%
|
40th
|
80%
|
50th
|
100
|
60th
|
120%
|
70th
|
140%
|
80th
|
160%
|
90th
|
180%
|
100th
|
200%
|
|
|
|
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 Holdings, LLC
|
|
Texas
|
|
|
|
Longwood Midstream Southeast, LLC
|
|
Texas
|
|
|
|
Longwood Midstream South Texas, LLC
|
|
Texas
|
|
|
|
Longwood RB Pipeline, LLC
|
|
Texas
|
|
|
|
Longwood Wolf Pipeline, 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
|
|
|
|
San Mateo Black River Oil Pipeline, LLC
|
|
Texas
|
|
|
|
San Mateo Midstream, LLC
|
|
Texas
|
|
|
|
Southeast Water Management Company, LLC
|
|
Texas
|
|
|
|
WR Permian, LLC
|
|
Delaware
|
|
|
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, 2019
|
|
/s/ Joseph Wm. Foran
|
|
|
Joseph Wm. Foran
|
|
|
Chairman and Chief Executive Officer
(Principal Executive Officer)
|
|
|
|
March 1, 2019
|
|
/s/ David E. Lancaster
|
|
|
David E. Lancaster
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
|
March 1, 2019
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/s/ Joseph Wm. Foran
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Joseph Wm. Foran
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Chairman and Chief Executive Officer
(Principal Executive Officer)
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March 1, 2019
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/s/ David E. Lancaster
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David E. Lancaster
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Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
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Net Reserves
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Future Net Revenue (M$)
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||||
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Oil
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Gas
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Present Worth
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Category
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(MBBL)
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(MMCF)
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Total
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at 10%
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Proved Developed Producing
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51,961.8
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240,055.1
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2,288,650.2
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1,516,081.4
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Proved Developed Non-Producing
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1,261.3
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6,174.3
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62,410.1
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43,826.0
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Proved Undeveloped
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70,178.2
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305,245.2
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2,372,985.3
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1,019,390.4
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Total Proved
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123,401.3
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551,474.4
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4,724,047.4
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2,579,298.8
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